ML19344B290
| ML19344B290 | |
| Person / Time | |
|---|---|
| Site: | 05000447 |
| Issue date: | 08/18/1980 |
| From: | Quirk J GENERAL ELECTRIC CO. |
| To: | John Miller Office of Nuclear Reactor Regulation |
| References | |
| MFN-143-80, NUDOCS 8008260359 | |
| Download: ML19344B290 (48) | |
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G E N E R A L h, E LE CTRIC suctsaa powna SYSTsMS DIVISION GENERAL ELECTRIC COMPANY.175 CURTNER AVE.. SAN JOSE. CAUFORNIA 95125 JFQ-41-80 MFN-143-80 August 18, 1980 J.R. Miller, Chief Standardization and Special Projects Branch Nuclear Reactor Regulation Washington, D.C. 20555 In our telephone conversation of August 15, 1980, I agreed to send you General Electric Company's response to the Office of Technology Assess-ment (OTA) request for information pertaining to our BWR standard plant.
Enclosed, find a cover letter with its Attachment A-D that respond directly to OTA's request. In addition, Attachment E to the OTA response provides our views on the need for and an approach to one-step licensing. If I can be of assistance in clarifying any matters discussed therein, please feel free to contact me.
This also confirms our tentative agreement to meet on Friday, August 29, 1980 to discuss General Electric's standardization activities including our latest submittal GESSAR II.
J.F. Q irk, Manager WR Standardization M/C 682 (408) 925-2606
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..........'.27.".*",.^.'..... Ju1y 29, 1980 Mr. Lionel S. Johns Assistant Director Office of Technology Assessment Washington, D.C. 20510
Dear 11r. Johns:
This is to respond to your letter of June 9,1980 in which you requested descriptions on the following for our BWR standard plant:
A) the decay heat removal systems available to bring the plant from a hot standby subcritical condition to cold shutdown under both normal .and accident conditions, B) the standard control rocm design in relation to state-of-the-art ergonomics, C) the methods used to incorporate changes in the standard design including the review and approval process, and D) the design changes already impleented in the decay heat removal system and the reasons for the changes.
The General Electric standard plant is the SWR /6 nuclear island submitted March 31, 1980 under GESSAR Docket STN 50-447 for NRC review and issuance of Final Design Approval. The report, GESSAR II, consists of eighteen volumes describing and analyzing a standard 3579 MWt boiling water reactor nuclear plant.
Each of the descriptions is contained in a separate attachment bearing the alphabetical item number. With regard to Attachment A, decly heat removal systems, the General Electric standard plant design has evolved since the Dresden 2 design which was developed in the mid 1960's. There have been only a few minor changes in the recent years.
Hence, the description given in Attachment A also applies to our custom plants. There is no need to explain differences in manufacturing or construction costs.
As you probably know, General Electric suoports standardization and considers that standardization coupled with licensing reform is critical to sustained progress of the nuclear industry. Therefore, we have taken the 1iberty of sharing our views cn the subject in Attach-ment E which is entitled "The Need for and an Aoproach to One-Stec Licensing of Nuclear Power Plants."
Mr. Lionel S. Johns July 29, 1980 It will be apparent from your reading of Attachment E that General Electric has expended a great deal of effort in obtaining approval of standardized designs because of the potential benefits which can be derived from standardization. We believe that standardization will: expedite the licensing process and make it more efficient; contribute significantly to improved plant performance in the important areas of reliability and availability; create significant efficiencies in. labor allocation and construction; and provide for better planning by eliminating unnecessary design changes. Most importantly, standardization will mean an improve-ment in predictability, Pennitting utilities to plan effectively in their future.
For these reasons, we believe that congressional action to expedite standardization and to initiate reform of the present licensing process is a significant step toward solving the licensing problems now facing the NRC and the nuclear industry. I hope our views on the licensing process and standardization will be helpful to you.
Sincerely,
/YLy* hA av -
A. Philip Bray cc: Glenn G. Sherwood Robe-t fi. Ketchel Ed Abbott
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e o' A. DECAY HEAT REMOVAL SYSTEMS AVAILABLE TO REACH COLD SHUTDOWN CONDITIONS A.1 INTRODUCTION At the hot standby or steam condensing condition for a BWR, criticality is maintained but fission power is reduced to a low level (about 0.01%
of rated power) sufficient to maintain operating temperature. Steam is bypassed around the turbine via the turbine bypass system to the main condenser. Reactor coolant collected by the main condenser is returned to the reactor vessel as feedwater. The hot standby condition is illus-trated in Figure A-1.
The decay heat removal systems available to bring the plant from this hot standby condition to cold shutdown (normal and emergency)' and maintain reactor water level are described in Section A.2. The operational sequences during normal and emergency shutdowns are covered in Section A.3.
A.2 DECAY HEAT REM'0 VAL SYSTEMS The decay heat removal systems available to bring the plant from hot standby to cold shutdown may be divided into three general groups: 1) systems necessary for normal shutdown; 2) systems which accommodate or provide backup to the normal shutdown systems in case of an accident condition requiring emergency shutdown; and 3) systems used in normal plant operation which supplement decay heat removal. These groups of
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decay heat removal systems are:
Normal Shutdown Systems e Turbine Bypass System e Main Condenser e Circulating Water System and Ultimate Heat Sink e Condensate and Feedwater System 141-F1 A-1
e Shutdown Cooling Function of the Residual Heat Removal (RHR)
System o Service Water System (Cooling Mode)
Emergency Shutdown Systems e Reactor Core Isolation Cooling (RCIC) System
- e Steam Condensing Function of the RHR System" e Suppression Pool Cooling of the RHR System e Low Pressure Coolant Injection (LPCI) Function of the RHR System o Containment Spray function of tne RHR System o High Pressure Core Spray (HPCS) System e Low Pressure Core Spray (L?CS) System e Safety Reli.ef/ Valves
- and Automatic Depressu"ization System (ADS) e Condensate Storage System
- e Suppression Pool e Service Water System (Makeup Mode)
Sucolemental Systems e Reactor Water Hydraulic (RWCU) System o Control Rod Drive (CRD) Hydraulic System (Seal Injection)
Each of these decay heat removal systems is individually describeo in the paragraphs to follow. Table A-1 summarizes their mode of use and the range of reactor vessel pressure they coerate.
l 1.
" Abnormal / transient snutdown systems (non-accident) 141-F2 A.2
1 A.2.1 Normal Shutdown Systems A.2.1.1 Turbine Bypass System The turbine bypass system is designed to control reactor pressure during reactor heatup to rated pressure while the turbine is being brought up to speed and synchronized during: power operation when the reactor steam generation exceed the transient turbine steam requirements and during cool down of the reactor. The turbine bypass system capacity is approximately one-third of the rated reactor steam flow. The bypass system works in conjunction with the turbine controls (pressure control).
The turoine bypass valves are capable of remote manual operation in their normal sequence, during plant startup and shutdown, and for exer-cising to verify that the valves are operable. They are fast response, modulating-type valves, controlled by the steam bypass pressure regulator system. Their primary function is to reduce the rate of rise of reactor pressure when the turbine admission valves are moved rapidly in the closing direction. The bypass valves also control reactor pressure during startup of the tur 'ne. This allows the reactor power level to be held constant while the turoine steam flow is varied as the turbine is brougnt up to speed under the control of its speed governor. Finally, the bypass valves help control reactor pressure after the turoine has been tripped, discharge the decay heat to the condenser, and control the rate o' cooling of the reactor syste.n.
A. 2.1. 2 Main Condenser The main condenser provides the heat sink for the turbine exhaust steam, turbine bypass steam and other turbine cycle flows. It also receives and collects reactor coolant for return to the reactor via the condensate and feedwater system. Thus, the main condenser is the principal heat sink for normal plant oceration and for that portion of the shutdown cycle when the reactor is at a pressure greater than 135 psig. The heat load of the main condenser is removed by the circulating water system.
141-F3 A-3
A.2.1.3 Circulating Water System and Ultimate Heat Sink The heat load of the circulating water system is removed by the ultimate sink which is capable of providing sufficient cooling for a minimum of 30 days without makeup following shutdown. The specific cesign of the ultimate heat sink depends on the location of the site. Where large bodies of water are not available, the ultimate heat sink is normally a cooling tower.
A.2.1.4 Condensate and Feedwater System The condensate and feedwater system provides a supply of high quality feedwater to the-reactor. It provides the required flow at the required pressure to the react.or under all operating conditions including reactor shutdown. The condensate and feedwater system consists of the piping, valves, pumps, heat exchangers, controls, instrumentation, and the associated equipment which supply the reactor with feedwater in a closed steam cycle. The main portion of the feedwater is condensate pumped from the main condenser.
A.2.1.5 Shutdown Cooling Function of the RHR System The shutdown cooling function of the RHR system (Figure A-2) removes residual heat (decay heat and sensible heat) from the nuclear boiler system after reactor shutdown in preparation for refueling or nuclear system servicing. When the reactor vessel pressure is reduced to 135 psig after shutdown, the function of decay heat removal is transferred from the main condenser to the RHR system. The shutdown cooling function of the RHR system is manually initiated. Reactor water is then taken from one of the reactor water recirculation loops, pumped through the heat exchanger, and returned to the reactor vessel by way of the feedwater lines. The shutdown cooling function of the RHR system has the capability of reducing the reactor vessel to a temperature of 125 F and atmospheric pressure after the control rods are inserted for shutdown. It is then used for continuous removal of decay heat and reactor coolant temperature control while the reactor remains in the cold shutdown condition.
141-F4 A-4
A.2.1.6 Service Water System (Cooling Mode)
The service water system cooling mode distributes cooling water during various operating modes during sh':tdown and during post loss-of-coolant operations. The system removes heat from plant auxiliaries and transfers it to the circulating water system. The following decay removal systems are cooled by this mode of the service water system: shutdown cooling function of the RHR system, suppression pool cooling function of the RHR system, steam condensing function of the RHR system, and the containment spray function of the RHR system.
A.2.2 Emergency Shutdown Systems A.2.2.1 Reactor Cor.e Isolation Cooling System The RCIC system (Figure A-3) maintains a sufficient flow of water in the reactor pressure vessel to cool the core and then maintain the iluclear boiler in the standby condition in the event the reactor vessel becomes isolated from the main condenser and from feedwater makeup flow. The system also allows for complete plant shutdown under conditions of loss of the normal feedwater system by maintaining the necessary reactor water inventory until the reactor vessel is depressurized.
The RCIC system is one of several means used to provide cooling water to the core while the reactor syste:n remains pressurized - i.e. , over the range of operating pressure dow.1 to 135 psig. Below 135 psig, the RHR system is used in its normal shutdown cooling mode to remove decay heat and bring the plant to a cold shutdown condition. The system delivers rated flow of 725 gpm within 30 seconds after initiation. The system is operational in the reactor system pressure range of 1100 to O psig.
In the event the reactor vessel becomes isolated from the main condenser, the safetyfrelief valves automatically (or by operator action from the control room) maintain vessel pressure within desirable limits. I.. the 141-F5 A-5
event feedwater becomes unavailable, the water level in the reactor vessel drops due to continued steam generation and discharge of the steam through the relief valves to the suppression pool. When the water in the reactor vessel reaches a predetermined level, the RCIC system is initiated automatically. The turbine driven pump supplies makeup water from one of the following sources: the condensate < tor,ge tank (first source), or the suppression pool (a backup source). The turbine is driven with a portion of the decay heat steam from the reactor vessel and exhausts to the suppression pool.
The RCIC system operates independently of auxiliary a-c power, plant service air, or external cooling water systems. System valves and auxiliary pumps are designed to operate by cl-c power from the station batteries.
A.2.2.2 Steam Condensing Function of the RHR System During nuclear vessel isolation and in conjunction with the operation of the RCIC system and steam blowdown to the suppression pool, steam at reduced pressure and temperature is directed from the main steam lines to the RHR system heat exchangers (see Figure A-4). Condensate at a temperature not exceeding 140*F is directed to the RCIC system for the return to the nuclear boiler system. Noncondensable gases from the heat exchangers are vented to the suppression pool. Steam condensing is manually initiated.
A.2.2.3 Suppression Pool Cooling Function of the RHR System The suppression pool cooling function of the RHR system (Figure A-5) ensures that the temperature of the suppression pool water does not exceed specified limits of operation. Suppression pool water is pumped from the pool through either or both of two completely independent loops, including pump and heat exchanger, and returned to the pool. The heat removed 'c,y the heat exchanger is transferred to the RHR system service water system. Suppression pool cooling is manually initiated.
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141-F6
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A.2.2.4 Low Pressure Coolant Injection Function of the RHR System The LPCI function of the RHR system (Figure A-6) is used for pc;tulated accident events involving a loss of coolant, and reactor core cooling is maintained at reactor system pressures in the range of 250 to O psig.
The three LPCI loops are designed to provide cooling water to the reactor core at a rated flow of 7100 gpm per loop.
The operability of the LPCI pumps can be tested at any time during normal plant operation by bypassing the reactor vessel and pumping the flow back to the pressure suppression pool.
A.2.2.5 Containment Spray Function of the RHR System In addition to the functions of the RHR system already discussed, the RHR has a a ntainment spray function (Figure A-7) that condenses and removes heat of any steam that bypasses the drywell, and prevents over-pressurizatinn of the containment. The suppression pool water is pumped !
from the pool through either or both of the two completely independent loops, including pumps and heat exchanger, the same as the suppression ,
pool cooling mode, except the water passes through the containment spray headers before returning to the pool. The containment spray function is manually initiated and terminated. Full spray flow is achieved within three minutes of initiation.
A.2.2.6 High Pressure Core Spray System The purpose of the HPCS system (Figure A-8) is to depressurize the nuclear boiler system and to provide makeup watt:r in the event cf a loss of reactor coolant inventory. In addition, the HPCS system prevents fuel cladding damage (fragmentation) in the event the core becomes uncovered due to loss of coolant inventory by directing this makeup water down into the area o' the fuel assemblies. The makeup water is jetted as a spray over the area of the fuel assemblies from nozzles mounted in a sprager ring located inside the reactor vessel above the fuel assemblies. The HPCS system is an integral part of the total 141-F7 A-7
design for emergency core cooling which Drovides for adequate core cooling and depressurization for all rates of coolant loss from the nuclear boiler.
The primary source of cooling water for the operation of the HPCS system is from the condensate storage tank. Upon depletion of this supply, the system automatically transfers to the water in the containment suppression pool. Water inventory lost from the nuclear boiler system from a postulated pipe break fills the drywell to weir wall level and then into the suppression pool thereby providing an inexhaustible supply of cooling water allowing continued operation of the HPCS system until it is manually stopped by the operator from the control room. The HPCS system is operational in the reactor pressure range of 1100 to 0 psig. The HPCS pump is designed to provide cooling water to the core at a rated flow of 6100 gpm.
A.2.2.7 Low Pressure Core _ Spray System The function of the LPCS system (Figure A-9) is to prevent fuel cladding damage (fragmentation) in the event the core is uncovered by the loss of coolant. The cooling effect is accomplished by directing jets of water down into the fuel assemblies from spray nozzles mounted in a sparger ring located above the reactor core. The system is also an integral part of the total design for emergency core cooling which provides for adequate core cooling for all rates of coolant loss from the nuclear boiler. The system goes into operation once the reactor vessel pressure has been reduced and the operation of the other eu rgency core cooling systems prove inadequate to maintain the ncessary water level in the reactor vessel at the reduced vessel pressure.
The LPCS system is connected to the primary containment suppression pool for its supply of water. The system is operational in the reactor
' system pressure range of 315 to O psig. The LPCS pumps are designed to provide cooling water to the core at a rated flow of 6100 gpm.
141-F8 A-8
In the event of complete loss of normal electric power, the spray system may be operated (automatically or manually) from the standby diesel generator.
Water lost from the reactor vessel collects in the drywell to the level of the weir wall and then flows into the suppression chamber. This establishes a closed loop allowing the spray system to continue to operate until it is manually stopped by the operator.
To allow for system testing during plant shutdown, reactor water, via a temporary connection (removable spool piece) to the RHR system, is discharged into the reactor vessel through the core spray sparger. The spool piece is removed prior to plant startup and the open pipe capped.
A.2.2.8 Safety / Relief Valves and Automatic Depressurization System Safety / relief valves are provided to ensure that the vessel pressure does not exceed the design value. They also provide the means to depres-surize the reactor vessel in the event the reactor becomes isolated from the main condenser. They depressurize the reactor vessel by discharging steam from the main steam lines inside the drywell to the suppression pool. For this relief function, multiple safety / relief valves are operated from reactor vessel pressure signals. Reactor depressurization is performed by manual actuation of a relief valve, with the rate of cooldown being kept below a preset temperature limit.
Blowdown, through selected safety / relief valves (the ADS) in conjunction with the operation of the LPCI function of the RHR system and/or LPCS system, functions as an alternate to the operation of the HPCS system for protection against fuel cladding damage upon loss of coolant over a given range cf steam or liquid line breaks. The blowdown depressurizes the reactor pressure vessel, permitting the operation of the LPCI function of the RHR system and/or the LPCS system. Blowdown is activated automa-tically upon coincident signals of low water level in the reacto; vessel and high drywell pressure. A time delay of approximately 2 minutes after receipt of the coincident signals allows the operator time to 141-F9 A-9
bypass the ADS if the signals are erroneous or the condition has corrected itself. The operator can initiate the ADS from the control room at any time.
A.2.2.9 Condensate Storage System Minimum water volume inventory of 150,000 gal. is provided in the condensate storage tank for the RCIC and HPCS Systems. This water is used to remove the decay heat generated over an 8-hr period from the time the reactor is scrammed from rated power. The only outlets below the 150,000 gal. minimum water volume of the condensate storage tank are for the RCIC and HPCS pumps. Manual valves for HPCS, RCIC and CR0 pump suction condensate lines are locked open to prevent them from being inadvertently closed.
A 7000 gal. surge volume, made up of a section of 36 inch diameter pipe, is provided as a header for suction of the HPCS and RCIC pumps. A level switch and alarm on the surge volume notifies the control room operator of a low surge volume condition and automatically switches the suction of these pumps over to the suppression pool volume.
A.2.2.10 Suppression Pool The suppression pool, illustrated in Figure A-3, is an annular pool of i demineralized water between the drywell and the outer containment boundary.
l This pool covers the horizontal vent openings in the drywell to maintain a water seal between the drywell interf or and the remainder of the containment volume.
The suppression pool orovides:
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- 1. means to condense steam released in the drywell area by discharging through the horizontal vents or through the safety / relief valves; 141-F10 A-10
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- 2. a heat sink for the RCIC system; and '
- 3. a source of water for the RCIC system, LPCI function of the RHR system, containment spray function of the RHR systen, HFCS system and LPCS system.
A.2.2.11 Service Water System (Makeup Mode)
The overall arrangement of the service water system and its cooling mode are described under paragraph A.2.1.6. The makeup mode of the service water system is a method of using the service water system to inject water into the reactor via one of the RHR/LPCI nozzles. The makeup made of the service water system is operational in the reactor system pressure range of 100 to 0 psig. Approximately 300 gpm of makeup water can be supplied by the servi.ce water system.
A.2.3 Suoplemental Systems' t
A.2.3.1 Reactor Water Cleanup System The primary purpose of the reactor water cleanup (RWCU) system (Figure A-10) is to maintain high reactor water quality by removing fission products, corrosion products, and other soluble and insoluble impurities.
In addition, the system provides a means for water removal from the primary system during periods of increasing water volume.
The cleanup system is sized to process the water vo'ume of the reactor system approximately 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />. The system can be operated during startup, shutdown, and refueling operation, as well as during normal plant opera-tions.
Recirculation Mode l
Water is removed from the reactor through the reactor recirculation pump suction line and returned through the feedwater line. Under normal operation, the water is removed at reactor temperature and pressure and 141-F11 A-ll r
pumped through regenerative and nc3 regenerative heat exchangers where it is cooled, and then through the filter-demineralizer units. The flow
, continues through the shell side of the regenerative heat exchanger where it is heated before returning to the reactor.
Blowdown Mode Ouring startup and other times of increasing water volume, excess water is normally removed from the reactor by blowdown through the cleanup system to the main condenser, or alternately to the waste collector tank, or waste surge tank. During this operation, the return flow to the regenerative heat exchanger is reduced, thereby reducing the cooling capability of this exchanger and correspondingly increasing the duty of the nonregenerative heat exchanger. The nonregenerative heat exchanger is designed to cool r.eactor water flow to the filter-demineralizer units to approximately 120 F during both normal operation and reactor vessel blowdown. Cooling water is supplied to the nonregenerative heat exchanger by the closed loop cooling water system.
A.2.3.2 Control Rod Drive Hydraulic System (Seal Injection)
The contral rod drive (CRO) hydraulic system, located close to but outside of the drywell, supplies pressurized demineralized water to the CR0 system to provide hydraulic operating pressure and cooling water for the drives. The cooling water to the drives leaks past the seals and into the reactor vessel. The CR0 hydraulic system (seal injection) is an effective source of makeup water to the core providing approximately 100 gpm (depends on seal wear). This water is injected over the full range of reactor vessel pressures.
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141-F12
A.3 NORMAL AND EMERGENCY SHUTDOWN PROCEDURES A.3.1 Normal Shutdown All control rods are inserted to make the core subcritical and system pressure is reduced by progressive readjustment of the pressure regulator setpoint to ensure controlled cooling. The determining factor is the allowable cooling rate (not in excess of 100 F per hour) for the pressure vessel and selected equipment. Steam is bypassed around the turbine to the main condenser until the shutdown cooling function of + r RHR is manually initiated at a vessel pressure of 135 psig.
A.3.2 Emergency Shutdown The plant is designed to accommodate emergency shutdown from all operating conditions including hot standby. If an emergency situation occurs prior to or during shutcown, all control rods are automatically inserted if the core is not already subcritical.
- The reactor vessel water level is maintained between established limits by the following systems:
e Condensate and Feedwater System o CRD Hydraulic System (Seal Injection) e RCIC System j e HPCS System e LPCS System -
e LPCI Function of the RHR System o Service Water System (Makeup Mode)
Pressure Reduction Assuming tnat the main condenser is available, the pressure vessel is then cooled and depressurized utilizing the turbine bypass valves with pressure reduction augmented by one or more of the following systems:
141-F13 A-13
e RCIC System e Steam Condensing Function at the RHR System o RWCU (Recirculation Mode) e RWCU (Blowdown Mode) e HPCS System If the main condenser is not available, the pressure vessel is depres-surized by safety / relief valve- in the relief or ADS mode and the cooldown rate is maintained with one or more of the following systems:
e HPCS System e Steam Condensing Mode of the RHR System e RWCU (Recirculation Mode)
Pressure reduction under this condition can be augmented by the RWCU blowdown mode.
Shutdown Cooling When the vessel pressure reaches 135 psig and has stabilized, the shutdown cooling function of the RHR system is initiated.
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B. STANDARD CONTROL ROOM DESIGN IN RELATION TO ERGONOMICS 8.1 CONTROL ROOM DESIGN
.The primary objective in t,he design of a control room for a standard plant is to provide an efficient coordinated power plant control system which increases operating availability and decreases construction and operating costs by using proven available designs and techniques in display and control hardware and software. Major design guidelines are:
o Integrate nuclear steam supply system (NSSS) and balance of plant (BOP). control and display functions into a plant control system capable of operation by a single operator under normal circumstances.
o Improve operator interface with the plant to simplify operation without compromising reliability of safety.
o Optimize the quantity of data the operator must continuously survey, comprehend, and analyze thus decreasing operator response time and decreasing the likelih;od of operator error.
o Optimize, simplify, and integrate the number of control devices the operator must routinely manipulate.
o Incorporate human engineering design and operational experience to optimize the location of control and display devices.
o Prefabricate the control room at the factory to facilitate complete factory system test before shipment and thereby reduce field costs.
141H 8-1
Based on these criteria, General Electric's Nuc14 net
- control complex is utilized in the standard control race design. The Nucienet control complex includes the major components necessary for controlling the operation of the plant. This includes consoles, benchboards, panels, computers, and computer peripherals integrated with their panels into a prefabricated, prewired and pretested control room complex.
The Nucienet complex Display Control System (DCS) is a video display based operator information system. The OCS uses computers to acquire data from the plant, convert the data into meaningful form and display the results on 10 color cathode ray tubes (CRTs) mounted in the operator's console (Figure B-1).
Basic features of the DCS include the ability to monitor hundreds of analog and digital pr.ocess variables and to display any selected variable within k second from the instant a significant change occurs to that variable. The system is designed to process a maximum of 25 significant changes within any % second period. Additional features include hardware and software redundancy for maintaining no less than 99.5 percent system availability, continuous on-line testing for hardware failure, and automatic reconfiguration if a major hardware component fails.
Major harcware components of the system (Figure B-2) include:
o Four central processing units o Rotating drum bulk memory o High speed computer-to-computer data links o Four video display generators o Eight remote digital units o Test and Reconfiguration (TRU) o Various switches Monitoring and processing of the analog and digital variables are performed by a pair of Data Acquisition Processors-(DAPs) controlling the remote analog and digital units.
- Trademark of the General Electric Corraany 141H B-2
Each remote analog unit is capable of scanning, signal conditioning and converting to digital form 32 analog variables at 5 samples per second.
Each remote digital unit can scan up to 64 digital variables at the same rate. The resulting data is multiplexed and sent to the DAPs over high speed serial data links.
During normal conditions each DAP processes one half of the variables or 150 analog and 100 digital variables. Redundant hardware is provided .
between the OAPs and the remote scanning units so that if either DAP fails or is undergoing routine maintenance, the remaining DAP assumes processing of the inoperative OAPs variables at a reduced rate.
On receipt of the data from the remote units, the DAPs adjust the data by gain compensation, offset correction, digital filtering, sensor drift compensation, and sensor calibration. In addition, the DAPs convert the input values to engineering units and check the data for error conditions, range limits, and significant enange. To reduce the processing load on the computers, an analog input compression technique is used. Data are compressed by comparing the absolute difference between the present and last stored value against a stored constant called a compression limit.
If the difference does not exceed the compression limit, then the stored value remains unchanged. A typical compression limit will have a value of 1 to 5 percent of the maximum value of the variable. Each DAP communi-cates with each Display Control Processor (DCP) over high speed data links, passing on any significant variable changes or error conditions detected for further processing, display and/or alarming.
Additional processing and video display control is the function of the two redundant DCPs, one designated on-line and the other standby. Each j DCP receives and processes identical information from the two DAPs.
However, only the on-line OCP is able to display the necessary information.
If the on-line OCP should fail, then the TRU will perform the necessary switching and the standby DCP is designated on-line. Disruption to the system is kept to a minimum because the standby DCP is receiving and processing identical data in synchronization with the on-line OCP. ,
1 141H B-3
The CCPs maintain a table of current values for all the analog and digital variables, uncate changing values anc gra: hic informatica displayec on the CRis, and, en operator cesand, retrieve new for.ats frem the bulk sescry to replace existing formats en the screens.
Each CRT cisplay consists of a coscinaticn of backgrounc and dynamic information. The background infersatica is cescriptive and never changes wnile en cisplay. Typical background inferzatien uses alphanumeric characters and gra nic syzccis for la els and icentifiers, a:Oreviated cescription, units of measure, points of reference, f.evice eneccing, connectors, anc line ciagrams anc area delineatien (Figure 3-3). Dynamic infersation is quantitative reflecting tne =agnicuce or status of peccess varia les. It is tre iaforsation which is cocated as significant cnanges cccur. Typical cynasic cata are displayed using al:hanumerical characters and/cr graphic sy=:cis for dar gra:ns, ti e picts, nuzerical values, atoreviated ceces, anc binary status.
3.2 CCNTROL RCCM ERGCNCMICS The ajor 0:erator-to-plant interf ace elesents (Figure E-4) in the Nucienet c::alex control recs are:
o The c:erator's c:nscie o The icng res;:ense bencn card o The reactor core c: cling benchtcard o The stancty inferaation panel Also located in the control roce are a superviser's enit ring console and equi;sent to print cecputer cut:ut and provice harc c: ies of CRT cisplays.
The cperator's censole (Figure 3-5) is the pri:ary interface cet-een the plant anc ne 0;erator. It hcuses all cisolays and c:nt ls recuirec for plant c:eration. The disclays consist of 10 CRTs. The ::ntrols are IGi E-a L
conventional miniature devices and in all cases are hardwired back to the control equipment. The annunciators are also hardwired.
The long response benchboard contains all auxiliary functions not requiring quick operator response. Displays on the long response benchboard are not processed by the DCS.
All display and manual control devices required for operation of safety equipment are located on the reactor core cooling benchboard. All circuits on the panel are har'Jwired to the safeguards systems and are not processed by the DCS.
The standby information panel can be used to back up the CRT displays in the event of failure of the DCS. This panel displays selected process variables using hardwired indicators. These indicators and the hardwired controls on the operator's console allow the plant to be maintained safely at a steady power level or to be shutdown in a safe and orderly manner.
The operator's console is human engineered to present plant data to the operator with maximum comprehensibility. Design of the console includes integration of the plant data into meaningful display formats which accurately present what is happening in the plant and can be readily understood by the operator. Human engineering has been applied to the shape of the console, the angle of its " wings", the distance between the operator and system control devices, the location of devices of the same l and related systems, the grouping of devices for ope'rator convenience, I and the selection of devices for maximum visibility, maximum usability, and minimum vulnerability to misoperation.
The layout of the operator's console is organized into three horizontal bands. From the top down, the bands consist of annunciators, displays, and controls. The operator's console is further arranged such that each plant system function is located within a vertical band. Within each system, controls are located in proximity to one another and arranged in l
141H B-5
functional groups. Controls are arranged so that sequence of use is in all cases left to rignt, or top to bottom, or both, relating to activity sequence. The more frequently used groups and more important group > are located in areas of easiest access.
Functional groups are visually set apart by outlining and by physical separation. The selection, marking, and arrangement of funtionally similar controls are consistent from system to system and panel to panel. Control functions are located so that they are not susceptible to accidental actuation. Pushbutton devices located in proximity to one another are provided witn barriers between the= to avoid accicental actuation. Instruments and controls related to systems requiring frecuent ,
operator interface are grouped on the central portion of the console while systems which require only infrequent operator interface are grouped on the " wings" of the console. When prudent, NSSS and SCP display and control devices are grouped together to permit more effective operator interface. An example of such regrouping is the NSSS anc SOP feedwater systems which in a contescorary BVR control room are located on different panels, sepaetted a distance of some 15 feet. In keeping with the philosophy for locating systems requiring only infrequent operator interface, instruments and control for the emergency core cooling system (ECCS) are located on a separate freestanding panel. In a contemocrary BWR control room these systems are centrally located as if they were part of the operator's major plant interface. Other systems, both NSSS and 50P, that have long response times are located on a long response panel. By removing the ECCS functions and systems with leng response times to separate panels, utilizing miniaturized switches, and replacing incicating devices with CRTs the conventional benchboard of the contemporary SWR control room, 50 feet in length is replaced by an operator's console only 15 feet in length. Eacn of the 10 CRTs mounted in the operator's console normally displays information recuired for operation of the system with which the CRT is grouped.
Several display formats are availacle for each system and, for cackup, each CRT is capable of displaying the formats r.ormally associated witn any other CRT.
141H 3-6
The operator is provided with three methods of display selection.
Located adjacent to each CRT are switches which select system assignment and any format associated with the assigned system. At the center of the console are master display select pushbuttons which, when operated,
! cause all CRTs to display those formats most appropriate to a give plant operating condition.
For example, " approach to critical" can be selected causing all CRTs to display preselected formats that contain display data more helpful during that phase of operation. The purpose of the master display select is to reduce operator effort in setting up all CRTs for specific operating conditions.
9 l
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.,'.o C. STANCARD PLANT DESIGN CONTROL C.1 GENERAL The design of structures, systems and components is controlled within the various design organizations to assure safe and reliable performance of products and services to be supplied. The design control processes are documented in practices and procedures which establish the responsi-bilities and interfaces of each organizational unit that has an assigned design responsibility. The practices and procedures include measures to assure that:
1 e design requirements are defined and design activities are carried out,in a planned, controlled, and orderly manner; e appropriate quality requirements and standards are specified in design documents; e suitable materials, components, and processes are specified in design documentation; l
e appropriate design verification methods are selected and implemented by individuals or groups not having direct responsibility for the original design; and e design changes are controlled to the same level as was applied l
to the original design, including review and approval by the same organization that performed the original review and approval unless another responsible organization is designated by GE management.
Each plant offered for sale is of a current product line which has been engineered as a standard plant design. The standard plant designs, and l changes thereto, is reviewed for conformance to GE product safety standards l
l l
C-1 141825 i
and to the applicable NRC regulations independent of sales commitments, and is updated as necessary to assure its compliance with changes to these standards and regulations. Modifications to the standard plant for a particular sale are made only pursuant to the contract with the Owner, provided safety and warranty conditions are not adversely affected.
Since each plant sold (a project) is based on a standard plant, it is not necessary to repeat the review of the standard plant for each specific plant design documentation for each project, but only to review the modifications, if any, for eech project.
The GE engineering organizations define and document acceptable and approved materials, parts, equipment and processes. The definition is documented in controlled design manuals and standards specifications.
Standard off the shelf commercial items are included. The standards specifications are reviewed, approved, and issued in accordance with the engineering review system. In addition, all equipment designers have available to them direct consultation services of materials engineers during the design action and design review phases. Application selection of materials is based upon this review system, and review of suitability occurs during the engineering review of design verification action.
Where engineering experience identifies a need for testing confirmation, suitable controlled qualification tests are performed.
(
Each discrete design for the GE standard plant is subject to the GE design control system. The GE design contro. measures are applied to:
analyses for performance parameters; reactor physics; stress; thermal; hydraulic; radiation; accidents; co.apatibility of materials; accessibility for in-service inspection, maintenance, and repair; and specification of criteria for insrection and test.
l
! The contractual design basis and data unique to a specific project is defined to the engineering organizations by the project or program manager. The infornation is documented in the appropriate project / program release document, e.g. , the Project Work Authorization (PWA), which authorizes and initiates the engineering and licensing work for the project.
141826
The design documentation for purchased components within the standard plant scope consists of one or more of the following documents: equipment procurement specifications which specify general requirements including codes, materials, processes, workmanship, and acceptance criteria; purchased part drawings which show the outline and interface requirements to match the standard plant design; and specific data sheets or project sheets which define the project unique requirements of the equipment.
The purchase specification identifies the engineering documents, such as drawings, procedures, calculations and test data which must be submitted by the vendor for review and approval.'
C. 2 STANDARD PLANT CHANGES The changes which are considered in the issued design are evaluated against the standard. plant reference and solutions are developed for the standard plant design. Changes required for safety are considered mandatory and are applied to the standard plant as well as the project to which the standard applies. Reviews and procedures which control these activities are described in the following paragraphs.
C.3 OESIGN CHANGE CONTROL Following initial issuance of engineering documents, a design change contro' procedure is implemented with controls commensurate with those applied to the original design. Measures for documenting and dispositioning design changes or design modifications are described 'n i the paragraphs to follow. The end result, after all changes have been incorporated, is reflected in accurate drawings, specifications and other documents which fully describe the final design for systems and equipment. The control procedure requires documentation of the change, design verification review of the change, and approval by the responsible engineer. The responsible engineer has the responsibility for defining all other design documents affected by the change, and for resolving and coordinating i changes with other engineers whose documents are affected. The Engineering l Change Notice (ECN) is used for documenting and recording approval for the change.
l 141827 C-3
ECN's are identified, issued, and controlled in accordance with documented procedures. Copies of the ECN's are distributed to desig,n interface personnel, including the responsible engineer who approved the change, the project manager, and to engineering, manufacturing, procurement, and QA personnel as appropriate. Design changes affecting interface conditions between Owner and GE supplied equipment are identified and reviewed by the project manager with the Owner or his designated representative.
Such documented changes are transmitted by the project manager to the owner or his designated representative for implementation of design and field changes, as appropriate, in his interfacing scope of supply.
C.4 FIELD CHANGE CONTROL After delivery of equipment and during the installation and sta. tup phases at the plant site, field changes that become necessary fd!' into two general classes: first, those generated by design changes, and second, those initiated in the field as a result of unique field conditions.
In order to accomplish a field change on GE furnished components, the responsible engineer processes a design change and issues a Field Disposition Instruction (FDI) which identifies the components affected, the changes to be made, the parts to be replaced, the source of replacement parts, the disposition of parts replaced, the procedures to be followed in making the change, and the quality requirements to be met. The responsible engineer is also responsible for providing instructions for the manufacture or procurement of the replacement parts, as applicable, and for assuring that instructions are issued for other projects requiring such changes.
The design documentation supporting the FDI is subjected to a design verification review and is reviewed by the project engineer. The field
! change is then authorized by the project manager prior to distribution of the FDI.
i l
141828 C4 l
When it becomes necessary to ship products to the site before manufacturing is complete either by GE or its suppliers, an FDI is issued which identifies the work to be completed in the field. Such FDI's identify the necessary engineering and quality requirement:.
Changes initiated by field organizations generally are the result of deviations from the planned construction or preoperational conditions.
In order to initiate action to accomplish a field change on GE furnished components, the field organization generates a Field Deviation Disposition Request (FDDR) which identifies the deviation and the proposed changes to correct or compensate for the deviaiton. The Engineering and Project Management organizations review the FDDR for compliance with the established design criteria and for safety, performance, and functional design res:framents. If the proposed method i found to be satisfactory, the FDDR is then reviewed and released for field implementation: If the proposed method for correction does not comply with the established criteria and requirements, the responsible engineer disapproves the FDDR, and an alternate solution is presented by modification of the FDDR or by issuing an approved FDI. If a FDDR results in a design change, documents are changed by use of the ECN. Whan a FDDR indicated an inherent problem which affects more than one project, the responsible engineer issues appropriate ECN's to effect changes to the design documents for all plants affected. The FDI's, FDDR's, and ECN's are formally identified, prep'ared, and controlled in accordance with documented procedures.
The GE installation engineers and technical specialists provide technical direction of Owner implemented field changes during the installation, preoperational and startup testing phases. Also, verification of fielo change implementation during the ins'.allation phase is accomplished by GE surveillance of GE-supplied systems and components. GE implemented changes at the site are performed and controlled under the direction of GE.
141829 C-5
C.5 DESIGN CHANGE APPLICATION The system for assuring controlled changes in the design has been described in the preceding sections. In addition, when conditions adverse to quality or safety are identified in designs, they are documented with corrective action and proposed project application of the corrective action. This is reviewed by appropriate management through a review board to fin'alize agreement on the necessary design change action and the projects affected. Following specific projects, the responsible engineer makes the necessary changes and issues documentation as appro-
- priate to implement the design change. As a result, action is applied to all projects where action to correct the cause of the condition is deemed appropriate.
141830 C-6
- - - - _ - - - . e , . _ n ,
m
- 0. DESIGN CHANGES IMPLEMENTED IN THE DECAY HEAT REMOVAL SYSTEMS The GE standard plant decay heat removal systems described in Attachment A have remained unchanged for a good number of years because of demonstrated redundancy and reliability-of these systems. GE has rigorously examined these systems since the T.MI ircident and, thus far has not identified any changes that are needed to enhance decay heat removal capability.
However, GE is continuing to work with the Nuclear Regulatory Commission in tne identification of potential design improvecen*s.
9 9
0-1
E. THE NEED FOR AND AN APPROACH TO ONE-STEP LICENSING OF NUCLEAR POWER PLANTS .
E.1 BACKGROUNO ON LICENSING REVIEW PROCESS In March 1973, the U.S. Atomic Energy Commission issued a policy statement for the implementation of an intensive standardization program for nuclear power facilities. The industry has been responsive to this program as manifested by the standardization applications which have been issued Preliminary Design Approvals. The reference system concept, one option of the standardization program, utilizes an approved design on a number of applications thus eliminating the need for a custom review of the' design on each application. This significantly reduces Nuclear Regulatory Commission (NRC) staff resources required to review an application, and stabilizes the design for each project using the design. However, experience to date with standardization at the Construc-tion Permit (CP) stage of the licensing process has shown minimal improvements in the schedules for completion of safety reviews and for issuance of CP's.
In May 1978, the NRC reaffirmed its support of standardization and published new guidance (Reference 1) to further enhance the effectiveness of standardization. The most beneficial modification to the reference system concept permits an applicant to submit a Standard Safety Analysis Report (SSAR) describing the plant design features in order to obtain a Final Design Approval (FDA). The preapproved standard design will be l utilized by utilities in both Operating License (OL) and CP applications.
, While several SSAR's by reactor vendors and architect-engineers (AE) l have been submitted for approval, the NRC has not yet issued an FDA.
Thus, any potential improvements to the licensing review process via an l
FDA have not yet been realized. It could easily take from 3 to 5 years to obtain sufficient experience to make an assessment of the present l process. This waiting pariod is protracted and unnecessary. In addition, l the currently defined FDA concept only adds a small increment of efficiency l
l 141833 E-1 l
l .
in the licensing process since the applicant must still submit a Preliminary Safety Analysis Report (PSAR) and a Final Safety Analysis Report (FSAR) as part of the normal licensing application. Finally, the reference system concept does not appreciably lessen the demands on NRC staff resources because it generates a larga. number of standardization submittals.
The many permutations and combinations of the reference system concept result from reactor vendors having multiple submittals depicting more than one size and AEs matching their standardized balance of plant (BOP) designs to the vendors nuclear steam supply system (NSSS) designs. It is apparent that a simpler less cumberse,me form of standardi7ation be implemented.
E.2 IMPROVED STANDARDIZATION i
One approach to improve standardization includes a single U.S. reactor design similar to the system used in the U.S. nuclear navy. Such an approach includes a prototype design having the best features of all thermal reactor designs and would be sponsored by the Department of Energy. The single design concept would result in an entirely new configuration of systtms and components never before assembled into a working configuration. A mature industry cannot afford to throw away all the accumu'ated years of experience and start over.
A more logical approach to standardization is to work within the present framework of the nuclear industry and develop the discipline that minimizes unnecessary changes. Recognizing that plant sizes will always be an option, we must provide designs that integrate the NSSS and 80P. This means greater coordination between NSSS suppliers and AE's than has been required in the past. It is possible through this approach to limit the number of standard designs.
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While it is clear that standardization is important in the licensing review process, the reason that overall schedules have not been reduced under the present system is due to a combination of factors. Some of the reasons become obvious upon consideration of the NRC staff review procedure. The staff's review of a typical application is separated into four areas: 1) The NSSS, 2) the BOP, 3) site related matters, and
- 4) utility related matters. Standardizing in one review area without making changes in the others continues the resource demand on the NRC and does not, as a result, significantly shorten the licensing schedules.
For example, if a reactor vendor or a BOP designer (the AE) obtains y e-approval Of its standara plant design, this effectively eliminates approximately 35% of the total plant review leaving 65% of the review to be completed in the context of a utility application. An approach which consolidates in a single desipn the parts of the plant which traditionally have been split between the reactor supplier and the AE would eliminate about 70% of the plant review. This approach could be developed either by a single party, such as a reactor supplier or jointly between a reactor supplier and an AE. Further, early site reviews can eliminate an additional' 20% of the review leaving only the utility related matters to be approved, which is tbout 10% of the plant review.
l l
i E. 3 THE POWER WORTHINESS CERTIFICATE i
Improved standardization by itself is not enough. We must also streamline the licensing review process. The most obvious means of doing this is to devel;p SSARs that are suitable for both CP and OL stages. This would eliminate the need for the applicant to submit a PSAR and a FSAR.
A " verification report" would then be submitted by the utility to the NRC prior to fuel loading to confirm that the actual design conforms to the requirements of the SSAR. In effect, one-step licensing is a suitably approved SSAR at the CP stage followed by a verification report at the
! OL stage. The approved SSAR in the proposed one-step licensing approach is referred to as a Power Worthiness Certificate (PWC). The PWC would, of course, require an extension of the present NRC policy coupled with new legislation.
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For the PWC to be effective it must:
- 1. Contain information suitable for the NRC to conduct a thorough safety review;
- 2. not exclude qualified AE's and equipment vendors; and
- 3. be sufficiently broad in scope so that a significant improvement in project-unique licensing review time is realized.
4 E. 4 RECENT SSAR EXPERIENCE The SSAR, GESSAR II, recently submitted by GE (Reference 2) describing ,
its BWR/6 nuclear island is an example of consolidating the NSSS and BOP into a standard plant design. This SSAR includes the NSSS and all of the buildings and contained structures that have radiological significance.
l It defines a reference site envelope that includes 80-90 percent of the U.S. plant sites which enables the utility to merely certify that the site lies within this reference envelope. It is estimated that 90 percent of the information required for a CP will have been preapproved upon NRC issuance of the FOA. The remaining portion of the information is either site unique, equipment vendor, or BOP plant designer dependent.
This type of SSAR not only promotes standardization in three of the four areas previously described but the amount of new information required for the OL application stage approaches that which is needed for a
! one-step licensing process.
1 E.5 PRECEDENT FOR ONE-STEP LICENSING There is a precedent for one-step licensing,in another closely regulated industry. .weiy the airline industry which utilizes an Air Wortniness
{
Certificate (AWC). The similarities of the airline and nuclear industries i include:
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- 1) high public safety awareness
- 2) high technology products
- 3) a few system vendors
- 4) many sub-tier suppliers, and
- 5) many other companies as operators.
However, there are substantial differences in licensing, namely the Federal Aviation Administration (FAA) licenses design (separately licenses operators) and the NRC still licenses each utility nuclear design. With a PWC, the nuclear industry seeks a certificate from the NRC for the majority of the plant design operating basis, plant protection systems, instrumentation and control and fuel design. With an AWC, the aircraft industry seeks a certificate from the FAA for an airframe coerating enveloce, control systems, avionics and plane performance. There is also similarity associated with an operating license. The utility seeks an operating license for coerator training, maintenance training, start-up procedures and technical si .cifications. Similiarily, the airlines seek an operating license for crew training, maintenance training, test instructions and technical manuals.
E. 6 ONE-STEP LICENSING OF NUCLEAR POWER PLANTS One-sten licensing could war.V in the following manner:
- 1. NSSS vendors would seek NRC approval of plant designs wnere:
- a. The NSSS vendor, AE or (team) becomes the aoolicant l b. The NRC acoroves the NSSS vendor's and AE's final safety design and issues a PWC. The basis far approval, being a document comparable to a FDA.
- 2. Utilities seek an operating Ifcense which references the preapproved design (PWC) and a preapproved site frca state and federal governments. The NRC checks ;ite aporoval with the
- preapproved design to ensure compatibility and then issues a E-S 19537
CP. From that point, there is no re-review of the PWC on the project. However, prior to fuel loading, a verification report is submitted by the utility to the NRC that verifies that the plant was constructed in accord'ince with the requirements of the PWC. Also, as currently perforned, the NRC maintains surveillance during the construction phase to gain assurance that construction is in accord with the preapproved design.
Utilizing a PWC, the utility first has the site selected and approved.
Next, the utility chooses a certified plant design, applies to the NRC for a compatability check (PWC to site) and receives +he OK to start construction. Eighteen months before fuel load the utility submits a verification report providing assurance that the plant is constructed in accordance with the terms of approval. .With this approach, it takes lese than twelve months for NRC project approval.
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The NRC audit process is completed in para 11el with construction. A :cmparison of the current custom and proposed PWC cycles is illustrated >y Figure E-1. We believe that the overall licensing-construction time can be reduced to the order of 7-8 years by applying this simplified, yet rigorous licensing process.
E. 7 CERTIFICATION BY THE NRC The one-step licensing prccess could work with standardized designs since the designs of nuclear plants is at a mature stage. More importantly, complete designs can be submitted to the NRC and this would allow a more exhaustive review by the NRC since there would be no need for de novo
! plant-by plant reviews. In this manner, a standard plant can be certified by the NRC before being marketed which will substantially reduce the i time it takes to license a plant and thus .emove a significant uncertainty.
1 E. 8 GE's APPROACH FOR PWC USING GESSAR II i
l Our approach in developing a PWC is to utilize the content of GESSAR II l and clearly identify infor; ,cion concerning equipmant supplied by vendors
- and detailed information supplied by AEs which is subject to change i depending on the specific equipment vendors and AEs selected. This l
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information would constitute the verification report. The balance of the information (i.e. GESSAR II less the equipment vendor and AE unique information) is the PWC.
E.9
SUMMARY
The proposed one-step licensing approach is adaptable to combinations of NSSS vendors and AEs. In summary, it consists of the following:
- 1. A licensing document (SSAR) that describes the design in sufficient detail, including the NSSS and the entire radiologically significant parts of the plant, for the NRC to conduct a thorough safety review, and
- 2. in lieu of an FSAR, the utility applicant would submit a verification report to confirm that the plant was constructed in accordance with the preapproved licensing document described above.
The standardized design approval by the NRC would permit the utility applicant to construct a nuclear power plant after site approval, and then to operate the plant if it were constructed consistent with the requirements of the licensing document. This process ensures one thorough and exhaustive safety review of the standardized design and a confirmatory check via the verification report prior to fuel load.
l E.10 REFERENCES
- 1. U.S. Nuclear Regulatory Commission, " Review of the Commission Program for Standardization of Nuclear Power Plants and Recommen-dations to Improve Standardization Concepts", NUREG-0427 (May 1978).
l l 2. General Electric Company, "238 Nuclear Island General Electric
! Standard Safety Analysis Report GESSAR II", submitted under GESSAR Occket STN 50-447 for NRC review and issuance of a Final Design I Approval (March 31, 1980).
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i20.0 Figure E-1. Comparisen-Custom and Power Worthiness Certificate Cycles E-8