ML17275A496

Responds to Round One Questions,Set 9,Questions 211.049 - 311.106

ML17275A496
Person / Time
Site:	Columbia
Issue date:	07/11/1980
From:	Renberger D WASHINGTON PUBLIC POWER SUPPLY SYSTEM
To:	Youngblood B Office of Nuclear Reactor Regulation
References
GO2-80-149, NUDOCS 8007310409
Download: ML17275A496 (227)

Text

Washington Public Power Supply System A JOINT OPERATING AGENCY'.

O. Box 908 3000 Gco. W~sH>voroN Wxr Ric~c.xylo. WAseiNoro~ 99352 P~o~c (509) 375 5000 Docket No. 50-397 July G02-80-149 ll, 1980 Director, Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission ltashington D.C. 20555 Attention: Mr. B. J. Youngblood, Chief Licensing Branch No, 1 Division of Licensing

Subject:

MPPSS NUCLEAR PROJECT NO. 2 RESPONSES TO ROUND ONE QUESTIONS SET NINE, REACTOR SYSTEMS BRANCH RSB

Dear Mr. Youngblood:

Enclosed please find sixty (60) copies of the responses to Round One,,

Set Nine questions from the Reactor Systems Branch (RSB). These questions are to be incorporated formally into the FSAP, in-the next amendment.

Very truly yours, D. L. RENBERGEP.

Assistant Director-Technology DLR:CDT:ct.

Enclosure cc: JJ Verderber, B&R, w/o attachment Do."I:et'-'<

~ Q-39 7 RC Root, B&R, w/o attachment Cosh'oI y 8&F7 3/Q RE Snaith, B&R, w/o attachment J Ellwanaer, B&R, w/attachment ~t ~T0@Y D,Q,CERMET P~

A Lageraaen, B&R, w/attachment JA Satir, B&R, w/attachment FA MacLean, GE, w/attachment E Chang, GE, w/attachment

'S g JR Lewis, BPA, w/attachment ND Lewis, EFSEC, w/attachment NS,Reynolds, D&L, w/attachment Manager, LIS Corporation, w/attachment MM Taylor, EI DuPont DeNemours 8 Co., w/attachment SOOVsvogo'f,'

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STATE OF WASHINGTON) WPPSS NUCLEAR PROJECT NO. 2

) ss RESPONSES TO ROUND ONE QUESTIONS,

' .SET NINE, REACTOR SYSTEMS BRANCH (RSB)

COUNTY OF BENTON Wm. W. Waddel', heing first duly sworn, deposes and says: That he is the Acting Assistant Director, Technology, for the WASHINGTON'UBLIC POWER SUPPLY SYSTEM, the appli'cant herein; that he is authorized to submit the fore-going on behalf of said applicant; that he has read the foregoing and knows the contents thereof; and believes the same to be true to the best of his knowledge; DATED WM; W. WADDEL On this day personally appeared before me, Wm. W. Waddel, to me known to be the individual who executed the foregoing instrument and acknowledged that he signed the same as his free act and deed for the uses and purposes therein mentioned>.

GiyEN under.my hand and seal this ~asaa'day of , 1980 N ary Public in and for the State of Washington Residing at

Ri.:GULATORY INF OR ~IAT IOk'ISTRIBUTION SYSTEfi { fe IDS)

ACCESS IOf" foBR: B007310409 DOC ~ DATE: 80/07/11 NOTARIZED: YES DUCKEf FACIL: 50<<397 ~PPSS f<uc ear Pro j ec t E Uni t 2i <washington Pub 1 i c Powe 1 05000397 AUfh DNA'L]E AUTHOR AFF ILI A1IUN Bc.RGEferD.L. 'ashinqton Public Power Supply System

.'P ~ YA "fE RECIPIENT AFF ILIA'tIUN iiGT LEOD p B. J. Licensing Branch 1 I SUBJECl: feesponds to Round One Questions<Set 9<Questions 211.0ff9 311 F 106.

OI SIR IBtITIOii COO": BVOIS CORIES RECE IVES:LTR Q ERCL (PD SIZE:j+Z T I TLE: PSAR/FSAR Af'IDTS and Re at ed Co r r espondence 1

NOTf.S:PH: 2 copies of al l material. 05000397 RECIPIENT COPIES RECIPiENT COP IFS ID CODE/hA<E LTTR ENCL ID CODE/NAvE LTTR ENCL ACTION: A/D LI CENSi<G 1 0 YOUNG8LOODrB 1 0 RUSHBROO~ W. 1 0 LYNCHgD ~ 05 1 1 INTERNAL: ACCID EVAL BR 1 1 AUX SYS BR 18 1 1 CHE~1 ENG BR 1 1 CONT SYS BR 1 1 CORE PERF BR 17 1 1 DIRg HURRI FAC SFY 1, 1 DIRg SF fY TECH 1 1 EFF TR SYS BR .1 1 E~<EieG PREP'2 1 0 EQUIP QUAL BR 1 1 GEOSC IEf'ACES 1 1 HYD/GEO BR 11 1 1 1.8C SYS BR 20 1 1 I@E 06 3 3

'"ATL ENG BR 1 1 HECH ENG BR 1 1 HPA 1 NRC PDR 02 1 1 DELD 1 0. POfNER SYS BR 1 1 PROC/TST REY BR 1 1 QA BR 10 1 1 R

" BR12 1, 1 REAC SYS BR 1 1 EG F 01 1 SIT ANAL BR 27 1 T ENG BR 1 1 1'x T'Efef>AL: AGRs 16 16 LPDR 03 AS IC PQ 1 1 AUG 2 >98o 59 TOTAL I'>U"!E'ER OF CIlPIES REQUIRED: LT TR f E i~CL

RESPONSES TO REACTOR SYSTENS BRANCH (RSB)

QUESTIONS 211.049 211.106

WNP-2 Q ~ 211 . 049 Th e analyses you present in the FSAR to show compliance with the requirements for protection against overpressurization which are contained in the ASNE BoiLer and Pressure Vessel Codex'efers to t e General Electric topical reports NEDO 10802'or the analy" tical model used to evaluate tr ansients in the WNP-2 facility.

Howevers GE has submitted an updated analytical models ODYNi to evaluate plant transients. Accordinglyi reanalyze the pressure transients in the WNP"2 facility using the ODYN code. Alterna-tivelyr provide assurance that the method of analysis described in NEDO-10802 is bounding in regard to predictions of the peak pressure. The analysis must include the effects of the recircu-ation pump trip (RPT) due to high pressure and the RPT trip re-sulting from the turbine stop valve/control valve cLosurei where app icable. If you reanalyze the pressure transients usin g th e ODDYN codes provide an analysis which establishes whether the closure of aLL main steam isolation vaLves (NSIV's) is the most severe overpressure transienti including consideration of a second safety-grade scram (e.g.i a scram resuLting from a high neutron flux) and the effects of the RPT.

Response

WPPSS P S commits=.to reper formance of the overpressure protection analysis'o demonstrate compliance with the ASNE BSPV Code considering the effects of end"of-cycle and ATWS RPT. For the imiting rapid pressurization transientsi the ODYN code will be used to reperform the calculations using the resolution basis of Option B of the NRC Letter on the subject code dated Januar y (GE/NRC generic resoLution in progress estimated to be com-23'980 p etedi summer 1980) . Appropriate analyses will also be done with ODYN to bound Ch. 15 Limiting pressurization transients. The FSAR will be updated when the analysis are completed to reflect the results of these analyses both in Ch. 5 and Ch. 15.

WNP-2 Q. 211 . 050 You have not provided sensitivity studies in the FSAR which show the effect of the initial operating pressure on the peak transient pressure attained during a Limiting over-pressure event. Accordinglyi submit the foLLowing additionaL information.,

a. Provide a sensitivity study which shows that increasing the initial operating pressure. up to the maximum pressure permitted by the high pressure trip setpoint wilL have a negligibLe effect .on the peak transient pressure.

b. ALternativelyr propose an operating Limitation on the reactor pressure which wi LL be incorporated into, the WNP-2 Technical Specifica tionsr thereby providing assurance that the actuaL reactor operating pressure wilL not exceed the initiaL pressure assumed in your analysis of pressure tran sients.

Response

The overpressure analysis shown in Chapter 5 of the FSAR dome assumed the plant is initiaLLy operating at 105%

steam flow condition with a maximum vesseL dome pressure of 1020 psig. The maximum operating dome pressure at 100% power is expected to be 1005 psigr thereforer the assumed init iaL operat ing pressure of 1020 psig is expected to be conservative relative to expected actuaL operation. In additioni the nominaL high pressure scram setpoint is expected to be set at 1043 psig. A study has been performed for a BWR-3 to investigate the effects of increasing the initial reactor pressure relative to the initiaL value used in the overpressure protection analysis on the peak system pressure. The conclusion was that increasing the initial operating pressure results in an increase of the peak system pressures which is Less than half the initiaL pressure increase as shown in Figure 211.050-1 for the overpressure design transient (i.e.i all NSIV closure with indirect high neutron f Lux scram).

The same generaL trend is expected to exist for WNP-2.

For the WNP-2 projects the allowable value for the pro-posed technicaL specification Limit on the high reactor pressure scram is 1063 psig. Thereforer the maximum increase in the initiaL pressure would be Limited to only 43 psi and the maximum peak system pressure increase during the over pressure design transient would be Limited to Less than 20 psi. Thus the overpressure criteria would sti LL be satisfied.

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WNP-2 Q. 211 . 051 (5.2.2)

The performance of essentialLy all types of safety/relief valves has been, below the expectations for this type of safety-related component. Based on the number of report-able events involving maLfunctions of these valves in operating boiling water reactors (BWRs) r we believe that significantly improved performance of the safety/relief valves (SRVs) should be required of the SRVs installed in new plants such as the WNP"2 facility. Accordinglyi provide a detaiLed description of the provisions you wiLL incorporate in the SRVs of the WNP-2 faci Lity which represent an improvement over the SRVs of presently operating BWR plants in thei x areas L i sted below. In responding to thi s i temi explain why or how your additional provisions wiLL provide the improvements which we seek in the performance of the SRVs. FinaLLyr identify the SRV manufacturer.

a. Valve and Valve 0 erator T: e and/or Desi n. Provide a discussion of your proposed improvements in the air actuatori especiaLLy in the materials used for such components as the diaphragms and the seals. Discuss the safety marg'ins and confidence Levels associated with the air accumulator design. Discuss the capa-biLity of the reactor operator to detect Low pressure in both air accumulators.

b. S ecifications. Indicate what new provisi ons you have employed to ensure that the specifications for the valves and valve actuators include design requirements which reflect the operation of the SRVs ov er the anti ci pated range of envi ronmentaL condit i ons (i.e.r the temper aturer humidityi and vibration) r to which the valves and valve actuators wiLL be sub jected during pLant transients and postulated, accidents.

c. ~Testis . It is our position tost prior to instsllstionr the SRVs should be proof-tested under the appropriate environmentaL conditionsr for time periods representative of the most severe o'perating conditionsr to which they may be subjected.

WNP-2

d. Qualit Assurance. Indicate what new programs you have instituted to assure that valves are manufactured to your design specifications and wi ll operate as required by your specifications. For examples indicate the test you wiLL perform to assure that the blowdown capacity of the SRVs is correct.

e. Valve 0 erabilit . Provide a description of your sur" vei LLance program to monitor the performance of the SRVs during the pLant Li fetime. Identi fy the information that wi l be obtained in thi s survei Lance program and L L indicate how these data wiLL be utilized to improve the operability of the valves. For example indicate how this program wiLL reduce the malfunctions that have occurred in operating BWR facilities.

Valve Ins ection and Overhaul. You state in the FSAR that half of the SRVs wiLL be bench-checked and visually inspected every refue ling outage. Howeverr depending on operating cycle Lengthr this may result in severaL years between inspections. Our concern in this matter arises from operating experience which has shown that failure of the SRVs may be caused by exceeding the manu-facturer's recommended service Life for the internal components of the SRVs or their air actuators. Accord" inglyr indicate the frequency at which you intend to visuaLLy inspect and overhaul those SRVs which function as part of the automatic depressurization system (ADS)-

Indicate 'what provisions wiLL be incorporated into the WNP-2 facility to ensure that inspection and overhaul of alL the SRVs is in accordance with the manufacturer's recommendations for the SRVs instaLLed in the WNP-2 facility and that the design service Life for any corn" ponent of the SRVr is not exceeded.

Response

A. Valve and Valve 0 erator T e and/or Desi n Past BWRs uti i zed reversed-seated'i L Lot "operatedi safety/relief"type valves as shown in Figures 211.051-1 and 211.051-2. WNP-2r which is a GE BWR/Sr uti Lizes a convent iona'-type simplei di rect-act ingr spring-Loadedi safety/relief valve with an auxiliary pneumatic actuator assembly with solenoid valves to provide for an independent mode of operation for relief service based upon user/operator command. (See Figures 211.051-3 and 211.051-4.) As such'he safety/relief

WNP-2 function is directLy and automatically controLLed by the static steam pressure acting at the main seat of the valve inlet nozzle and disc.

The independent mode of operation is via the servo-air-pneumatic cylinder-valve arrangement and mechanism when actuated by the user/operator. Use of the conventionaL simpler direct-actingr spring-Loadedr safety/relief valve provides the optimum accepted type of overpressure protection device presently available with numerous years of reLief experience in simiLar industrialr mariner and naval steam service applications. See Table 211.051-1 for SRV improvements as compared to present operating plants.

Naterial selections for this type of safety/relief valve (Crosby duaL function) are in accordance with ASNE Section III and are suitable for the intended environment and functionaL appLication. SuccessfuL qualification test results confirmed the adequacy of materiaL selections.

Each safety/relief valve and actuator assembly is sub-jected to relief operations to verify proper operability and Leaktightness prior to de livery.

Note that should the air supply faili the pneumatic actuator assembly may not be able to open the vaLve in the re lief mode of operation. The independent safety mode for overpressure protection is not affected by a Loss in ai r supply.

With regard to the air accumulatorsr each safety/relief valve has a relief accumulator sized to aLLow one actuation against normal drywell pressure with reactor pressure at 1000 psigr shouLd the air suppLy to the valve fai L ~ The ADS valves each have a separate accumulator sized to aLLow one actuation against maximum drywelL pressure with the reactor at 0 psigr should the ADS air suppLy faiL. Failure of the air supply is extremely unlikely since the ADS air supply is Seismic Category I back through the nitrogen bottles.*

See the response to Question 211.048.

A summary of operating experience of the Crosby direct acting valve to date is contained in the response to Question 212.131 on the LaSaLLe docket. The des,ign of the SRVs to be insula LLed in WNP-2 are a modi f ied version of those instal Led in Chinshan 1 and 2. Based on operating experience (principaLly Bro wns Ferry) i recent modifications to the Crosby valve s were incor"

WNP-2 Each air or nitrogen supply system (2 ADS + 1 normal) has pressure indication and alarm to indicate Low pressure conditions in the system. Excessive compres-sor cycling would indicate Leakage if pressure does not drop Low enough to actuate the alarm. Specific indication of individuaL accumuLator pressure is not required since the only occurrence not indicated by the above would be isolation of an accumulator system with the manuaL isolation valve. This is extremely unlikely since each accumulator/check val~e is inspectdd and tested per IWV (Section XI) . A pressure decay test is performed as a final part of the maintenance procedure to prove system operability. (See part C of this response.) This test requires the manual isolation valve be open. In additioni of coursei the safety/

reLief vaLve for protection against overpressure is automatically controLLed and actuated by static inlet steam pressure and is not dependent on an air supply.

WNP-2 porated to reduce the potential for steam Leakages thereby minimizing maintenance and improving plant avaiLability. The changes include the following:

1. Nodifications to the Lifting mechanismr adjusting bolt and thrust bearing adapter to improve the opening and closing kinematicsi reduce friction and improve alignment of the valve during operation;

2. Replacement of the nozzle and disc from Crosby's standard design configuration to a semi-f Lexible di sc of InconeL and a 316 stainless steeL f Lexi" disc nozzle for improved seat tightness;

3. Raising of the setpoint or the Lowest set SRV to be 150 psi above the nominal reactor operating

~I ~< pressure to reduce re L i e f valve simmering.

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"~/ B. B ac ificati one The GE Safety Relief Valve Equipment Specification(s) identifies and includes alL the design requirements necessary for operation of the valve and valve actu-ator assembly'in its expected normaL and postulated abnormal environments. Verification of the design for safety/relief valve acceptability is and has been demonstrated by Life cycle testingr environmental testing in accordance with IEEE 323-1971'nd seismic testing in accordance with IEEE 344-1975.

C. ~Test in The design of the safety/relief valve has success-fully demonstrated compliance with performance require-ments when subjected to the foLLowing qualification test programs:

1. Li fe Cycle Test(s)

This test program consists of subjecting production" tested safety/relief vaLve assembly of the design to be used to 300 relief (power) and safety (pressure) actuations in order to demonstrate acceptability of the valve design to meet: (1) set pressurer (2) opening and closing response timesr (3) blowdownr (4) seat tightness; (5) fLow-rated capacity Lift (ASME) during each actuation; (6) rec losure (after each actuation) without demonstrating a tendency

~e Prequalification production tests were made on each modified SRV at the vendor's plant. Data on those II I/ tests is filed at GE (San Jose) in "Design Reference File 207C-B21/22 F013-D (6xRx10) " Crosby SRV Nodifi-cation Effort". These design improvements signifi" cant ly reduced the inherent SRV potential Leakage to below specification Leakage (20 Lb/hr); these design improvements did not adversely affect other required functions.

WNP-2 to stick opens chatter or disc osciLLationr and emergency operabi Lity requirements. Conditions such as environmental temperature~ pressure ramp ratesr pneumatic operating pressurei solenoid voltage and backpressure were variedi consistent with test facility capabilitiesr to assure valve operabi Lity under the Limits of the normal expect-ed conditions to which the safety/relief valve may be summary subjected. This test program establishes the qualified service Life of the safety/relief valve.

A "of the resut (s" of., thxs'.test-prog ram i s as'oLLows.

Following the prequa l i f i c'at i on production modified SRV was then subjected to Life tests'ach cycLe qualification tests as outlined in Wyle Lab Test Procedure 444414-01 in accordance with the GE Specification 22A6595. This inc luded approxi" mately 300 relief (power) and safety (pressure) actuations to demonstrate and characterize each valve for acceptable BWR service. Test parameters included:

a ~ seat tightness/L eakage characteristicsr

b. set pressurer c ~ opening and clos ing response timer

d. blowdowni

e. SRV Lift-achievi ng rated flow capaci ty L i ft during each acti vationr SRV reclosure wi thout chatteringi disc osciLLation~ or stick open. and gi capabiLity to op en without inlet steam when activated o n demand.

Test conditions were varied according to facility capability to assure valve operability across the design Limits to which the SRV may be subjected while in service. These included: temperatur er pressure ramp ratesi pneumatic operating pressurei solenoid voltage~ inlet pressurer and the dyna-mi caL Ly imposed backpressure.

Test results indicate essentiaLLy zero Leakage for both the relief (power) and safety (pr'essure) modes of SRV operationr aLL valves and seat-tightness capability to meet the 20 Lb/hr speci" fication Limit and saturated steam conditions.

Each valve demonstrated safety actuation at the nameplate value plus 1% at a confidence Level of 0.95. The response is also Linear with ambient

WNP-2 temperature in the negative directionr i.e.i at temperatures above 135 0 F the actuaL pop pressure is Lower= than the nameplate value. The tempera" ture correction value is 0.2 psi per F for this SRV. Set pressure is independent of ramp rate var iance. Response of the SRV is directLy related to the effective differentiaL pressure force acting to open the SRVr thereforer outlet static pressure at the exit can be accurately accounted for.

Opening times were as foLLows for the test set up:

safety actuation time " 0.020 : t < 0.30 seconds relief actuation time 0.020 < t < 0.15 seconds Actual instaLLation times could result in a delay time of 0.10 seconds added for wire Lengths and other non-SRV wire Losses. CLosing times were:

safety actuation none.. blowdown requirement controls this relief actuation time to de-energize solenoid 0.90 seconds di sc t rave L af ter solenoid was de-energi zed 1.50 seconds Blowdown within the required range of 2 to 11% was demonstrated. Each SRV is adjusted according to its spring rate for accept, able blowdown.

Qualification test results demonstrate that the modified SRV wiLL open to rated capacity Lift in either the relief or safety modes of operation when actuated.

SRV rec losure was demonstrated throughout the qualification tests without stickingr chatters or disc oscilLation during the closure stroke. When inLet pressure was increased to repressurize to the set pressurei the SRV reactuated to the fuLL open position. The modified SRV wilL open to its fuLL rated capacity Lift position when operated in the relief mode with the inlet pressure at zero psigi thus demonstrating its emergency operability.

WNP-2 Six SRVs were included in this Life cycle qualifi-cation test program. Test anomalies corrected during this demonstration do not invalidate the adequacy of the test results obtained the finaL-ized modified SRV design is considered acceptabLe for BWR main steam applications.

EnvironmentaL Test(s)

This test program consists of subjecting a produc" t ion-tested pneumatic actuator assembly (inc Ludes air cylinder with electricaLLy operated solenoid valve assemblies) unit of the design to be used on the safety/relief valve to the environmental inf Luences of radiationr thermal agingr mechanical agingi negative pressure and the postulated LOCA steam environment in order to demonstrate accept-ability of the actuator design to meet operability requirements. The test program is in accordance with IEEE 323-1971 requirements and establishes the quaLified service Life of the actuator assembly' summary of the results of the test program is as follows.

The solenoid valves of the pneumatic actuator were subjected to a test sequence as foLLows:

a. radiation aging to 30 x 10 6 radsr

b. mechanicaL aging to 200 cycles~ and c ~ exposure to emergency environmentaL conditions of 340 F at 65 psig decreasing to 250 F at 25 psig0 Valve operability was demonstrated during and after exposure to the emer gency environment.

Sei smi c Test(s)

This test program consists of subjecting a safety/

releif assembly of the design to be used to seismic tests in accordance with IEEE 344-1975 to demonstrate acceptable funct iona L i ty and st ructural integrity of the design when static moments are applied to the inlet and outlet flanges and dynamic and seismic OBE and SSE Loads are imposed separately and combined.

A summary of the results of the test program is as foLLows.

WNP-2 One valve specimen was subjected to 08E and SSE acceLerations and flanged end connection moment Loading with valve inlet pressurized with satur-ated steam. Valve operability was demonstrated during and after application of Loading,. Maximum test Loads were 8 x 105 inch pound moment at valve inlet and 6 x 10 inch pound moment at valve outlet. Maximum seismic accelerations were 5.0g hori zonta and 4.2 vert i ca L.

L D. QuaLit Assurance The GE saf'ety/reLief valve specification incorporates aLL of the required performances structural'nter" face and test requirements.

To assure that safety/relief valves are manufactured and wiLL perform to the requirements specified by the GE safety/relief valve specificationr the foLLow-ing types of actions are taken with the valve supplier:

1. Valve supplier is evaluated for capabi Lity in complying with specification requirements.

2. A quaLified design is established that demonstrates compliance with specification requirements.

3. The detaiLs and manufacturing process of the qua l i f i ed desi gn is f rozen.

4. Each safety/relief vaLve assembly is manufactured to the approved design freeze List and manufacturing procedures.

5. Each safety/relief vaLve and actuator assembly is production tested to GE approved procedures to assure a high degree of confidence that the delivered equipment will perform as required.

6. Quality Assurance inspection points are instituted throughout the process along with both generaL and random GE surveiLLance and periodic audits.

For examples to verify that the SRV flow capacity is corrects the foLLowing is verified or performed:

1. Design is ASME certified for flow capacity.

MNP-2

2. Nozzle bore diameter is dimensionalLy inspected.

3. Each valve is checked to assure that it opens to flow capacity Lift position by use of an LVDT and 0-Graph 'readout.

E. Valve 0 erabi lit Each S RV is equipped with a position indicating device showing actuaL valve position instead of the or dered position. The indicators permit prompt operator response to a malfunction or emerge ncy situation and contribute to identifi-cation of corrective maintenance requirements.

(Note: This indication system is currently under design and is not yet refected in the FSAR.)

2. Routine surveiLLance of SRV discharge-port thermo-couple recorder readings are conducted to identify valves which have operated or show a tendency to Leak. This data wiLL be used in identifying pre" ventative or corrective maintenance requirements.

3. SRV accumulator check valves are funct ionaLLy tested for seating capability by perfo rming an accumulator pressure decay test on a f requency as specified by IWVi'SNE Section XI. In con" junction with the pressure decay testi a c'cumu l a t o r s are blown f rom Low-point drains and ev idence of excessive moisture or particulate matt er is used in adjusting refurbi shing schedules of SRV piston-cylinder actuator assemblies and pilot solenoids.

4 Solenoid circuit integrity for valves performing an ADS function is monitored during normaL controL room operations. Energized indicating Lights at controL room panels H13-P628 and H13-P631 verify solenoid circuit continuity.

5. For va Lves performing an ADS functions channel functionaL testing wiLL be performed monthly in accordance with the WNP-2 Technical Specifications.

Testing wi LL verify operability of sensors and associated circuitry.

6. SRV histor y Logs are maintained which contain the foLLowing type of information in a readily retriev-able form:

WNP-2

a. Valve identification by SRV suppliers typer style or, model number and seriaL number..

b. Date placed into service.

c. Date removed from service along with the estimated number of cyclic operations and hours that the SRV has been in actual servi ce.

d. Identification of alL tests'esults noted~

disassemblies performed (including extent and purpose) r maintenancer refurbi shmentsi modi fications and replacement parts-made to the SRV along with reference to the appli" cable procedure or instructions used. The historicaL information provides insight into the potentiaL problem area(s) that can be corrected.

F. Valve Ins ection and Overhaul

1. SRV/ADS pilot solenoids and air-cylinder actuators wiLL be inspected and refurbished on a three-year cycle in accordance with the manufacturers recommend-ation; unless surveiLLance activities indicate a more frequent refurbishment as evidenced by excessive moisture or particulate matter in the a i r supply.

2. Adherence to the manufacturer's recommended schedule of inspection and overhauL is aided with the use of the SRV history Log. Routine surveiLLance of the SRV history Log and instruction manuaL insures that the design service Lift for any components of the SRVs or their air actuators is not exceeded. SRVs wiLL be refurbished in accordance with the manu" facturer's recommendation on a frequency defined by IWVr ASNE Section XI.

PLease note that in addition to the above responser the BWR Owner's Group for Three Nile Island.'Concerns is working with GE to develop a more comprehensive response to these concerns.

We are actively participating in this program and wilL imple-ment applicable recommendations developed as a result of the meetings and discussions between the Owners Group and the NRC.

• Draft FSAR page changes.:attached.

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. ig 8 MJ J ~ ' ~ ~ ~ ~ d <Ii) j~====-m "ti ~ F turrs '/ i (/J. fr ~ Ip l ]) l /JSS///f'p Ji ~$ Q I LIFTING NUT LEVER PISTON TYPE LIFTING PNEUMATIC "DOG" ACTUATOR SPINDLE ADJUSTING BOLT SET POINT C '+$ 4+Pi4n SPRING BONNET SOLENOID AIR CONTROL VALVES DISCHARGE BODY r XCr INLET ANN EAM ELECTRIC ION C/ossY I/w<va UNITS PAND NAL SAFE A YSIS R T Figure zeal CROSB FI ~ 0-2 SPRING BONNET WASHER SPINDLE AUXILIARY BALANCING PISTON IC(prrrrSgy'ALANCING BELLOWS DISC B LOWDOWN DISCHARGE ADJUSTING RINGS BODY INL'NOZZLE... Rev. 9 EHANt4A STEAM ELECT TATION U L SAFETY AMALYStS REPOR 4an~ ~~TSAR.S ~S. CnS~F USSR~ FiguCa Zll~ z/ E-211. 0-2a WNP-2 AMENDMENT NO . 8 February 1980 The air compressors, dryer filters, and supply piping for the containment instrument air system provide air for charging the accumulators of the 'main steam isolation valves (inside pri-mary containment) and the main steam safety/relief valves during normal operation (see 5.2 and 5.4). Since operation of this portion of the equipment in the containment instrument air system is not required for safe shutdown of the reactor (see 7.3 and 7.4 for effects of loss of instrument air on the main steam isolation and safety/relief valves), the pressure containing components are designed and constructed in accor-dance with ASME Section VIII, and system piping is designed and fabricated in accordance with ANSI B31.1, Seismic Category II. (System piping supports are Seismic Category I. ) The only exception is that portion of the piping system from the outer-most containment isolation valve to the solenoid valves of the main steam safety/relief and isolation valves ( inside primary containment) which are ASME Section IXI Class 2, Safety Class 2 and Seismic Category I'wo banks of nitrogen gas bottles and supply piping are pro-vided as part of the containment instrument air system to supply the Automatic Depressurization System (ADS) main steam safety/relief valves with a pneumatic supply. For a dis-cussion of the function and operation of the ADS, see 6.3 and 7.3. The nitrogen bottles and associated equipment. are L and the supply piping is ASME Rection XXI, Class of M 4'May 9.3.1.2 ~~/~ 2 and Class 3. ~<4. )~~ ~ ~w,~ue

System Description

9.3.1.2.1 Control and Service Air System The control and service air systems are shown schematically in Figure 9.3-1. Three compressors and three air receivers supply both control and service air requirements.

Each compressor has a start-standby-stop remote selector switch and an unloader control. When the selector switch is.

set 'in the start position","'the"compressor"runs'continuously and loads and unloads to maintain receiver pressure. When the selector switch is in standby position, the standby compressor will automatically start when receiver pressure falls below 90 psig. Normally two compressors are running and one compressor is placed on standby.

9.3-2

~"

WNP>> 2 AMENDMENT NO., 8

~ ~ February 1980 his system consists of two 100% capacity air compressors, associated coolers, a twin tower air dryer, filters, an air receiver, valves, and piping of a leak tight design. In addition, two nitrogen gas bottle banks and associated piping are provided as a backup to the compressor supplied air for seven of the main steam relief valves which perform the ADS function.

The compressors located in the reactor building take suction from the building atmosphere through intake filter-silencers which are 98% efficient in filtration of particles as fine as five microns. The air is then discharged through an aftercooler, a prefilter, a dryer, an afterfilter and air receiver to deliver dry, clean, pressurized air to the pneu-matic control systems of the following valves inside the primary containment vessel:

a. Four main steam isolation valves and their accumulators,

b. Eighteen main steam safety/relief valves and their accumulators.

The two independent nitrogen bottle bank subsystems are pro-vided to deliver pressurized nitrogen to seven of the safety/

relief valves and accumulators. These seven valves perform the ADS function, if required, during postulated LOCA con-ditions. These nitrogen banks ensure a 30-day supply of nitrogen for the ADS function during isolation of the compressor loop. One bank of 15 bottles supplies nitrogen for three main steam safety/relief valves and. accumulators, while the other bank of 19 bottles supplies four main steam safety/relief valves and accumulators (see Figure 9.3-2). QA'3 The nitrogen bottles are located in the railroad lock of the reactor building to facilitate access. The bottles are s an-dard, commercially available units pressurized to 2490 si Each bottle has a capacity of 257 SCF. p The required quantity.

'of bott1'es "for each'ank was conservatively based on providing a 30-day supply to the ADS valves to satisfy the long term post-LOCA demand based on the following:

MA

9. 3-4

WNP-2 AMENDMENT NO . 8 February 1980, 9.3.1.3.2 Containment Instrument Air System Since each of the two nitrogen supplies and the compressed air supply are independent of each other, a single component failure in one will not effect the operational function of the other.

During normal operation, one compressor will operate inter-mittently to restore loss of pressure in the main steam isolation and safety/relief valve accumulators. The compres-sor loop discharge piping can be isolated, if required, under accident conditions. Each nitrogen bottle supply line isola-tion valve is powered from a different division of the critical power supply.

In the event of loss of power to the compressed air supply, the, individual air accumulators serve as a reliable source of compressed air for the main steam isolation and safety/

relief valves. Further discussion of the effects of loss of axr to the main steam isolation and safety/relit f valves is presented in pg / / //

9.3.1.4 Testing and'nspection Requirement The systems are inspected and cleaned prior to service. In-struments are calibrated during testing, and automatic con-trols are tested for actuation at the proper set points.

Alarm functions are checked for operability and limits during plant operational testing. The systems are operated and tested initially with regard to flow paths, flow capacity, and mechanical operability in accordance with .Chapter 14.

The air compressors normally 'in operation will be selected based upon a rotating schedule to equalize operating time.

The rotation of operation also acts as an operational test of the compressor. Conformance to Regulatory Guide 1.5. (ASME Code,Section XI) is discussed in 6.6.

1 9.3.1.5 Instrumentation Requirements The accumulators in addition are suppLied with a safety grade source of nitrogen (two independent banks of nitrogen bot t Les) .

9 '-5

E WNP-2 Q. 211.052 (5.2.2)

Provide the initiaL values of all system and core parameters assumed in your anaLysis of -pressure transientsr including:

(1) their nominal operating range; (2) their uncertainties; and (3) the operating limits on these parameters that will be established in the WNP-2 TechnicaL Specifications.

Response

The initiaL values of system and core parameters assumed in the overpressure analyses are Listed in 5.2.2.2.2.1 of the FSAR. They are:

Analysis Nominal Value Value

a. Operating Power

- NWt 3463.0 3323.0 NBR 104.2 100.0

b. Steam FLow 6

10 Lb/hr 14.98 14 ~ 29 NBR 105.0 100.0

c. Dome Pressure ps 1 g 1020.0 1005.0 The operating power and steam flow are Limited by the oper-ating License to their nominaL values. The effect of different operating dome pressure on overpressure protection is shown in the response to Question 211.050'hich concludes that even with a dome pressure of 1063 psigi which is the

. alLowabLe value for the proposed TechnicaL Specification Limit on high reactor pressure scram setpointr the overpressure criteria would stilL be satisfied. Thereforei no Technical Specification Limit on operating steam dome pressure is necessary.

WNP-2 Q. 211.053 (5.2.2)

In Section 5.2.2.2.4 of the FSARi you discuss SRV charac-teristics .which include valve groups and pressure setpoints.

Howevers it is not apparent to us how these two items are factored into your analysis. For examples the setpoint range for the spring actuation safety mode is indicated in Section 5.2.2.2.4 as 1165 to 1205 pounds per square inch gauge (psig) whereas Table 5.2-2 Lists 1130 to 1205 psig for th'is range. Define the phrase "valve groups" and indicate how you include consideration of vaLve groups in your analysis. Discuss how you use these different set-point values in your analyses.

Response

It is assumed that the question is directed to 5.2.2.2.2.4r Safety/ReLief Valve Transient Analysis Specifications.

In the ove'rpressure analysis described in 5.2.2.2.2.4r the valves are divided into five hypotheticaL groups or "vaLve groups" such that each group has 1/5 of the totaL calcu-,

Lated capacity. Within a groups the vaLves have the same opening and closing pressure setpoints.

The group pressure setpoints Listed below are u sed in the overpressure analysis'hile the valve setpoint s shown in Table 5.2-2 are the specified nominaL values. It is clear that the setpoints in the analysis are higher ( i.e.r more conservative) than the specified values. This is to account for initiaL setpoint errors and any instrument setpoint drift that might occur during operation.

~Grou ~Set oint 1177 1'1 87 1197 1207 1217 Section 5.2.2.2.2.4 incorrectly states the setpoint range used in the transient analysis. It has been revised to ref Lect the values shown above.*

• Draft FSAR page change attached.

' b. Pressure Spring-action safety mode ~ ~

setpoint (maximum safety limit):

(i 77 I2]7 psig The setpoints are assumed at a conservatively high level above the nominal setpoints. This is to account for initial setpoint errors and any instrument setpoint drift that might occur -during operation. Typically assumed setpoints in the analysis are 1 to 2S above the actual nominal setpoints.

High conservative safety/relief valve response characteris-tics are also assumed.

5.2.2.2.2.5 Safety Valve Capacity Sizing of the safety valve capacity is based on establishing an adequate'argin from the peak vessel pressure to the vessel code limit (1375 psig) in response to the reference transients in 5.2.2.2.2.2.

5.2.2.2.3 'valuation of Results 5.2.2.2.3.1. Safety Valve Capacity The required safety/relief valve capacity is determined by analyzing the pressure rise from a MSIV closure with flux scram transient. The plant is assumed to'be operating at the turbine-generator design conditions at a maximum vessel dome pressure of 1020 psig. The analysis hypothetically

" assumes the failure of the direct isolation valve position scram. The reactor is shutdown by the backup, indirect, high neutron flux scram. For the analysis, the spring-action safety setpoints are to be in the range of 1177 to 1217 psig.

The analysis indicates that the design valve capacity is capable of maintaining adequate margin below the peak ASME code allowable pressure in the nuclear system (1375 psig)=.

Figure 5.2-4 shows curves produced by this analysis. The sequence of events in Table 5.2-10 assumed in this analysis was investigated to meet code requirements and to evaluate the pressure relief, system exclusively.

Under the General Requirements for Protection Against Over-pressure as given in Section III of the ASME Boiler and

'Pressure Vessel Code, credit can be allowd for a scram from the reactor protection system. In addition, credit is also taken for the protective cizcuits which are indirectly de-rived when determining the required safety/relief valve capacity. The back-up reactor high neutron flux scram is conservatively applied as a design basis in determining the required capacity of the pressure relieving dual purpose safety/relief valves. Application of the direct position 5,2-7

v~ /

WNP-2 Q. 211.054 (5.2.2)

The peak pressures occurring af ter c Losure of the flSIV's due to scrams initiated by high f Lux and high pressure signals are not consistent between Figures 5.2-4 and 5.2-5 of the FSAR. Further'ection 5.2.2.2.3.1 erroneously states that generator load rejection with bypass failure is shown on Figure 5.2-4. Correct these inconsistencies.

Response

The inconsistencies stated are corrected in revised 5.2.2.2.3.1 and revised Figures 5.2"4 and 5.2-5. The curve for peak vesseL bottom pressure from pressure scram in Figures 524 and 52"5 were mistakenly placed onto these figures and have been deLeted. The reference to generator Load rejection with bypass failure in 5.2.2.2.3.1 was incor ect and ha's been deleted.*

• Draft revised FSAR page changes attached.

WNP-2 scrams in the design basis could be used since they qualify as acceptable pressure protection devices when determining the required safety/relief valve capacity of nuclear vessels under the provisions of the ASME code. The safety/relief valves are operated in a relief mode (pneumatically) at set points lower than those specified for the safety function.

This ensures sufficient margin between anticipated relief mode closing pressures and valve spring forces for proper seating of the valves.

The parametric relationship between peak vessel (bottom) pressure and safety/relief valve capacity for the MSIV transient with high flux scram is described in Figure 5.2-4.

Also shown in Figure 5.2-4 is the ~g p~g~4g SCrC4bf U~veea peak vessel (bottom) pressure ~ ~

f 4)lrR (g V4l.Vhz CA<AcrT'f.

ent Pressures shown for flux scram will result only with multiple failure in the redundant direct scram system.

The time response of the vessel pressure to the MSIV trans-ient with flux scram is illustrated in Figure 5.2-5. This shows that the pressure at the vessel bottom exceeds 1250 psig for less than 7 seconds.

5.2.2.2.3.2 Pressure Drop in Inlet and Discharge Pressure drop on the piping from the reactor vessel to the valves is taken into account in calculating the maximum vessel pressures.

Pressure drop in the discharge piping to the suppression pool is limited by proper discharge line sizing to prevent backpressure on each safety/relief valve from exceeding 40%

of the valve inlet pressure, thus assuring choked flow in the valve orifice and'no reduction of- valve capacity due to the discharge piping. Each safety/relief valve has its own separate discharge line.

5.2.2.3 Piping and Instrument Diagrams See Figure 5.2-6 which shows the schematic location of pres>>

sure-relieving devices. The schematic arrangement of the safety/relief valves is shown in Figures 5.2-7 and 5.2-8.

5. 2-8 gee(5>

k 1550 251 BWR/5- MSIV 14$ /% VOIO COEFFICIENT 1500 1450 Ell D

CO LIJ C

PRESSUR E SCRAM 0I 1400 I

O CO EO UJ Y 1350 1300 FLUX SCRAM 1250 POSITION SCRAM 1200 50 60 70 80 90 100 110 120 130 140 150 160 170 40 SAFETY VALVECAPACITY -% NB RATEO STEAMFLOW 7 8 9 'IO 11 12 13 14 15 16 17 18 NUMBER OF OPERATING SAFETY VALVES WASHINGTON PUBLIC POWER SUPPLY SYSTEM VERSUS FIGURE PEAK VESSEL PRESSURE NUCLEAR PROJECT NO. 2 SAFETY/RELIEF CAPACITY 5.2-'4

I I <<I I ~ a$

~

'i)ii O

A I

1400 m c I

M A MSIV PRESSURE SCRA SAFETY VALVES O

nm O

m Kl C/l 1300

~Wc.F 7K.

L

~ Q

~ M PC C/l 1250 7C O 1200 C t:

C C/J Cn MSIV FLUX SCRAM FOR 18 SAFETY VALVES D

Z7 m 1150 C/l Kl m

Im

'M+7 251 BWR/5 R. C/l Q<<c C/1 1100 jt IX VOID COEFFICIENT

~

14 g)M cnm m,'

R<<O W'XI 1050 C/l 0 10 12 14 n ,

m TIME (scd

WNP-2 Q. 211.055 (5.2.2)

Indicate whether the WNP-2 facility wiLL incorporate a fast scram system.

Response

WNP-2 wiLL not incorporate a fast scram.

WNP-2 Q. 211.056 (5.2.2)

Provide calculations to support the values you assume for the discharge coefficients and the flow capacities of the SRV's.

Response

The values used for the average discharge coefficient and fLow capacities are not assumed but rather were determined by experiment. The valve manufacturers Crosby VaLve and Gage Company Located in Wrenthamr Massachusettsi physically tested. three-different size valves of, the type used at WNP-2 at three different popping pressures using saturated steam to obtain flow data for the valve type. These tests were performed in L968 and the data obtained was submitted to the National Board of Boiler and Pressure VesseL Inspectors for certification. Certification was approved in November of 1971. The certification includes verification of the average discharge coefficient shown in paragraph 5.2.2.4.2.1. The foLLowing table gives the certified flow capacities for a Crosby-style HB pressure relief valve.

CROSBY VALVE 8 GAGE COMPANY STYLE HB Section III'uclear (Formula: W = 51.5 x .966 x AP x .90)

Accumulation 3% per Section III Popping Capacity Press. Lbs. Lbs. Per Hour Inlet S i ze: 6 in. 50 47r789 100 84w966

'ore D i a.: 4 ~ 530 200 159r321 300 233r675 Area: 16.117 500 382~385 1000 754r158 1500 1 s125r931 The experimentaL results veri fy the use of the ASME f Low r ate formuLa as used in Table 5.2-2.

Flow Rate (LBM/HR) = 51.5 x 0.966 x A x P x 0.90

WNP-2 Where A is the orifice area of the valve in squre inches and P is the 'absolute pressure at the upstream position of the valve measured in PSI.

It should be noted that the Crosby Style HB safety/relief valves used at WNP 2 have been returned to the manufacturer for design changes which wiLL greatly improve the valves functional characteristics and reliability. The design changes do not affect discharge coefficient or flow capa-cities obtained experimentalLy for the valve.

WNP-2 Q. 211.057 (15.0)

Indicate the power-operated pressure reLief setpoints and the fLow capacities assumed in-your transient analyses in Section 15 of the FSAR.

Response

The re lief setpoints are. '1091r 1101m 1111r 1121'131 (psig). The fLow capacity of the 18 vaLves is 111.'5%

NBR at 1213 psig. The above information is Listed in Table 15.0-2 of FSAR.

The individual relief valve capacity at 1213 psig is:-

111.5% NBR 885~558 Lbs/hr where NBR = 14.296 meb/hr at 3323 NWth Now at the relief valve setpoints:

Nominal Respective Set oint i si Ca acit i Lbs/hr 1091 798r000 1101 805r000 1111 81 2 F000 1121 81 9r000 1131 826s000

WNP "2 Q. 211. 058 (6.3)

Confirm that adequate wiLL exist if operator netact positive suction head (NPSH) ion is not init iated within 20 minutes following a postulated Loss-of-coolant accident (LOCA) .. Provide your detailed NPSH calculation to demonstrate conformance with our positions in Section C of ReguLatory Guide 1.1i "Net Positive Suction Head for Emergency Core Cooling and Containment= Heat'Removal System Pumps"r flovember 1970'or th'e pumps in the emergency core cooling system (ECCS).

Response

The ECCS NPSH caLculation demonstrating conformance to Regulatory Guide 1.1 has been presented in the response to Question 022.038. The suppression pool temperature used in this calculation is 220 F. The available NPSH is 36 feet'sing the unrealistic assumption of not taking credit for wetweLL air space pressure being the vapor pressure of the suppression pooL water, at 220 F.

The NPSH required by the RHR pumpsr as documented by the pumps performance curves (Figures 6.3-10ar b and c) is 11 feet at 7450 gpm rated flow. The NPSH required for the LPCS pumps as documented by the pump performance curve (Figure 6.3-8)r is 12 feet at a maximum flow of 7800 gpm.

The HPCS pump was tested by the manufacturer from 500 gpm to runout (7270 gpm) with an available NPSH of 31.6 feet and there was no evidence of cavitation. This is not considered the required NPSHi but it does verify the adequacy of the available NPSH.

The response to Question 211.062 addresses the affect on NPSH due to a drop in suppression pool water Level from passive fai lures post"LOCA. About five days of operator

'ction time is avai lab le before the NPSHA drops to 31.6 ft ~

The 220 0 F peak suppression pooL temperature predicted by the containment response and analysis presented in Section 6.2.1 assumes the folLowing:

1. no containment heat removaL for the first 1-0 minutes;

WNP-?

2. containment 'heat removaL after 10 minutes assuming a fulL fouLed RHR heat exchanger and rated RHR flow~ 7450 gpmr through the sheLlside of the heat exchanger;

3. no credit taken for any heat Losses other than through the RHR heat exchangers; 0

4. a conservativei steady 95 F standby serv,ice water (SW) temperature, and

5. a suppression pooL volume of 107i850 feet 3 No specific calculations on suppression pool temperature were performed to show the effects of starting Long-term cooling 20 minutes after the accident. Howevers there are enough conservatisms in the suppression pool temperature analyses to justify the adequacy of the WNP-2 design if a 20-minute operator action time is usede The assumption of no containment heat removal prior to operator action is not realistic. ECCS and Standby Service Water (SW) to ECCS componentsi including the RHR heat exchangersi, are automatically started after receipt of the LOCA signalr even if off-site power is Lost. The RHR systems which is used for Long-term containment coolingi is automaticaLLy aligned to the Low pressure cooLant injection (LPCI) mode at the start of the accident. About 45% of the LPCI flow goes through the RHR heat exchangerr whiLe the balance of the flow goes through the heat exchanger bypass valve F048 (reference Figure 5.4"13) . Valve F048 automatically opens after a LOCA si,gnal. W thout any operator actions some containment cooling is initiated. In order to place the plant in a Long-term cooling modei alL the operator has to do is close the RHR heat exchanger by"

'ass valve F048. Even with only 45% LPCI flow through the RHR heat exchangeri 73% of the rated therma L conduc" tivity is still available. The RHR heat exchanger's thermal conductivity is 229 BTU/sec F with the reduced sheLL side flow as compared to 289 BTU/sec F with rated sheLL side fLow.

Because of the smaLL temperature difference between the suppression pool and the ultimate heat sink during the early part of the transient~ the RHR heat 'transfer rate is not high. Changing the assumption in the analysis presented in 6.2.1 of no containment cooling until 20

WNP-2 minutes results in Less than 2 F increase in the suppression pool temperature 20 minutes after the start of the accidents This was determined by calculatin g the totaL heat removed by the RHR heat exchanger between 10 and 20 minutes after the accident and then adding that quantity of heat to the suppression pooL mass. This smaL l temperature increase wiLL in turn resuLt in Less than 1 F i ncrease in the peak suppression temperature> which oc curs several hours later.

This increase wiLL not cause NPSH problems.

The assumption of a steady 95 F SW temperature is very conservative. Ultimate heat sink parametric studies have determined that if the realisticr aLthough stilL conservatives SW transient presented in the response to Question 010.023 and presented in 9.2.5 is usedi the geak suppression pooL temperature wiLL be agproximately 10 F Lower than predicted using a steady 95 F SW temperature.

In the ult imate heat sink temperature transient analysis in 9.2.5.3i the ef feet on suppression pool temperature transient was d eterminedi assuming a fuLly fouled RHR heat exchangerr no operator action to cLose F048'nd the predicted s ervice water temperature response. This suppression poo transient is shown in Figure 9.2-7ai and it results in a suppression pooL temperature Less than 220 F.

As shown in Table 6.2-1i the actual minimum suppgession pool volume outside the pedestal is 127i197 feet r not the 107i850 feet used in the analysis. The Latter figure is used to maximize the initiaL blowdown effects after a LOCA and does not include the water volume more than 12 feet below the downcomer exigts. Since the maximum caL-cuLated suppression pool temperature does not occur untiL about 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> after the accident (reference Figure 6.2-8)i credit can be realisticaLLy taken for aLL )he water out" side the pedestaL arear'.e.i 127i197 feet Thereforer there is enough conservatism in the suppression pooL temperature transient analysis to show that even with an assumed ?0-minute operator timer the suppression pooL wiLL remain below 220 Fr and at 220 Fi there is adequate NPSH available in accordance with ReguLatory Guide 1.1 to operate the ECCS pumps.

WNP-2 Q. 211.059 (6.3)

You state in the FSAR that no operator action is re quired until 10 minutes after an accident. Howevers it is our position that no operator action should be required for 20 minutes after an accident. Accordinglyr discuss the consequences of the reactor operator not performing demode his required duties untiL 20 minutes after a postulated LOCA.

Discuss alL actions which the operator is required to perform to place the plant in the Long"term cooling foLLowing a postulated LOCA.

Response

As indicated in Section 6.3.2.8r no operator actions are assumed for 10 minutes after a postulated LOCA. Of the five criteria specified in Section 50.46 and Appendix K, to 10 CFR 50'he maximum peak cladding temperatures maximum cladding oxidationr maximum hydrogen generationi and transients which might jeopardize maintaining eoolable geometry aLL occur before 10 minutes for the design-basis accident.

The only criterion not met in Less than 10 minutes is that of maintaining Long-term cooling. This Latter cri-terion is met by the initiation of the suppression pooL cooling mode. As explained in Section 6.2.2.3 and in the response to Question 211.58'he onLy action the operator must perform to place the pLant in a Long-term cooling mode is to close the RHR heat exchanger bypass valve F048 (Ref erence Figure 5.4-13) . As shown in the response to Question 211.058'here is enough conservatism in the suppression pooL transient analysis to show that even with an assumed 20-minute operator action timer the suppression pooL wiLL remain below 220 Fi and at 220 Fi there is adequate NPSH available in accordance with Regulatory Guide 1.1 to operate the ECCS pumps.

The only type of Loss-of-coolant accident which would require operator action is a break outside the containment in a Line connected directly with the reactor pressure vessel. Operator action is required to activate the automatic depressurization system if HPCS is not available because there wiLL be no high dr yweLL pressure signaL.

Then the Low pressure ECCS can terminate the transient.

The maximum steam Line break (MSLB) is representative of this class of break. A discussion for assuming a 20-minute operator action time after a MSLB is presented in the response to Question 211.065. The concLus'ion is )hat the peak c.ladding temperature only reaches about 1250 Fi far below the 2200 F Limit.

WNP-2 Q. 211 . 060 (6.3)

On page 6.3-10 of your FSARi you state that the high pressure core spray (HPCS) is automatically shutdown by a .signa l indicating a high water Level in the reactor pressure vessel (RPV). Indicate what provisions are incorporated in the WNP-2 faciLity to prevent premature termination of the HPCS flow. State whether any inter-Locks are provided (e.g.i a LOCA signaL) which wouLd prevent automatic shutoff.

Response

Premature termination of HPCS fLow prio r to attaining high water Level (Level 8r per Figure 5 .2"6) is prevented by a requirement that the Level 8 high Level trip consist of a two-out-of-two Logic permissive to close the HPCS injection valve NO-F004 (Reference Figu re 6.3-2) . LOCA Logic does not prevent automatic shutof f on L eve L 8.

If water Level decreases to Level 2 aft er HPCS f Low has been shut off'he HPCS injection 'valve wiLL automatically reopen. The -Logic for NO-F004 is shown in FSAR Figure 7.3- 8 r High Pressure Core Spray'CDi Sheet 1. During

~

the time the injection valve is closedr the HPCS pump is circulating fLow to the suppression poo L.

7

WNP-2 Q ~ 211. 061 (6. 3)

When the water Level in the con densate storage tanks (CST) drops to a predetermined Levels the HPCS pump switches auto-mat icaLLy to the suppression po oL. Provide assurance that the water Level in the CST wilL supply an adequate NPSH at the time this switchover occurs In additionr show that the minimum submergence of the suet ion piping in the CST wiLL precLude formation of- an undesi rable vortex. Describe the preoperational testing you wiLL perform to demonstrate that such vortex formation wiLL not occur.

Response

During performance testing of the HPCS pumps no direct measure-ment of the required NPSH was obtained. Howevers in Lieu of a direct measurement of the required NPSHi the pump was tested with the available NPSH held constant at approximately 31.6 feet (reference centerline suction nozzle) for flows ranging from 519 gpm to 7255 gpm (runout). During these tests no evidence of cavi-tation in the pump was detected. ALthough this is not considered the required- NPSHi it does indicate that the 31.6 feet used in the tests meets or exceeds the required NPSH for the fuLL flow range of the pump. The rated HPCS pump fLow is 6856 gpm with the RPV pressure 20 psi above primary containment pressures and 1550 gpm with the RPV pressure 1130 psi above the pressure at the source of suction. The available NPSH to the HPCS pump at suction transfer from the CST to the Suppression Pool is calculated using the foLLow" ing data:

a) atmospheric pressurer 14.7 psiai above the CST's.

b) vapor pressurei 1.7 psiai conservatevely assuming the CST' a re at 120 F.

c) pressure drop due to frictioni 7.2 feet'or a f Low of 6856 g pm.

d) static head when the CST's are at 447'4" (switchover Level) r 26.96 feet. (pump suction C.L. eL. 420'-481/2")

The available NPSH is 49.8 feet which is significantly. greater than the per formance test parameter of 31.6 feet.

4

wNp-2 The HPCS pump is guaranteed a continuous suction supply during suction switchoveri since the suppression pooL suct ion supply valve is designed to open on a Low Level signaL from the CST's.

Once the suppression pool suet ion supply valve is fully opens the i

suction suppLy vaLve from the CST' i s automat cat Ly c Losed.

Refer to figure 6.3"1 for the HPCS valving conf iguration.

The suction piping in the CST's is being reviewed to determine if vortexing will be a problem under any operating mode of the of that tionss. This response wiLL be HPCS- revised upon completion review. In any casei subsequent preoperationaL testing wiLL verify the absence of vortexing in accordance with the calcula-

WNP-2 Q. 211.062 (6.3)

Provide assurance that adequate NPSH exists in the event of a passive failure of the ECCS in a water-tight pump room.

Discuss the possibility of vortex formation at the suction intake of the remaining ECCS pumps with the Lowered suppres-sion pool Level that would resuLt from this type of postu" Lated accident. Discuss the preoperationaL tests you wiLL perform to demonstrate that ther is no impa irment of the functionaL capability of the ECCS due to a Lowered suppres-sion pooL Level.

Response

Passive fai lures in ECCS piping and their affects on avaiL-able NPSH were previously addressed in the response to Question 212.003. In th is responser it was determined that the operator has approximately 5 days to detect and isolate any ECCS passive failure before the suppression pooL drops below the minimum Level required for ECCS pump requiring the most NPSHr which is the HPCS pump (31.6 ft) . See the response to FSAR Question 211.061 for further information on NPSHR.

Five days represent more than enough time to isolate any Leaksr since the safety grade Level alarm system in the ECCS pump rooms wiLL alert the operator to ECCS room flood-ing prior to any significant Loss of suppression pooL water Level.

ALL ECCS suet.,ion Lines in the suppression pooL have been designed with Large diameter piping (24 i nches) to reduce the inlet velocity (maximum 6.67 ft/sec). Thi s inlet velocity wiLL support a vortex of no more than 2-1/2 f eet in height. The inLet to each of the ECCS suet ion L ines is greater than 22 feet beLow the minimum suppression pooL Level. Vortex formation at the ECCS pump inlets as a result of Lowered suppression pooL Level is thus not considered a problem.

Since it has been conservative ly established that'll ECCS suction Lines are adequately submerged to preclude formation of an undesirable vortex'o confirmatory preoperational testing wiLL be performed.

MNP-2 Q. 211.063 (6.3)

Confirm that the Low pressure coolant injection (LPCI) system does not perform any other function such as con-tainment cooling during the short-term portion of the recovery phase folLowing a postulated LOCA. If the LPCI system wilL be used for another function during this time periodi this additional function must be considered in your LOCA analyses. (Refer to Question 211.082 of this encLosure.)

Response

A LOCA signali which automatically initiates the LPCI mode of RHR systems is also used to isolate aLL other modes of RHR operation and revert system valves to LPCI Line up. The RHR system continues in the LPCI mode untiL the operator determines that another mode of operation is needed (such as containment cooling) and takes action to manuaLLy initiate that mode. By trainingr the operator wiLL not divert LPCI to any other mode of operation for ten minutes. No operator actions are needed during the short-term (see also Section 6.3.2.8 and 6.2.2.2).

WNP-2 Q. 211.064 Provide the values of the totaL- break area which you assumed for the foLLowing postulated breaks: (1) the recirculation Line break; (2) the steam Line break inside and outside con" tainment; (3) the feedwater Line break; and (4) the core injection spray Line break.

Response

The maximum recirculation break area of 3.113 ft 2 is comprised of t$ e foLLowing areas: recirculation safe end area (2.565 ft ) r total jet pump nozzle area of one recirc-ulat ion: Loop (0.468 ft ) i and the minimum f Low area of the reactor water cleanup system piping connecting the two Loops (0.080 ft ). As explained in 6.2.1.1.3.3.2r the maximum steam Line break inside the containment js initialLy based on the steam Line safe end arya (3.05 ft ) plus the minimum f Low rest rictor area (0.91 ft ) . After the main steam isolation valves have closedr the flow is Limited by critical f Low through the safe end. This is shown in Figure 622-10. The maximum outside steam Line break area (3.65 ft ) is based on t)e minimum flow Limiter area for each steay Line (0.91 ft ). The feedwater Line break area (0.362 ft ) is based og the inside area of the feedwater sparger pipe (0.181 ft ). The maximum core spray Line break area is based on2the Limiting area of the core spray Line safe end (0.47 ft ).

Pshaw-p~ A~~

TABLE 6.3-2 SIGNIFICANT INPUT PARAMETERS TO THE LOSS-OF-COOLANT ACCIDENT ANALYSIS A. PLANT PARAMETERS:

Coze Thermal Power 3462 MWt which corresponds to 105% of rated steam flow*

Vessel Steam Output 15.01 x 106 Lbm/h which corre-sponds to 105% of rated steam flow Vessel Steam Dome Pres- 1055 psia sure Recirculation Line Break i (DBA) and 1.0

~

Area for. Large Breaks 9. //3 (ft.2)

Recirculation Line Break 1.0 and 0.10 Area for Small Breaks (ft.2)

B. FUEL PARAMETERS:

Fuel Type Initial Core Fuel-Bundle 8 x 8c Geometry 62 fueled rods Peak Technical Specification Linear Heat 13.4 Generation Rate (kw/ft)

Design Axial Peak Factor 1.4 Initial Minimum Critical Power Ratio 1.18 A more detailed list of input to each model and its source is presented in Reference 6.3-2.

• This power level exceeds the Appendix K requirement; of 102%.

The core heatup calculation assumes a bundle power consistent with operation of the highest powered rod at 102% of its maximum (technical specification) linear heat, generation rate.

6,3-39

~~

TABLE 6 3-3

SUMMARY

OF RESULTS OF LOCA ANALYSIS Peak Local PCT( F> Oxidation Break Size Location Single Failure Break S ectrum Anal sis~

<DBA> 1960 Recirc. Suction I LPCI D/G failure 1.0 Recirc. Suction Large LPCI D/G failure Break 1568 <1.0 HPCS D/G failure I Methods 1675 LPCI D/G failure Small 1100 <1 ~ 0 HPCS D/G failure Break 1385 Methods 0.1 ft 1473 <1.0 Recirc. Suction HPCS D/G failure I

The corewide metal-water reaction for the subject plant has been calculated using method 1 described in Reference 6.3-2.

The calculation was done using the standard nodal power distribution consistent with the assumption of 102% of licensed core power. The value is 0.07%.

(1) For other breaks in spectrum see lead plant analysis, Reference 6.3-3. For justification of selection of lead plant, see Reference 6.3-1.

6.3-43

WNP-2 Q.~ 211.065 (6 3)

~

Indicate the differences between the assumed values of break areas for postuLated steam Line breaks inside and outside'containment. Your analyses of thes,e postulated breaks indicates that the reactor core could become un-covered if no operator action took place within 20 minutes after this postulated accident. Indicate the effect on the peak clad temperature if the operator takes no action for 20 minutes after an accident. In your responser include a discussion of aLL your assumptions.

Response

The difference between the assumed values of break areas for postulated steam Line breaks inside an'd outside con-tainment is explained in Section 6.2.1.1.3.3.2 and in the response to Question 211.064. The maximum steam Line break inside containment is2initialLy based on the steam Line safe end2area (3.05 ft ) plus the minimum restrictor area (0.91 ft ). After the main steam isolation valves have closedr the steam flow is Limited by criticaL flow through the safe.end. This is shown in Figure 6.2210.

The maximum outside steam Line break area (3.65 ft ) is based on the sum of the yinimum flow restrictor areas for each steam Line (0.91 ft ) .

Any break outside the primary containment <in a Line connect-ing directly to the reactor pressure vesseL will need operator action under Loss-of-coolant accident (LOCA) analysis assumptions because there wiLL be no high".dryweLL pressure signaL to activate the automatic depressurization system (ADS). Given LOCA analysis assumptionsr no credit is taken for the feedwater system and the reactor core isolation cooling (RCIC) system. Also'he high pressure

'core spray (HPCS) system is assumed to faiL. With no credit for the above systemsr the operator must manually initiate the AOS to depressurize the vesse l below the shutoff head of the Low pressure ECC systemsi allowing these systems to terminate the transient.

The outside steam Line break is representative of this class of breaks. A complete analysis of the outside steam Line break assuming no operator action for 20 minutes. is presented in the response to LaSaLLe Question 212.098. Briefly summarizing that analysis'o operator action was assumed

/ WNP-2 v<

untiL 20 minutes after a maximum steam Line break outside the containment. This resulted in a peak c ladding temper-ature of about 1250 0 Fi far below the 2200 0 F Limit. Zt is appropriate to apply the LaSaLLe analysis to WNP-2 because the two plants are identicaL in size and have the same ECC system design and therefore wiLL exhibit LOCA that are very similar. Significant margin is demon-characteris-'ics strated in the LaSaLLe case to account for any minor differences between the two plants.

+

~

)JNP-2 Q. 211.066 (6. 3)

Identify aLL ECCS valves which may be potentially submerged or subject to spray impingement foLLowing a postuLated LOCA.

Discuss the environmental qualification oftheCe vaLves for these conditions:

Response

The below Listed valves represent the ECCS systems valves inside containment required for safe shutdown following a LOCA which may be subject to spray impingement folLowing a postulated LOCA:

Va Lve No. Type Qty. System HPCS-V-5 Testable Check 1 High Pressure Core Valve Spray HPCS-V-51 Gate Valve High Pressure Core Spray LPCS-V-6 Testable Check 1 Low Pressure Core Valve Spray LP CS-V-51 Gate Va Lve Low Pressure Core Spray RHR-V-41ArBiC Testable Check 3 Low Pressure Coolant Valve Injection RHR-V-111 AiB i C Gate Va L ve 3 Low Pressure Coolant Injection NS-RV-3Dr 4Ai48 Sa f ety/Re i e f L 7 Automatic Depressuri-4Cw 4Dr 5Br 5C Va ives zation System None of the above Listed valves are subject to f looding following a postulated lOCA because al l ".he water r e leased by the LOCA wiLL flow to the suppression pool and aLL the Listed valves are above the drywell f Loor.

WNP-2 The safety/relief valvesi testable check valves and gate valves Listed above and associated components are designed to be suitable for the following accident thermal environment:

Temperature 340 F 320 F 250 F 200 F Pressure -2 to 45 -2 to 45 -2 to 25 -2 to 20 psi9 ps1 9 ps>9 pslg Relative 100% 100% 100% 100%

Humidity Duration 3 hrs. 6 hrs. 1 day 100 days In addition~ they have been designed to be operable during and after an SSE.

The gate valves Listed above are maintenance valves and are norma lly Locked open. ALthough they are designed to be operabler they are not required to operate following an accident. The only electrical components on these valves are the Limit switchesr which are utilized to provide veri-fication that these valves are open during normaL plant operation. Therefore ther e is no effect on the operation of the ECCS if these valves are subject to jet impingement f ol lowing a postulated LOCA.

The testable check valves are equipped with an air operator to allow vaLve stroking during plant shutdown and thus verify operability. This air operator is designed so that it wiLL not prevent the check valve from opening for forward flow or closing to prevent reverse flow. The only electrical components on these valves are the stem actuated Limit switches which provide position indication of the air operator rods and magnetic sensors which provide position indication of the valve disc. The solenoid valve for the air operators and controL element for the magnetic sensors are Located outside primary containment. Therefore there is no effect on the operation of the ECCS if these valves are subject to jet impingement foLLowing a postulated LOCA.

The ADS valves are not designed for operability after steam jet impingement- Howevers MNP-2 is currently evaLuating the consequences of jet impingement on the ADS valves. If the analysis shows that the results are unsatisfactoryr then the ADS valves wiLL be protected from jet impingement. The results of this analysis will be reported by amendment to Chapter 3.6.

J WNP-2

a. 211. C67 (6.3)

Indicate whether there have been any recent changes or corrections to your ECCS analysis. If sos provide the references for the Latest modeL changes and corrections in the List of references provided for your ECCS analysis.

Response

The additionaL references required for the Latest modeL changes and corrections to Section 6.3.6 are as foLLows:

6.3-4 "Safety Evaluation for General ELectric ECCS EvaLuation Model Nodificationsr" Letter from K. R. Goller (NRC) to G. G. Sherwood (GE) r dated Apr il 12'977 6.3-5 Letters A. J. Levine (GE) to D. F- Ross (NRC) dated January 27'977'General Electric (GE)

Loss-of-Coolant Accident (LOCA) Analysis Model Revisions Core Heatup Code CHASTE05."

6.3-6 Letters A. J. Levine (GE) to D. B. Vassallo (NRC)i dated Narch 14'977'Request for Approval for Use of Loss-of-Coolant Accident (LOCA) Evaluations Nodel Code REFLOOD05."

Section 6.3.3 ' ' has been revised for the SAFE/REFLOOD and CHASTE modeL descriptions to include the appropriate references above. References 6.3-4 and 6.3-6 apply to SAFE/REFLOOD and references 6.3-4 and 6.3"5 apply to CHASTE.*

• Draft FSAR page changes attached.

LONG-TERN THER".QM HYDRAULIC MODEL AND REFILL/REFLOOD MODEL (SAFE'ZFLOOD I

The SAFE/REPLOOD code is a model which is used to analyze

~ ~

the long-term thermodynamic behavior of the coolant in the

~

~

vessel. The SAFE/REFLOOD code calculates the uncovery and reflooding of the core and the duration of spray cooling

.and (for small breaks) the peak cladding temperature.

For a detailed description of the model and a discussion egarding sources of input to the model refer to the "SAFE code and REFLOOD Code Documentation" Sections XI.A.1 an)

II.A.2 of Reference 6.3-2> ~g P CORE HEATUP MODEL (CHASTE)

The CHASTE code solves the transient heat transfer equations for specific axial planes of each fuel bundle; type,- for-large breaks. CHASTE receives input from SCAT, SAFE and RE=LOOD and calculates cladding temperatures and local cladding. oxidation during 'the entire LOCA transient. For a detailed description of the CHASTE model and a discussion regarding sources of input, refer to the "CHASTE code g documentation"Section XI.A.5 of Reference 6.3-2> a-r <

~~ermees'.3-F ~a g.3-~

The significant input variables used by the LOCA codes are listed in Table 6.3-2.

6.3.3.7.2 -. Accident Description A detailed desc iption of the LOCA ca culation is provided in Reference 6.3-2. For convenience, a short description of the major events during the design basis accident (DBA) is included here.

Immediately after the postulated double-ended recirculation suction line break, vessel pressure and core flow begin to decrease. The initial pressure response (Pigure 6.2-2lb) is governed by the closure of the main steam isolation valves and the relative values of energy added to the system by decay heat and energy removed from the system by the initial blow-down of fluid from the downcomer. The initial coze flow de-crease (Figure 6.3-18) is rapid because the recirculation pump in the broken loop looses suction and almost immediately ceases to pump. The pump in the intact loop coasts down relatively slowly. Th' pump coastdown governs the core flow response

=o the next several seconds. When the jet pump suctions uncover, calculated core flow decreases to nea" zero. When 6.3-28

r8NP 2 REFERENCES Compliance with Acceptance Criteria of 10 CFR 50.46 Letter G. L. Gyorey to V. Stello, May 12, 1975.

"General Electric Company A'nalytical Model for Loss-of-Coolant Analysis in Accordance with 10 CFR 50, Appendix K, "NEDO-20566 submitted August 1974, and "General Electric Refill Reflood Calculation" (Supplement to Safe Code Description) transmitted to US NRC by letter, G. L. Gyorey to Victor Stello, Jr, dated December 20, 1974 ..

Hilliam H. Zimmer. Nuclear Power Station, Unit 1; FSAR (Section 6.3) docket number 50-358.

8Pcr + Z Duznp (p<)

P~~~ >/ <mays

'~e <<=-. 4 I'<proua r:

+ -=r g~=wZdoH oK

'.3-37

WNP-2 Q. 211.068 (6.3)

Justify the designation in Table 6.3-3 of the FSARr of the Zimmer facility as the Lead plant for the WNP-2 facility with respect to the LOCA break spectrum analysis. Our concern is that the Zimmer fuel assembly is an Sx8 fueL array with one water rod while the WNP-2 fueL assembly wiLL be an 8x8r two .water rod array.

Response

The Zimmer LOCA analysis is an appropriate representative break spectrum analysis for WNP-2 because the LOCA charac-teristics of similar plants of a given product Line are similar. The lead plant ana lysis serves to identify the Limiting failures and breaks and to define the LOCA charac" teriscis for Like pLants. Individual plant specific analyses are then provided at these points to define the specific plant response for the Limiting cases. The Location of the limiting break is insensitive to changes in power Level or fuel type. This is the basis of the Lead plant concept.

WNP-2 Q. 211.069 (6.3)

Correct the smaLL break model curves shown on Figure 6 3 13 of the FSAR for both the failure of the dieseL"generator which disables the LPCI and the dieseL-generator failure which di sables the Low pressure core s'pray (LPCS) . Spec if i-caLLyi correct the apparent inconsistency between the values of peak clad temperature (PCT) in Figures 6 3 32 and 6 3 39 of the FSAR and those in Figure 6.3-13 at a break area equaL to 80 percent of the br eak area for the design basis accident (DBA) and at 60 percent of DBA break area.

Response

The smaLL break modeL curves shown on Figure 6.3"13 for both the faiLure of the diesel-generator which disabLes LPCI and the diesel "generator which disables LPCS are

=-

correct. Some confusion may have arisen because at the 0.5 ft ':break size- the two curves appear to intersec$ i which they do not. They intersect onLy at the 0.8 ft (approximate) break size.

The PCT curves shown in Figures 6.3-32 and 6.3-39 are taken from the Zimmer Lead plant analysis for BWR/5's.

The curve in question in Figure 6.3-, 13 shows the plant specific results at the Limiting points of the break spectrum de'termined by the Lead pLant analysis and shows that the rest of the spectrum is Less Limiting than the DBA. Figures 6.3-32 and 6.3-39 from the Lead plant analysis are included in the FSAR as representative resuLts for non-Limiting breaks. For further discussion of the Lead plant concepts refer to Question 211.068.

WNP-2 Q. 211.070 (6.3)

Demonstrate that a postulated failure of the HPCS in conjunction with a postulated break whose area ranges from 1.0 square foot to the DBA break area is not more Limiting than the postulated failure'of the dieseL-generator whi ch di sables the LPCI system over the same range of break areas.

Response

In the Large break regions the single failure which disables the greatest number of ECCS systems is in general the most Limiting. In the Large break regions substantiaL amounts of initiaL vesseL inventory are Lost through the break during the blowdown. With fewer systems availabler there is Less ECCS fLow avaiLable for refLooding the core and the core wilL reflood Later.

The Later reflooding resuLts in higher peak cladding temperatures. Thus the failure of either diese l which powers two Low pressure ECC pumps is more severe than the faiLure of the HPCS system which involves the Loss of only one pump.

The current Section 6.3.3 of the WNP-2 FSAR is composed of "typicaL" results representative of any BWR/5. The plant specific LOCA analysis for WNP-2 has not been completed. When the plant speci fic analysis is completyr the Limiting failure for the break spectrum from 1.0 ft to the DBA wiLL be supplied. PLant specific analyses are deLayed for incorporation into the FSAR to take advantage of ECCS modeL improvements which naturally occur as time progresses. The normal time for submittal of these analyses has been approximately six months before fuel Load.

WNP-2 Q. 211. 071 (6.3)

Indicate why the plots of water Level versus time for the 1.0 square foot transition break assuming a failure of the HPCS system are different for the small break method and the Large break method.

Re,sponse:

The difference in the water Level plots for the 1.0 square foot transition break is due to the differences in the vaporization and the void calcu lations between the small and Large break modeLs in the REFLOOD code.

The two most significant differences between the smaLL and Large break models are:

I a ~ Use of the'Vaporization Correlation: The vaporization of spray water in the c ore during the period when core sprays are operating is calculated using a bounding correlation. The corre Lation requires the Peak Cladding Temperatures PCTr at ti me of spray initiation. The LBN corr ectly uses a consta nt value whereas the SBN con-servat ive ly uses a cont inuous Ly increasing value. Thi s difference generaLLy re suits in a more conservative

'alculation of the ref L ooding time using the smaLL break mode L.

b. Level and Va porization Following Bottom Reflooding:

The LBN uses an empirically based void fraction of 0.50 for calculat ing the Level and the vaporization below the Level. The SBN uses the conservative fue l rod heatup mode with a reflooding heat transfer coefficient L

to caLculate the Level and the vaporization below the leveL. This difference generaLLy results in a more conservative calculation of the ref Looding time using the SBN.

A further discuss i on of the sma l l and Large br eak mode Ls of the REFLOOD code is contained in FSAR Reference 6.3-2r "GeneraL ELectric Company Analytical Nodel for Loss of CooLant Analysis in Accordance with 10CFRSOi Appendix K (NEDO 20566)".

MNP-2 Q. 211 . 072 (6.3)

Provide in format ion on a pplicabLe tests which demonstrate that the pumps used for Long-range coolingr both for normal operation and foLLowing a postulated LOCAL wi L L operate ef f ect i vely during the t ime period required to fuL f i L L their function.

Response

The RHR pumps and LPCS pumps are used for Long-term cooling.

Tests to which these pur.os are subjected for operabi lity assurance and performance have been described in the response to Question(11.42.

GE operating experience of IngersolL"Rand ECCS pumps is as foLLows:

Hatch 2 RHR Pump 2A 864 hours 28 1 r112 hours 2C 62o hours 2D 569 hours LPCS Pump 2A 13.5 hour5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> s 28 11.8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> Chinshan 1 RHR Pump 100 hours Core Spray Pump 30 hours Chinshan 2 RHR Pump 75 hours Core Spray Pump 20 hours No problems have been reported on these pumps.

Pump design principles applied by IngersoLL"Rand to these units are not unique. Assurance of a predictable functional i eliability is also provided by a history of designr pro-duction~ and application of pumps for similar pumping require-ments in other nuclear and non-nuclear applications.

MNP-2 Q. 211 '73 (6.3)

TabLe 6.3-5 i s not clear. Di scuss the intent of the column headed'Effect on ECCS"i with regard to the particular break Location; i.e.i indicate the postulated break Location.

Response

Table 6.3-5 has been deleted because the information is also included in revised Table 6.3-7. In 6.3.2.5 of the FSAR texts the reference to Table 6.3"5 has been changed to refer to the revised Table 6.3"7.*

• Draft FSAR page changes attached.

WNP-2 AYHNDMENT NO. 5 August 1979 6.3.2.4 Materials Specifications and Compatibility Materials specifications and compatibility for the ECCS are presented in 6.1. Nonmetallic materials such as lubricants, seals, packings, paints and primers, insulation, as well as metallic materials, etc., are selected as a result of an engineering review and evaluatio'n for compatibility with other materials in the system and the surroundings with concern for chemical, radiolytic, mechanical and nuclear effects. Materials used were reviewed and evaluated and found to be acceptable with regard to radiolytic and pyrolytic de-composition and attendant effects on safe operation of the ECCS.

6. 3. 2. 5 System Reliability A single failure analysis shows that no single failure pre-vents the starting of the ECCS when required, or the delivery of coolant to the reactor vessel. No individual system of the ECCS is single failure proof with the exception of the ADS, hence it is expected that single failures will disable individual systems of the ECCS. The most severe effects of single failures with respect to loss of equipment occur the loss-of-coolant accident results from an ECCS pipe break if and is coincident with a loss of off-site power. The con-Cg sequences of the most severe single failures are shown in Table 6.3-P.

7 For protection against and mitigation of passive ECCS failures, for Class lE level instrument is mounted just above floor level in each ECCS pump roora 'to'etect the failures during long-term cooling, assuming'oss of the other non-Class 1E leak detection equipment. See 3.4 for more details. The maximum leak rate postulated is 23 gpm, which is caused by the total failure of an RHR pump seal. With this leak, at least 44 hours5.092593e-4 days <br />0.0122 hours <br />7.275132e-5 weeks <br />1.6742e-5 months <br /> is available for operator action after detection of the leak to identify and isolate the source before

-adverse-.effects on=ECCS-"operation.--- it has any additional The functional testing and calibration of the ECCS will be performed in accordance, with -the schedules established in Chapter 16, Technical Specifications. These schedules will based on the requiiements defined in the Standard Tech-

'e nical Specifications'or BWR's.

6.3.'2.6 Protection Provisions Protection provisions are included in the design of the ECCS.

Protection is afforded against missiles, pipe whip, and flooding. Also accounted for in the design are thermal stresses, loadings from a LOCA, and seismic effects.

6.3-21

4 0

g E.~,

TABLE 6.3-5 lg['in SINGLE FAILURE ANALXSIS Remainin le Fa re Effect on ECCS ECC Loss of HPCS Loss of one of two ADS + 1 LPCS + LPCI loops, or ressurization and ADS + 3 LPC oops operative los 'f one of three coolen elivery systems Loss of one diesel Loss of HPCS AD + 1 LPCS + 2 LPCI loops, or generator S. + 3 LPCI loops operative Loss of LPCS and one ADS + HPCS + 1 LPCI loop, or Ol LPCI loop ADS + 2 LPCI loops operative 4J I Loss of 2 LPCI ops A + LPCS + 1 LPCI loop, or HPCS + LPCS, or oD Ul ADS ADS + CS + 1 LPCI loop operative Loss of one division . Loss f HPCS ADS + 1 LPCS 2 LPCI loops, or of dc power ADS + 3 LPCI lo s operative Loss of LPCS and one ADS + HPCS + 1 LPCI oop, or LPCI loop. Loss of one ADS + 2 LPCI loops op ative ADS logic control path Loss of 2 LPCI loops ADS + HPCS + 1 LPCI loop, o ADS + HPCS + LPCS, or ADS +

LPCS + 1 LPCS loop operative (1) See 6 .3 assumed

'.5) in addition to be in to the failure postulated, the pipe break is line disabling that subsystem.

an ECCS

TABLE 6 3-7 SINGLE FAILURE EVALUATION The following table shows the single, active failures con-sidered. in the ECCS performance evaluation.

Qecwa Suction Break)

Assumed Failure S stems Remainin LPCI Diesel Generator All ADS, HPCS, LPCS, 1 LPCI (D/G)

LPCS D/G All ADS~ HPCSg 2 LPCI HPCS D/G All ADS, LPCS, 3 LPCI One ADS Valve All ADS minus one, LPCS, HPCS, 3 LPCI Other postulated failures are not specially considered be-cause they result in the same or less impact on ECCS capacity.

SYS~< ~HAlhtlhtg/ AS I~T7FI~~ lH 'TRIS ~BC'. ALE AeruCA,rS~

Nab( - E CC,S c IN E acEw~. peg. p f0~

ay~z~s gawWINIMC A~ ~asm

( L ~ ~ ~~~;

6,3-49

WNP-2 Q. 211.074 (6.3)

Check valves in the discharge side of the HPCSi the LPCI/RHR and the LPCS systems perform an isolation function since they protect these Low pressure systems from the high pressures in the reactor. We require that: (1) these check vaLves be classified as ASME IWV-2000'ategory AC; and (2) the Leak testing for these vaLves be performed according to the applicable code specifications. You should recognize that a test which simply draws suction on the Low pressure side of the outermost check valvesr will not be acceptable. Such a test only verifies that one of the check valves in ser ies is fulfilling its iso-Lation function. The required testing frequency is that specified in the ASME Boiler and Pressure Vessel Codes except in those cases where only one or two check valves separate high and Low pressure systems. In these cases~

we require that you perform Leak testing of these valves at each refueling after the vaLves have been exercised.

Accordinglyr ident'ify alL ECCS check vaLves which should be classified as Category AC in accordance with our position on this matter. Verify that you wiLL perform the required Leak testing in accordance with the required frequency and that you have the necessary test Lines to Leak test each valve. Provide the Leak detection criteria that you propose for the WNP-2 Technical Specifications.

Response

The valves enumerated below are check valves which separate a Low pressure system from reactor pressures. These valves are ASME Section XIr IWV-2000'ategory AC valves: LPCS-V-6r RHR-V-41Ar RHR-V-41Br RHR-V-41Cr RHR-V-50Ai and RHR-V-50B ~

.To assure that these vaLves adequat ely protect the Low pressure systemsr they wilL be test ed as part of the WNP 2 Pump and Valve Test Program in acco rdance with the requi re" ments of ASME Section XIr IWV-3000. Thi s program and the appropriate Leak detection criteria wil L be submitted for your review in accordance with the response to Question 110.034. The test Line arrangement for the valves in question is shown in Figures 6.2-31 L and 6.2-31m.

WNP-2 Q. 211 - 075 (6.3)

Indicate the provisions incorporated in the WNP-2 facility to protect the water Level instrumentation for the CST and the lines from this tank Leading to the HPCS systems from the effects of cold weather and dust storms. In, responding to this itemi cross-reference your responses to Items 010.16 and 211.12.

Response

The water Level instrumentation for the CST and the Lines from this tank leading to the HPCS system are totally protected from the effects of cold weather and dust storms.

The Lines are electrically heat traced and a Seismic Cate" gory I enclosure has been provided for all tubing and instrumentation. ALL LeveL instrumentation shaLL be NENA type 4 rated (watertight and dust"tight indoor and outdoor).

See also the response to Question 211.12. The response to Question 10.16 does not address the concerns of this question.

The safety related instrumentation necessary for switchover of HPCS and RCIC pump suction from the CST is Located indoors andi as suchi is not directly affected by cold weather or dust storms.

WNP-2 Q. 211.076 (6.3)

Some of the ECCS relief valve discharge Lines penetrate primary containment and have outlets below the surface of the suppression pooL. Since these Lines are part of the primary containment boundaryr we are concerned that excessive dynamic Loads resulting from water hammer during a'ctuation of the relief valves may cause cracking or rupture of these Lines. Accordinglyr identify these Lines which penetrate the primary containment. Provide information concerning the measures you are taking to prevent line damage due to'ater hammer.

Response

The ECCS reli:ef vaLves shown on Table Q211:.076-1 have discharge Lines which penetrate the- pr imany'ontainment and have discharges below the suppression pooL water Level (Reference Figures 5.4-'13ai 5.4-13br 6.3-1i 6.3-5).

ALL safety/relief vaLves are purchased to ASME III'Lass 2 requirements to match the requirements of the piping they are protecting. As such'he -setpoint tolerance is

+3%i per ASME III'ection NC-7513.1.

For discussion on dynamic Loads resulting from water hammer for RHR-RV-55(ArB) (E12-F055AiB)i RHR-RV-95(ArB)i and RHR-RV-36 (E12-F036) see response to Question 211.040'he remaining relief valves are installed to accomodate thermaL expansion and Leakage across closed valves in isolated piping systems.

Pressure buildups in isolated lines wiLL be slow and dis-charges from the relief valves in these Lines wiLL be smaLL.

Water hammer and other hydrodynamic Loads are not considered a potentiaL problem in these Lines.

Table Q211.076-1 Piping Relief Valve Set oint/Ca acit Location Desi n Pressure E21-F018 550 psi g/100 gpm LPCS Discharge Leg Relief 550 psig E21-F031 100 psig/ 10 gpm LPCS Suction Leg Relief 100 psig E22-F035 1575 psig/25 gpm HPCS Di scharge Leg Relief 1575 ps 1 9 E22-F014 100 psig/ 10 gpm HPCS Suction Leg Relief 100 psig E12 F025 (ArBr C) 500 psig/ 25 gpm RHR Discharge Leg Relief 500 psig E12 F088 (Ar Br C) 125 psig/ 10 gpm RHR Suppression Pool Suction Relief 220 ps i g ArB 125 psig - C E12-F005 220 ps i g/ 25 gpm RHR Shutdown Cooling Suction Relief 220 psig E12-F030 125 psig/ 10 gpm RHR Flush Line Relief 125 psl 9 E1 2- F055 (ArB) 500 psig/330i000 RHR Heat Exchanger Steam Relief 500 psig lb/hr RHR-RV-95(AiB)* 500 psig/330i000 RHR Heat Exchanger Steam Relief 500 ps i g lb/hr RHR-RV-1(ArB)** 500 psig/ 20 gpm RHR Heat Exchanger Thermal Relief 500 psig F12-F036 75 psig/1750 gpm RHR Heat Exchanger Condensate Relief 125 psig

• RHR-RV-95ArB are not currently shown on Figures 5.4-13a and 5.4-13bi but are shown on Figure 326'ones ErH and Er13.

• • RHR-RV-1ArB are shown on Figures 5,4-13a and 5.4-13b (the rma l relief valve on heat exchangers RHR-HX-1ArB) but are not designated by tag number.

WNP-2 Q. 211. 077 (6. 3)

Since the ECCS contains both manuaLLy operated and motor-operated va'.vest there is a possibility that manual valves might be left in the wrong position and that this condition will remain undetected when an accident occurs. Accordinglyr provide a List of the Locations and types of alL manually operated valves in the safety-related systems of the WNP-2 facility. For each of these valvesr provide a discussion of your procedures to minimize the possibility of an occurrence as described above. We require that you provide indication in the controL room for alL critica l ECCS valvesi either manuaLLy or motor-operated.

Response

The foLLowing table provides a List of the Locationi types size and speciaL features of alL manuaLLy operated valves (excluding tests roots vents drain and instrument block valves) in the safety related ECCS systems of the WNP2 facility. Testi roots vent and drain valves are excluded from the List since such improperLy positioned valves wi lL initiate a high Reactor Building sump Level alarm or Low pump discharege pressure alarm and cannot remain undetected.

Instrument block valves are checked on a frequency established by instrument calibration requirements.

As can be seen from the Listr precautions have been taken to minimize the possibiLity that manuaL valves may be Left in the wrong position. Host of the valvesr including all the valves in the main process f Lowpathi are equipped with a padlock and chain to help ensure administrative controL over their being maintained in the appropriate position. In additions aLL motor operated valves~ as weLL as critical manuaL valves (i.e.i the maintenance valves in the ECCS injection lines) are provided with Limit switches to provide position indication in the control room. Nanual valves are considered critical if they are in the main process flowpath and cannot be verif ied to be 'in the correct position either by visual inspection during nor maL plant operation or by monthly ECCS pump surveillance testing. Please refer to Figure 3.2-6': Residual Heat Removal System< and Figure 3 2-7r High Pressure Core Spr ay Systemsr for the relative Location of the valves Listed.

A criticaL ECCS manual valve which is not accessible dur ing norma l plant oper at i on and for which no verification is provided during monthly RHR pump surveillance testing that the valve i s open.

2. The position of this valve does not effect the ability of the Low Pressure Core Spray (LPCS) to perform its safety function.

3. Closure of this valve will initiate the LPCS .

pump discharge Line low pressure alarm in the Control Room.

4. Closure of this valve will initiate the High Pressure Core Spray (HPCS) pump discharge line Low pressure alarm in the Control Room.

5. The position of this valve does not effect the ability of the HPCS to perform its safety function.

ll

6. C'Losure of thi s valve will initiate the Residual Heat Removal (RHR) pump discharge line Low pressure alarm in the Control Poom.

7. The position of this valve does not effect the abi L ity of the RHR system to perform its safety function.

SPECIAL VALVE NO. QTY. SIZE TYPE FEATURE LOCATION NOT ES RHR-V-171 1-1/2 Gate LO Drain Pot outlet RHR V 1?2r Ar B 18 Gate LO RHR Test Line RHR V-173r Ar B 2 Gate RHR Heat Exchange Vent RHR-V-174 18 Gate LO RHR Test Line LPCS-V-4 3 Gate LPCS Pump discharge check valve bypass LPCS-V-8 Gate LC LPCS drain LPCS-V-25 Gate LC Flush supply to LP.S pump discharge LPCS-V-32 Gite Water leg pump suction isolation LPCS-V-34 1-1/2 S'top Check Water leg pump discharge isolation.

LPCS-V-51 12 Gate LOrLS LPCS line at RPV LPCS-V-52 6 Gate LO LPCS pump minimum flow LPCS-V-60 12 Gate LO LPCS test line HPCS-V-3 Gate LC Flush supply to HPCS discharge HrCS-v-6 1-1/2 Stop Check Water legr pump discharge 4 isolation IIPCS-V-19 Gate LC HPCS dr a in IIPCS-V-26 Gate HPCS pump discharge check 5 valve bypass Hrcs-v-34 Gate Water leg pump suction 4 isolation.

HPCS-V-51 12 Gate LO/LS HPCSr line at RPV 1 HPCS-V-64 12 Gate LO HPCS test line

[IPCS-V-31 3 Gate LC Flush supply to HPCS discharge

• LO " has padlock and chain to lock valve in open position.

LC - has padlock and chain to lock valve in closed position; LS has integrally mounted limit switches to provide position indication in control room blind flange is attached to BF piping on side of valve away from ECCS process piping 1-1/2" and smaller.

SPECIAL VALVE NO. QTY. SIZE TYPE FEATURE LOCATION NOTES Rli R-V-7 GATE LC Flush supply to loop A suet ion RIIR V-1 8r Ar Br C Gate LO RHR pump minimum flow.

RIIR V 63r Ar Br C Gate LC Flush supply to shut-down cooling loop.

Rl) R- V-67 Gate LC RHR loop C crosstie ~

Rli R-V-70 Gate LC SHRr HPCS 5 LPCS to drain to radwaste.

RIIR V 71 Ar Br C 3 Gate LC RHR pump suction drain.

RHR-V:72 Ar 0 2 Gate LC RHR pump discharge drain.

RHR-V-82 1 Gate Mater leg pump suction 6 isolation.

RIIR-V-85r Ar Br C 1-1/2 Stop Check Water leg pump discharge 6 to RHR pump discharge line.

RIIR-V-86 Gate LC Flush supply to reactor head spray.

RHR-V-104 10 Globe LC Intertie to Fuel Pool Cooling system.

RHR-V-106 Gate LC F lush supply to RHR Pump C suction.

RIIR-V-109 18 Gate LC RHR pump c suction from condensate system.

RIIR-V-110 Ar Br C 18 Gate LO RHR pump discharge isolation.

RHR V 111 Ar Br C 14 Gate LOr LS LPCI line at RPV 1 Rl<R V 11.2 Ar 8 12 Gate LOr LS Shutdown cooling injection RI(R-V-113 20 Gate LOr LS Shutdown cooli-ng suction RHR-V-114 3 Gate LC RHR pump c discharge drain.

RHR-V-121 3 Gate LC Radwaste sump pump intertie to suppression pool.

RHR V 130 Ar 8 3 Globe BF Spray ring header test connection.

RHR-V-170 1-1/2 Gate LO Drain Pot outlet

WNP-2 Q. 211. 078 (6;3)

Recent experience at an operating plant identified a potentiaL for a common mode f Looding of ECCS equipment rooms. The problem involved the equipment drain Lines. (Refer to IE Circular No. 78-06'ay 30'978 which is attached to this encLosure). Verify that the specific design of the WNP-2 floor and equipment drains is such that fLooding in any one room or locations wiLL not result in flooding of redundant ECCS equipment in other rooms. In responding to this items cross-reference your response to Item 010.28.

Response

Cross connection of ECCS pump rooms from the Reactor BuiLding equipment drain system (Figure 9.3-5) is not possible. The equipment drain from RHR pump rooms A and B are capped. The equipment drains in the other ECCS pump rooms are directed to the floor drains.

As described in the response to Question 010.28'he Reactor Building floor drain system is served by four sumps. Each sump serves up to two roomsr with an isolation valve in the interconnec'ting piping. The isolation vaLve is not Seismic Category 1 or' lass 1Er but using the acceptanc criteria of Standard Review PLan 3.6.1i the fLoor drain system design is acceptable. Our conclusion is based on our ability to bring the reactor to cold shutdown after a pipe break outside containment and assuming single active failures. Assuming a failure of the isolation valve while flooding one room could flood the 'interconnected room. However4 there is still adequate essential equipment not affected by the f Looding to shut down the reactor.

For'onditions where credit cannot be taken for non"Sei sm'ic Category 1 or non-class 1E equipmentr i.e. post-LOCAL no credit is taken for the isolation valves in the cross-connecting f Loor drain piping. CLass 1E leak detection devices in each ECCS pump room will give the operator at Least 44 hours5.092593e-4 days <br />0.0122 hours <br />7.275132e-5 weeks <br />1.6742e-5 months <br /> to identify and isolate passive failures in the ECCS post-LOCA before the flooding has any additionaL adverse effects on another ECCS pump or on the available HPSH from the suppression pool. See the response to Question 212.003 for justification of the available operator act ion t ime.

WNP-2 Q. 211. 079 (6.3)

The discussion in 6.3.2.2.5 of the FSAR regarding the filL system you propose to prevent water hammer resulting from empty discharge Lines in the residuaL heat removaL (RHR) system and in the ECCSr is inaddquate. Since there have been about fifteen damaging events due to water hammer that resulted from empty discharge Lines of the core'pray and RHR systemsr incLuding their associated instrumentation and alarmsi to minimize water hammer. Accord inglyr respond to the foLLowing matters:

a ~ Provide a detailed description of the fill systems including the associated instrumentation and alarmsr with appropriate references to process and instrumenta-t ion drawings (PSID '.)

b. Level transmitters apparently are not used to detect trapped air bubbles upstream of injection valves. A pressure Level read downstream of a pump discharge check valves which is greater than the gravity head correspond-ing to the highest point in the systems does not necessarily indicate the absence of trapped air pockets. Accordinglyi indicate what provisions you have made to avoid trapping of air pockets in the Lines. In your responser incLude a dis" cussion of the effect of Leaking valves in bypass test Lines.

c- If required maintenance on a particular Loop (e.g.r the RHR system) necessitates draining of this Loopi indicate how the fiLL system protects the other Loop and systems; e.g.r the containment spray (CS) system.

d- Indicate the surveiLLance testing which wiLL be required to demonstrate that the fiLL system instrumentation is capable of performing its function.

e. Indicate how surveillance tests wiLL be made to determine if the discharge Lines for the RHR and CS systems are fulL as wiLL be required in the WNP-2 TechnicaL Specifications.

Assuming the jockey pump system does not maintain full Linesi water hammer could occur during surveiLLance tests of the RHR and CS pumps. If damage occurred due to water hammers the event would be reported in a Licensing event report (LER).

Howevers if spec iaL fiLL and vent procedures were used prior to these tests'ater hammer would not occur and any inadequa-cies of the jockey pump system might not be evident. Accord" inglyi discuss: (1) your procedures for surveiLLance tests invoLving startup of RHR and CS pumps; and (2) your reporting procedures if special filling and venting procedures are used and indicate partiaLLy empty Lines.

WNP-2

Response

a 0 Each of the three ECCS divisions and the RCIC system has a separate water Leg pump system powered from essentiaL power of the same division and remote manuaLLy operabLe from the controL room. The four water Leg pump systems are shown on the following drawings:

RHR Loops B 5 Ci water Leg pump RHR-L"3 (Division 2) 3.2-6 RHR Loop A and LPCSi water Leg pump LPCS-P-2 (Division 1) 3 2 7 HPCSi water Leg pump HPCS-P-3 (Division 3) 3 2 7 RCICr water Leg pump RCIC-P-3 (Divi sion 1) 3.2-8 Each water Leg pump motor is provided with indicating

'ights in th'e main control room to aLLow the operators to monitor that the motor is energized. In additions each ECCS Loop has a Low pressure alarm in the controL room which wiLL a lart the operator that the Loop is not pressurized. These alarms are:

E12-N022A RHR Loop A 80 psig 3.2-6 E12-N022B RHR Loop B 80 psig 3.2-6 E12"N022C RHR Loop C 80 psig 3.2-6 E21-N005 LPCS 40 psig 3.2-7 E22-N013 HPCS 50 psig 3%27 E51-N034 RCIC 60 psig 3.2-8

b. The water Leg pumps maintain the ECCS Loops pressurized.

Any Leakagei except as noted below's out of the Loops and is made up by the water Leg pumps. Leakage across the valves on the injection Lines is from the reactor pressure vesseL into the ECCS Loop; howevers this Leakage consists of water.

Gases in the ECCS Loops are expected as a result of corrosion and temper ature changes. The surveiLLance testing di scussed below in dr e~ and f wil L ensure that no signif icant gas accumulation occurs.

c ~ Division 1 and 2 water Leg pump systems each maintain two ECCS Loops filled. (See part a. above). They take a suction on the LPCS pump suction and RHR Loop C pump suctioni respectively. Naintenance on the LPCS or RHR Loop C can disable the respective water leg pump system; howevers no more than one ECCS division is affected.

WNP-2 Naintenance on RHR Loop A or B does not disable the..water Leg system since these Loops can be isoLated from their respective water Leg pump system by a stop check valve.

Thus'he other Loop is not affected.

d. Every 31 days as part of the surveillance testing programs each of the "keepfiLLed" pressure instruments wiLL be tested to verify that each alarms at its Low pressure set points (see part "a" for List of alarms and set points).

Every 18 monthsr the "keepfiLled" pressure instrumentation wiLL be reca librated.

e. SurveiLLance testing verifying fuLL RHRr HPCS and LPCS pump discharge Lines wilL be performed every 31 days by manuaLLy opening the high point vents in each system to verify there is no trapped air in the system.

f- Prior to startup of the HPCSr LPCS and RHR pumps during surveilLance testings the pump discharge Lines are verified as being fuLL be venting the systems high point vents-If the discharge Lines are found to contain of air or gases the system wiLL be refiLLed and the significant'mounts as"found condition reported per technicaL specification surveiLlance test non-conformance procedures. If manage-ment determines that the incident is a reportable licensing events it wiLL be reported in accordance with Regulatory Guide 1.16. No special f ilL procedure is requir ed'ince the jockey pumps for the systems run continuously to maintain the dis-charge Lines fuLL. It should be noted that the design of the fiLL system on WNP2 meets the same criteria as was documented as acceptable in the Zimmer Safety Evaluation Report (NUREG" 0528r P 7-9r 1 0)

~ ~

WNP-2 Q. 211.080 (6. 3)

It is our position .that the ECCS should be designed to provide sufficient capability to cool the reactor in the event of any single active or passive failure in the ECCS during the Long-term cooling phase foLLowing a postulated accident. Howevers you have not presented sufficient information in the FSAR to demonstrate that you satisfy our requirement with regard to passive failures. In particulars our position is that you should provide, leakage detection and appropriate aLarms which would: (1) alert the reactor operator in the event of passive ECCS failures during the Long"term cooling phase; and (2) allow the operator to identify and isolate the faulted ECCS Line. This sufficient'ime design feature should satisfy the requirements of IEEE Std 279-1971'xcept for the single failure requirements.

According lyi discuss the following considerations:

a. Indicate the assumed maximum Leak rate in the ECCSr including a justification for this value.

b. Indicate the maximum allowable time for corrective operator actions including a justification for this time interval.

co Demonstrate that your Leak detection system wiLL be sensitive enough to. (1) initiater by alarms operator action; (2) permit identification of the faulted Line; and (3) permit isolation of the Line prior to a Leak creating undesirable consequences su ch as f Looding of redundant equipment. Our position s that the minimum initiation time for operator action for this task is 30 minutes after the alarm.

d. "Demonstrate that your Leak detection system can identify the faulted ECCS train and that a Leak would be isolable.

You should determine the effects on the ECCS.of passive failures of such components as pump seals'alve seals'nd measuring devices. Your analysis should address the potentiaL for flooding caused by the ECCS and the potential for ECCS inoperability which could result from a depletion of the water inventory in the suppression pool Your analysis should include consideration of (1) the flow paths of the radioactive f luid through fLoor drains sump pump discharge pipingi and the auxiliary building; (2) the operation of the

WNP-2

~ aux lLla ry systems that would receive the rad i oactive. f luids; and (3) the ability of the Leakage detection system to detect a passive failure. Examine the auxil iary system piping in the vicinity of ECCS equipment and address the potenti al for f Looding from nonsafety-graade piping. (Refer to Atta chment 1 to this enclsoure).

Response

See response to Question 212.003'mendment 5r concerning Reactor Systems Branch Technical Positions Leak Detection Requirements for ECCS Passive Failures. Zt addresses the potentiaL for flooding caused by the ECCS and the potential for ECCS inoperability which could result from the depletion of the water inventory in the suppression pool. An examination of the auxiliary system piping in the vicinity of ECCS equipment and the potential for f Looding from nonsafety grade piping is addressed in the response to Questions 010.28 and 211;78.

r MNP-2 Q. 211.081 (6.3)

During the Long-term cooLing phase following a smaLL break LOCAr the reactor operator must control the primary system pressure to preclude overpressurization of the RPV,after it has been cooled down. Accordinglyi provide the foLLow" ing information:

a ~ Describe the instructions which the operator wiLL foLLow while performing Long-term cooling of the plant.

Indicate the time frame in which the operator wiLL perform the required actions. including justification for the timing of the operator's actions.

c ~ List the instrumentation and components needed to per-form this action and confirm that these components meet safety grade standards.

d. Di scuss, the pertinent safety concerns during thi s cooL-down period and indi cate the design margins avaiLable for each concern.

e. Provide plots of the temperatures pressurei and the water inventory in the reactor coolant system (RCS)i showing the important occurrences during this cooL" down period.

In your response account for the foLlowing events: (1) a Loss of offsite power; (2) an operator error:. or (3) a singLe fai Lure.

Response

During Long-term cooling foLLowing a smaLL LOCAL there are

'no operator actions required to control system pressure to preclude overpressurizing the pressure vessel after been cooled off. The system is aLways protected by relief it has valves wh'ich are more than adequate to handle decay heat energy generation. If the smaLL LOCA caused reactor vessel water Level to drop to Level 3 or resulted in sufficient drywelL pressurizationr then the plant would automatically scram. If water Level drops to Level 2r then HPCS would come on automaticaLly and re-establish water Level for the

WNP-2 postulated smaLL LOCAL and would automaticaLly controL water Level to provide adequate core cooling. If the small LOCA had caused sufficientLy high dryweLL pressure and the water Level decreased to Level 1r then ADS would automatically come on to depressurize the vesseL and all remaining ECCS systems would automatically initiate to re-establish water Level.

The ADS valves stay open once actuated. and are designed to stay open for at Least 100 days thereby precluding any sig-nificant repressurizing of the .reactor vesseL.

In response to particular portions of this questions we offer the following:

a. There are no operator actions required foLLowing a smaLL LOCA to precLude overpressurizing the pressure vessel after it has been cooled off. Operator actions to establish Long-term cooling are discussed in 6.2.2.2 and 6.2.2.3.

b. No operator actions are required.

c. No operator actions are required.

d. Limiting safety concerns are addressed in 6.2i Contain-ment Barrier Integrity; 6.3r Peak Cladding Temperature; and Chapter 15> Radiological Releases. The event is not a Limiting event for designing to assure the health and sa fety of the publi c.

e. System characteristics for the more severe design basis

~

events are shown in 6.2 and 6.3.

The above discussion accounts for:

(1) Loss of Offsite Power (2) Operator Error or Single Failure

WNP-2 Q. 211.082 (6.3)

Demonstrate that for all sizes of breaks in a recirculation Loop or in ECCS Lines which would thereby require actuation of the ECCSr the reactor core is suf ficiently covered with water so that diversion of the LPCI system to wetweLL spray after 10 minutes is acceptable and that the ECCS systems are in compliance with the requirements of Criterion 35 of the General Design Criterion (GDC) and Section 5046 of 10 CFR Part 50. In your responser indicate what consideration you have given to the fuLL spectrum of potentiaL single failures and to potential break Locations. Confirm that no operator action affecting the performance of the ECCS is requir ed prior to 20 minutes after the initiation of the accident.

In particulars discuss the effects of the following matters on cooling of the reactor core and provide information to show that the requirements of GDC 35 and Section 50.46 of 10 CFR Part 50 are not violated.

Provide assurance that the system which diverts the LPCI f Low meets the single failure criterion so that diversion of the LPCI system Less than 10 minutes after a postulated accident ~ need not be considered.

b. Provide justification for the conclusion that a break in a ECCS Line is the most Limiting break Location when evaluating the effects of a postulated LOCA foL Lowed by diversion of the LPCI f Low.

c Provide a sensitivity study of the PCT as a function of break size for smaLL break LOCA'sr assuming LPCI diversion wiLL be initiated 10 minutes after the start of the accident. Perform this study for postu-Lated breaks in the ECCS and recirculation Lines.

For the most Limiting breaks provide the foLLowing figures'. (1) the water Level inside the shroud as a function of time folLowing the postulated LOCA; (2) the reactor vesse l pressure versus time; (3) the convective heat transfer coefficient versus time; (4) the peak clad temperature versus time; and (5) the ECCS fLow rate versus time

WNP-2

d. Provide assurance that LPCI diversion after 10 minutes wilL have Less severe consequences than diversion at 10 minutesi considering the appropriate break sizes for diversion at times greater than 10 minutes after the accident.-

e. Provide a'discussion which contrasts the need for LPCI diversion for the Limiting break size with the need for abundant core cooling required by GDC 35. For examples this discussion could consider the LikeLihood of LPCI diversion -for the Limiting break size.

Response

An analysis which shows acceptable results following diversion of LPCI 10 minutes after a break is pr ovided in the Zimme'r docket in response to their Question 212.072. The Zimmer analysis is typicaL o'f any BWR/5r as they have the same complement of ECCS systems- and is therefore applicable to WNP-2.

No operator action affecting the performance of the ECCS is required prior to 20 minutes after initiation of the accident. We have evaluated the consequences of no opera" tor action for 20 minutes in 'our response to Question 211.059 and conclude that the requirements of GDC 35 and 10 CFR 50.46 are met. The diversion of LPCI for wetweLL sprays is addressed in the response to Question 031.070.

Diversion is not anticipated to gabe required at alla. and certainly~)not "in the first 2Q minutes Bouhding studies indicate that over 167 minutes are available for the operator to take action after a smaLL break before dry-welL design pressure is exceededi assuming bypass Leakage five times that aLLowed per technical spec ification require-ments. Leakage rates smaLLer than this do not exceed dryweLL design pressure.

Specific parts of this question are answered as foLLows:

a. This question presumes that an automatic wetweLL spray system is provided. Howevers in our response to Question 031.070'e showed why automatic sprays are not needed for WNP-2. The Residual Heat Removal system~

which provides for diversion of LPCIr is safety-relatedr redundant and -powered from different divisions.

WNP-2

b. The HPCS Line break/LPCS dieseL-generator failure is the Limiting event. Justification is provided in the Zimmer analysi s.

c. The information requested on PCT is provided in Figures Q212.72-1 through Q212.72-5 of the Zimmer analysis. The information requested for the most Limiting break is provided in Figures Q212.72-6 through Q212.72-10 of the Zimmer analysis.

d. 'he information requested is provided in the Zimmer analysis.

e. The information requested is provided in the Zimmer ana lysi s.

WNP-2 Q. 211.083 (6;3)

Provide assurance that the fast closure of a recircu-Lation flow controL valve conincident with a LOCA is not

'e x e c.t e d t o occur .

p A l t e r n a t i v e L y i p r o v i d e the r e s u l t s of a sensitivity study which ev luates the effects .of a fast closure of a recirculation f Low valve conincident with the design basis LOCA and the worst postulated ECCS failure.

Response

Refer to our response to Q. 31.058 for a detailed discussion of why closure of the recirculation f Low control valve wiLL not occur.*

• Draft FSAR page change attached.

WNP-2 AMENDMENT NO. 3 l

MARCH 97 9 Page 3 of 3.

A complete system failure mode and effects analysis along with a more detailed system description are described in

~e4 "Appendix H" of the FSAR. shed~ ~

W~~ubmitted inthe-first-quarter of 19-'~

~ ~

031.058-3

WNP-2 Q. 211 . 084 (15.2)

Your proposed recLassification of the transients resulting from a generator trip and a turbine trip without bypass'rom a frequent to a infrequent event in Section 15.2.2.1.2.2 of the FSAR has not been accepted by us and is stiLL under generic review. Accordinglyr reanalyze the events cited above to determine the operational Limit on the minimum criticaL power ratio (NCPR) which would not violate the minimum safe valve of 1.06 for the NCPR. It is our position that the Limiting transient be reanalyzed with the ODYN code cited in Item 211.49 of this encLosure.

Response

See the response to Question 211.049.

HNP-2 Q. 211.085 (15.A)

Nodi fy your nuclear safety operationaL analysis (NSOA) drawings to show the nonsafety-gr ade equipment for which you take credit to mitigate transients and accidents.

Such equipment includes relief valvesi turbine bypass valvesi and a vesseL LeveL trip indicating high water in the RPV (i.e.r a Level 8 trip).

Response

Each transient and accident discussed in Chapter 15 corresponds to one protection sequence of an event in Appendix 15A. The NSOA drawings (protection sequences) are consistent with the ana lyticaL bases of 15A.3 and the measures of safety (unacceptable results) of 15A.2.7 and are primarily directed at system Level response requirements.*

Certain Chapter 15 events assumed'oLLowing the initiating single-failures the normal operation of some nonsafety-grade equipment functions; these instances are ident if iable f rom text. 'he Nuch discussion has occurred between the NRC and General ELectric concerning the use of nonsafety-grade equipment in analyzing transients. Table 211.85-1 summarizes the nonsafety"grade equipment which is utilized and gives approp" riate justification for taking credit for such equipment.

• Draft FSAR page changes attached.

Table 211.085-1 Identification of Nonsafety-Grade Equipment Assumed to Function in Chapter 15 Analyses Nonsafety-Grade System/Function

-Util'ized Transient(s) Involved Just if ication for Taking b Number .Credit in Feedwater Control System (High Rx Water Level 21r 22r 23r 27'0/ The L8 circuitrynis 2 out of 3 25r 31m 38r 29r Logic-with diverse power supplies Trip Logics L8) 11r 38r 39 13'2r such that a single Level switch (Ls) failure will not cause or prevent the trip function from occurring. The Tech. Spec.

surveillance committed to by the 211.086 response will provide assurance that the trip function will operate when required. This resolution was agreed upon by the NRC (GE-NRC meetings Nov. 20i21i 1978) and affirmed at the Zimmer ACRS hearings.

Turbine DEH (Bypass Valve System 11'2'3r 21'2' 23~ 25r 26'7/ 28r The DEH system i s funct ioning continuously at power which Operabi L i ty 29r 38'9 demonstrates its operability.

The Tech. Spec. surveillance committed to by the 211.086 response wiLL provide additional assurance that the BPVs themselves are functional. This resolution was agreed upon by the NRC (GE-NRC meetings No.v 20'1r L978) and affirmed at the Zimmer ACRS hearings.

Table 211.085-1 Identification of Nonsafety-Grade Equipment Assumed to Function in Chapter 15 Analyses Nonsafety-Gr ade System/Function Trans i ent (s) Involved Justification for Taking

Utilized b Number .Credit i Pressur e Relief (Power Actuated System Relief 8i 22'3'7/ 29r13r 30'1 12'4'6'0r 15'0r s For aL L transients ident ifi to actuate has no impact Node) 24'5'8'8r 44r 45'1r 52'3 39@ 40'2'3/

upon Core Thermal Limits (NCPR).

ed'failure Peak Rx pressure would be higher.

Howevers the vessel over-pressur-ization analysis is stiLL bounding.

See the response to 31.064. In additions NRC concerns in this area include the use of protection system inputs which are non-seismic category I or are Located in non-seismic cate-gory I structures (ier the Turbine Building). Responses on the LaSaLLe docket to NRC questions 212.55'12.61' 212 105'12 115r 212-129r and 212-144 address this issue in detaiL and are considered appLicable to WNP-2. Simil-arlyr conclusions from responses on the Zimmer docket'uestions 221.270 and 221.359 are considered applicable to WNP-2.

RCIC Initiation (Initial Core Cooling) 8r 21 s 13r 14'5r The RCIC system has been upgraded by the addition of a seismic 1 water 31'8'9'0'1r 20'2'3'4r supply via auto-transfer of the pump 25'6'7'8'9'0r 53 suction from the CST to the Suppres-sion Pool. The system has Long been covered by Tech. Spec. surveillance and now is as reliabLe as a fuLLy safety-grade system. This resolution was agreed upon by the NRC. (Zimmer SERr NUREG-0528r p 7 9)

Table 211.085-1 Identification of Nonsafety-Grade Equipment Assumed to Function in Chapter 1S Analyses Nonsafety-Grade System/Function Transient(s) Involved Just ification for Taking

Utilized b Number .Cr.edit i RSCS/RWN/RBN (Prevent improper 16'7'0 (impl i c it/passive) The RWN/RSCS are tems.

independent sys-Below 20% power the RWN/RSCS rod movement) work in tandem to prevent rod with-drawal errors. At these Lower power Levels the neutron monitoring system via the IRNs acts to scram the Rx and prevent fueL damage in the event of RWN/RSCS failure. Above 20% power the RBN (2 independent channels; 1 required to initiate a rod block) pro-vides protection from improper rod motion. In additions strict adminis-trative controls enforce approved rod withdrawal sequences. Only unautho-rizedr unsupervised rod movements should challenge the RBN system to function. See the response to NRC .

question 31.109 for further information.

Refueling Interlocks/RPS 16 Refueling operations are a period of (Prevent more than 1 rod strictly supervised actions. Rod withdrawal while in states motion is required only to confirm A 8 B) proper fuel ceLL Loading/CRD mode operation and -subcriticality. The refueL ing interlocks in addition to admini strative controls prevent more than 1 rod withdrawaL. Several Levels of super vision would have to be bypass-ed to produce a challenge to the re-fueling interlocks. The refueling interlock systems in addit ion+ provides two independent channels of interlock protection designed to fai L-safe phi Lo-sophy. See revised secton 7.7.1.13 for more deta i L.

EVENT 8 LOSS OF PLANT INSTRUMENT AIR SYSTEM STATES A, 8, C, 0 D

STATES A, 8, C,$ STATE 5,D P (48exe'g la VS Iss P ) 400 IDVS Psig

~

ek A/s (wig A i< ~'~)

PLANNED OP ERAT ION SCRAM SIGNAL HIGH PRESSURE WHEN 3 MAIN REACTOR LIFTS VALVE PRESSURE STEAM VALVES PROTECTION TRANSF ERRING RELIEF CLOSED ) 10%

SYSTEM HEAT TO SUP-PRESSION POOL SYSTEM S F INSERT CONTROL ROD INCIDENT START HPCS AND HCIC, PRESSURE CONTROL DETECTION RODS DRIVE SYSTEM ON LOW WATER LEVEL RELIEF CIRCUITRY S F RCICS MAINTAINWATER LEVEL HPCS CORE COOLING FIGURE WASHINGTON PUBLIC POWER SUPPLY SYSTEM PROTECTION SEQUENCE FOR LOSS OF PLANT INSTRUMENT/SERVICE AIR SYSTEM 15.A.6 NUCLEAR PROJECT NO. 2, 8 I

~VI O AECIRCVLA'TIONLOOt FLOW CONTROL I f*ILVRE DECAEASING m STATES C AND O I ONEITWO VALVE FAST CLOSVAE OA M OHE/TWO VALVEFAST CLOSURE A STATE 0 ONLY ONEIMASTEA CONTROLLER FAILURE OA ONEIMASTEA CONTROLLER FAILURE STATES C AND D O

m o AFTER ISOLATION m ~ o ~ ~ oooooot INITIATE ISOLATION ON COHTAINMENT

~ AESSURE REACTOR f SCAAM SIGNAL ROM INCIDENT START NPCS ANO REACTOR LOWWATEA LEVEL

~

Q RELIEF PROTECT IOH l. TURSINE STOP VALVECLOSVAE DETECTIOH SYSTEM ON VESSEL I$OLATIOH SYSTEM SYSTEM CIRCUITRY LOW WATER CONTR OI.

~ FO I 8 ~

LEVEL SYSTEM C/l

$ f $ f u ~

$ F I/4 oo ~

PRESSURE CONTROL ROO MAIN STEAM RELIEF DRIVE SYSTEM INSERT CONTROL RODS LUIS ISOLATKNI RPCS 7 ~ VALVES OI

$ F $

I F

,OO S F ITI OO O+ REACTOR VESSEL

~

HO M tlANNED OPERATION INITIAL CGA E ISOLATION XI R COOLING I I/I ITl

~AD RNAS SuttRESSION M ITT POOL COOLING I RNRS NEAT EXCNANOER I AHRS PVIIP I MODE C:A oCI ITl t I STAN44Y SERYICC VATES tUNP ITI S f SUPPRESSION POOL TEMPERATURE LIMIT I L OO ITl W MANUAL START OEtRESSVAIZATION RELIEF VALVES TTl ITl WA I/I M RA

0) C=

MAINTAINWATER LEVEL IN Rf ACTOR LPCS LPCI I VESSEL t F

lD I EXTENDEOCORE O COOI.ING C)

D

~ Ul Ml~

~m I

EVENT 13 RECIRCULATION LOOP PUMP TRIP ONE OR BOTH

~

STATES C ANQ 0 ONE PUMP TRIP DhfO PUMP TRIP SACF STATE C STATE 0 TWO ONE PUMP TRIP PUMP TRI'P PLANNEO OPF RATION ONF. PUMP TRIP PRESSURE HEAT TO RELIEF SUPPRESSION SYSTEM POOL CON T Al N ME N T ANQ REACTOR VESSEL REACTOR SCRAM SIGNAL HIGH WATER PROTECTION TURBINE TRIP LEVEL ISOI.ATION SYSTEM CONTROL SYSTE M PRESSURE RELIEF MAINSTFAM CONTROL ROO INSERT INCIOENT LINE ISOLATION CONTROL DETECTION START HPCS, RCIC DRIVE SYSTEM ON LOWWATER LEVEL VALVES ROOS CIRCUITRY F

S F REACTOR VESSEL SCRAM RCICS MAINTAIN HPCS ISOLATION WATER LEVEL S F INITIAL.

CORE COOLING PROTECTION SEQUENCE FOR RECT RCUZATrON LOOP NUCLEAR PROJECT NO. 2 PUMP TRIP - ONE, OR BOTH

EVENT 14 ISOLATION OF ALL MAIN STEAM LINES STATES C, I)

STATES C AND O Il (~

STATL C TSIII STATE 0 PLANNED OPERATII)N P ) PSIESNI ZOVS OA T HIGH PRCSSURE REACTOR SCRAM SIGNAL WHEN PRESSURE LIFTS VALVE PROTECTION 3 MAIN . TEAM F RELIEF TRANSFERRING SYSTEM VALVES CLOSED>>O'X SYSTEM HEAT TO SUP PRESSION POOL S F PRESSURE RELIEF CONTROL ROO INSERT CONTROL DRIVE SYSTEM RODS S F INCIDENT START HPCS, RCIC, DETECTION CIRCUITRY ON LOW WATER LEVEL S F RCICS MAINTAINWATER LEVEL HPCS' F

INITIAL CORE COOLING WASHINGTON PUBLIC POWER SUPPLY SYSTEM FIGURE PROTECTION SEQUENCE FOR ISOLATION OF NUCLEAR PROJECT NO. 2 ALL HAIN STEAH LINES 15.A.6 14a

/

EVENT 14 ISOLATION OF ONE MAIN STEAM LINE STATES C, AND 0 STATES C AND 0 STATES C AND D

~

LESS THAN A$5 POWER E/O OVER A56 POWER CONTINUE PLANNED NEUTRON OPERATION HIGH NEUTRON MONITORING FLUX SIGNAL SYSTEM S F SCRAM SIGNAL REACTOR ON NEUTRON PROTECTION MONITORING SYSTEM SYSTEM TRIP S F INSERT CONTROL ROD CONTROL RODS DRIVE SYSTEM WASHINGTON PUBLIC POWER SUPPLY SYSTEM PROTECTION SEQUENCE FOR ISOLATION OF ONE FIGURE MAIN STEAM LINE 15.A. 6-NUCLEAR PROJECT NO. 2 14b

~VHT I IHAOVIR'ItHf OttHIHOOf A5Af5 TY/RELIEt VALVt STATE5A.OCO SIA114A.O.C 51Aft 0 HO f t EOWATER STATE D I.

IHITIAlt5CRAM ON IHC H COH TA IHU1 N 1 START HPCSI LPCI ANO MISSURE TAUTOUATIC TRANSf ER MAIN$ 1 5 AM REACTOR f1 tOHATtR tLON NUCLEAR SYSTEM WCIDENT LI'CS OH RTSKCTIVT.

It BIO C 1 ICW CON BIOL. 51*T 5 Ol

~ RESSVRE RELItt DECAY NEAT 10 OtftCTION TRIP SET TIHCSa STAllf AOS LWE RADIATION 5Y5TtM SYSTEM CIRCUITRY MONITON IHO TUIM5 55 ION (AUTOMATIC ILEOTIAISR 2.

WITIATETCRAM ON LOW WATER LEVEL IDOL r flOw COHTRCL ~ STATE OI SYSIIU 5 I CONT AIHUINT CONfROL ROO W St RT CONTROL MESSVRE RELltt I AHO R AC ICR DRIVE SYSTEM RODS MAINTAW Vttlttl50LA TIOH CONTROL YIATER CONTAINMENT LEVfL AND REACTOR 5YSIIM 5 ~ VttftLISOLATION 5 I CONTROL $ 1511 M 5 I OOH I A WU I H f O'A55IVII MAW STEAM LtCI LINE IIOLATIOH VALVES 5 I ESIAOLISN CON I A WMIHl tl AHRI IIUYERAIIOH 5 I t

R 5 ACTOR V 55$ L l$0L*TIOH WITIATt CL05URE Of ALL WITIALCOAT CONT A I MME H1 l50L*IIOH COOI, INC VALVES EXCttf MAINSTEAM LINC ONHICNCONTAIHUENI MESSVRt RWISOVttRE5$

tOOL COOL INC MOOS MICS A05ACTUATEO ACIUATEO SUAMESSIOH TOOL TtMttRATVRt ~ IMIT lfftH,START OEMESSVRIIATION MANUAL RELIES VALVE OttRATIOH I 5 LtCI 5 I MAIWU*LR\

LIEr VALVE OttRAINW 5 f EXTENDED CORE COOLINO WASHINGTON PUBLIC POWER SUPPLY SYSTEM PROTECTION SEQUENCE FOR INADYERTENT OPENING FIGURE OF A RELIEF OR SAFETY VALYE 15.A.6-NUCLEAR PROJECT NO. 2 15

l Mt 5tVA(

~VN f LVSSOS ALL Sf ldwaNA I ldw 5 I A N 5 C ANO 0 STAI I 0 STATt5C.0 ONL T

~ ( 155 tee aYATISC.O SO Illtao INI I IA N INIIIAIC TIIANSICA IAINUINI MCSSVAt

, Al AL'ION 5(AAU avd AIACION UAAISTCAU Lwft I IOLAI ION A(LIIS OCCAY I CAT fd SAOIIOI Idal ON Ldw t55(L I$0LAIION 5151tU KANNCOOSCAATION 5T51(U wA N N VN LOW TVSMCSSION SNVTOOYW COOLWO IAOL $ 15tlta LlylI wAICALCVCL KOL INCIOCNT 51AAI NK$

OI 1(CTION dv ldwwaf CA L(Vll 5 I $ I 5 S CIA(VIIAY w5(AI VAIN Sf(AU S F OONTAOL AOO LWI IVVV(SYSICU CON IAOL AOOS l

150 A f af N YALvls ACLIC I 5 I UAWTAWwaf(A l(V(l ACtdt KAAU Atad'IOA V(55(l 150( A I ION 5

WITIAL CON (

COOL INO ANAS SuttA(5QON ~ ~ <<ao ~ Caf I A%as tvvt lf(vavlto OOL COOL I ofaaoor ltawct va

~

tvd Uddl I ~ tvvt 5VSMtl(IONSOOL Ilvt(AAIVAI LIVIT IXVt.Stoat OftA(SSVAITAIION UANVAL ACLICS VALVC (NATION (p)

I UA IVIA W wAI A I 1 yl IN A(al 'NW ~ TTISL l

5 Ltdl 5 I IANNOIO COAI COdE Wd WASHINGTON PUBLIC POWER SUPPLY SYSTEM PROTECTION SEQUENCE FOR LOSS OF FIGURE NUCLEAR PROJECT NO. 2 FEEDl<ATER FLOW 15.A;6 20

EVENT 22 O FEEDWATEN l CONTROLLER FAILURE

-MAXIMUMDEMAND

~ Q STATES C, D,A,AND B M

O STATES A AND 8 O

m O STATE D STATES C AND 0 m

OTHER OPEilATING STATE D C/l MODES "RUN" MODE O

~

PRIMARY CON-Q INCIDENT TAINMENTAND

~ M ga DETECTION REACTOR VESSEL CIRCUITRY ISOLATION CON.

C/l TROL SYSTFM EA NEUTRON HIGH FLUX C/l SCRAM S F Ill MONITORING SYSTEM SIGNAL

{IRM)

PRESSURE MAIN STEAM S F REuEF HPCS RCICS LINE ISOLATION A

OR0 SYSTEM VALVE RO

~m O

S F S F f M g SCRAM SIGNAL mo MAIN REACTOR FROM TURBINE TRIP TURBINE PROTECTION IRUN MODE) OR INITIAL REACTOR VESSEL wm MAO TRIP SYSTEM NEUTRON MONITORING CORE COOLING PRESSURE RELIEF. ISOLATION I

cm C S F SYSTEM m A m

S F I

ZO INSERT OC RECIRCULATION CONTROL ROD M ll, PUMP CONTROL DRIVE SYSTEM Mm c:m TRIP (RPT) RODS CC7 W F S F Mm S F CJ PLANNED REACTIVITY OPERATION CONTROL Ul M Cll m

r ~

R O O EVENT 23 I

m PRESSURE REGULATOR I FAILURE OPEN

~ O STATES C . AND D O

m O n STATE D ONLY

~

cQ C/l SCRAM SIGNAL FROM

~ ~ I ~ MAIN STEAM LINE INITIATE ISOLATION ISOLATION ON C/1 ~ TURBINE TRIP CONTAINMENT 1. DEPRESSURI ~

PRESSURE REACTOR )RUN MODE POWER INCIDENT START HPCS, 2AT ION TO 850 PIICI C/l AND REACTOR RELIEF PROTECTION 3060%) DETECTION RCIC ON LOW {RUN MODE m WATER LEVEL VESSEL ISOLATION SYSTEM SYSTEM ~ HIGH PRESSURE CIRCUITRY POWER 0.100%)-

CONT)COL SYSTEM

)RUN MODE: 2. LOWWATER LEVEL POWER I 540%) (OTHER THAN S F ~ LOW WATER LEVEL S F RUN MODE; tOTHER THAN POWER 0-10%)

RUN MODE: POWER 0-1096)

O

~m mq CONTROI MAINTAIN MAINSTEAM c Ow I

PRESSURE RELIEF ROD DRIVE HPCS CORE COOLING RCICS LINE ISOLATION VALVES SYSTEM O I/1 S F INSERT

~m M+ CONTROL RODS rn cm S F m~ O I

INITIAL REACTOR O Q SCRAM CORE VESSEL mmDm COOLING ISOLATION M C/l PLANNED OPERATION:

RE ESTABLISH COOLING VIA MAIN CONDENSER Vl ~

~p ac KI Cll m I

EVENT 24) CIEIA 5 INST tA 5 SSV A E AORUlkWFR FAILURE CLOSEO STATES C ANOO SECONO PAE$ 5UAE REGULATOR OPERATE FAILVAC STATE 0 HIGH FLUX tRI M ART INCIOENT CONTAINMCNT tRCSSVAE OETECTION NEUTRON ANO REACTOR ACLIEF MONITORING V 5 SEE I. ISOLATION SYSTEM CIRCUITRY START ON SYSTEM CONTAOL SYSTCM LOW WATS R AC ICE 5 F LEVEL MAINTAIN 5 5 F CORE COOLING AEACTOA MAINSTEAM LINE tROTCCTION l5OLATIONVALVES tRC$ $ VAC SYSTEM AELIEF 5 F PLANNEO 5 OPERATION 5 CONTAOL ROO OAIVE REACTOR VE5$ EL SYSTEM ISOLATION INITIAL 5 F CORE COOLING SCRAM A HAS I RHRS Hl.'AT SVttAESSION CXCHANCEIE tOOL IA;IRS tUHP MOO E ISTANCOT SCAV ICE WAIEN PUVP PCOOL INC SV ttAE SCION tOOL

'TCMtERATVAE LIMI'T STARCW'EtRESSUAIZATION MANUAL AV OPERATION MAINTAINWATER IN A CACTOR VESSEL HtC5 t 5 PCI 5 F EXTENOEO CORE COOLHIG WASHINGTON PUBLIC POWER SUPPLY SYSTEM PROTECTION SEQUENCE FOR FIGURE FAILURE-CLOSED PRESSURE'EGULA'TOR G.A.6-NUCLEAR PROJECT NO. 2 '24

C R

cA EVENT 25 4Oatsa~aa b

I TRIP WITH BYPASS STATE D I

O O

m

~m o~ (POWER

)

POWER 30%

m eCA 3M'YPASS

~ FO I INCIDENT MAIN STEAM SYSTEM DETECTION LINE V) OPERATES ISOLATION CIRCUITRY C/l VALVE m 3 F RCIC Ci MB gm MAIN REACTOR S F

+

mo M TURBINE PAOT ECTION SYSTEM SCRAM SIGNALS:

FOR TURBINE TRIP TRIP. TURBINE

~ Vl (

S F S F CONTROL VALVE FAST CLOSURE PRESSURE RELIEF DAD SYSTEM Mm MZ AECIRCULATION CONTROL HA xm PUMP AOO DAIVE INSERT CONTROL RODS S F TRIP IRPT) SYSTEM

'Il

<O CQ S F S F S F PLANNED OPERATION REACTIVITY INITIAL PRESSURE CONTAINMENT RESUME POWER -CORE CONTROL RELIEF ISO LATI 0 N OPERATION OR COOLING 4 CHI EVE SHUTDOWN

--UlMl X7 Qlm I

'4 TV~TNT f MAINCOIIOTN$ $ A V*CUIW 5TA'IlsCANOO SIAIl OLWLV srafls c Alto o MAIN IUIICWt tata WCtclNT Ol TICIION LINCVITAV f

$ AIIT ~ IICIC IW LONNAICIILSVCL MT SSUAt Ittl Ill 5VSTSM IAkNSIIA OICAV Nlkf IO Sutta 5ION IOOL ls MAINSflAU MNl IIOLAINW VALVl5 S F AlctACULaf tlW MAINfAIM Ml$5UNt

~ ULV CUA 5 IVC$ AlLIlt tcavlcs

'I N tt COOLINC I

5 I alcvl IO'tell<A 5

$ $ IOtt stt IONIA Nl U f Nl W tttl' INITIAL MUttlI IWMal ~ tlUIN(W COAI COOI tNO STSIIM IIUI CONIAINUINT tIOI*fION AIIAS $ Uat tooL I ANASNIA~ tscaaacta

<xtoLINOMoot I was ~ twt I afaakkf stAVICC NaTta tttlt at at:IOII 5CA AM 5ICNAL ON t Mat ICINW I N lUTAON MON TOA

'TAttOA STSIIM SV5flM TUttftttl 5TOt VALVlCLO5UAl SUtta I $ 5 a w tOOL TSMtlAAIUttlI IMtf 5TAIIIUtMISSUAICATION IAININOLNl N ~ WST AT IWIVC $ 1'III M f CON AOL IIOOS 5 t At kt. I tV I I V MAIIITAW CON INOI I ACI IVC$ L tel vlaftA Llvll.

tat tNUIO COAI COOLWO WASHINGTON PUBLIC POWER SUPPLY SYSTEM PROTECTION SEqUENCE FOR LOSS OF FIGURE MAIN CONDENSER VACUUM 15.A.6-NUCLEAR PROJECT NO. 2 ,26

t C/I EVENT 21 O GENERATOA TRIP A

I WITH BYPASS STATE D g

~ X7 C

O O

POWER g 30% )

POWEA 30%

m O n m

~

g BYPASS INCIDENT MAIN STEAM

~ M I SYSTEM DETECTION LINE OPERATES CIRCUITRY ISOLATION C/l VALVE C

C/l 5 F Cll HPCS RCIC tl mm MAIN Pl M TURBINE AEACTOR PROTECTION SCRAM SIGNALS:

TRIP SYSTEM FOR GENERATOA OM IGENERATOR) TRIP. TUABINE

>O S F S F CONTROL VALVE PRESSURE FASTCLOSURE AELIEF

~

M C/I

~ SYSTEM PCRVICS Cl AD AECIACULATION CONTROL INSERT Mm

.M +

PUMP ROD DRIVE SYSTEM CONTROL RODS S F TRIP IAPTI HO M Pl S F S F CQ Tl KO am S F AEACTIVITY INITIAL CONTAINMENT PLANNED OPERATION CORE PRESSURE RESUME POWER CONTROL RELIEF ISOLATION COOLING OPERATION OR ACHIEVE SHUTDOWN

C/T EVE NT 2$

LOSS OF NORMAL ACPOWEA AUXIL.

lAAYTRANSP OIUIER FAllURE TATESC*NOD O

l m STATE D QO sV y.co M f STAIE SC,D

~$ PIG O REACTOA INITIATE SCRAM

~ AIMAAY CON1A INMENT NATIAIE MAINSTEAM tAESSVRE TRANSF A DECAY O PROTECTION ON LOW f ANO A ACTOR UNf ISOLA.

I IION OH OW Rf LIEF HEAT TO f ~PC 7$p O SYSTEM WATER VESSf L IQ)LATION WAIEAIfVfl SYS1f M SUPPA SS ION om + m LEVEL CONTAOL SY$ 1EM S F S F

~ OOL f

~ LAIIN D OtERAT IOtl.

SHVTDOWN COOllNG XJ ItlCIOENT EJS O START HPCS ON IOWWA'IEALETEL DETECTION CIACVITAY

~

g

'CS CONTAOL ROO INSERT CONTROL MAIN$ 1EAM llNE PRESSVAE AELIEF STAAT ON LOWWATEA RCICS ISOlATIOH VALVE

~ M DRIVE SYSTEM RODS lEVE L MAINTAIN CORE COOLING C/T C S F REACTOR VESSEL CONTAINMENT ISOLATION ISOLATION IIIITIARA CORE COOLING Tla POX CT cpm l RH ~ IAltl TAURINE 4 IIRS Mf TAIS f SVPPA SSI OH f I RltAS IIEAT XCHAHGfA POOL I PI FIS PUMP I STANDBY SEANCE WAI OI PlAIP pCCOLIHG MODE OO RECIRCULATION SVPPRf SSIOH POOl PVMt O C/T TRIP IEMPfAATIAIEINAT$ 1AAT DEFOE SSVRI1*ION Wm IRtTI mAD m SF O S F MANUAL xm C

g J,I8 RATION AOS MMNTAPIWATEALEVEL tH RfACTOR VESSEl iI-I O REACTIVITY CONTROL

<C LtCI LPC O p W C/T fXTENDE0 COllf COOLING

(VINS Tv LOSCTP NsTAMAL Cl AC FDAI A CAID CDWs(CION 1055 O 51 AT(5 A ~ CSI l SIAT(5 ~ AND D 5'I A II 5 C AN 0 0 m ALL5 I Alt t A7 ~ NITIATI5CAAM tSTATCSC.O

( IILSss STATCSC.O th IIIws f MAIN AIACTDA ON l05$ Of Ilt5 IA(SMSAC INAN5SCSID(CAV M TVASSN( FAOI(CION I IAO 5t 5 DA AC(sCf ~ CAT TOSvt.

A WAlt 5151ts TVsscwt Isst SV51(M FA($ ON tOOL

~ LASSN(00t(AA'TON O S 5 f 5 I SSSVT DOW N COOt INC sNCIOCII I STINT SeCSIACSC le O DC'ICCTON CIACVITAT ~ S LSSVAIlS LtvlL Cl m ts($ SVSIC X7 STAssDSI ACCsACIAATON CONT AOL ADO Nsl(AT ll(LSIS 5 f AC IONIA ~ VMt DSISVI SVSTCM COsst AOL II005 SYSTCM 1 Slit IAt'll 4 g 5 5 D 5 MAWTANI

~ M 5 CONC COOL WO

. C/l ACSI VIIC AtACIIYITY 5 C/l AC ION(A CON TAOL CTl WIIIAL CONC COOlWO MAW STCAM (INC AIIAS- I NYAS scAT tscscsc(A IVSts(SSON I Ssl ~ 5 tVSt O ISO(ATOM VAlVC FOOL COOlWO IKIOC

~ STANDST 'SCAVICC SATCS tSSS A CTl 5 5 F cuffs(SSIDN tOOl Tt NSC AATVAt t TAAt0(SACSSVAICATON KO CTl M ~ C 5 VICS I C/5 W CTl 5 f MINNAL M( A(lICS VALVC Ot(AA'ION Q ftl P OA O Cll STATC5 A. ~ 5 F Z OTl CTl 5 I 5 A(SCION I A III Mt NI MP VCSSCL CON OO SO LA TON SSOLAIIOS ~

I OOTl C/T 5 S MAWTAIN COAC COOlWO O txttssDCO COAC COO(INC

EVENT30 O GENERATOR TRIP WITHOLITBYPASS I STATE D Cll M

O O (POWER SONIC )POWER 3BIC m O C

O m V)

O

~

Q INCIDENT MAINSTEAM g DETECTION LINE BYPASS FAILURE ISOLATION CIRCUITRY CA VALVE Cll 2 SCRAM SIGNALS:

L HIGH PRESSURE

2. HIGH F LUX RCIC REACTOR PROTECTION SYSTEM

~Q Pl MAIN AEACTOR B F TURBINE PROTECTION SCRAM SIGNALS: ~

gM TRIP SYSTEM FOR GENERATOR I Z TRIP. TURBINE CONTROL VALVE PRESSURE

~

Mm CA S F S F FASTCLOSURE RELIEF PCRVICS WAD SYSTEM XC CONTROL AECIRCULATION CONTAOL INSERT ROD DAIVE PUMP ROD DRIVE F SYSTEM TAIP IRPTI CONTROL ADDS SYSTEM m~ S F S F S F Vl M S F

-I REACTIVITY INITIAL SCRAM CORE PRESSURE CONTAINMENT CONTROL RELIEF ISOLATION COOLING

EVENT 31 O

A I

MAINTURBINE TAIP WITHOUT BYPASS m ~ STATE D CD M

O O POWER POWER Pl (30% P 30%

m MAIN STEAM

~ PD I INCIDENT LINE DETECTION LSOLATION BYPASS FAILURE CIRCUITAY CA VALVE Vl S F m

HPCS ACIC W a ns g-I I Pl KA M+ MAIN REACTOR SCRAM SIGNALS PAOT ECTION FOR TURBINE XO OR TURBINE TRIP SYSTEM TRIP, TUFI BINE VALVE STOP

~ Cjl m S F CLOSURE PRESSURE RELIEF PCRVICS CD AD SYSTEM RECIRCULATION CONTROL Li) O PUMP ROD DAIVE INSERT CONTROL RODS S F TRIP IRPTI SYSTEM S F S

F'D IN ITIAI. PAESSUAE CONTAINMENT REACTIVITY CORE CONTROL AELIEF ISOLATION COOLING m

EVEN~/

RECIRCULATION LOOP PUMP SEIZURE STATE D ONLY P

INCIDENT HIGH REACTOR INCIDENT, LOW WATER PRE SSURE DETECTION VESSEL WATER OETE CTION LEVEL RELIEF CIRCUITRY LEVEL CIRCUITRY SYSTEM S F PRESSURE SCRAM SIGNAL RELIEF REACTOR PROTECTION FROM SYSTEM TUBS INE TRIP S RCICS MAINTAIN MAIN STEAM LINE F HPCS WATER LEVEL ISOLATION VALVE CONTROL INSERT ROO DRIVE CONTROL S F S F SYSTEM RODS INITIAL CORE COOI.ING PCRVICS RHRS SCRAM SUPPRESSION . S F

.POOL COOLING MODE p

CONTAINMENT Scypccicioa Wl TcepcRa4Ac ISOLATION c.<,E, S4 a< DcPacuuexabow MANUAL RV ACTUATION AOS p

LPCIS HPCS F EXTENDED CORE COOLING WASHINGTON PUBLIC POWER SUPPLY SYSTEM PROTECTION SEqUENCE FOR RECIRCULATION FIGURE LOOP PUMP SEIZURE 5.A.6-NUCLEAR PROJECT NO. 2 38

EVENT 39 RECIRCULATION LOOP PUMP SHAFT BREA STATE D ONLY INCIDENT HIGH REACTOR INCIDENT LOW WATER PRESSURE DETECTION VESSEL WATER DETECTION LEVEL RELIEF CIRCUITRY LEVEL CIRCUITRY SYSTEM S F S F PRESSURE SCRAM SIGNAL RELIEF REACTOR PROTECTION FROM SYSTEM TURSINE TRIP MAINTAIN MAIN STEAM LINE HPCS ISOLATION VALVE WATER LEVEL CONTROL INSERT ROD DRIVE CONTROL S F SYSTEM RODS INITIAL CORE COOLING S F PCRVICS RHRS SUPPRESSION S F SCRAM POOL COOLING MODE aarS<oa Poo( CONTAINMENT L

S~ Oopoost<<ex <'< ISOLATION MANUALRV AOS ACTUATION P HPCS F EXTENDED CORE S COOLING ASHINGTPN PUBLIC POWER SUPPLY SYSTEM PROTECTION SEQUENCE FOR RECIRCULATION FIGURE LOOP PUMP SHAFT BREAK 15.A. 6-NUCLEAR PROJECT NO. 2 39

o f7

C: O I

Ivtklks Q Q OWIAILAOO ONOI ACOavt IlkTl 0 AC)

M O

O o +

Pl m CIWINOLNOO VtIOOTT MIINSI CIWINOL NOCW NCATNIC, lkNTIA AILNI vtwclATNNL IITTIN QW AW

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WNP-2 Q. 211 . 086 RSP (15.1.2)

During recent meetings wi.,th GEi we have discussed whether non-safety"grade equipment can be assumed to function when analyzing anticipated transients. It is our understanding that one of the more Limiting events is the failure of the feedwater controLLer which would result in a maximum flow demand. For this transients the plant operating equipment which has a significant role in mitigating this events are:

(1) the turbine bypass system; and (2) the reactor vesseL high water Level trip (Level 8) that closes the turbine stop valves. To assure an acceptable Level of performances it is our position that the availabilityi the setpoints and the surveiLLance testing of this equipment be identified in the WNP-2 Technical Specifications. Accordinglyi submit your plans for implement ing thi s requi rem'ent along wi th any system modifications that may be required to satisfy our requi rements in this matter.

Response

As a means to assure an acceptable LeveL of performance of both the turbine bypass sys'em and the reactor vesseL high water Level trip Logier the Supply System wiLL place these components under WNP-2 Technical Specification surveiLLance. For the L8 trip circuitryr the trip set-points and surveiLLance frequency should be simi lar to that of the HPCS injection valve closure on high Level Logic presently controLLed by Technical Specifications-Tentativelyr a trip setpoint of +55.5" and a surveillance frequency of monthly functionaL checks and quarterly calibration is envisioned. A minimum number of two channels should be available in operational conditions 1 and 2. For the turbine bypass systems a setpointr per see does not apply. VaLve operabiLity wiLL be performed monthly while at power with a DEH Logic check performed at each refueling. AvaiLability requirements wiLL specify that all required valves must be operable in operationaL conditions 1 and 2.

WNP-2 Q. 211 . 087 (15.1)

It is not evident to us that the drop of 100 Fahrenheit which you assume in the feedwater temperature results in a conservative evaluation of the cold feedwater transient.,

when .the recirculation flow is manuaLLy controLLed. For examples a feedwater temperature drop of about 150 0 Fahren-heit occurred at an operating BWR in this country as a result of a single failure of an electrical component.

The electricaL equipment malfunction which was a break-trip of a motor controL center~ caused a complete Loss of all feedwater heating due to a total Loss of extraction steam. Accordinglyi submit: (1) a sufficiently detailed faiLure modes and effects analysis to demonstrate the conservati sm of the 100 Fahrenheit feedwater temperature drop you assume considering the potential effects of any single electrical maLfunction; or (2) calculations using a Limiting feedwater temperature drop which cLearly bounds current operating experience.

Further'eductions in feedwater temper ature less than 100 Fahrenheit can occur which would represent more realistic (i.e.r slower) changes in feedwater temperature with time.

In particulars slow transients .with the surface heat flux in equilibrium with the reactor power when the reactor scrams due to a feedwater temperature drop smaLLer than 100 0 Fahrenheitr could result in a Larger change in the criticaL power ratio (CPR). Accordinglyr evaLuate the cold feedwater transient for aLL sequences of events that can cause a slow transient and demonstrate the conservatism of the values of the feedwater temperature dropsy including the rate of change with respect to timer which you assume in your present transient analysis.

Response

The GE feedwater heater system design speci f i cat i on to the A/E requires that the maximum tempera ture decrease which can be caused by bypassing feedwater heater(s) by any equi p-ment single failure or operator error should be Less than or equaL to 100 F. This is the basis of the assumed drop of 100 F in feedwater temperature in the analysis. To veri fy proper design by the A/Er a review of the feedwater system will be performed during the start-up test program to deter" mine the most Limiting single failure or operator err or in

WNP-2 terms of impact on feedwater temperature drop. A.test wiLL then be performed which simulates such a failure or error to confirm plant responser MCPR tr ansient behavior and feedwater temperature drop.

From the analysis with the assumed drop of 100 F in feed" water temperatures it shows that reactor scram due to high thermal power occurs during the transient. It is evident that transients resuLting 0from feedwater temperature decreases greater than 100 F would also resuLt in reactor scram due. to high thermal power. There fores. the transients are not more severe than the one shown in the FSAR. The conclusion that a greater than 100 F feedwater temperature reduction does not result in more severe transients is substantiated by an analysis performed on the LaSalle docket in the response to LaSaLLe Question 212.142. Due to similarity of designr the analysis is applicable to WNP-2. The analysis assumed a feedwater temperature drop of 150 F..which bounds observed operating experience.

It should be pointed out that a steady state condition (i.e.i the surface heat flux in equilibrium with the neutron flux at the occurrence of scram) is assumed in determining MCPR during the transient. Thereforer reduction in feedwater temperature Less than 100 F will not result in a Larger Q,CPR than that reported in the FSAR.

WNP-2 Q. 211.088 (15.2)

In your evaluation of the generator Load rejection tran-sienti you assume 0.15 seconds for the fuLL stroke closure time of the turbine controL valve and state that it is conservative compared to an actual closure time of 0.2 seconds. Howevers in TabLe 15.2-2 of the FSA'Rr y'ou indicate that the turbine control valves close in 0.07 seconds. Explain this apparent discrepancy. Additionallyr the pressure peaks caused by closure times from the partiaLLy open to the fully closed position are not addressed in the FSAR.

cantlyy For fuLL"stroke closurei the cLosure time you assume appears to be conservative in Light of the information in the FSAR. Howeverr for operation in the fuLL arc (i.e.i fuLL throttLing) moder the closure times may be signifi-Less than 0.15 seconds for typical cases where the controL valves are only partiaLLy open. We have two con-cerns with respect to this particular transient. Our first concern is that the minimum closure times for part-stroke may be Less than those you assumed in your analysis. Our second concern is that your analysisr which is based on ini t i a l condi t i ons which include 1'05 percents nuclear bo i l er ratedi steam f Low and the controL valves wide opens may resuLt in a Less conservative evaLuation than the initial conditions at a somewhat Lower power with the controL valves partially open. Accordinglyr demonstrate that controL valve closure times smaller than 0.15 seconds do not result in unacceptable increases in the MCPR and in the reactor peak prcssure'Lternativelyr either provide justification that shorter closure times cannot occur or indicate a minimum closure time to be incorporated into the WNP-? Technical Specifications.

Response

'In the evaluation of the generator Load rejection transient as shown in Section 15.2-2i the closure characteristics of the turbine controL valves are assumed s uch th'at the vaLves operate in the fuLL arc mode and have a fuLL stroke closure timei from fuLLy open,to fully closedi o f 0.15 seconds. So Table 15.2"2 shows that turbine control valves close in 0.07 secondsi since the turbine control valves are initiaLLy partiaLly open.

Sensitivity study shows that the most severe initiaL condition for this transient is when the reactor operates

WNP-2 at 105% NBR steam flow with the assumption of fuLL arc operations since the pressurization rate is higher at higher initiaL power Level.

Other sensitivity study shows that turbine controL valve closure times smaLLer than the assumed 0.15 seconds do not result in unacceptable increase in CPR and reactor peak pressure. For examples if the turbine controL vaLve closure time is 0.10 secondsi the peak surface heat flux would increase by 1%r peak reactor pressure this transient is not the most Limiting transientspsi.which 1 Since determines the. operating CPR Limits the turbine controL valve closure time wilL not affect the operating CPR Limit.

WNP-2 Q. 211 . 089 (15.1.1)

For the t rans ient resulting from a Loss<< of feedwater heat" ing while in the manual flow controL modes the thermaL powe'r monitor (TPN) is used to scram the reactor.'xplain the need for the TPN and indicate the specific transients for which thi s trip signal initiates a reactor scram.

Describe the surveiLlance testing of the TPN wiLL be incorporated into the WNP-2 Technical Specifications.

Response

If there were no high thermaL power trip scram design available in the WNP-2 plant designs reactor scram during the Loss of feedwater heating transient would occur when the neutron fLux exceeds the high APRM fLux scram set-point. Usuallyi the high APRN fLux scram setpoint is higher than the high thermaL power scram setpoint by approximately 3"6%. Thereforer the Loss of feedwater, heating transient would be more severe without the high thermal power trip scram design. This would Lead to higher operating CPR Limit and reduce the fLexibility of plant operation.

TPN scrams are applicable to those transients associated with slow neutron flux increases. One such transient would be the Loss of feedwater heating (see the response to Question 211.087).

The surveiLLance testing of TPN wilL be defined in WNP-2 Technical Specifications. Typical wording is illustrated'n the attached sections from the Standard Technical Specifications.*

• The Technical Specifications are under deveLopment and the attached is for information only.

PCWER DISTRIBUTION LIMrTS 3/4. 2. 2 APRM SETPOINTS

'LIMITIHG CONDITION FOR OPERATION 3.2.2 The RM fl w biased simulate rmal ower-u scale scram tri set t 1

~S and flow biased simulated therma'I power-upscale control rod b ock trip setpoint (SRB) shall be es-ablished according to the ollowing relationships:

4 S < (0.66W + (54)~) T

< (0.66W + (42)') T SRB

~here: S and SRB are in. percent of RATED THERMAL POWER, W = Loop recirculation flow in percent of rated flow, T = Lowest, value of the ratio of design TPF divided by the MTPF obta-ined for any class of fuel in .he core,' greater than or equal to 1.0, and Design .TPF for 8 x 8 fuel = (2.43).

APPLrCABILiTY: OPERATIONAL.CONDITION 1, when THERMAL POWER is greater than or equal to (25)~ of RATED THERMAL POWER.

ACTION:

With the APRM flow biased simulated thermal power-upscale scram trip setpoint or the flow biased simulated thermal power-upscale control rod block trip setpoint less conse.vative than S or S B, as above de-ermined, initiate correc ive action within 15 minutes an[ restore S and S to within the required limits within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> or reduce THERMAL POWER 8 less than (25)~

of RATED THERMAL POWER within the next 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.

SVRYEILLAHCE PEOUIREMEHTS 4.2.2 The MTPF for each class of fuel shall be determined, the value of T calculated, and the flow biased scram and control rod block trip setpoints veri ied to be within the above limits or ad/us~ed, as required:

~

At least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, Withi'n ( ) hours after completion of a THERMAL POWER increase of at least 15 of RATED THERMAL POWER, and C. initially and at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> when the reac.or is ope. at'.ng wi-h MTPF greater han or equal to (2.43).

GE" STS 3/4 2-5 E

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TAOLE 3.3.1" I Cl m

{

REACTOR PROTECTION SYSTEH INSTRUHEHTATION I APPLICABLE HINIHUH

{

I OPERATIONAL OPERABLE CIIAHNELS FUHCTIOHAL UNIT COND IT ION S PER TRIP SYSTEH a <<1CV<<ON I

~

1. Intermediate Range floni tors:

a. Neutron Flux - Upscale 5(b) 3 3, 4 2

b. Inoperative 2,'5(b) 3 3, 4 2

2. Average Power Range'Honitor:

a. Heutron Flux - Upscale 5(b) 2 1

,3, 4 2 2

b. Flow Biased Simulated Thermal ower - psca e 1 3 4l I

. II 2 ~

I'al hl d. Inoperative z '2 4

e. LPRH s{b'(d)

(c) HA

3. Reactor Vessel Steam Dome Pressure - lligh

<<7

<<J

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~ Level 3 1, 2 5 J

5. Hain Steam Line Isolation Valve-t{

Closure 1(e) 3

{ {

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I.

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-I

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~

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'I,

n. tleutron Flux - Upscale S/u('),S. S/U

" R 2 le. '.

S M R 3, 4, 5 Inoperative Hn M Hn

)" .I

2. Averiite Power Range Honitor:

I

a. Heutron Flux - Upscale S/u('),S S/u(" , M SA 2

~

,'L S M SA 3,4,5 ly Flow Biased Simulated Thermal Power - pscale S S/U(b), M M

" (') SA

~

IS C. tleutron Inoperative ux - psca e HA M M,

tN S l 1,2,5

~ I

.'III

~ ~

~ s

0. LPRH S Hh (f)

Jl A

3. Reactor Vessel Steam Dome 'lA I Pressure - Iiigh 1, 2

4. Reactor Vessel Mater Level-Low, Level 3 1, 2 f:a fl,

-II1 ~ 5. Hain Steam Line Isolation I~

Valve - Closure ttn II

6. Hain Steam Line Radiation " .

I lliOh M(g) R(h) 1, 2 I 7. Primary Containment Pressure-lliOh tlh 1, 2

~

I

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m

~ I lt REACTOR PROTECTION svSTEH RESPONSE TIt<ES

$  :. ~

"~i) ': RESPONSE TINE FUNCTIONAL UNIT Seconds

~1 Intermediate Range Honitors: ".

l,y,i 4 ~

~

a. Neutron Flux - Upscale

f)i'-)

b. Inoperative

2. Average Power Range Honitor*:

a. tteutr on Flux - Upscale tin

b. Flow Biased Simulated Thermal Power - Upscale (0.09**)

c. axe eu ron ux - psca e 97

d. ti I nopera ve ttn

e. LPAH Hn

3. ,Reactor Vessel Steam Borne Pressure - lligh < (0.55)

Reactor Vessel Mater Level - Low, Level 3 < (1.05)

I~

5. Hain Steam Line Isolation Valve - Closure < (0.06)

~ I 6. Hain Steam Line Radiation - lligh Bn r' 7. Primary Containment Pressure lligh Nn

8. Scram Oischarge Volume Mater Level - lligh HA I 9; Tgrbine Stop Valve - Closure < (0.06) t'y 10. Turbine Control Valve Fast Closure, p

~

~

I~

Trip Oil Pressure - Low < (0.08)8

~

11. Reactor Hode Switch in Shutdown Position ttn

12. Hanual Scram Hn tleutron detectors are exempt from response time testing. Response time shall be measured from the detector output or from the input of the first electronic component in the channel.

(This provision is not applicable to Construction Permits docketed after January 1, 1978.

See Regulatory Guide 1.18, tlovember 1977.)

(""Not including simulated thermal power time constant.) I measured from start of turbine control valve fast closure.

WNP-2 Q. 211.090 (15.2)

Provide assur ance that the plots of pressure with time in Section 15 of the FSAR are consistent with the initiation Logic for the SRVs. For examples you may have modified the safety/relief system to prevent sub-sequent reopening of these valves during transients involving an increase in the reactor pressure to sati sfy your present design bases 'for pooL dynamic Loads in the containment.

Response

The plots of pressure with time in Section 15 of the FSAR are indeed consistent with the initiation Logic for the SRVs. If changes to accommodate the Low-Low Set design are made in the futures the transient anaL-yses wiLL be revised accordingly. Currentlyi this feature is not necessary on WNP-2.

WNP-2 Q. 211.091 (15.4.5)

Provide the initiaL operating MCPR determined at 56 percent of~ rated power (nuclear boi Ler) and 36 percent of the core f Low for the postulated fai Lure of the recircuLation f Low controL system whi Le undergoing an increasing f Low transient.

In additions provide the Kf* factors as a function of the core flow for both the automatic and manuaL fLow control modes of operation. Provide the maximum .fLow control set" point ca libration Limit (e.g.i 100 percent or 105 percent of rated f Low) for the recirculation Loop f Low controL valves used in the transient analysis. Additionallyi we note that you re ference the GE topi cal reports, NEDO-10802'or the dynamic modeL which you used to simulate this event. How-evers NEDO-10802 does not describe the complete event.

Accordinglyi discuss in greater detail the overall method you used to calculate the change in the CPR.

Response

The, initial operating MCPR at 56% of nuclear boiler rated power and 36% of core fLow is 1.54.

A plot of the Kf factor vs. core f Low appears on the attached figure. The mode of operation (automatic or manuaL) of the recirculation flow controL system has no impact upon the Kf curve.

The Kf curve for WNP-2 is based upon 114% maximum flow. The maximum fLow wiLL be Limited to a value of 102 '% maximum.

Thereforer the Kf curve is conservative.

The method of calculating the change in CPR is described in the General Electric BWR Thermal Analysis Bases (GETAB):

data'orr eLati on and design appLi cation'ED0-10958A.

• Kf is def ined as the ratio of the MCPR at a given reactor coolant f Low rate to the MCPR at 100% power (i.e.r 1.20).

I

' II

WNP-2 Q. 211.092 (15.3.3)

In Table 15.3-5 of the FSARr you take credit for non"safety grade equipment to terminate the postulated accident involv-ing seizure of the recirculation pump. Howevers it is our position (refer to Section 15.3.3r Reyi si on 1r NUREG-75/087, of the Standard Rev iew PLan) that only safety grade equipment can be used and tha t the required safety functions must be accompli shed assumi ng the worst single failure of an active component. Accordi nglyi reevaluate this accident with the-speci fi c criteria c ited above. Indicate the resulting change in the CPR and the percentage of fueL rods which would be in boiling transition for this postuLated accident.

Response

The recirculation pump seizure event was recLassified as an accident with the introduction of the General Electric BWR Thermal Analysis Basis Report (NEDO-10958-A) because of the highly unlikely nature of this event. The FSAR analysis assumes that the attendant water Level sweLL wiLL cause a high Level (L8) trip thereby shutting down the main turbine and feed pump turbinesi and indirectly initiating scrams as a result of the main turbine trip. The FSAR analysis also explains (Section 15.3.1.2.3.2 as referenced in 15.3.3.2.3) that a turbine trip can eventuaLLy occur even in the event of failure of the non-single failure proof turbine trip sig-nal circuitry. Pump seizure event analyses have shown thatr although coolant flow rate drops rapidlyr NCPR does not decrease significantly before fueL surface heat flux begins droppi'ng enough to restore greater thermal margins as the plant intrinsicalLy responds to the reduced flow rate.

The pump seizure event is a. very mild accident in relation to other accidents such as the DBA-LOCA addressed in the FSAR. Th is is easily verified by consideration of the two events. In both accidentsi the recirculation driving Loop flow is ost extremely rapidly in the case of seizures L

stoppage of the pump occurs; for the DBA LOCAL the severance of the Li ne has a similarr but more rapid and severe influ-ence. Fo lowing a pump seizure events fLow contingesi water L

Level is maintainedi the core remains submergedi and this provides a continuous core cooling mechanism. Howevers for the DBA-LOCA complete flow stoppage occurs and water Level

WNP-2 decreases due to Loss of coolant resulting in uncovery of the reactor core and subsequent overheating'f the fuel rod cLadding. Also'omplete depressurization occurs with the DBA-LOCAL while reactor pressure does not significantly decrease for the pump seizure event. CLearlyr the increased temperature of the fueL cladding and the reduced reactor pressure for the DBA-'OCA both combine to yieLd a much more severe stress and potential for cladding perforation for the DBA-LOCA than for the pump seizure. Thereforer it can be concluded that the potentiaL effects of the hypotheticaL pump seizure accident are very conservatively bounded by the effects of the DBA-LOCA-and a specific core performance analysis or radiological evaluation is not considered necessary.

This has been found to be an acceptable generic Licensing basis for this event by the NRC staff (see the General ELectric LTR "Gene ri c ReLoad Fuel Appli cat i on" NEDO-24011-A) .

In additioni the non-safety"related equipment used in the analysis (L8 trip/turbine bypass system) has been made more reLiable based on Technical Specification surveiLLance.

See the response to Ques,tion 211.086.

MNP-2 Q. 211.093 (15.1.2)

For the transient resulting from a postulated failure of the water controLLer during maximum f Low demands you indi cate a feedwater f Low of 146 per cent in Table 15.1-3 of the FSAR. Howevers you indicate in Section 15.1.2.3.2 that the feedwater'flow is 135 percent for the maximum flow setting in simulating this transient. CLarify this apparent di screpancy.

Response

Section 15.1.2.3.2 states that 135% feedwater runout fLow wiLL result if the operating pressure is at the design pressure of 1060 psig. In the analysisr the operating dome pressure is 1020 psigr hence higher runout flow wiLL resul't.

WNP-2 Q. 211.094 (15.1.2)

When a sudden increase in feedwater flow occurs'here wiLL be a corresponding drop in the'feedwater temperature which contributes to the reactivity increase during the first part of this transient. For examples the combination of a drop in the feedwater temperature and a smdller maximum flow rate could cause a Level 8 trip with the surface heat flux cLose to the flux scram'setpoint. If you have assumed remained that the feedwater temperature into the reactor vesseL has constants reanaLyze this transient to include the effect of the variation in the feedwater temperature on the NCPR.

Provide your basis for determining the time variation in the feedwater temperature in the reactor, vessel. Demonstrate that a smaLLer increase in the feedwater flow rate than the one you analyzedr in conjunction with the change in feed-water temperatures does not result in a Lower NCPR.

Response

It is true that there, wiLL be a drop in the feedwater tempera-ture with an increase in feedwater fLow. Howevers the feed" water heater usuaLLy has a Large time constant (in minutesr not in seconds) so the feedwater temperature change is very slow. In additions there is a Long transport delay time before the cold feedwater reaches the vesseL. Thereforer it is expected that the feedwater temperature change during the first part of the feedwater controller fai lure (maximum demand) transient is insignificant'nd'ts effect on the transient severity is minimaL.

WNP-2 Q. 211.095 (15.1.4)

In your ana lysis of an inadvertent opening of an SRV in Section 15.1.4.2.1.1 of the FSARr you state that a plant shutdown "should" be initiated if the valve cannot be cLosed. Indicate how much time the operator has to initiate plant shutdown before exceeding the proposed WNP"2 Technical Specification Limits for the suppression pooL temperature.

Response

The operator wiLL have the time period between the 'valve first sticking open and the bulk pool temperature reach-ing 110 F before he must scram the reactor to be in compliance with the Technical Specifications.

If it is as sumed that the suppression pooL is at its maximum ope rating temperature and minimum operating volume with no pooL cooling systems in operation when the valve f irst opensr the operator wiLL have more than 8.7 minutes before the pooL scram temperature of 110 0 F is reached. If the above worst case assumptions were relaxed'h e time for operator action would be increased.

WNP-2 Q. 211.096 (15.2.6)

You.indicate in your'nalysis of the transient resulting from a postulated Loss of off-site power that closure of the NSIV's occurs at 30 seconds after the start of the transient due to a Loss of condenser vacuum. Our concern

~

in this matter is that the NSIV's may close at an earlier time in the transients thereby causing higher system pressures than your analysis indicates. Apparentlyr you-take credit for operation of the MSIV air accumulator since the normaL air supply to the MSIV's would trip at the start of this particuLar transient. Discuss the design provisions incorporated into the Wl'JP-2 facility which pre-vent closure of the NSIV's any earlier than 30 seconds after the start of this transient. Additionallyr discuss your verification testing which wilL demonstrate that the NSIV performance assumed in your analysis wiLL be achieved.

Response-Section 15.2.6 has been reanalyzed and revised to take into consideration that reactor scram and MSIV closure are-initi.ated at two seconds due to Loss of power to the scram and NSIV soL'enoids. This applies to both Loss of auxiLiary power transformers transient and Loss of aLL grid connections transients Two seconds is assured due to the inertia of the RPS MG set flywheels which provide power to the MSIV solenoids. See the response to Question 211.097. Also'he pertinent items in Table 15.0-1 are revised accordingly. During the startup test program a generator Load rejection/Loss of alL grid connections test wilL be performed to verify proper plant response in comparison to analysis assumptions.*

/

• D ra ft FSAR page changes at t ached.

E 15.0-1 RESULTS SUMMARy OF Tl aNT EVENTS APPLICABLE TO ltNP 2 Haximum Duration of Cora Slowdown Average Dura-Hnximum Surface No. of tion Haximum- Hnximum Haximum Steam Neat Valves of Para- Neutron Dome . Vessel Line Flux Minimum 1st Blow-graph Fi,gure Flux Pressure Pressure Pressure \ of CPR Frequency Blow- down I.Da I.D. r~csrrl tioo ~ rrR ~aati ~aati ~aati Initial ~Cate or down sec 15.1 DECREASE .IN CORE COOLANT TEMPERATURE 15.1.1 15rl 2 Loss of Faedwater Neater, Hanual Flow Control 124.2 1030 1070 1001 117.1 1.08 15.1. 2 15. 1-3 FeedwnteJ Cntl Fail-ure, Hak Demand 176.0 1141 1170 1124 110.6 1 ~ 09 18 5.8 t

15r1.3 15.1-4 Pressure IPegulator Fail-Open 104.3 1098 1117 1097 100.1 >1.18*@ 2 6 '

iI 15.1.4 Inadvertent Opening oE Safety or Re-lieE Va ve SEE TEXT t

15 1.6 RNR Shutd wn Cooling Malfunction Decreas-ing Temperature SEE .TEXT ii 15.2 INCREASE IN. REACTOR PRESSURE \

I(

15 2.1 Pressure Aagulntor Fail - Closed SEE 15'.2.2 and 15.2.3 N/Bypass on 15.2.2 15.2-1 Generator Load Re-jection Bypass-On 165.1 1137 1165 1122 103 ' 1.15 18 5.5 15.2 2 15 '-2 Generator)Load Re-r, jection, Bypass-Off t) 254.5 '165 1193 1148 110.5 1.05 18 8~2 i

15.2.3 15.2-3 Turbine Trip, Bypass-147.5 1136 1163 1121 101 ' 1.18 18 5 5 15 2 3 15 '-4 I Turbine Trip, Bypass-OEE 233.7 1163 1191 1147 108 9 1.07 18 8 '

15 '-5 EI 15.2.4 Inadvertent HSIV fi Closure, 186.2 0

1154 1191 1146 100 ' >1 20~+ 18 5,7 15.2r5 15.2-6 Loss of Condenser Vacuum 157.5 1135 1162 1120 102 ' >1 ~ 07*~ 18 5.4 15.2.6 15.2"7 Loss of Auxilinry Power Transformers 104.3 100 0 +I ~ 24*~ 0 0 "l rfSZ

TADLE 15.0-1 - (Continued)

Haximum Duration of Core Blowd own Average Dura-Haximum Surface No. of tion Haximum Haximum Haximum Steam lleat Valves of Para- Neutron Dome Vessel I ine Flux Hinimum 1st Blow-graph Figure Flux Pressure Pressure Pressure 0 of CPR Frequency Blow- down I'E IeD. ~De ark tioa

'I Na a ~sl ~et Initial C~ate or down sec 15.2.6 15.2-8 Lose of All Grid Connections

//5. 2 //77 /o/. C

>1.15<* 18 '.5 lf 15 ' ' 15.2 Loss of all Feed-water Flow 104.3 1095 1107 1095 ~ 100.0 <1.24>> 2 6.0 15.2.8 FeedwateL Piping Break SEE 15.6.6 I

15.2 9 Failure of RllR Shut-down Co6 ling SEE TEXT I

15.3 DECREASE IN REACTOR

~, COOLMIT SYSoEH FLOW-RATE l

15.3 1 15 3-1 Trip of On e Recircula-tion Pump Hotor 104.4 1021 1061 994 100 ~ 0 wl.24ca a 0 0 lf 15.3.1 15 '-2 Trip of BOth Recircu-lation Pump Hotors 104.4 1104 1116 1100 100.1 +1. 24' 6 5.3 15 ~ 3 ~ 2 15 '-3 Fast Closure of One Hain Redirc Valve 104.3 1101 1115 1097 100.0 +1.24c~ 2 6.8 15.3.2 15 '-4 Fast t

Closure of Two Hain Recirc Valves 104.4 1105 1115 1100 100. 0 <1. 24<

• 6 5e4 Il 15.3.3 15.3-5 Seisure of One Recir-culatioA Pump 104.3 1105 1117 100 100. 2 >I. 24+ s 6 5.4

'I 15.3.4 Reci rc Pump Shaft Break SEE 15.3.3 15 ' PSACTIVITY AND POWER DISTRIBOTION AtlOHALIES II 15.4.1 1 RWL - Refiteling SEE TEXT 15.4.1.2 RWE - Startup

!I SEE TEXT

'I 15.4.2 RWE - At dower SEE TEXT 1.17 I

15.4 3 Control Rod Hisee operation SEE 15.4.1 and 15.4.2 r

15.4 ' 15.4-6 Abnormal 0 tartup of Idle Loop Rec I

I irculation 94,2 981 995 '70 146.6 >1.06

• I I

I

time, t=0, with normal coastdown times.

b. Wx '0'ater circula seconds, the loss of main pumps causes denser vacuum enser to drop to t urbine t 'etting. However, the LS high water earlier, trip turbines

'he ma set point is reached er the set point, turbine and feedwater xceeded.

c t approximatelyis denser vacuum 30 seconds, the loss o expected to reach the bypass Operation of the HPCS and RCZC system functions are not simu-lated in this analysis. Their operation occurs at some time beyond the primary concerns of fuel thermal margin and over-pressure effects of this analysis..

15.2.6.2.2.2 Loss of All Grid Connections Same as 15.2.6.2.2.1 with the following additional concern.

The loss of all grid connections is another feasible, al-

~

though improbable, way to lose all auxiliary power. This

~ ~ ~

~

~

event would add a generator load rejection to the above sequence at time, t=O. The load rejection immediately forces

~ ~

the turbine control valves closed, causes a scram and in- ~

itiates recirculation pump trip (RPT) (already tripped at reference time t=O) .

15.2.6.2.3 The Effect of Single Failures and Operator Errors Loss of the auxiliary power transformers in general leads to a reduction in power level due to rapid pump coastdown with pressurization effects due to ~W/

. Additional-Xailures -of. the =>

other systems assumed to protect the reactor would not oPpc~e result in an effect different from those reported. Failures /css of the protection systems have been considered and satisfy single .failure criteria and as such no change in analyzed g /~no,~~.

consequences is expected. See 15A for details on analysis. single'ailure

15. 2-48

Insert to 'Page 15.2-48:

a 0 Recirculation pumps and condenser circulatory water pumps trip off at time = 0. RecircuLation pumps coast down with the fastest rate specified in the Nuclear BoiLer Systems TDS.

b. Due to Loss of power to the scram and NSIV reLay solenoidsr reactor scrams and MSIV closure is initiated at two seconds time.

co Feedwater turbines trip off at four seconds due to NSIV closure at two seconds.

15.2.6.3 Core and System Performance 15.2.6.3.1 Mathematical Model The computer model described in 15.1.1.3.1 was used to simu-late this event.,

Operation of the RCIC or HPCS systems is not included in the simulation of this transient, since startup of these pumps does not permit flow in the time period of this simulation.

15.2.6.3.2 Input Parameters and Initial Conditions 15.2.6.3.2.1 Loss of Auxiliary Power Transformers These analyses have been performed, unless otherwise noted, with plant conditions tabulated in Table 15.0-2 and under the assumed systems constraints described in 15.2.6.2.2.

15.2.6.3.2.2 Loss of All Grid Connections Same as 15.2.6.3.2.1 15.2.6.3.3 Results 15.2.6.3.3.1 'oss of Auxiliary Power Transformers Pigure 15.2-7 shows graphically the simulated transient.

~ ~

g ~ ~ ~

Sensed level drops to the RCIC and HPCS initiation set point at approximately seconds after loss of auxiliary power.

The RHR, in the team condensing mode, is initiated to dissi-pate the heat. yg There is no significant increase in fuel temperature or de-crease in the. operating MCPR value, fuel thermal margins are not threatened and the design basis is satisfied.

0 a~J g s~eonZs 8+~ ~c'~am PPwzv a~A feE'cycuceCc r Ngi ~ aery .,

o~~r 15.2-49

15.2.6.3.3.2 Loss of All Grid Connections

~

~ ~

Loss of all grid connections is a more general form of loss

~ ~ ~

of auxiliary power. It essentially takes on the character-

~

istic response of the stand'ard full load rejection discussed in 15.2.2. Figure 15.2-8 shows graphically ghe simulated event. Peak neutron flux reaches . % of NB rated power while fuel surface heat flux peaks . % of initial value. Peak fuel centerline temp ature ise is only M F.

/H'~. 4C 15.2.6.3.4 Consideration of Uncertainties The most conservative characteristics of protection features are assumed. Any actual deviations in plant performance are expected to make the results of this event less severe.

Operation of the RCIC or HPCS systems is not included in the simulation of the first 50 seconds of this transient. Start-up of these pumps occurs in the latter part of this time period but these systems have no significant effect on the results of this transient.

Following main steam line isolation:and prior to RHR initia- '~

tion the reactor pressure is expected to increase until the safety/relief valve set points are reached. During this time the valves operate in a cyclic manner to discharge the decay heat to the suppression pool.

15.2.6.4 Barrier Performance 15.2.6.4.1 Loss of Auxiliary Power Transformers The consequences of this event do not result in any signifi-cant temperature or pressure transient in excess of the criteria for which the fuel, pressure vessel or containment 15.2-50

TABLE 15 . 2-9 SEQUENCE OF EVENTS'OR'IGURE 15.2-7 Event Loss of auxiliary power transformers occurs.

Recirculation system pump motors are tripped.

Condensate and booster pumps are tripped.

Condenser circulating water pumps are tripped.

Inde I'5.2-52

Insert to Page 15.2-52:

Reactor scrams due to Loss of power to the scram solenoid.

NSIV closure is initiated due to Loss of power to MSIV solenoids.

Feedwater turbines trip off due to NSIV closure at two seconds.

4.71 Group 1 safety/relief valves actuated.

4.84 Group 2 safety/relief valves actuated.

4.98 Group 3 safety/relief va l ves actuated.

5.14 Group 4 safety/reLief vaLves actuated.

5.43 Group 5 safety/relic f valves actuated.

TABLE 15.2-9 (Continued) Page 2 of 2 Time-sec Event RCIC and HPCS systems initiation on low water level (L2)ygng x>ri c la.~vcr J.

50+ Group:1 relief valves cycle open and close on pressure.

15.2-53

TABLE 15.2-10 Page 1 of 2 SEQUENCE OF EVENTS FOR FIGURE 15.2-8 Time-sec Event

(-)0.015 (approx.) Loss of Grid causes turbine-generator to detect a loss of electrical load; 0 Turbine-generator power-load unbalance (PLU) devices trip to initiate tur-bine control valve fast closure and turbine bypass system operation.

0 Condenser circulating water pumps are tripped.

0 Recirculation system pump motors are tripped.

0 Fast control valve closure initiates a reactor scram trip.

0 Feedwater condensate and booster pumps are tripped.

~ ON W /5 P/'lppeeeef QA AM *~ +4 gCA~AI ~lp~

0.07 Turbine control valves closed.

0.10 Turbine bypass valves start to open to regulate pressure; 1.58 Group 1 safety relief valves actuated.

1.73 Group 2 safety relief valves actuated.

1. 89 Group

....AV 3

I' afety relief relief valves act valves actuated te

+ ~o~wr 2.09 Group safety E Group 5 safety relief valves actuate4.

15'.2-54

TABLE 15.2-10 (Continued) Page 2 of 2 Time-sec Event trip d~ ae

/

turbines /PPSZu'eedwater Gee'one c.

5. 1 (est. ) Group 5 safety relief valves start to close.

7.2 (est.) ALl relief groups closed.

~3 (est. ) RCIC and HPCS systems operation initi-ated on L2 low water level (not simulated). I 50+ Group 1 relief valves cycle open and close on pressure.

an Cv e'a 15.2-55

)5.2-56 IHGTOH PNLIC P(NER SUPPLY SYSTEH FIGURE LOSS OF AUXILIARY POWER TRANSFORHERS HUCLEAR PROJECT H0..2 15.2-7 I

I R

g R

' CI Cl t4) SLHPQdR03 IllAIC3GH CI 8

I MASHTHGT(N PUBLI C PORER SUPPLY 'SYSTEM LOSS OF ALL GRID COHHECTIONS HUCLEAR PROJECT HO. 2

~ I WI,'4J cho A >jap'J c

A4 I Ul W LlJ l IfI~~~C, + tA CIdh Cnmplma Vh~'+5 O v

. r R

R

' ~ CI CI tt) 5JHBNOdhQ3 AlIAIl3538 I

IC 0C lA I

AmK XWl Q QJ e

hjm 8

g g

R CI CI 8 8 CI 8 CI 8

ID3ltS % LH3383d)

WNP-2 Q. 211 .097 (6. 3)

We have a similar concern to that stated above regarding the potentiaL for NSIV closures times that may be shorter than those assumed in your analyses of the transient resulting from a Loss of off-site power since this Loss of power could generate an isolation signal that would close the NSIV's.

Indicate the sour ces of electrical power for the NSIV iso-Lation Logic and the isolation actuators. State whether these power sources would be available following a Loss of off-site power. Indicate whether the NSIV isolation Logic and the isoLation actuators could faiL in a manner which would initiate an NSIV isolation signaL on Loss of off"site power.

Response

The NSIV isolation Logic and air pilot valve solenoid

-(actuators) receive e lectricaL power from the Reactor Pro-tection System (RPS) motor/generator set buses in the following arrangement:

Isolatiop Logics "A" and "C" and one pilot solenoid for each NSIV (inboard and outboard) rec eive eLectricaL power from RPS bus "A" while Logics "B" and "D" and the second pilot solenoid on each NSIV s powered from RPS IIB II bu $

As a result of this power supply configurationi an NSIV closure wiLL not result from the Loss of power to a single RPS bus. Howevers a complete Loss of off-site power will result in Loss of'oth RPS buses and an NSIV closure after the RPS motor generators voltage drops. (Approximately 15 seconds) .

The Logic and actuators are powered in such a manner that

'Loss of power to a single Logic channeL or pilot solenoid group (i.e.i blown fuses open circuit or ground) wiLL not cause an NSIV closure.

The RPS buses are powered from the standby power system and would be avai Lable f ol lowing a loss of off"site power since diesel generator power becomes available in approximately 10 seconds.

See the response to Question 21 1.096'; for the significance of these response times.

Q. 211.098 (15.0)

We are concerned that operation of the WNP2 facility with partial feedwater heating might occur during routine main-tenance or as a result of a decision on your part to oper-ate with a Lower feedwater temperature near the end of a fuel cycle. Demonstrate that this mode of operation will not result in: (1) maximum reactor vessel pressures greater than those obtained using the assumptions in Section 5.2.2 of the FSAR; or (2) a more Limiting change in the NCPR than would be obtained with the assumptions used in Section 15.0.

Provide the basis for the maximum reduction in feedwater heating considered in your response to this item (e.g.~ the specific Limitations on the turbine operation).

Respon'se:

There are two distinct periods of concern when operating with reduced feedwater temperature. Reducing the feed-water temperature before rated EOC will result in Less severe transients. The peak pressures wilt. be Lower due to the reduced steam production. The CPRs wiLL be smaLL-er due to a stronger scram caused by additionaL insertion of the control rods to keep the reactor power within Licensed Limits and a Less negative dynamic void coefficient.

Operating with reduced feedwater temperature after rated EOC is the other period of concern. The basis for the plant safety analysis does not cover this operating condi-tion. ALthough it is expected that the original safety analysis wiLL cover operation under a derated feedwater

~

condition after EOCi an analysis is considered'ecessary to confirm this. Before operation in this condition is begun'he required analyses wiLL be performed to ensure pLant safety.

WNP-2

a. 211.099 (7. 5)

Since systems such as the HPCSi HPCIi and RCIC are initiaLLy aligned to draw coolant water from the CST and switch to the suppression pool following a signal indicating a Low water Level should be included in Table 7.5-1, of the FSARr entitled "Safety-Related Display Instrumentation." Accordinglyr add the signaL indicating Low water Level in the CST in Table 7.5-1.

Alternative lyi just i f y its omission.

Response

1.eveL indication for the Condensate Storage Tank (CST) is provided in the Control Room. Howevers it is 'our position that the safety function of HPCS and RCIC is determined by displaying to the reactor operator pump discharge pressure and flow to the reactors both of which are included in Table 7.5-1. Loss of Level indication in the CST when HPCS or RCIC is operating wiLL have no effect on the safe operation of the HPCS or RCIC systems because both system.s switch their suctions from the CST to the suppression pooL automat" icaLly foLLowing a signaL indicating a Low water Level in the CST. The instrumentation effecting the switchover is CLass 1E and an alarm is provided in the 6ontrol Room to indicate when switchover has occurred.

WNP-2 Q. 211.100 (7. 5)

Identify which parameters are used to monitor the plant conditions foLLowing an accident and which are input to the safety-related display instrumentation shown in Table 7.5-1 of the FSAR.

Response

The first half of this question basicaLLy asks for a description of WNP-2 compliance with Regulatory Guide 1.97. The regulatory guide is undergoing revision as a result of the Three Ni Le Island acc ident.'NP-2 site engineering is reviewing the various proposed draft revisions. to the regulatory guide Since Revision 2 has yet to be issuedi the Supply System can only make an educated guess as to what parameters and their requirements are to be defined in the regulatory guide.

WNP-2 has responded to the Regulatory Guide 1.97'ev. 2 draft by providing comments and a generaL Listing of variables and WNP-2 compliance with the draft revision-This information was submitted to the NRC staff via docket Letter no. G02-80-29'ated February 1r 1980.

Following the issue of Regulatory Guide 1.97'ev. 2r WNP-2 engineering wiLL finalize the plant design in regard to monitoring the variabLes described in the regulatory guide. Because of the preliminary engineer-ing already performed it is unLikely that the issue of Regulatory Guide 1 .97'ev. 2r wiLL cause any appreciable

'additional redesign of the plant. Section 7.5 of the FSAR wiLL be modified as required in Light of the above.

This FSAR revision wiLL answer both parts of Question 211.100.

WNP-2 Q. 211. 1 01 (7. 5)

In Table 7.5-1 of the FSARr you identi fy the range of the instrument which monitors the reactor vessel pressure to be, from 0 to %500 psig. Since the design pressure of the reactor coolant pressure boundary is 1250 psigi justify the upper bound of this instrument range in Light of the potential transients and accidents that may cause Large pressure excursions (i.e. ATWS).

Response

The reactor pressure instrument, range of 0 to 1500 psig is prudent for this device. .This range enveLo pes the anticipated pressure transients while providing adequat e resolution at mid-instrument range for normal operating c onditions. The range also envelopes adequately postulated Large'ressure excursions due to potentiaL transients and accidents (i.e.

ATWS) since the maximum pressure encountere d for any of these events is approximately 1250 psig for a sho rt duration (usually Less than 20 seconds). This conclusion is also. true considering the turbine trip without bypass event."

NEDE-24222'Assessment of BWR Mitigation of ATWSr Volume IIi" December 1979-

WNP -2 Q. 211.102 (7.4.1)

Provide display instrumentation indicating the water Level in the,CST on the remote shutdown control panel.

You state in the FSAR that the RHR flow indicator wiLL be Located on th'e remote shutdown paneL. Verify that fLow indication wilL be provided for both RHR systems (i.e.i A and 8) and that the flow range will be the same as that shown in Table 7.5-1 of the FSAR.

Response.

Endication of CST water Level on the remote shutdown panel is not necessary. Vessel inventory make-up requirements during a remote shutdown event are low and with a 135i000 gallon minimum CST inventory require-ments sufficient make-up capability exists for the Length of t ime RCIC may be used.

The Remote Shutdown System is not required to meet single failure criteria. For this reason only the RHR 8 Loop controls exist on the remote shutdown panel.

Flow indication for the 8 Loop i s pr'ovided on this paneL and the flow range is the same as that shown in Table 7.5-1r i.e.r 0-10r000 gpm.

WNP-2 Q. 211.103 (9.2.7)

In Table 9.2-5 of the FSARi you show a fLow rate of 7400 gaLLons per minute (gpm) from the standby service water system to the RHR heat exchanger. This fLow rate is based on an inlet temperature of 95 Fahrenheit. Howevers in Section 5.4.7.2.2i the service water side flow rate of 7400 gpm to the RHg heat exchanger is based on a rated inlet temp-erature of 85 Fahrenheit. Explain this apparent discrepancy.

Additionallyr demonstrate that you have adequately selected the r equired f Low rates for the standby service water system for heat Load removal from the ECCS pumps as shown in Table 9-2"5 of the FSAR. Provide justification for these f Low ratesr including a List of the design duty heat Loads for the equipment identified in Table 9.2-5.

Response

Section 5.4.7.2.2 is in error and is being revised to indicate 0 an inlet SW temper ature to the RHR heat exchangers of 95 Fahr-enheit. It should be noted that although the SW maximum design temperature is 85 Fahrenheitr severaL componentsi including the diesel generators and portions of 0the ECCS systems as indicated in Table 92-5 were designed to 95 Fahrenheit. This higher de" sign temperature adds additionaL conservatism to the system.

ALso Table 9.2-5 has been revised to include the caLculated and design duty heat Loads for the standby service water cooled equip-ment. The standby service water flow rates for the ECCS pumps and all other equipment Listed in Table 9.2-5 are the based on the standby service water temperature manufacturers'ecommendations Listed in Table 9.2-5. The flow rates for the RHR pump seals are set by the shutdown cooling mode which initiaLLy has a process fluid temperature of 358 F.*

'*Draft FSAR page changes attached.

WNP-2 , AMEIPDMENT NO. 8 February 1980

5. 4.7. 2. 2 Equipment and Component Descr iption a e System Main Pumps The RHR main system pumps are motor-driven deep-well pumps with mechanical seals and cyclone separators The umps are sized on the basis of the LPCI mode (Node A) and the minimum 'flow mode (Mode G) of the Process Data Figure. 5.4-14b. Design pressure for the pump suction structure is 220 psig with a temperature range from 40'F to 360 F. Design pressure for the pump discharge structure is 500 psig. The bases for the design temperature and pressure are maximum shutdown. cut-in pressures and temperature, minimum ambient temperature, and maximum shutoff head. The pump pressure vessel is carbon steel, the shaft is stainless steel. A comparison between the required NPSH (obtained from the pump characteristic curves provided in Figures 6.3-10a, h and c) and the NPBB needed in [

the Process Diagram Figure 5.4-14b (Note 8) demonstrates the required NPSH is adequate.

Available NPSH is calculated per Regulatory Guide

l. l.

b. Heat Exchangers The RHR system heat exchangers are sized on the basis of the duty for the shutdown cooling mode (Mode E of the Process Data). All other uses of these exchangers, including steam condensing, require less cooling surface.

Flow rates are 7450 gpm (rated) on the shell side and 7400 gpm (rated) on the tube side (service

~ ~P water side) . ated inlet temperature is ~~".

~F tube side; 'The overall heat rsnsder:=cue'Tdicient=i~'195" BTU'erricur'quare foot. The exchangers contain ft2 of effec-tive surf ace. Design temperate ~ range of both shell and tube sides are 40 F to 480'F. Design tor's are 0. 0005 shell side and ~~

pressure is 500 psig on both sides..Fouling fac-The construction materials are carSon steel for tube side.

the pressure vessel with stainless steel tubes and- stainless steel clad tube sheet.

5. 4-41

TABLE 9.2-5 Page 1 of 3 EQUIPMENT REQUIRING STANDBy SERVICE WATER TO ENSURE PLANT SHUTDOWN Design Heat Calculated Required 1 Load Heat Load F~low -m ~

(Btu hz) (Btu/hr)

Ecui . ent Cooled-"'.;;.

Division I

1. Standby Service Water 80 404,000 380,600 Pumphouse "A" Cooler

2. Diesel Generator "A" 1650 (2) 15,600,000 11,692,427

3. Diesel Generator Building..'-'.-'..:.,

"A" Coolers 144 716,000 716,000 4.'PCS Pump Motor Bearings 4 (3) w 0

5. LPCS Pump Room Cooler. 56 270,860 "A"

6. Seals

'80,000 12 (2)

RHR Pump w 0

7. RHR "A" Room Cooler 33 165,000 149,650

8. D.C. Motor Control Center Room Cooler 20 84,200 40,533

9. Motor C'ontzol Center Room Cooler 71,280 43,130

10. Control Room Cooler 120 285,000 256,500 e

11. Cable Spreading Room Cooler 40 160,000 74,600

12. Switchgear Room Cooler 60 370,000 327F100 Hydrogen Recombiner "A" MCC Room Cooler 52,500 36,174 14; Hydrogen Recombiner "A Aftercooler 50 250,000

15. Hydrogen Recombiner "A" Scrubber 10. 50,000

16. ~> "A" Heat Rcchanger- 7400 (2) (4) Variable

17. Analyzer Room Cooler 10 42,500 23,571

'OTAL F7E5

1) Based on 85 P Standby Service Water Supply .~-

unless otherwise zated;,=;.".;:-"".::." ..

2) Design based on 95 P Standby'ervice Wat'er Supply

3) Design based on 90 Z Standby Sezvice Water Supply ~

4) See Table 6.2-2 for design parameters 9.2-40

'o ~ ~

4 (t

~E E

E E r

~ 0 ~ E' ~

TABLE 9.2-5 (Continued) Page 2 of 3

~",...'"

~~ui ment Cooled "t..".,-":.i .=;.,-,;:.,::

'.. ~ . Required Flo~-qTB Design Heat Load (Bto/ht)

'eat Calculated Load (Bto/ht>

- ~ ~ .. ~:-~- -. ~ r Standby Service Water.'!:":-:=.-',:;-"-:,:. :- ,-..-',-... 80 Pumphouse "B" Cooler:-. -:...=" "..

..: .. 404 000 '58 100

2. Diesel Generator."B" ' ~

1650 (2) 15,600,000 11,692,427 E

3. Diesel Generator Building "B" Coolers -:"'.: .-- "-: ,.".-'=.'... =":,'-'-'.:"144.'. ! ,-','16 000 '-". 716 000

4. Diesel Generator Area Cable Cooler (Corridor) . ' .. ".-:... '

~

~

..'0 . 149,000 109,680

5. RHR "B" Pump Seals', '2 (2) w 0

6. RHR "C" Pump Seals 12 (2)

7. RHR "B" Room Cooler

....33.. 165,000 145,650 9

RHR RCZC Pump Room Cooler'2 "C" Room Cooler Cooler'.

. 33 165,000 60,000 160,530 37,270

10. Motor Control Center Control Room Cooler Room

=',=...= -"; ... -",

....'-'0,"

15 120 71,280 285,000 43,130 256,500 14.

Cable Spreading Room Switchgear Cooler-;:

Room Cooler."-";.".,.:.~;; ."3 Hydrogen Recombiner "B" Aftercooler.;:: ".'...';:50

~

'0" T, ~

160,000 320,000 74,600 305,400 250,000 E

15. Hydrogen Recombiner "B" Scrubber -.':.:;:,'..3.0 " 50,000

16. Hydrogen Recombinez "B",. MCC Room .

.':.-. ll 52,500 36,174

'7.

.RHR "B" Heat Exchanger,'.,'.",'.,=:",....., . 7400 (2) (3) Variable

18. Analyzer. Room Cooler ~~6: ", ';..~-.::i.-=-'.."" 10 '.(:: ':: ;'-.

~

42, 500-:...3, 571

"':,i::.:.TOTAL'". ':., ':.;,;.E =.-. 9~73 E

1) Based on 85 F Standby 'Service 'Hater..'Supply-'.;..','".-..:-." .":,"':

unless otherwise nated.=.

2) Des:gn based on 95 F Standby Service Water Supply

3) See Table 6.2-2 for design paxameters 9.2-41

'\~ aw ~

TABLE 9.2-5 (Continued) Page 3 of 3 Design Heat Calculated Required Load Heat Load F~law a-a ~

(Btu/hr) (Btu/hr)

Equipment Cooled'.

r

l. HPCS Diesel Generator 910 (2) 8F 872 F000 7F 401 F000

2. HPCS Diesel Building Coolers 144 716,000 716 F 000

3. HPCS Pump Room Cooler 50 500,000 473q580 TOTAL . 1104 .

Based on 85 = Standby Service Water Supply" unless otherwise n8ted.

2) Design based on 95 F standby Service Water Supply r

9 ~ 2-62

WNP-2 Q. 211.104 (9.2)

Provide a table Listing the standby service wateri system cooling duty Loads as a function of the time intervals Listed below foLLowing a postulated DBA. In this tables indicate the operating status of the appropriate safety-

related equipment (e.g.r the RHR pumpsi the RHR heat ex-changersi the CS pumpsr the ADS valvesi and the RCIC).

The time intervals for this tabulation should be: (1) 0 to 10 minutes; (2) 10 to 30 minutes; (3) 30 minutes to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />; (4) hours to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />; and (5) 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to 30 days.

Response

Table 9.2-8r revised Table 9.2-9 and Figures 9.2"7br 9.2-7c and 9.2-7d list aLL the Loads to the service water system. Table 9.2-8 Lists the heat rates and Table 9.2"9 Lists the integrated heat Loads.*

The ADS wilL automaticaLly actuate unless reset by the controL room operator at 120 seconds into a DBA. Howevers by 2 minutes into the accidents the vesseL wilL already be fuLLy depressurized (see Figure 6.3-21b for RPV pressure vs. time curve). The energy addition to the suppression pooL by the ADS is accounted for in Tables 9.2-8 and 9.2-9.

The RCIC system does not operate following a DBA as discussed in note 32 of Table 6.2-16.

@gag

Ill TABLE . -9 INTEGRATED HEAT DATA MNP-2 UHS RE-ANALYSIS Time After LOCA Min. Deca Sens A A . 2'4) Total sw")

10 BTU 0 0 0 0 0 0 1 3. 51 . 014 .020 .030 .015 ~ 3.59 .174 2 4.28 .027 i .041 .061 .029 4.44 .355 4 5.57 . 054 .083 ;121 .058 5.89 .719 10 8.72 .136 .205 .303 . 146 9.51 1.83 20 13.02 .271 .413 .606 .291 14.62 3.75 40 20.26 .543 .823 1.21 .582 23.45 7.80 90 35.16 ',1. 22 1.85 2.73 1.31 42.32 18.69 120(2H) 43.03 ~1. 63 2.48 3.64 1.75 52.57 25.57 240 (4H) 70.65 l3.26 4.94 7 '7 .

3.49 89.66 54.51 360(6H) 94.84 .,':4. 88 7.41 10.91 5.24 123.3 84.37 480(8H) 117.0 ~

I.

6.51 9.88 14.54 6. 98 155.0 114.3 720(12H) 157.6 ~9. 77 12.08 ~ 21.92 6.98 208.4 172.4 960(16H) 194.9 13. 02 14.27 29. 39 6.98 258.6 227.3 1200(20H) 229.9 16. 28 16.47 36.86 6.98 306.5 279.3 1440(lD) 263.1 19.54 18.66 44 '5 6.98 352.8 328.6 2160(1-1/2D) 354.5. 19.54 25.25 68.67 6.98 475.0 461.1 2880(2D) 435.3 19.54 31.84 94.64 6.98 588.3 581.1 4320(3D) 577.2 19.54 45.02 148.2 6.98 796.9 796.6 5760(4D) 702.3 19.54 58.19 201.7 6.98 988.8 995.4 7200(5D) 816.2 19.54 71.37 255.3 6.98 1169 1182 8640(6D) 922.0 19.54 84.54 308.8 6.98 1342 1358 A W 11520(8D) 1116 19.54 110.9 415.9 6.98 1669 1689 C R N U 14400(10D) 1292 19.54 137.2 523.0 6.98 1979 2001 17280(12D) 1456 19.54 163.6 630.1 6.98 2276 2300 rV aQ 23040(16D) 1756 19.54 216.3 844.2 6.98 2843 2870 Q 28800(20D) 2029 19.54 269.0 1058 6.98 3383 3412 LO M 34560(24D) 2282 19.54 321.7 1273 6.98 3903 3935 0

~

Q 43200(30D) 2635 19.54 400.8 1594 6.98 4656 4689

WNP-2 AMENDMENT NO. 5 August 1979 Page 2 of 2 p)g7 B~: TABLE 9.2-9 (Continued)

(1) Q Decay Integrated core decay heat rejected to suppression pool.

(2) Q Sensible Integrated sensible heat rejected by the reactor vessel, piping, and core to the suppression pool.

(3) Q Auxiliary 1 Integrated heat from ECCS pump work rejected to the suppression pool.

(4) Q Auxiliary 2 Integrated heat from auxiliary systems rejected to Division 1 service water system. This heat includes all sources of heat into Division 1 SW system except for. the RHR heat exchanger. The RHR heat exchanger transfers heat from the sup-pression pool to Division 1 SW system.

(5) Q Auxiliary 3 Integrated heat from HPCS service water system. This heat is a straight heat dump into spray pond A.

(6) Q Total Sum of Q Decay, Q Sensible, Q Auxiliary 1, Q Auxiliary 2, and Q Auxiliary 3.

(7) Q Service Sum of Q Auxiliary 2 and the heat. rejected Water. by the RHR heat exchanger into Division 1 service water system, i.e., the sum of the heat rejected through the spray nozzles.

<c r ( le ~ /

5p yAfÃ~>> ~

C<<

(~ 0, chal z.), - Ao 5

~ I

/lf

<<~'-

~~

-'QX'C 4c gg~

Ahcagl

<SScc, ~ecj Pl+5p ms< CCRC'S d I'

~ 4 ~ 44Cr Oq>>, ~

le I c S~~) 6e'm 9.2-50

WNP-2 Q. 211.105 (3.9.1)

Provide the following information related to the contents of Table 3.9-1 of the FSAR. This table shows the number of plant cycles or events considered for the reactor assembly design and f at igue ana Lysi s.

a 0 Discuss the events contained in Item i for and testing conditions and relate these to the normal'pset transients analyzed in Section 15.0 of the FSAR. In part i cula ri di scuss the following events.:

(1) The number of cycles (i.e.i eight cycles) for the 40 year Life of the WNP-2 facility shown in Table 3.9-1 of the FSAR (i.e.r Item i.4) for a single safety or relief valve blowdown for upset condi-tionsi appears to be Low. Specificallyr we note that Table 15.0 of the FSAR indicates that these valves will Lift for a variety of transient events and that more than one valve wiLL blow down.

Accordinglyi provide justification for your design basis of eight cycles-(2) Clari fy whether the loss of feedwater pumps in Item i.3 -is due to NSIV closure or whether both of these events occur independently. For either casei the number of cycles (i.e.r ten cycles) which you state for the 40-year L i fe of the WNP-2 facilityr appears to be Low. In particularithesince a number of'ransients can cause a trip of feedwater pumps and cLose the NSIVsr more than ten events'ausing the above conditions can be antici-pated throughout the plant Lifetime. Accordinglyi justify your design basis of ten cycles for this

,event.

b. Indicate w'hether Item 1(2) for emergency conditions in Table 3.9"1 of the FSAR is the automatic blowdown feature related to the ADS function.

c ~ Explain Item 1(2) for emergency conditions and relate it to your analysis omission in Sections 5.2.2 or 15.0 of the FSAR. Justify your of the event in which the reactor is overpressurizedr there is a scram initiated by a high f Lux signal and the isolation valves stay closed under "emergency conditions."

WNP-2

Response

a 0 The scram events Listed occur from various causes as follows:

Turb'ne Generator Tri r Feedwater Onr Isolation Valves 4

These events correspond to the 'Generator Load Rejection Turbine Control Valve (TCV) Fast Closure'nd "Turbine Trip" described in Chapter 15 without other fai lures assumed'uch as bypass failure. The same condition with bypass failure is included with the "Loss of Feedwater Pump" scram events.

Loss of Feedwater Pum si Isolation Valves CLosed 10 Cycles These are composite events which assume "Generator Load Rejection With Bypass Valve Failure" or "Hain Steam Isolation Valve Closure "r coupled with a "Loss of Auxiliary Power" which are aLL described in Chapter 15.

Sin le Safet or Relief Valve Blowdown 8 Cycles These are complete reactor depressurization cycles due to the 'failure of safetyr relief'r turbine bypass valve to reclose automatically after pressure has dropped below its design setting.

The specified 8 valve blowdowns are based on reli-ability studies which considered the failure rates of such valves to close as intended after actuationr and 'the number of valvesr and the expected number of valve actuations. The valve Lifts in Table 15.0 include the Larger number of actuations which are expected to occur where the valves function normally without completely depressurizing the reactor.

2. As noted in the "Loss of Feedwater Pumps Isolation Valve CLosed" event described abover the simultan" eous occurrence of feedwat r pump trip is but one effect of Loss of auxiliary oower and reactor iso-Lation. The effects of fe dwater pump trip are

'.ncLudedi where appropri ates in all other scram situations. Feedwater pump trip may also cause a scram due to Low water Levels which is included in the "Other Scram" category.

WNP-2 Item ~(. (~)

a complete i s related to the ADS function. It assumes reactor depressurization due to unintended operation of the ADS system or an assumed failure of several safety or relief valves to reclose automati-caLLy at their reset pressure.

The "Reactor Overpressure With Delayed Scram" event assumes closure of main turbine admission valves assum-ing that scram is delayed so that power and pressure are initially Limited by safety valve operation and reactor recirculation pump tripoff. A similar condition is discussed under the study of the "Anticipated Transient Without Scram (ATWS)" event in Chapter 15.

This delayed scram event resuLts in more severe pressure and power transient conditions than a-"Flux Scram With Isolation Valve Closure" which is conserva-tively considered to be an "Upset Condition" covered under the "Loss of Feed Pumps Isolation Valves CLosed" event discussed under a. above.

WNP-2 Q. 211 .106 (15.0)

Provide the correct units (or value) for the recirculation pump trip inertia for Item 32 of Table 15.0"2 of the FSAR.

Response

TabLe 15.0-2 has been modified.*

• Draft FSAR page change attached.

- TABLE 15.0-2 '(Continued)

28. High Pressure Scram Set Point, psig 1071

29. Vessel Level Trips, Feet Above Separator. Skirt Bottom Level 8 - (L8), feet 5.750 Level 4 - (L4), feet 3.750 Level 3 - (L3), feet 2.167 Level 2 (L2), feet (-) 2.041

30. APRM Thermal Trip Set Point, 8 NBR 9 100% core fLow 122.03

31. Recirculation Pump Trip Delay, Seconds 0.140

32. Recirculation Pump Tri inertia a ~ p ~sA~~Y Scconag 4 P. /,"F~'r

• The inertia time constant is defined by the expression:

t=.

2'n where t = inertia time constant (Sec) .

g T J 0 = pump motor inertia (lb-ft2

)

n = rated pump speed (rps) g = gravitational constant, (ft/sec 2 )

T = pump shaft torque (lb-ft) 0

15. 0-20

G~O~OGIC UNITS

~aa I

-)

I Iil) i TECTQNIC BRECCIA OF' HE

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-. ~~X((( Qg WAI IUI A FAD)1 TONE. -~~ i COO Alluvial sand and gravel AREAS.

OUFCROI'S Of'SH Okl'OS)IS

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(

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Light brown, windblown silt Gi variable age:

~ LOCATION OF Ef!RATICS ABOVE ELEVATION 1000 FEET I,( ( x

.'ib x x x,( x x E(k x L x ( a )ba a a (!) '

a

~a~

Qi LOCATION OF A PROBABLE Touchet beds of the Glaciofiuvial deposits.

~ QUATERNARY FAULT 3

lii!ht l,ray and brown, bar)dad silt with a networl<

a .'. Qg

~ ~

~ ~

I I

I of clastic dikes, Locally includes channel canc) SIR)I(E ANO DIP OF BASALT FLOWS LN< XXX any '(a>((,N>i(L.V>> Xt,( t 'a(,ha ~ ~

and gr~vel, and reworkeil colluvium a)orig narrow

~ ~

~ ~ canyons (13, 000 ybp) STEEI'I.Y DIPPING IEOVI'S (DIPS cc.

GREATER THAN 75 )

mm C

n)

.Q i ' (atwxa')'(( )'tiki(R(,

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('(ia a'(at XxE( (

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( I Undifferentiated silt. OBLIQUE SLIP FAULTS Yi'IIH RAIL ittt j t,z.

Incluiles windblown and Touchet silt. ON DOYINIHROWN BLOC)(; DOTILU i,(a'( ( a I - at ( WHERE CONCEAIEO;ARROW I~<<I,"ATES

<Tem ijh ( N ~ a 4 a$

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SENSE OF MOTION

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'5't a( 'i

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Angular basalt frag~ants of varying sizes intermixed with silt mantling steep slopes, I.OCAIION Or THE PHOTO-I NEAfi iinderlain by basalt flows at shallow clepth. (G'i)UND-SURFACE ilUPFURE Ol (Not mapped as a separate unit in order to sl.cw BI)fr)HAM, ANO Oihf.RS IBTO) ay) I Q, )

the basalt stratigraphy]

'1 I

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I'

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..7 c 9/j Qtll 'lilt

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,, v/ I Tf Ar NUCltAR PROJECT NOS. I & 4 I) I I

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(I 4. 0-1 6. 5 mybp) 'WllRM SPRINGS CANTON AREA Tu j/.

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)

SOU~HEASTE~N VillSHINGTON DECEMBER, 1979 UE & CONTRACT ~ 44013 C

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A/

SIANNON & WILSON, OEOEECHN)CAI CONSUIIANES INC.

I I rl>RTEANO, OREGON

A A SOUTH NORTH Loess Idealized flows of the

~ Frenchman Springs showing drag Member Undifferentiated Touchet/Loess Faulted ColluvIum (see fig.4)

~

Z~,f'(ilia 4~~)gti

')~ ~il'(/j

~ giver TOO VERTICAL SCALE IN FEET 200 200 400 I(I(;Py

'////

lail r l//////!'P';/l///f

-, /ll'I HORIZONTAL SCALE IN FEET Grande Ronde Basalt PllIf)~ < 'lr((- Touchet Beds WALLA WALLA VERTICAL EXAGERATIOH X2

//ill/ y, 7 RIVER Alluvium lt I reccacic areccia

~>tl,', A

'i'I,! 0 E GR3(, I '.

I Crrafn eitcalm

~ Plr/ EXPLANATIONS c" ~

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tMAAEC) o /7$ /V" -

W~ . t'/W~na .> g/n f)5 db//f/ento,/ tr; and Figs. 2 thyu 6.

'C k

'\

oar neh,. '

'5GO

'egG 20

'Gabe e Iopr lo Jr ~y( /f/IP, 4 ., 38 2. KENNEWICK-COLD CREEK LINEAMENT;

'a 560

~ PteIbb see Section 3 and Figs. 7 thru 9.

/GGCP . I(

i 3/ 3 Shee lbnch 744 4//f/~Pf /f 0 f/ qo, 3 BUROKER FAULT; Figs. 10 thru 12.

see Section 4 and

~ //,,'~p~i~p 4S't 5

624 1 4/V / / ,/~ Sidts

,,n'n'1

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Codd

4. GAME FARM HILL FAULT; see Section 5.

5 MIOO/d)Ar)f

5. SILVER DOLLAR FAULT; see Section 6.

51G fo r I

PP~ ./m 6. BADGER MOUNTAIN FAULT; see Section 7.

/'

Vr TQ ~ "C-." /Ceynf'553'

' / 7. BADGER CANYON FAULT; see Section 8.

Q Oo/ 11' C

/ sRfdlt C

/One; o /S r.

0 / g g oo

~<i)//y o 0

P CP, oo 0

Itdo/th 730/r /C AVjj/~I i h, ) 4 S nysi Richfanif P I0 to IU ymds ta tattf the

,~OVP)/ v

(

I etio 0 Cuss~et PI)~P,(

Col Nomdmff l255 P/escrdt (/WP~~ 'C 0

5 s 513 l3 AppR+otrrthbt RicjtlartRU 'o t tio

~ Gr I C/ r ~J I liam a

Sand nest Its Be on Cty Grain op ra oo I

n Chga land CAP etecator

./f/ I, ~g SCALE I:250,000 rf logo i/~I, '.; 45 i Pc 'c

/In 700 Wht an 0 10

'W,'

rmn eletstor trans n

/ r rtianstmmer 5 Miles

'l'p

- c~ 'o/tlt

/003 Wetland Station btabtbn station nl I 0 'Wea I t 4 I

'C QP~t,,7 0 5 10 It 512 f y ron I M .I ~ ":~nd ]kg /geo 2'0G .

tl 'i HamonsfGtation /.

I (

yf Kilometers I

Gram terstor ~A K neo/tck 5

R 8 N, Graij o)banter

<<(

/6 Hewn isoo BADAE M. ~: ~ a~co .

-y Ll~ K BASE MAP TAKEN FROM AMS DUADRANGLE OF I ~

,+'tfL-T4k P~P:)Vh /t I '.- Z CC / WALLA WALLA 4 f~ /i Or ettty n

C. 51i 3-

~,

CC/1 c)I to ct 5 C

& <., /7 o ,Gigot ~ih eteiltrt 'WUARIL

/Gr odt WASHINGTON PUBLIC POWER SUPPLY SYSTEM hRsratory L tlalla smboo Walls ,/e Po NUCLEAR PROJECT NOS. I & 4

-County

','Ci /7 Bn C

/205 e tend + ., t i:"0 istG)t n 5

I Walla Wall 30 logo t

/r-,,f t-m 5GO I.

INDEX AND LOCATION MAP ont la

~v /, / / /Po ',, 5%, I 3.

113 ,Goo, C~~/

ror Ra 3 rc 7 Wh tmsn Sthbao tt Lt Cc

, 'goo, mt

• @J 0 MAY, 1980 UE & C CONTPACT jj 44013 i OO/ I i'i SHANNON & WILSON INC

'oo

'md COG i

Geotechnical Consultants FIG. 1 I/07 C, . -

• Portland, Oregon

GEOLOGIC UNITS SOUTH 45 UNIT I Loess FINLEY OUARRY FAULT ZONE UNIT 2 Colluvsum 40 40 2a Young 2b Old 35 UNIT 3 Fault Breccia Zone 35

~ -SHEARED BASALT~ 3a Gouge 3b Gouge pq;.: ~3g 3c Tuff 30 4 30 3d Breccia 3e Gouge LLI 4 SHEARED BASALT 4

/ 3f Breccia uJ 25

-SOUTH FAULT

/ 25 LIJ 3g Shear SHEARED BASALT cC I/>

UNIT 4 Umatilla Basalt 4 DEBRIS Ld 20 ll 20 SEE SECTION 2 FOR DETAILED DESCRIPTIONS OF LITHOLOGIC 3d UNITS.

/0 ',

15 15 I((lr 4

j)j rl r/(IrIj 10 )lI)j I)gt CUT FACE ON OLD SPOIL PILE 10 WASHINGTON PUBLIC POWER SUPPLY SYSTEM NULCEAR PROJECT NOS I & 4 NORTH FAULT~ DEBRIS

,I DEBRIS GEOLOGIC SKETCH DEBRIS OF FINLEY QUARRY FAULT 2b DEBRIS DEBRIS i ., ~ ~

.I I I J 0 MAY, 1980 UE & C CONTRACT II 44013 0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 150 160 170 180 190 200 SH NN N & WILSON, INC.

APPROXIMATE SCALE IN FEET Geotechnscal Consultants FIG.2 Portland Ore on aO VS! C Lj 0 9 G Lr

i'EFINITION OF LINEAMENT ON LANDSAT PHOTOGRAPH h

U

,jci pi V' DEFINITION OF LINEAMENT ON Ii AMS SHEET xJ/,

0 DEFINITION OF LINEAMENT ON 0

7.5 AND 15 TOPOGRAPHIC MAPS AND ON LOW AI.TITUDE AERIAL PHOTOGRAPHS. (DASHED WHERE C'ii LESS DISTINCT)

SCALE Ir62500 0 1 4 Miles 0 I 2 3 4 Kilometers CONTOUR INTERVAL 20' 4:,r!e;...+ >~", ~'r,"'I'J KI( ~ .. '.'$ (N" g" ." -"'-I BASE MAP TAKEN FROM U.S G.S I,( ".'

j

~

OUADRANGLES OF 15'OPOGRAPHIC RICHLAND BADGER MOUNTAIN ELTOPIA PASCO AND CORRAL CANYON.

LINEAMENTS FROM WPPSS ( 1977)

AND THIS INVESTIGATION i=

qn'

~ a

,~'1 WASHINGTON PUBI.IB POWER SUPPLY SYSTEM NUCLEAR PROJKT NOS. I ~ 4 p, 's,l" x ', 4

', ',i'.

" i MAY, 1980 H N N Geotechnical LINEAMENT 8

Portland WILSON, TNC.

Con

~P UE & C CONTRACT~>>

ultants Ore on FI G 44013

. 7

f'ND i.

vl

'I;4 ', VQQ ', I ,

1 ~

35'TRIKE AND DIP Alluvial Xl sand and gravel TERRACES APPROXIMATE ELEVATIONS t If'( FAULT WITH VERTICAL DISPLACEMENT, - 600' T4

~

U ON UPTHROWN SIDE Alluvial fan deposits - 500' AXIS OF FOLD, DASHED WHERE APPROXIMATE,

& iy tk t7 1' 3/() '

I I

'4 e D

DOTTED WHERE CONCEALED

- 340' Active dunes A

A'OCATION OF GEOLOGIC CROSS-SECTIONS SHEAR ZONE Stabilized dunes 1', SCALE I:62, 500 CC Landslide debris 0 I 2 3 4 CL M les I

<l C7 Loess 0 I 2 3 4.

silt of Kilometers Light brown, wind-blown various ages.

CONTOUR INTERVAI.

20'D Touchet beds of the Glaciofluvial deposits Light gray and brown, bedded silt w th a network of clastic d~kes.

,0 f 15' Locally includes channel sand and Glaciofluvial deposits BASE MAP TAKEN FROM U.S.G.S. gravel, and reworked colluvium along undifferentiated TOPOGRAPHIC OUADRANGLES OF RICHLAND, narrow canyons ( 13,000 ybp).

DGER MOU NTA IN, ELTOPIA, PASCO

+Qk f 0

2 CORRAL CANYON.

t Pasco ZI gravel of the Glaciofluvial Kennewick fanglomerate

.11 deposits

(( OQ.

Ringold Formation undifferent ated WASHINGTON PUBLIC POWER SUPPLY SYSTEM W

NUCLEAR PROJECT NOS. I ~ 4 C) Ti Tw Tem Tp Tu tl'L Saddle Mountains Basalt of the CEOLOGIC MAP W Yakima Basalt Subgroup OF KENNEWICK-COLD CREEK (y Z:

W

~o Ti, Ice Harbor h1ember (B.S mybp) LINEAMENT AREA Tw, Ward Gap Member ~~Y, 19BD UE & C CONTRACT ~ 44013 Tem, Elephant Mountain Member ( 10.5 mybp)

SH W Tp, Pomona Me~her (12.5 mybp) Geotechnical Consultants FIG, 8 Tu, Umatilla Member Portland Ore on