ML051440051

FAQ Log (Part 2) 4/28/2005, Att. 9

ML051440051
Person / Time
Site:	Nine Mile Point
Issue date:	04/28/2005
From:	Constellation Energy Group
To:	Office of Nuclear Reactor Regulation
Thompson JW, NRR/DIPM/IIPB, 415-1011
References
Download: ML051440051 (29)

Text

v -' , sti I . l FAQ Log (Part 2) 4/28/05 TempNo. PI Topic Status Plant/ Co.

52.1 IE03 Initiation of contingency 3/17 Introduced Nine Mile planning 4/28 Discussed Point 52.2 EP03 Crediting of siren testing 3/17 Introduced Kewaunee conducted at facilities that are 4/28 Discussed not normally attended 4/28 Revised 4/28 Tentative Approval 52.3 IE02 Loss of main feedwater flow, 3/17 Introduced River Bend condenser vacuum, or turbine 3/17 Discussed bypass capability caused by 4/28 Discussed partial loss of offsite power 4/28 Withdrawn 52.4 IE02 Loss of main feedwater flow, 3/17 Introduced River Bend condenser vacuum, or turbine 3/17 Discussed bypass capability caused by 4/28 Discussed partial loss of offsite power 4/28 Withdrawn 53.1 MS02 Equipment unavailabilitydue to 4/28 Introduced Palo Verde design deficiency 4/28 Discussed 53.2 EPOI Controller intervention 4/28 Introduced VogtIe Attachrent 9

FAQ 52.1 Submitted 2/14 by Terry F. Syrell Licensing Engineer Nine Mile Point Nuclear Station 315-349-7198 Terry.SyrellIconstellation.com Ouestion: As defined in NEI 99-02, unplannedchanges in reactorpower are changes in reactor power that are initiated less than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> following the discovery of an off-normal condition, and that result in, or require a change in power level of greater that 20% of full power to resolve. The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> period between discovery of an off-normal condition and the corresponding change in power level is based on the typical time to assess the plant condition, and prepare, review, and approve the necessary work orders, procedures, and necessary safety reviews, to effect a repair. The key element to be used in determining whether a power change should be counted as part of this indicator is the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> period and not the extent of planning that is performed between the discovery of the condition and the initiation of the power change.

Nine Mile Point Nuclear Station (NMPNS) Unit 1 performed a >20% downpower that commenced on 6/15/04 to swap power supplies on condensate pumps in order to exit a High Pressure Coolant Injection (HPCI) LCO action. The timeline leading up to the dQwnpower is as follows:

- 6/7/04. Condensate Pump 13 is removed from service for planned maintenance to repair gland packing problems. Condensate Pump 13 is part of HPCI train #12. A 15 day LCO is entered for the HPCI train being inoperable.

- 6/10/04. During maintenance, it was determined that the existing pump was unusable.

A contingency plan was implemented to replace the existing pump with an old rebuilt pump. A second contingency plan was started by plant personnel to swap out pump power supplies to make Condensate Pump 12 act as a HPCI pump. This would allow the station to exit the LCO and complete pump repairs on a normal schedule.

Swapping out power supplies required pump 12 to be removed from service which would require a planned downpower to 45% rated.

- 6/11/04. A Temporary Design Change Package was initiated to swap the HPCI power supplies.

- 6/13/04. The first contingency for installing a rebuilt pump was unsuccessful when the pump failed post-maintenance testing due to high running amps. The station then concentrated on implementing the second contingency plan.

- 6/15/04. The down-power to perform the second contingency plan began. The LCO was exited on 6/17/04.

The resident inspection staff questioned the off-normal condition that caused the power change. They considered the rebuilt pump PMT failure on 6/13/04 as the off-normal

FAQ 52.1 condition that resulted in the power change. Since the time from the PMT failure to the downpower was less that 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, the resident inspection staff considered the downpower unplanned.

In evaluating this event for reporting under the NRC ROP PI process, the Licensee concluded that the down-power was planned. The basis for this position is as follows:

The initial "off-normal" condition was the degraded gland packing on the Condensate pump. This condition necessitated removal of the pump from service to implement repairs. The pump was removed from service and the appropriate Technical Specification LCO was entered on 6/7104. It was this "off-normal" condition that ultimately led to the down-power that occurred on 6/15/04. Since the down-power was more that 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> after the corrective maintenance evolution was initiated, it was classified as "planned."

Should the power change described above be counted in the ROP Performance Indicator for Unplanned Power Changes per 7,000 Critical?

Proposed Answer (Recommended). No. The degraded gland packing constitutes the "off-normal" condition that ultimately resulted in a down-power. Since the time between the initiation of the corrective maintenance activity and the down-power was >72 hours, the downpower is considered "planned."

Alternate Answer. No. The time that the station recognized that alternate methods of repair might be required and that one of the methods would require a down-power constitutes the "off normal" condition as described in NEI 99-02. Since the time between the initiation of contingency planning and the down-power was >72 hours, the downpower is considered "planned."

FAQ 52.2 FAQ TEMPLATE Plant: -Kewaunee Nuclear Power Plant Date of Event: -_none Submittal Date: -March 4, 2005 Licensee

Contact:

Tel/email:

NRC

Contact:

Tel/email:

Performance Indicator: Alert and Notification System (ANS)

Site-Specific FAQ (Appendix D)? No FAQ requested to become effective when approved.

Ouestion Section On January 13, 2005 the NRC transmitted the results of an inspection conducted at Davis-Besse Nuclear Power Station related to a discrepant ANS Reliability Performance Indicator. The inspection report concluded that some siren tests could not be counted because they were performed from a licensee test point that was not normally attended.

NEI 99-02 Guidance needing interpretation Page 95 Lines 19 Specifically lines 27 and 28 listed below and Line 25 and 26 in the NEI Document "Siren systems may be designed with equipment redundancy or feedback capability. It may be possible for sirens to be activated from multiple control stations. Feedback systems may indicate siren activation status, allowing additional activation efforts for some sirens. If the use of redundant control stations is in approved procedures and is part of the actual system activation process, then activation from either control station should be considered a success. A failure of both systems would only be considered one failure, whereas the success of either system would be considered a success. If the redundant control station is not normally attended, requiressetup or initialization, it may not be consideredas partof the regularlyscheduled test. Specifically, if the station is only made ready for the purpose of siren tests it should not be considered as part of the regularly scheduled test."

Event or circumstances requiring guidance interpretation:

BACKGROUND: The Kewaunee siren testing procedure, states that Kewaunee County or Kewaunee Count Sheriff's Department will initiate all actual or systems tests that are needed. The procedure also states that the tests are alternated between the two entities.

The Sheriff Dispatch is manned continuously and the Kewaunee County Emergency Operations Center (EOC) is manned during most normal business hours and declared emergencies. As previously stated, both locations are expected to be able to activate the sirens. Hence the process for testing the sirens from both locations since either may be

FAQ 52.2 required to activate the sirens. This FAQ has generic implications because many county Emergency Operations Centers (EOCs) are not co-located with the dispatch centers and therefore, not normally attended .

The guidance in NEI 99-02 pertaining to the counting of tests from redundant control stations that are not normally attended could be interpreted to apply to any facility conducting a siren test and not just a specific licensee facility. The Kewaunee County EOC is not maintained for the purposes of siren testing but for the purposes of planned emergency response. This would result in excluding tests conducted at the Kewaunee County EOC and other EOCs not co-located with dispatch centers. In most situations, the EOC is the most probable location for an actual activation of the system in emergency conditions. When an emergency situation escalates the EOC is staffed and performs as the Emergency Center. If situations continued to deteriorate the ANS system would generally be activated from the EOC. Prohibiting testing from this facility could potentially reduce the reliability of the system most likely to be actually used.

Potentially Relevant Existing FAQ: 358 The following in an excerpt from FAQ 358, (emphasis in italics):

Q: Can the licensee modify the ANS testing methodology when calculating the site value for this indicator?

A: Yes. Page 95, lines 19-23 of NEI 99-02 will be modified as follows:

Changes to the activation and/or testing methodology shall be noted in the licensee's quarterly PI report in the comment section. Siren systems may be designed with equipment redundancy, multiple signals, or feedback capability. It may be possible for sirens to be activated from multiple control stations or signals. If the use of redundant control stations or multiple signals is in approved procedures and is part of the actual system activationprocess, then activationfrom either controlstation or any signal should be considereda success.

Question:

May siren testing conducted at faeilities redundantcontrol stations, such as county EOCs, that are not normally attended staffed duringan emergency by an individual capable of activatingthe sirens be credited in the ANS PI?

Proposed Response:

Answer: Yes. If the redundantcontrol station is in afacility that is staffed duringan emergency by an individual capable of activatingthe sirens, then it is consideredto be normally attended. The restriction on crediting redundant control stations was intended tc apply to control stations that are not normally attended in an nmeryene for purposes ef aetivatien.

IFAQ 52.3 I ; A n+ rkllk/-rD Mr'lrl% CTATrlrl Lzmtjus M/rdiaM; rMlvaF -- lu.- I f ItM IWM Datc of Event: October 1' FAQ Submittal Datc: February 3, 2005 Licensee

Contact:

Robert L. Biggs Tcl/email: 225 381 3731!/rbiggs@cntcrgy.com NRC

Contact:

Pcter Altcr, RBS Senior Resident InSpectoF Tel/email: 225 381 4566

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aype Or I-AU Kequestca: ucneri Effcctivc Date: FAQ requested to become effeetivc on issuance NEI 99-02 Guidance Needina-Intcrprctation IureMnt nonormanscR indicator PIl RnRcA PrAviidr' Mt TfoiiAMInn i mcasurcs bv

- -j which a licensee can interpret a scam that must be evaluated as a potential input to the Unplanned Scrams With a Loss of normal Heat Removal performance indicator.

• NEI 99 02 Revision 2 defiRe6 a Loss of the normal heat renmovl path (Power Conver6ionR Systemn!C!S) as: when any of4 the following conditioRs have vaae yr rl r 7 .-.- ~ fk r wrJv, r,- rr wrv if rr 9GGUrorl and GR-nnot be teaoly Feoneveoe frrn.M thPGAortFO FGGrrR zWithG+th nRed for deai.snnn or rFneair to restore the normal heat removal pgath:

epcomplete loss of all main fcedwater flow oinsufficient main condenser vacuum to remove decay heat ccnmplete loesure of at least one MSIV 'i each main steam line ofailure of turbine bypass capacity that results in insufficient bvoass capavility remaining to maintain reactor temperature and pressure eThe guidansc vI. further provides that opervator actions or design . features to control MP valvce refacMr cooPFown o- clsin.- l MS ralc

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I FAQ 52.3 an off normal condition or for thc saf*ty of personnel or equipment (e.g.,

cloinGOf MSIV_ to isolate a steam leak) are rcForted-.

NOTE: Thc key message here is the nced to be abic to rapidly recover PCS from the control room without the nelod for diagnosis OFrrepair. No crdit is considered for mitigation actionS oeutide of these guidelincs by NEI 90 02 Revision 2.

• NEI 99 02 Revision 2 also states that the following examples do not count:

loss of all main feedwater flow, condenser vacuum or turbine opartial losses of condenser vacuum or turbine bypass capability after an unplanned scram in which sufficient capability remains to remove deGay heat.

Noto: Additional examples cxcluded due to non applicability to this issuc.

The River Bend Station Partial Loss of Offsite Power event of October 1, 2004 that ultimately resulted in a reactor scram and a loss Of normal heat removal would not count in the perfbormance indicator proces except as an unplanned scram. This is becausc of the following:

I .Thc flash over/failure of insulators nn inconming feed line! main gencrator line at the station resulted in electrical fault pr-otectin actuations. These actuations resulted in protective tripping of the unit main generator that initiated a scram.

2.Fecd water pumps were lost due to partial loss of offsite power ('A' directly and 'B' and 'C' duetoloss Of ondenRsate supply due to poweFr loss) 3.Condenswr vacuum was lowering because of a 1los of condenser circulating water. Two of the three main condenser circulating water pumpS (CWS) in screice before the event shut down due to loss of power. The output of the remaining pump was Shoet Gyeed through the diScharge of the idle pumps due to the loss of power to their discharge valves.

This positioR is consistent with the response to FAQ #355. The respnse is Th¢ carifying notes for this pcfformance indicator exempt Fcramn resulting in loss of all main fce dwater flow, condenser vacuum, or turbine bypass capability caused by loss of offote power-. Thore is no dtnctinoRGn madeor impferd regardin a complte or partial lose of offtite power. In this case, whie the 8loss of -offite power was not a complete less, the loss did affect the feedwater, condensate and condenser systems."

l FAQ No. Page 4 of 6

lFAQ 52.3

.Event desr On October 1, 2004, at 7:17 a.m., a flash over occurred in the 230kV station transformer yard across a post insulator. This caused the loss of Rescrve Station SeArice (RSS) Nc . 1, vWhih iRterrupted power to the Divis ioR 1 standby bus. The Division I diesel generator sta-ted auteomaticAly and restored power to the bus. This event also interrupted power to the "A" reactor protection system (RPS) bus. Operators responded to this event by restoring power to the "A' RPS bus and resetting the half scram.

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4 7sg.v. a second flash over occurred aross a 2

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the maiR generator line, resultin in a maein nerater trip and main turbine The main generator trip combined with the loss of RSS no. 1 resulted in the trip of two mn condensate pumps an d one main feedwater pump. The remaining two feedwater pumps tripped on loW suction pressure following the lors of the rcondenate pumps. Ten mFaiR steam safety relief valves (SRVs) actuated automatically during the pressure transient resulting from the main turbine trip. SRVs were subsequently cycled manually to control reactor pressure and to aid in achieving cold shutdown.

TAwo of the three main ondeRnser crcOulating water pumps (cWS) i;n seGiee before the event shut down due t leoss of power. The output of the remaining pump was short cycled through the diScharge of the idle pumps due to the loess of power to their discharge valves, diverting flow from the main condenser. It was not possible to maintain main condenser vacuum, and the operators maRnually cos1ed the outboard main steam isolation valves, and then ceyled SRVs as Reeded to control reactor pressure.

Pr-opIsdT FA Answef:

The scram described here does not count as a scram with loss of normal hear removal. There is no distinction made or implied regarding a complete or partial loss of offsite power. In this case, while the loss of offsite power was not a complete less, the loss did affect the feedwater, condeRsate and onRdenser systems (vac~uum).

Do the licensee and NRC resedent/Recdon aciree on faots and circumstanscs? Ycs I FAQ No.___ Page 4 of 5

lFAQ S.3 Potentiallv relevant existinn FAQ numbers: 282, 249, 248, 65, 351, 3554 FAQ 1355 Question Our plant automatically SGramemd at 0918 CDST on 412412003 due to a turbine trip from a load reject. Breakers opened in both the local switchyard and in remete vWitchyards that removed all paths of gencration onto the grid and offsitc power to the power conversion system. At the time of the scram, there was a severe thunderstorm in the vicinity. High windS caused a closure of an open disRonect into a grouRded breaker underon going maintenance. This loGkout coRdition led t protective relayirng atuatiRng to isolate the fault, and caused the load reject.

During the event, Division 1, 2 and 3 Diesel Generators (DGs) started and e their respective safet' busses. All safet' 6ystems fuRnctined as designd -andresponded properly. DuROin this transient, no deviations were noted in any safety funrtions. Offsite power was automatically restored to the East 500 KV bus, the main turbine output breaker opened aRd the fault was eonc cleared. The West 500 KV bus, which was undergoing maintenance at the time of the event, remained deenergized. While all three DGs started and Supplied their buses, this did constitute a design bases Loss Of Offsite Power (LOOP) and ar emrngeRny declaration ofn u nRusual event because orne of the three eorUces of off site power (a1 15KV liRe to Engineered Safety Featulr (ESF) TraRsformne 12 (ESF12) remained energized and was available throughout the event. Any of the three ECCS buses could have been transferred to this source of power at any time during the event. Based on the above considerations, it is concluded that this event would be best nodeled as a T2, or Loss of PCS (Power ConversioR System), initiator. A T2 initiator resutRs in the lossof the power cvcscirn systems (feedwatre, oendenser, and condensate) and the modeling of this event does allow for recovery of the power conversion systems.

Under the current Revision 2 of NEI 99 02, does this Scram count as a Scram with Loss of Heat Removal?

Responsc No. The clarifying notes for this peformance indicator exempt scrams resulting in loss of all main feedwater flow, Gondenser vacuum, or turbine bypass Gapabilit' caused by loss of offitc power. There is no distinctiR nmade or implied regarding a complete or partial loss of offsitc power. In this case, while the loss of offsite power was not a complete loss, the loss did affect the feedwater, condensate and condenser systems.

fevslo-G MslrfiA fl) IA+ ~~f4onal shet K reu-4 Revise NEI 99 02R2, Page 16, line 41 as follows:

1 FAQ No. 355 isthe most relevant to this particular circumstance although the others substantiate existing guidance that is being referenced inthis FAQ.

I FAQ No.___ -Page Pg-e64 of 6

I FAQ 52.3 "Thore io no 6sntioin maci or irnpiaed roegardig a orn pleto or parall lass tf offsite pawor, W-hie a loss of offsite PoAre may net bceeaomct less, the lass did affect the feedwater, condensate and condenseFr yste's.^

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Licensee

Contact:

Robert L. Biggs Tellemail: 225 381 373 l/rbiggs~entergy.com NRC

Contact:

Peter Alter, RBS Senier-Resident Inspecter TelIemail:.225 381 4566

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=t - . __ I=_ T I ' I' ,_ I EfLItCvC mate: FAQ requestea to be.orne cffct.ve on issuance NE! 99 02 Guidanee Needine interovetation CufFent performance indieator guidanee provides the following key measures by which a licensee can interpret a scram that must be inaluated as a potential input to the Scrams Wishf -O A r... ogn _4PM6 Aeat_Rege-Q npflfrf-nanpp i-1;Jip+s-.

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nofa!ets eeAmpAeie less of all main feedAater flow oinsufficient main condenser vacuum to remove decay heat zeomplee closur-e ^f at least one MSIV, in each main steam line

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• The guidanee further pro-vides that operetor aeteone or designfeatures to conr oJ'the reacorcooldoen rate or water level, such as closing the main feedwater valves or closing all MSIVs, are not reported in this indicator as long as the normal heat dian or en pai. oeveil reeperator ac tin to mitigate an off nhu condieetion diagnosis or repair. However-, eperater actions to mitigate an off normal condition

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I FAQ 52.4 rI , r I {_ _1I; _I sj~ors 1 Ai vIs to isoatae a I

or for-me sater: of nersonnc or quipment (CAf. --o I closinig -- o stcam leak- -a --repocd steA leak)Z aIe .eported

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- svvWs5- s ultimately resulted in a reactor scram and a lOss of normal heat removal would not count in the per-foanee indicator; p rocess Ax ept as an unplanned scram. This is because ct te fellewifgt r rr +^

s l The scram ultimately resulted Wfom a partial loss e otetsite power 2.Condensate and feedwater were affected by the partial less of offsite pow1 er 3.Condeiser V^ - V- JI-vacuum --- " ~----

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4.MSIVs were operated consistent with eood operational practice and procedure e.e..

- - ._ --. _-- I I b A  ; n+IAA-A Evet tseipio At 4:05 a.m. on August 15, 004, with the plant operating at 100 pereent power, an automatic reactor scram oceurred as a result of a main generator trip and subsequent main turbine trip. The 2301cv, oil circeuit br-eakers at the River Bend switchyarfd (irnown as Fancy Point) responded to a fault signal en the 230k1v transmission system remote from the switchyard. The fault was initiated by the failure of a guy wir. leading to a stct ral failure of aV23 0ev, transmiVssi n vtosr.

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- v-v- vi"-i.i .WiWi]ivi-i operation of br-eaker baelcup protection and led to the loss of one of the two main generator output breakers and loss of power to the Division 2 standby switchgear, as well as parts of the balance of plant electr-ical system. The Division 2 diesel gener-ator- started as designed and resto-red power to its swvitchgear-. In addition, the ground fault protection system for the main generator step up transformers aetuated due to the delay in the fault clearing time. This resulted in the trip of the remaining Eenerator output breaker.

I a xempli gratia l FA,4Q No. Pog I ofA

IjFAQ 52A4 The main generator trip signal initiated a turbine trip signal, which then initiated the reactcr scram. The turbine tip caused an expected reactor pressure transient that caused the actuation of all sixteen arelief valves.

Two reactor feedwater pumps shutdown at the time of the scram due to lass of their power supplies. The remaining "A" main feedwater pump tripped automatically at approximately 4:35 a.m. when reactor water level reached the high alarm setpoint.

The rtr oe isolation coling (RC) system was initiated manually following the loss of the third main reactor feedwater pump.

The inboard main steam isolation valves were closed manually in anticipation of a loss of main condenser vacuum. Main condenser mechanical vacuum pump "B" was unavailable due to the loss of power, and the "A" mechanical vacuum pump failed to statn due to a fauilty relay in its feeder breaker. The lossof both mechanical vacuuim pumps (one due to failure and the other due to the loss of power) resulted in a lowering condenser vacuum. Main steam safety relief valves were subsequently cyeled manually to assist in controlling reactor pressure. The outboard main steam isolation valves were elosed to maintain the reactor eooldown rate within limits.

The "A" feedvwater pump could not be immediately r-estanted due to a loss of instrumentation power which disabled permissive interlocks required for the pump stafr sequence. Power was subsequently restored to the affected instrument buses and to the motor operated valves in the feedwater reglating system.

The Fancy Point switchyard provides the connection to the effsite grid for the main generatfr, as well as the two independent surces of off-site powervto the plant's safety related buses. The switchyard eontains the two 230kv buses, referred to as the North and South buses. The switehyard provides the connections to the 230kE transmission lines entering and leaving the switchyard, as well as the River Bend generator. There are four 230kv lines exiting the station connecting to the transmission grid, two lines 'which provide offsite power to River Bend and a main generator output line. The circuit breaker arrangement allows the two River Bend ff-site power-lines, the main generator line, and three of the foar lines exiting the switehyard to be cannected to either the North or South bus. The remaining line exiting the station can be connected only to the North bus.

The initiating event for-the fault in the Fancy Point switehyar-d was the failuire ofa uy wire on a 230kV transmission tower on one of the four transmission lines south of the sit. The guy wir-e failuar-e allowed the pole te collapse and lean ov casing a phase to ground fault. The faulted line connects only to the Fancy Point norh bus.

The associated circuit breaker at Fancy Point received a trip signal to clear the fault, but its operation vwas slow, resulting in actuation of the back up breaker protection.

All other circuit breakers on the North bus were tripped by the back up protection system, but two of these also operated slowly. The fault was eventually isolated, but the River Bend main generator step up transformer ground fault protective relay it, .I Err2 I rFAQ MIFA9

IFAQ 52A4 had already actuated due to the extended fault duration. The actuation of this relay r-esulted in the main gener-ator trip, which in turn caused the main turbine trip and a r-eactor scram.

The strctural failure of the 230kv tower also caused a second, short duration fault on a second line, adjacent to the faulted line, when the static line attached to the top of the failed stfrneur-e broke and momentar-ily contacted or-other-wise violated minimum clear-ance for-the "C" phase. The br-eaker for-this line also operated s en. 2 and loss of power to the Division 2 safet' related bus.

fDl------ Af A" rn..

rsurEcu rewu ts1Es.r-.

The scram described here does not count as a scram 'with loss of normal hear removal.

There is no distinction made or implied regarding a complete or-paial ls of offNiie power. In this ease, while the loss of offsite power was not a complete loss, the loss did affect the feedwater, condensate and condenser systems (vacuum).

Do thcelieensee nnd NRC-r-esident/Rceion avreeon facts andecir-eumstanees? Yes flt 14,r.nAYALS!A NT13 ripAr ..-

n tner Q A

nn i -n.nC r nnnc9 Potentially relevant existingF numbers: 282, 219, 218, 65, 354, 35_

F,1Q ff355 Question Our plant automatically scrammed at 0948 CDST on 4/24/2003 due to a turbine trip from a load reject. Breakers opened in both the local switchyard and in remote power conversion system. At the time of the scram, there was a severe thunderstom in the vicinity. High winds caused a closure of an open disconnect into a grounded breaker under on going maintenance. This loclkout condition led to protective relaying actuating to isolate the fault, and caused the load reject.

During the event, Division 1, 2 and 3 Diesel Generators (DGs) stanted and energized their r-espective safet' busses. All safeg' systems ffinctioned as designed and r-esponded proeper-ly. Daring this transient, no devain eentdi n safiety functions. Off-sit-e power was automatically restored to the East 500 KV!bus, once the main turbine output breaker opened and the fault was cleared. The West 500 KV bus, which was undergoing maintenance at the time of the event, remained deenergized. While all three DGs staIed and supplied their buses, this did constitute a design bases Loss Of Off-site Powe (LOOP) and an emergency declaration of an unusual event because one of the thfee sourees of off site power (a 115KV line to Engineered Safety Feature (ESF) Transfomer 12 (ESF12) remained energized and 'was available throughout the event. Any of the three ECCS buses could have been tfansfenfed to this source of power at any time during the event. Based on the above consider-ations, it is concaded that this event would be best 4 FAQ No. 355 is the MOst relevant to this paiC-Ular circumstance although the others substantiate existing guidanee that is being refcrenced in this FAQ.

FAQ No. Page 1 of 5

FIAQ52.4 mnodeled as a T-2, or Less of PCS (Power-Conversion System), initiator. A T2 initiator results in the loss of the power conerio systems (feedwater-, eondenser-, and condensate) and the medeling ef this event does allowy, for recovery of the power conversion systems.

Under the current Revision 2 of NEI 99 02, does this Scram count as a Scram with Loss of Heat Removal?

Rcsponse No. The clarifying notes for this performanee indicator exempt serams resulting in less of all main feedwater flow, condenser vacuum, or turbinc bypass capability caused by loss of offsite power. There is no distinction made or implied regarding a complete or pafial loss of offite power. in this ease, while the less of off it pow.er was net a complete loss, the loss did affect the feedwater, condensate and eondeasef systems.

Prevosed Resolution of NE! 99i 02 uidaneso attaoh swsr:ate mark NEI 99 02 wordine (Attseh additional sheets if rmquired):-

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D^A- I A C I FAQ N. -

FAQ 53.1 Plant: Palo Verde Units 1, 2, and 3 Date of Event: Initial plant operation Submittal Date: 03/25/2005 Licensee

Contact:

Duane Kanitz Tel/email: (623) 393 5427 /

dkanitz@apsc.com NRC

Contact:

Greg Warnick Tel/email: (623) 393 3737 / gxw2@nrc.gov Performance Indicator: Mitigating Systems - HPSI Safety System Unavailability Site-Specific FAQ (Appendix D)? Yes ori)

FAQ requested to become effective when approved or N/A Question Section NEI 99-02 Guidance needing interpretation (include page and line citation):

NEI 99-02 revision 2, page 33, lines 8 through 23 8 Equipment Unavailability due to Design Deficiency 9

10 Equipment failures due to design deficiency will be treated in the following manner:

11 12 Failures that are capable of being discovered during surveillance tests: These failures should be 13 evaluated for inclusion in the equipment unavailability indicators. Examples of this type are 14 failures due to material deficiencies, subcomponent sizing/settings, lubrication deficiencies, and 15 environmental degradation problems.

16 17 Failures that are not capable of being discovered during normal surveillance tests: These failures 18 are usually of longer fault exposure time. These failures are amenable to evaluation through the 19 NRC's Significance Determination Process and are excluded from the unavailability indicators.

20 Examples of this type are failures due to pressure locking/thermal binding of isolation valves or 21 inadequate component sizing/settings under accident conditions (not under normal test 22 conditions). While not included in the calculation of the unavailability indicators, these failures 23 and the associated hours should be reported in the comment field of the PI data submittal.

Page 1 of 6

FAQ 53.1 Event or circumstances requiring guidance interpretation:

Safety Injection Diagram (Simplified)

Refueling Water Tank C

S Check MOV Valve Low-Pressure Safety Injection Pump (Stops on RAS)

Containment *Outside Check Isolation Valve Containment Valve (Inboard) Isolation High-Pressure Safety Valve Injection Pump (Outboard)

• Opens on a recirculation actuation signal (RAS)

In July 2004 Palo Verde Engineering identified a concern that an air pocket existed in the safety injection recirculation suction piping between the containment sump inboard and first check valve downstream of the outboard isolation valves. This section of safety injection suction piping is used following a Loss of Coolant Accident (LOCA) when the system shifts to recirculation mode. Engineering determined that the air in this unfilled section of suction piping could potentially be drawn into the High Pressure Safety Injection (HPSI) pump and the Containment Spray (CS) pumps when the system shifted to recirculation mode, following a Recirculation Action Signal (RAS), and potential affect the operability of both the HPSI and CS system.

During a LOCA, when large quantities of water escape the reactor coolant system, water is injected into the core from the Refueling Water Tank (RWT). When the water level in the RWT gets to an identified low point, a RAS allows reactor cooling to continue by recirculating the water that has collected in the containment sump.

Page 2 of 6

FAQ 53.1 Palo Verde took the initial corrective action of providing a step for operators to open the inboard valve in the event of a loss of coolant accident. This would draw water from the sump and fill the line between the inboard and outboard valves and displace the air in the pipe. Engineering believed that the additional approximately 10 cubic feet of air between outboard isolation valve and the downstream check valve would not prevent water flow through the HPSI and CS systems.

To mitigate the need for operator action and place the units in a safer condition, the sumps and the entire length of pipe between the sump and the safety injection pumps were filled to remove any air pockets. Palo Verde units 1, 2, and 3 are currently maintained in this condition while Engineering completes its analysis and determines what permanent modifications, if any, are required.

As part of the Palo Verde incident investigation, a very comprehensive evaluation was performed to determine how the system would have operated if called upon and determine the significance of the design configuration deficiency. The evaluation included a scale model test and a full scale test. The tests were performed in two distinct steps. First, the scale model test was performed to demonstrate that the behavior of the air in the piping could be determined. This test was performed at Fauske and Associates. Once the behavior of the transient was determined and verified through sensitivity testing, the output of the scale model test was "scaled up" and used as an input to the full scale testing performed at Wyle Laboratories in December 2004. The full scale test was performed to determine the impact of the flow of water and air on the performance of the actual pumps used in the plant.

Based the tests and analyses, Palo Verde concluded that under certain accident scenarios, the HPSI system may not have been able to deliver sufficient flow to perform the required system safety function and therefore was considered inoperable from initial plant startup. However, the CS system was able to perform the required system safety functions and was considered operable. The incident investigation determined that several causes contributed to the condition which included:

A breakdown in communicating the design requirement to the end user in that the documents used as references for writing the operating and test procedures did not include the requirement to maintain the sump line in a filled condition.

The Palo Verde Technical Specifications only required verifying full the discharge piping and did not mention the suction piping.

The design of the system did not facilitate filling this section of piping.

Page 3 of 6

FAQ 53.1 Because the engineering evaluation had not yet been completed, Palo Verde included the following notes in the third quarter 2004 NRC performance indicator submittal for the HPSI and Residual Heat Removal (RHR) systems respectively:

Engineering evaluation of HPSI unavailability due to air in containment recirculation sump piping is pending.

Engineering evaluation of RHR unavailability due to air in containment recirculation sump piping is pending.

In the fourth quarter 2004 NRC performance indicator submittal, after the engineering evaluation results were known, Palo Verde included the following notes with the HPSI and RHR system unavailability data:

An engineering evaluation of HPSI unavailability due to air in the containment recirculation sump piping determined that the HPSI system may not have been able to perform its safety function in response to certain accident scenarios. The deficiency was not capable of being discovered during normal surveillance testing and as such is a design deficiency. The design deficiency has existed since initial plant operation. The condition is being evaluated under the NRC's Significance Determination Process and the associated fault exposure hours are not included in the calculation of the unavailability indicator in accordance with the provisions of NEI 99-02, "Equipment Unavailability due to Design Deficiency."

An engineering evaluation of RHR unavailability due to air in the containment recirculation sump piping determined that the RHR system was able to perform its intended safety function. No design deficiency existed. As such, no fault exposure hours are included in the calculation of the unavailability indicator.

No fault exposure hours were reported in the data that affected the performance indicator for the HPSI system because, as indicated in the submitted note, Palo Verde considered this a design deficiency that existed since initial plant startup. The condition was not capable of being discovered during normal surveillance testing because Palo Verde intentionally operated with the containment suction line unfilled and the Palo Verde Technical Specifications only required that the HPSI pump discharge piping be verified full. There are leak rate surveillance tests and valve stroke surveillance tests performed on the inboard containment sump suction valve. However, since Palo Verde intentionally operated the system with the suction piping unfilled and the Palo Verde Technical Specifications had no requirement to verify that the suction piping was full, the leak rate and valve stroke surveillance testing would only verify that the inboard containment sump valve seated tightly. The testing results would not discover that the HPSI system was inoperable as a result of the containment sump suction piping being left in an unfilled condition.

Page 4 of 6

FAQ 53.1 While Palo Verde was conducting the incident investigation and engineering evaluation, the NRC performed a special inspection in response to the discovered design configuration deficiency. The NRC characterized the condition as an apparent violation of 10 CFR Part 50, Appendix B, Criterion Ill, 'Design Control." The finding was further characterized as more than minor with potential safety significance (i.e. greater than green) based on a Significance Determination Process, Phase 3 analysis because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events.

The change in core damage frequency value based on assumptions from the NRC SPAR models was 2.5e-5 (which equates to a yellow finding). The change in core damage frequency value based on assumptions using Palo Verde's PRA was 7.0e-6 (which equates to a white finding.)

Should fault exposure hours be included in the performance indicator calculation for HPSI?

If licensee and NRC resident/region do not agree on the facts and circumstances explain The NRC resident/region do not agree that the condition as described can be considered an "equipment failure" as referenced in NEI 99-02 revision 2, page 33, line

10. Furthermore, the NRC resident/region do not agree that Palo Verde was unable to discover the condition during the performance of normal surveillance tests (i.e. the leak rate and valve stroke surveillance testing would have been able to discover that operating HPSI system with containment sump suction line unfilled would have prevented the HPSI system from performing the system safety function by either performance of the testing or during the process of revising the test procedures.) Note that in 1992, the leak rate and valve stroke test procedures were revised to drain and operate with the containment suction piping unfilled following performance of the leak rate test.

Therefore, fault exposure hours must be reported and included in the HPSI performance indicator calculation.

Potentially relevant existing FAQ numbers: 316 and 348 Response Section Proposed Resolution of FAQ Page 5 of 6

FAQ 39.1 No. The increased accumulation of gracilaria in the river water was anticipated because of the high salinity levels in the river, but the timing of the graciliaria release into the intake canal could not be predicted greater than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in advance. In addition, the actions to be taken in response to the high salinity levels in the river water were proceduralized.

FAQ 40.2 The answer to your question is as follows: A safety system train may be considered available if it is capable of meeting its design basis success criteria. In addition, support systems for the train must be capable of meeting their design basis criteria. In this case, the support system is the Essential Services Chilled Water (ESCW) system. The guidance provides an alternative if the normal support system is not available, as follows: "In some instances, unavailability of a monitored system that is caused by unavailability of a support system used for cooling need not be reported if cooling water from another source can be substituted" (NEI 99-02, Revision 2, page 37, lines 23-25). The use of a fan rather than a cooling water source in place of the normal cooling water source does not meet the limitations. In addition, credit is not given for portable equipment installed temporarily to maintain availability of monitored equipment.

FAQ 40.3 No. NRC approval means a specific method or methods described in the technical specifications.

FAQ 40.4 Yes. The actions to recover from the equipment malfunction are uncomplicated, proceduralized, and accomplished from the control room by a qualified operator without the need for diagnosis or repair.

FAQ 50.2 No. For the purpose of excluding planned overhaul hours, valves are not considered major components.

FAQ 39.1 No. The increased accumulation of gracilaria in the river water was anticipated because of the high salinity levels in the river, but the timing of the graciliaria release into the intake canal could not be predicted greater than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in advance. In addition, the actions to be taken in response to the high salinity levels in the river water were proceduralized.

FAQ 40.2 The answer to your question is as follows: A safety system train may be considered available if it is capable of meeting its design basis success criteria. In addition, support systems for the train must be capable of meeting their design basis criteria. In this case, the support system is the Essential Services Chilled Water (ESCW) system. The guidance provides an alternative if the normal support system is not available, as follows: "In some instances, unavailability of a monitored system that is caused by unavailability of a support system used for cooling need not be reported if cooling water from another source can be substituted"(NEI 99-02, Revision 2, page 37, lines 23-25). The use of a fan rather than a cooling water source in place of the normal cooling water source does not meet the limitations. In addition, credit is not given for portable equipment installed temporarily to maintain availability of monitored equipment.

FAQ 40.3 No. NRC approval means a specific method or methods described in the technical specifications.

FAQ 40.4 Yes. The actions to recover from the equipment malfunction are uncomplicated, proceduralized, and accomplished from the control room by a qualified operator without the need for diagnosis or repair.

FAQ 50.2 No. For the purpose of excluding planned overhaul hours, valves are not considered major components.

FAQ 53.2 Plant: Vogtle Date of Event:

Submittal Date: 4/28/2005 Licensee

Contact:

Tel/email:

NRC

Contact:

Tel/email:

Performance Indicator: Drill/Exercise Performance Site-Specific FAQ (Appendix D)? No FAQ requested to become effective when approved Event Description During a recent drill at Vogtle, 9 minutes after an EAL condition had been met, the shift manager and shifty upervisor were still debating whether a "transient" had occurred and if the plant wx "stable'., in order to mlake a -ccisuu n die EMA. The controller than asked if.- I "transient was in progress." The shift manager said "yes" and declared an Alert. In its critique, the licensee identified that the controller may have interfered with the decision, and therefore, determined that no classification opportunity existed. The licensee claims that the opportunity for the shift manager to independently declare the event was removed when the controller "asked a question."

question If during the performance of a DEP PI opportunity, a controller intervenes in a way (e.g.,

coaching, prompting) such that the action interferes with an individual making an independent and correct classification, notification, or PAR, shall the DEP PI opportunity be considered a failure, success or a non-opportunity?

Proposed Response If a controller intervenes (e.g., coaching, prompting) with the performance of an individual to make an independent and correct classification, notification, or PAR, then that DEP PI opportunity shall be considered a failure.

77*). ._-

Page I of I

ID Cornerstone Pi Question Response Date Entered ID Cornerstone P1 Question Response Date Entered 382 Initiating Events IE01 On November 22, 2003, Salem 2 initiated a reactor startup at 2210 following refueling. No. This event does not need to 04/28/2005 The reactor was declared critical at 0106 on November 23, 2003. At 0226, low power be counted as an Unplanned physics testing began. Based on a review of information from the plant computer, the Scram. This PI counts the reactor was subcritical prior to this event. With low power physics testing continuing, a number of scrams while critical.

control rod dropped into the reactor core, causing the subcritical reactor to become During this event, operators more subcritical. At 0507, the Operating crew entered the abnormal procedure for a tripped the reactor after dropped control rod. Based on the reactor being in a subcritical condition, the abnormal determining the reactor was procedure directs all rods to be inserted. The procedure does not require all rods to be subcritical.

inserted if the reactor remains critical. At 0519, following a crew brief, the reactor was manually tripped per procedure as directed by the Control Room Supervisor.

NRC POSITION The NRC resident office has indicated that an unplanned scram should be counted for this event. The inspectors believe that the appropriate guidance in NEI 99-02, Revision 2, which should be followed begins on line 39 of page 12. This guidance states that the types of scrams that should be Included are: 'Scrams that resulted from unplanned transients, equipment failures, spurious signals, human error, or those directed by abnormal, emergency, or annunciator response procedures."

BASIS FOR NRC POSITION The inspectors considered that for the conduct of physics testing, the reactor was maintained critical or if subcritical, very near critical. In fact the main control room logs did not distinguish otherwise and only included a log entry stating that the reactor was critical. The inspectors also considered that many transients may actually render the reactor subcritical before the resultant scram is inserted. It is the intent of this Pi to count all unplanned transients that begin while the reactor is critical and result in an unplanned reactor scram. The November 23, 2003, manual reactor trip was Immediately preceded by plant conditions that maintained the reactor very near critical or critical.

PSEG POSITION This was not reported as an Unplanned Scram in November 2003 because the scram occurred while the reactor was subcritical. A review of the post-trip review and notification documentation indicate that both the Operations Superintendent and the Control Room Supervisor were aware of the fact that the reactor was subcritical prior to the trip and that there was a procedural requirement to Insert all rods if the reactor was subcritical as a result of the dropped rod. Tripping the reactor is a conservative method to insert the rods.

BASIS FOR PSEG POSITION PSEG utilized the following guidance from Section 2.1, Initiating Events Comerstone,

of NEI 99-02 to determine that the subcritical scram should not be counted:

• Page 11, Lines 24 - 26, Indicator Definition is the number of unplanned scrams during the previous four quarters, both manual and automatic, while critical per 7000 hours0.081 days <br />1.944 hours <br />0.0116 weeks <br />0.00266 months <br />.

• Page 11, Lines 28 - 31, Data Reporting Elements, instruct licensees to report the number of unplanned automatic and manual scrams while critical in the previous quarter

• Page 12, Lines 1 - 4, Calculation, demonstrates that the value for this PI is derived by multiplying the total unplanned scrams while critical in the previous 4 quarters by 7000 hours0.081 days <br />1.944 hours <br />0.0116 weeks <br />0.00266 months <br /> and dividing the result by the total number of hours critical in the previous 4 quarters

• Page 12, Lines 16 - 17, defines criticality as existing when a licensed operator declares the reactor critical. The scram in question occurred after the reactor was verified to be subcritical.

• Page 12, Lines 17 -19, states that there may be Instances where a transient initiates from a subcritical condition and is terminated by a scram after the reactor is critical and that these conditions count as a scram. The guidance specifically requires that the reactor must be critical at the time of the scram.

The relevant condition Is to determine if the reactor is critical at the time of the scram and, if so, is reportable under this PI.

• Page 12, Line 30 states that dropped rods are not considered reactor scrams.

• Page 13, Lines 4 and 9 state that an example of a scram that is not included in this PI is Reactor Protection System actuation signals that occur while the reactor is subcritical.

Should this event be counted as an Unplanned Scram?

383 Initiating Events IE03 NEI 99-02 specifically requests an FAQ for this condition: Anticipated power changes This event does not need to be 04/28/2005 greater than 20% in response to expected problems (such as accumulation of marine counted as an unplanned power debris and biological contaminants in certain seasons) which are proceduralized but change because the high cannot be predicted greater than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in advance may not need to be counted if vulnerability condition in the they are not reactive to the sudden discovery of off-normal conditions. The intake canal was being circumstances of each situation are different and should be identified to the NRC in an monitored, the response to the FAQ so that a determination can be made concerning whether the power change high vulnerability intake canal should be counted. condition was proceduralized, and the rapid accumulation of Event Descriptlon: On August 31, 2004, Unit 2 experienced a trip of the 2D debris was not predictable Circulating Water Intake Pump (CWIP). This caused a reduction in condenser vacuum, adevater han 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in

which was mitigated by a 21% power reduction. The CWIP tripped due to a high differential pressure on the traveling screen, (i.e., a moving screen upstream of the pump intake that removes debris and marine growth.) Increased accumulation of debris and marine growth on the traveling screens is an expected condition during extreme lunar tides, as was the case on August 31. Although the timing and potential vulnerability of the lunar low tide was known, it was not possible to predict if, or when, an excessive influx of marine growth or debris would occur.

The plant was in a 'high vulnerability' condition, meaning that conditions in the intake canal were more likely to challenge the traveling screens and CWIPs. The marine growth Is a particular nuisance in the summer months during periods of lower tides.

The Increased canal bottom temperature during these periods causes organic debris to decay at a higher rate and tends to produce more suspended solids inthe intake water.

Plant operating experience includes several instances when traveling screens have experienced high differential pressures and CWIP trips. For example, LER 2-1999-006,

'Automatic Reactor Shutdown Due to Condenser Low Vacuum Main Turbine Trip" documents a similar event. Mitigating actions have been taken, such as canal dredging; however, these changes must be compatible with state environmental water quality regulations. Therefore, changes to reduce traveling screen clogging, such as increasing the mesh sizing on traveling screens, are limited in their effectiveness.

On August 30, 2004, Unit 1 traveling screens received high differential pressure alarms. As a result, both units' traveling screens were placed in the "hand fast" position. The procedure for intake canal blockages includes steps for high vulnerability conditions, such as ensuring the traveling screens are operating in "hand fast" speed and reducing reactor power for a sustained high differential pressure. Both units' screens remained in this alignment throughout the event; however, the increase in the 2D screen differential pressure was too rapid to counteract with mitigating actions to prevent the pump trip.

FAQ 54.1 Plant: Catawba Nuclear Station Units 1and 2 Date of Event: TBD Submittal Date:

License

Contact:

Kay Nicholson Tel/email: 803-831-3237 kenichol@duke-energy.com NRC

Contact:

Tel/email:

Performance Indicator: Mitigating Systems Cornerstone - Safety System Unavailability Site-Specific FAQ (Appendix D)? YES QUESTION SECTION NEI 99-02 Guidance needing interpretation (include page and line citation):

NEI 99-02, revision 3, page 27, lines 28 through 33 Event of Circumstances requiring guidance interpretation:

Catawba Nuclear Station (CNS) plans to refurbish the 'A" and 'B1 trains of the Nuclear Service Water System (NSWS) supply header piping. This refurbishment will occur with both Unit 1and Unit 2 at 100% power operation. CNS has submitted a Technical Specification (TS) change for NRC approval to provide for a completion time sufficient to accommodate the overhaul hours associated with the refurbishment project.

The proposed TS changes will allow the 'Aw and 'B" Nuclear Service Water System (NSWS) headers for each unit to be taken out of service for up to 14 days each for system upgrades. This will be a one time evolution for each header. System upgrades include activities associated with cleaning, inspection, and coating of NSWS piping welds, and necessary system repairs, replacement, or modifications. It has been estimated that the work required in taking the system out of service and draining the affected portions, will take approximately 1day. The affected sections of piping will be cleaned which should take approximately 3 - 4 days. After cleaning, this evolution will include inspection and evaluation of the NSWS piping. The inspection results will be evaluated for repairs and/or coatings for the welds. After inspection, the welds in the affected piping will be coated and allowed to cure. This portion should take approximately 6 - 7 days. Upon completion, Operations will be required to fill the NSWS, and perform any necessary post maintenance testing which should take approximately 2 days. Therefore, the total time should run from 12 - 14 days.

CNS desires to apply the overhaul hour exemption to the NSWS supply pipe refurbishment project.

The NSWS Improvement plan is divided into three distinct phases. The phase one of the plan specifically targets the stabilization of the welds in the NSWS supply headers. Phase one includes activities associated with cleaning, inspection, and coating of NSWS piping welds, and necessary system repairs, replacement, or modifications. Civil engineering evaluations of the longitudinal and circumferential welds in the supply headers have determined that the first priority area for the initial phase should be main buried 42 inch supply headers. These activities are being done to Page 1 of 3

FAQ 54.1 preclude any further degradation of the affected welds. This will allow the second and third phases of the NSWS Improvement Plan to commence with a predictable and reliable schedule.

Although the NSWS is not a monitored system under NEI 99-02 guidance, its unavailability does affect various systems and components, many of which are considered major components by the definition contained in FAQ 219 (diesel engines, heat exchangers, and pumps). The specific performance indicators affected by unavailability of the NSWS are Emergency AC, High Pressure Safety Injection, Residual Heat Removal, and Auxiliary Feedwater. NEI 99-02 states that

.overhaul exemption does not normally apply to support systems except under unique plant-specific situations on a case-by-case basis. The circumstances of each situation are different and should be identified to the NRC so that a determination can be made. Factors to be taken into consideration for an exemption for support systems include (a)the results of a quantitative risk assessment, (b) the expected improvement in plant performance as a result of the overhaul activity, and (c) the net change in risk as a result of the overhaul activity." The following information is provided in accordance with the NEI guidance.

QUANTITATIVE RISK ASSESSMENT Duke Power has used a risk-informed approach to determine the risk significance of taking a loop of NSWS out of service for up to 11 days beyond its current TS limit of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. The acceptance guidelines given in the EPRI PSA Applications Guide were used as a gauge to determine the significance of the short-term risk increase from the outage extension.

The current PRA model was used to perform the risk evaluation for taking a train of NSWS out of service beyond its TS limit. The requested NSWS outage does not create any new core damage sequences not currently evaluated by the existing PRA model. The core damage frequency contribution from the proposed outage extension is judged to be acceptable for a one-time, or rare, evolution. The estimated increase in the core damage probability for Catawba for each NSWS loop outage ranges from 2.7E-06 for a 2-day extension up to 1.5E-05 for an 11-day extension. Based on the expected increase in overall system reliability of the NSWS, an overall increase in the safety of both Catawba units is expected.

EXPECTEb IMPROVEMENT IN PLANT PERFORMANCE The increase in the overall reliability of the NSWS along with the decreased unavailability in the future because of the pipe repair project will result in an overall increase in the safety of both Catawba units.

NET CHANGE IN RISK AS A RESULT OF THE OVERHAUL ACTIVITY Increased NSWS train unavailability as a result of this overhaul does involve an increase in the probability or consequences of an accident previously evaluated during the time frame the NSWS header is out of service for pump refurbishment. Considering the small time frame of the NSWS trains outage with the expected increase in reliability, expected decrease in future NSWS unavailability as a result of the refurbishment project, and the contingency measures to be utilized during the refurbishment project, net change in risk as a result of the overhaul activity is reduced.

Page 2 of 3

FAQ 54.1 If licensee and NRC Resident/region do not agree on the facts and circumstances explain:

Not Applicable, NRC currently reviewing license amendment request to revise TS to allow for time necessary to perform overhaul of NSWS.

Potentially relevant FAQ numbers:

FAQ 178 & 219 RESPONSE SECTION Proposed Resolution of FAQ:

For this plant specific situation, planned overhaul hours for the nuclear service water support system may be excluded from the computation of monitored system unavailability.

Such exemptions may be granted on a case-by-case basis. Factors considered for this approval include (1)the results of a quantitative risk assessment of the overhaul activity, (2) the expected improvement in plant performance as a result of the overhaul, and (3) the net change in risk as a result of the overhaul.

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