ML102371282

Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3)

ML102371282
Person / Time
Site:	Kewaunee
Issue date:	08/18/2010
From:	Dominion Energy Kewaunee
To:	Office of Nuclear Reactor Regulation
References
10-457, TAC ME2139
Download: ML102371282 (74)

Text

ITS NRC Questions Id 1961 NRC Question Number KAB-073 Category Technical ITS Section 3.3 ITS Number 3.3.2 DOC Number L-4 JFD Number JFD Bases Number Page Number (s) 190 NRC Reviewer Supervisor Carl Schulten Technical Branch POC Singh Matharu Conf Call Requested N NRC Question BSI page 190 of Attachment 1, volume 8, the discussion of changes L04.

Provide a detailed description of the design of loss of voltage relay and degraded voltage relay schemes, including number of channels, for safety related buses and the reactor coolant pump busses.

Attach File 1 Attach File 2 Issue Date 5/7/2010 Added By Kristy Bucholtz Date Modified Modified By Date Added 5/7/2010 10:14 AM Notification NRC/LICENSEE Supervision Page 1 of 1 Kewaunee ITS Conversion Database 06/24/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=1961 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 1 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 1 of 74

Licensee Response/NRC Response/NRC Question Closure Id 3351 NRC Question Number KAB-073 Select Application Licensee Response

Response

Date/Time 5/28/2010 10:30 AM Closure Statement

Response

Statement Kewaunees 4160V AC system is divided into six buses, as shown in USAR Figure 8.2-

3. Buses 1-1 and 1-2 can be called the reactor coolant pump buses, as reactor coolant pump (RCP) A is powered from Bus 1-1 while RCP B is powered from Bus 1-2. Buses 1-5 and 1-6 are Kewaunees safety related 4160-volt AC buses.

The attached files provides the requested description.

Question Closure Date KAB-073 Response.pdf (88KB)

Notification Kewaunee ITS Conversion Database Members NRC/LICENSEE Supervision Kristy Bucholtz Added By Charles Smoker Date Added 5/28/2010 10:33 AM Modified By Ray Schiele Date Modified 5/28/2010 10:58 AM Page 1 of 1 Kewaunee ITS Conversion Database 06/24/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=3351 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 2 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 2 of 74

Page1of4

NRCQuestionKAB073

Provideadetaileddescriptionofthedesignoflossofvoltagerelayanddegradedvoltagerelay

schemes,includingnumberofchannels,forsafetyrelatedbusesandthereactorcoolantpumpbusses.



DEKResponse

Kewaunees4160VACsystemisdividedintosixbuses,asshowninUSARFigure8.23.Buses11and12

canbecalledthereactorcoolantpumpbuses,asreactorcoolantpump(RCP)AispoweredfromBus11

whileRCPBispoweredfromBus12.Buses15and16areKewauneessafetyrelated4160voltAC

buses.



ReactorCoolantPumpBuses

ReactorCoolantLowFlowReactorTripsprotectthecorefromDNBduetolowcoolantfloworalossof

coolantflow.OneofthemeansofsensingcoolantlowfloworflowlossistheReactorCoolantPump

BusUndervoltageReactorTrip.AbovetheP7setpointanundervoltagesignalfromboth4160Vbuses

(Buses11and12)resultsinareactortrip.

AlossofpoweronbothRCPbuseswillstarttheturbinedrivenAFWpumptoensurethatatleastoneSG

containsenoughwatertoserveastheheatsinkforreactordecayheatandsensibleheatremoval

followingthereactortrip.

TheRCPbuseshavefourundervoltagerelaysforeachbus,twotrainAandtwotrainB.Allfour

undervoltagerelaysareusedfortrippingofthereactorandstartingoftheturbinedriven(TD)auxiliary

feedwater(AFW)pump(TDAFWP).FortrippingtheRCPs,onlytwoperbusareused,trainspecific.For

trippingofthereactorthefourrelaysaredividedintotwochannelsperbus,onechannelisassociated

withTrainAreactortripwhiletheotherisassociatedwithTrainB.Thus,eachbushasachannelfeeding

eachtrainofreactortrip.ToreceiveareactortripandstarttheTDAFWP,onechannelfromeachRCP

bus(11and12)mustindicateanundervoltagecondition.Thus,toreceiveareactortripandstartof

theTDAFWP,anundervoltageconditionmustbeindicatedbyatleastoneoftwoundervoltagerelayson

twooftwoRCPbuses.Requirementsfortheoperabilityofthesechannelsarecontainedinthe

proposedITSsections3.3.1and3.3.2.ProposedITSsection3.3.1isconcernedwiththereactortrip

functionwhileproposedITS3.3.2coversthestartoftheTDAFWP.



SafetyRelatedBuses

Kewauneessafetyrelatedbuses(15and16)havesixundervoltagerelayseach,fourareusedforthe

safeguardsbusundervoltage(lossofvoltage)channelsand2areusedforthesafeguardsbussecond

levelundervoltage(degradedgrid)channel.Thecurrenttechnicalspecifications(CTS)andtheproposed

Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 3 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 3 of 74

Page2of4

improvedtechnicalspecifications(ITS)requireonechannelofeachfunctiontobeoperable.

Additionally,foreach4160voltsafetyrelatedbusthelossofvoltagefunctionhastwochannelswhile

thedegradedgridfunctionhasonechannel.ThesetpointsfortheundervoltagerelaysareintheCTS

andlistedas:

SafeguardsBusUndervoltage(Lossofpower)

85.0%+/-2%nominalbusvoltage,2.5seconds

timedelay

SafeguardsBusSecondLevelUndervoltage

(Degradedgridvoltage)

93.6%+/-0.9%ofnominalbusvoltage7.4seconds

timedelay



Thesafeguardsbusesundervoltage(lossofpower)triplimitandassociatedtimedelayissettoprotect

againstlossofvoltageordegradedvoltagetothesafeguardsbuswhileeliminatingmostspurioustrips.

Allsafeguardsequipmentisdesignedtostartandprovidefullfunctionwithsupplyvoltagesaslowas

80%ofnominal.Thetimedelayfeatureavoidsinadvertenttrips,yetitassuresthatasafetyinjection

sequencewillproceedasassumedintheUSAR,Section8,withthedieselgeneratorsatfullcapacity

beforethesafetyinjectionpumpsstart.Eachrelayintheundervoltageprotectionchannelswillfailsafe

andisalarmedtoalerttheoperatortothefailure

Thesafeguardsbusessecondlevelundervoltage(degradedgrid)triplimitissettoprotectagainst

degradedgridvoltageconditionswhichlastforextendedperiodsoftime.Eachrelayinthe

undervoltageprotectionchannelswillfailsafeandisalarmedtoalerttheoperatortoafailure.

Boththelossofpowerandthedegradedgridchannelsprovideinputtothebusvoltagelosssignal.To

generateabusvoltagelosssignalfromthelossofpowerchannelsbothrelaysonatleastoneofthetwo

channelsmustindicatealowvoltageforgreaterthantheassociatedtimedelay.Togenerateabus

voltagelosssignalfromthedegradedgridchannelbothrelaysinthechannelmustindicatealow

voltageconditionforgreaterthantheassociatedtimedelay.Ifanyofthefollowingconditionsaremet

thelossofpowerorthedegradedgridsignalsareblockedfromgeneratingabusvoltagelosssignal.

Theseconditionsare:



Nooffsitepowersuppliesareconnectedtothebus(Anytransformersupply)



Thebushasalockout



ThebusManual/Autocontrolswitchisinthemanualposition

Whenabusvoltagelosssignalisgenerated,severalactionsoccur.

1.

Simultaneously:

a.

Asignalissenttostarttheassociatedemergencydieselgenerator

b.

IfabussvoltagelosssignalisgeneratedduetodegradedgridactuationthenaLoad

Sheddingsignalisgenerated,otherwisetheLoadSheddingwaitsuntilaBlackoutsignal

isgenerated.

Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 4 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 4 of 74

Page3of4

c.

Asignalissenttotripopenallthebussupplybreakers

d.

Avoltagechasingsearchschemeisinitiatedtolocatesuitablepower

2.

ABlackoutloadingsignalisgeneratedoncepowerisrestoredtothebus

a.

TheBlackoutsignalgeneratesanAutoInhibitsignalpreventingmajorequipmentfrom

startingexceptbythetimerelaysequencingoftheBlackoutcircuit

3.

Selectloadsaresequencedontotheemergencydieselgenerator

Thetimingsequencerusedforblackoutusesthetimingsequencerforsafetyinjection.Thesafety

injectionsequencerhas11steps.Generallythestepsare:(Notethisisnotadetailedlistandhasone

sequencerforeachoftwotrains)

0.

MotorValvePositioning

1.

StartSIPump

2.

StartRHRPump

3.

StartICSandEmergencyVentilationFilterUnits

4.

Start1of2SWPumps

5.

StartContainmentFanCoilUnits

6.

StartMDAFWPump

7.

StartCCPump

8.

StartSecondSWPump

9.

StartOtherSafetyRelatedEquipment

10. RemoveAutoInhibitSignal

IfonlyaBlackoutSignalisgenerated(i.e.,fromtheLossofPowerorDegradedVoltagerelays)theload

sequencingstartsatstepsixoftheSIsequencerandcontinuesthroughstepten.

LossofVoltageandDegradedVoltageRelaySetpoints

Thelossofvoltagerelays(LVRs)aredesignedtoprotecttheESFbusesagainstalossofvoltagewhenthe

voltageissuchthatthemotorswillstall.Theminimumtimedelayassociatedwiththeserelaysis

selectedsuchthatatransientduetoagridfaultwillnotcausetherelaystotimeout.

Themaximumtimedelayassociatedwiththeserelaysisselectedtominimizethedurationunderwhich

motorsmaybestalledduringalossofvoltageevent,whilemaintainingtheminimumtimedelay

requirement.Thedegradedvoltagerelays(DVRs)aredesignedtoensureadequatevoltagelevelsatthe

Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 5 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 5 of 74

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ESFequipmentunderallplantconditionsincludingadesignbasisaccident.Theminimumtimedelay

associatedwiththeserelaysisselectedtobelongenoughsuchthatatransientduetoalargemotor

startorloadsequencingwillnotcausetherelaystotimeoutandisshortenoughtopreventpossible

nonactuationofMotorControlCentercontactors.

UndervoltageRelaySettings

Function

CTSLimit

CTSAPS

ITSNTSP

ITSAFT

ITSALT

Lossof

Voltage

85%2%

84.47%

84.47%

84.470.200% 84.470.166%



2.5seconds

1.75seconds

1.75seconds

1.750.25

seconds

1.750.10

seconds

DegradedGrid 93.6%0.9%

93.8%

93.8%

93.8%

0.179%

93.8%

0.166%



7.4seconds

6.72seconds

6.72seconds

6.720.68

seconds

6.720.10

seconds

RCP

Undervoltage

75%

76.667%

76.667%

76.667%

0.885%

76.667%

0.833%`

APS-ActualPlantSetting

NTSPNominalTripSetpoint

AFT-AsFoundTolerance

ALT-AsLeftTolerance



LicensingHistoryforAFWUndervoltageFunction

The4KVBuses15and16undervoltagefunctionalunitwasaddedtoKewauneesCTSinresponsetoan

industryissuefromtheTMI2LessonsLearned.InJulyof1980theNRCstaffsentalettertoall

PressurizerWaterReactor(PWR)Licenseesstatingthatthestaffhascompleteditsevaluationofthe

actionsyouhavetakentosatisfytheCategoryAitemsofourrecommendationsresultingfromTMI2

LessonsLearned.TheNRCStaffstatedUndertheprovisionsof10CFRPart50.36(d)(3)andinorderto

providereasonableassurancethatyourfacilityoperationismaintainedwithinthelimitsdetermined

acceptablefollowingtheimplementationoftheTMIlLessonsLearnedCategoryAitems,wehave

preparedtheenclosedmodelTechnicalSpecifications(TSs).OneofthoseModelTSdealtwithAuxiliary

Feedwater.

BasedonthemodelTS(althoughthemodellistedtheSIandBlackoutstartsignalsseparately)the

licenseeforKewauneesubmittedaproposedTSthatlistedTSTablefunctionalunit4,MotorDriven

AuxiliaryFeedwaterPumps,withitem4.cidentifiedasSafetyInjectionorBlackout.Thesubsequent

approvedLicenseAmendment38listedthetwoitemsastheyaretoday.

Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 6 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 6 of 74

Licensee Response/NRC Response/NRC Question Closure Id 4011 NRC Question Number KAB-073 Select Application Licensee Response

Response

Date/Time 7/29/2010 3:05 PM Closure Statement

Response

Statement This supplemental response is based on requests made during follow up discussions with NRC staff.

This response is a supplement to a previous response to KAB-073, and adds narrative detail to the Technical Specification Bases for 3.3.1, RPS Instrumentation, Function 12 (Undervoltage RCPs) and 3.3.5, Loss of Offsite Power (LOOP) Diesel Generator (DG) Start Instrumentation.

Also, this response includes a markup to the Notes in specification 3.3.5.A.1, REQUIRED ACTION, reordering the two notes, and making a distinction between channel and relay. The supporting JFD and Bases are edited accordingly.

Question Closure Date KAB-073 Markup.pdf (1MB) ITS 3.3.5 Note issue.pdf (871KB)

Notification NRC/LICENSEE Supervision Kristy Bucholtz Victor Cusumano Robert Hanley Melissa Krcma Ray Schiele Added By Charles Smoker Date Added 7/29/2010 3:08 PM Modified By Date Modified Page 1 of 1 Kewaunee ITS Conversion Database 07/29/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=4011 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 7 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 7 of 74

RTS Instrumentation B 3.3.1 WOG STS B 3.3.1-22 Rev. 3.0, 03/31/04 P

All changes are unless otherwise noted 1

BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

The LCO requires one RCP Breaker Position channel per RCP to be OPERABLE. One OPERABLE channel is sufficient for this Function because the RCS Flow - Low trip alone provides sufficient protection of unit SLs for loss of flow events. The RCP Breaker Position trip serves only to anticipate the low flow trip, minimizing the thermal transient associated with loss of an RCP.

This Function measures only the discrete position (open or closed) of the RCP breaker, using a position switch. Therefore, the Function has no adjustable trip setpoint with which to associate an LSSS.

In MODE 1 above the P-7 setpoint and below the P-8 setpoint, the RCP Breaker Position (Two Loops) trip must be OPERABLE.

Below the P-7 setpoint, all reactor trips on loss of flow are automatically blocked since no conceivable power distributions could occur that would cause a DNB concern at this low power level. Above the P-7 setpoint, the reactor trip on loss of flow in two RCS loops is automatically enabled. Above the P-8 setpoint, a loss of flow in any one loop will actuate a reactor trip because of the higher power level and the reduced margin to the design limit DNBR.

12. Undervoltage Reactor Coolant Pumps The Undervoltage RCPs reactor trip Function ensures that protection is provided against violating the DNBR limit due to a loss of flow in two or more RCS loops. The voltage to each RCP is monitored.

Above the P-7 setpoint, a loss of voltage detected on two or more RCP buses will initiate a reactor trip. This trip Function will generate a reactor trip before the Reactor Coolant Flow - Low (Two Loops)

Trip Setpoint is reached. Time delays are incorporated into the Undervoltage RCPs channels to prevent reactor trips due to momentary electrical power transients.

The LCO requires three Undervoltage RCPs channels (one per phase) per bus to be OPERABLE.

In MODE 1 above the P-7 setpoint, the Undervoltage RCP trip must be OPERABLE. Below the P-7 setpoint, all reactor trips on loss of flow are automatically blocked since no conceivable power distributions could occur that would cause a DNB concern at this low In MODE 1 above the P-8 setpoint, the RCP Breaker Position (Single Loop) trip must be OPERABLE.

8 In MODE 1 above the P-8 setpoint, Reactor Coolant Flow - Low and RCP Breaker Position Functions provide the necessary reactor trip on a loss of flow.

two 8

5 5

5 5

5 INSERT 4A Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 8 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 8 of 74

INSERT 4A The RCP buses have four undervoltage relays for each bus, two train A and two train B. All four undervoltage relays are used for tripping of the reactor. For tripping the RCPs, only two per bus are used, train specific. For tripping of the reactor the four relays are divided into two channels per bus, one channel is associated with Train A reactor trip while the other is associated with Train B. Thus, each bus has a channel feeding each train of reactor trip. To receive a reactor trip, one channel from each RCP bus (11 and 12) must indicate an undervoltage condition.

Thus, to receive a reactor trip, an undervoltage condition must be indicated by at least one of two undervoltage relays on two of two RCP buses.

Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 9 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 9 of 74

LOP DG Start Instrumentation B 3.3.5 WOG STS B 3.3.5-1 Rev. 3.0, 03/31/04 O

B 3.3 INSTRUMENTATION B 3.3.5 Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation BASES BACKGROUND The DGs provide a source of emergency power when offsite power is either unavailable or is insufficiently stable to allow safe unit operation.

Undervoltage protection will generate an LOP start if a loss of voltage or degraded voltage condition occurs in the switchyard. There are two LOP start signals, one for each 4.16 kV vital bus.

Three undervoltage relays with inverse time characteristics are provided on each 4160 Class 1E instrument bus for detecting a sustained degraded voltage condition or a loss of bus voltage. The relays are combined in a two-out-of-three logic to generate an LOP signal if the voltage is below 75% for a short time or below 90% for a long time. The LOP start actuation is described in FSAR, Section 8.3 (Ref. 1).

The Allowable Value in conjunction with the trip setpoint and LCO establishes the threshold for Engineered Safety Features Actuation System (ESFAS) action to prevent exceeding acceptable limits such that the consequences of Design Basis Accidents (DBAs) will be acceptable.

The Allowable Value is considered a limiting value such that a channel is OPERABLE if the setpoint is found not to exceed the Allowable Value during the CHANNEL CALIBRATION. Note that although a channel is OPERABLE under these circumstances, the setpoint must be left adjusted to within the established calibration tolerance band of the setpoint in accordance with uncertainty assumptions stated in the referenced setpoint methodology, (as-left-criteria) and confirmed to be operating within the statistical allowances of the uncertainty terms assigned.

Allowable Values and LOP DG Start Instrumentation Setpoints

---

REVIEWERS NOTE-----------------------------------

Alternatively, a TS format incorporating an Allowable Value only may be proposed by a licensee. In this case the Nominal Trip Setpoint value is located in the TS Bases or in a licensee controlled document outside the TS. Changes to the trip setpoint value would be controlled by 10 CFR 50.59 or administratively as appropriate, and adjusted per the setpoint methodology and applicable surveillance requirements. At their option, the licensee may include the trip setpoint in the surveillance requirement as shown, or suggested by the licensee's setpoint methodology.

O Offsite INSERT 1 INSERT 2 2

All changes are unless otherwise noted 1

DG O

U

2.

O Page is added for Information only Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 10 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 10 of 74

B 3.3.5 Insert Page B 3.3.5-1 INSERT 1 Each DG is capable of starting automatically on a Safeguard Bus Undervoltage (loss of voltage) or Safeguard Bus Second Level Undervoltage (degraded voltage) signal from its corresponding 4160 V Safeguard Bus (Emergency Bus 1-5 or 1-6). The signal will start the associated DG and trip the offsite power supply breakers to the associated emergency bus. Each DG has adequate capacity to supply one train of the engineered safety features (ESF) for the Design Basis Accident (DBA).

INSERT 2 Four voltage relays provide input to the logic for each 4160 V bus for detecting a Safeguards Bus Undervoltage (loss of voltage) condition and two voltage relays provide input to the logic for each 4160 V bus for detecting a Safeguards Bus Second Level Undervoltage (degraded voltage) condition. The four loss of voltage relays are paired into two Safeguard Bus Undervoltage channels, with each channel consisting of an instantaneous loss of voltage relay in series with a time-delayed loss of voltage relay.

Both relays must trip for the channel to trip and send a start signal to the associated DG and close supply breakers to the associated 4160 V emergency bus. The two time-delayed degraded voltage relays are paired (in series) in a single Safeguard Bus Second Level Undervoltage channel. Both relays must trip for the channel to trip and send a start signal to the associated DG and trip in supply breakers to the associated 4160 V emergency bus. The time delays are applied within the two Functions (loss of voltage and degraded voltage) to prevent actuations during normal transients.

1 1

INSERT 2A INSERT 2B Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 11 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 11 of 74

INSERT 2A The safeguards buses undervoltage (loss of power) trip limit and associated time delay is set to protect against loss of voltage or degraded voltage to the safeguards bus while eliminating most spurious trips. All safeguards equipment is designed to start and provide full function with supply voltages as low as 80% of nominal. The time delay feature avoids inadvertent trips, yet it assures that a safety injection sequence will proceed with the diesel generators at full capacity before the safety injection pumps start. Each relay in the undervoltage protection channels will fail safe and is alarmed to alert the operator to the failure.

There are two safeguard buses (bus 1-5 and bus 1-6). Each safeguard bus undervoltage Function has two channels per bus with only one channel per bus required to be OPERABLE.

INSERT 2B Therefore, with all four relays (two relays per channel per bus) OPERABLE the plant will be able to withstand a single active failure. Additionally, with one of the four relays inoperable the plant is no longer required to withstand a single active failure.

When all four relays are OPERABLE, if one of the four relays were to fail (single active failure) coincident with a loss of offsite power (LOOP), then the unaffected buss relays would actuate causing the buss emergency diesel generator to start loading the buss ESF associated equipment mitigating the event. Alternately, if a single relay was inoperable or if one relay for each bus was inoperable then these relays would be tripped and the single active failure requirement would no longer be required. The OPERABLE relays would sense the LOOP causing both buses emergency diesel generators to start loading both buses' associated ESF equipment. Thus, with only one channel per bus required to be OPERABLE the accident analyses are met and the single active failure criteria is met.

1 1

Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 12 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 12 of 74

LOP DG Start Instrumentation 3.3.5 WOG STS 3.3.5-1 Rev. 3.0, 03/31/04 O

3.3 INSTRUMENTATION 3.3.5 Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation LCO 3.3.5

[Three] channels per bus of the loss of voltage Function and [three]

channels per bus of the degraded voltage Function shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, 3, and 4, When associated DG is required to be OPERABLE by LCO 3.8.2, "AC Sources - Shutdown."

ACTIONS

---

NOTE-----------------------------------------------------------

Separate Condition entry is allowed for each Function.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more Functions with one channel per bus inoperable.

A.1

---

NOTE--------------

The inoperable channel may be bypassed for up to

[4] hours for surveillance testing of other channels.

Place channel in trip.

[6] hours B. One or more Functions with two or more channels per bus inoperable.

B.1 Restore all but one channel per bus to OPERABLE status.

1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> C. Required Action and associated Completion Time not met.

C.1 Enter applicable Condition(s) and Required Action(s) for the associated DG made inoperable by LOP DG start instrumentation.

Immediately CTS 2

O Offsite O

2 1

1 1

3.5.b, Table TS 3.5-1 Functional Units 9 and 10, Table TS 3.5-5, Functional Units 1 and 2 one One DOC A02 3.5.b, 3.5.c, Table TS 3.5-5 Functional Units 1 (including Note 2) and 2, Columns 3 and 6 3.5.c, Table TS 3.5-5 Functional Units 1 and 2, Columns 3 and 6 DOC M02 B

B 3

)

Safeguards Bus Undervoltage (

Safeguards Bus Second Level Undervoltage (

3 required affected portion of the required 1

INSERT 1

)

1.

2

2. Only applicable if inoperable channel is the result of one inoperable relay.

S the other relay of the channel 1

2 relay Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 13 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 13 of 74

JUSTIFICATION FOR DEVIATIONS ITS 3.3.5, LOSS OF OFFSITE POWER (LOOP) DIESEL GENERATOR (DG) START INSTRUMENTATION Kewaunee Power Station Page 1 of 2

1.

Changes are made (additions, deletions, and/or changes) to the ISTS that reflect the plant specific nomenclature, number, reference, system description, analysis or licensing basis description.

2.

The ISTS contains bracketed information and/or values that are generic to all Westinghouse vintage plants. The brackets are removed and the proper plant specific information/value is provided. This is acceptable since the generic specific information/value is revised to reflect the current plant design.

3.

ISTS 3.3.5 ACTIONS A and B are written for a design that includes a two out of three logic design for each of the two Functions, and all three of the installed channels are required to be OPERABLE. The KPS design for the degraded voltage function includes one channel per bus, with each channel consisting of two degraded voltage relays in series. This is described in the ITS 3.3.5 Bases. Thus, when a channel is inoperable due to a single relay being inoperable, placing the affected portion of the channel in trip is allowed by the CTS and is being maintained as ITS 3.3.5 Required Action A.1, similar to the allowance in ISTS 3.3.5 Required Action A.1. However, the time allowed to place the affected portion of the channel in trip is one hour, consistent with current requirements. If the channel is inoperable for other reasons, placing the entire channel in trip is not an option, since it could result in starting the DG and tieing it to the associated emergency bus. Therefore, under this condition, ITS 3.3.5 Required Action A.2 requires restoring the channel to OPERABLE status, similar to the ISTS 3.3.5 ACTION B when two of the three channels are inoperable.

For the loss of voltage Function, the KPS design includes two channels per bus, and either of the two channels can start the DG. Each of the channels consist of two loss of voltage relays in series, as described in the ITS Bases. However, the KPS CTS only requires one of the two channels per bus to be OPERABLE. This is being maintained in the ITS, because it is not necessary to require the loss of voltage instrumentation to be single failure proof for each of the DGs. The DGs themselves are single failure proof, in that only one DG is required to operate following a loss of offsite power event. Thus, based on the CTS allowance to only require one of the two channels per bus to be OPERABLE, the KPS channel design for the loss of voltage channels is similar to the degraded voltage channels, and the CTS allowance in Table TS 3.5-5 Note (2) to trip one of the two relays in a channel, the ITS 3.3.5 ACTIONS would apply to the loss of voltage Function similar to the degraded voltage Function actions described above. In addition, since the KPS design includes two Safeguards Bus Undervoltage (loss of voltage) channels per bus and the LCO only requires one Safeguards Bus Undervoltage (loss of voltage) channel per bus, ITS 3.3.5 Condition A and Required Actions A.1 and A.2 includes the word "required" and ITS SR 3.3.5.1 and SR 3.3.5.2 include the statement "of each required channel." This is consistent with the use of the word "required" in the ISTS (it is used when the design includes more components than the Technical Specification requires OPERABLE). Furthermore, since ISTS 3.3.5 ACTION B has been deleted, ISTS 3.3.5 ACTION C has been renumbered.

4.

ISTS SR 3.3.5.1 is deleted since the CHANNEL CHECK requirement is not applicable to the Kewaunee Power Station (KPS) instrumentation. A CHANNEL CHECK is defined as the qualitative assessment, by observation, of channel In addition, the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> test allowance provided in ISTS 3.3.5 ACTION A.1 Note has been modified to apply only to the other relay of the channel, consistent with the KPS design.

The 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> allowance of this Note is also consistent with the CTS allowances.

(i.e., the inoperable relay) and associated Note 1 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 14 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 14 of 74

LOP DG Start Instrumentation B 3.3.5 WOG STS B 3.3.5-4 Rev. 3.0, 03/31/04 O

BASES ACTIONS (continued)

Because the required channels are specified on a per bus basis, the Condition may be entered separately for each bus as appropriate.

A Note has been added in the ACTIONS to clarify the application of Completion Time rules. The Conditions of this Specification may be entered independently for each Function listed in the LCO. The Completion Time(s) of the inoperable channel(s) of a Function will be tracked separately for each Function starting from the time the Condition was entered for that Function.

A.1 Condition A applies to the LOP DG start Functions with one loss of voltage or one degraded voltage channel per bus inoperable.

If one channel is inoperable, Required Action A.1 requires that channel to be placed in trip within [6] hours. With a channel in trip, the LOP DG start instrumentation channels are configured to provide a one-out-of-three logic to initiate a trip of the incoming offsite power.

A Note is added to allow bypassing an inoperable channel for up to

[4] hours for surveillance testing of other channels. This allowance is made where bypassing the channel does not cause an actuation and where at least two other channels are monitoring that parameter.

The specified Completion Time and time allowed for bypassing one channel are reasonable considering the Function remains fully OPERABLE on every bus and the low probability of an event occurring during these intervals.

B.1 Condition B applies when more than one loss of voltage or more than one degraded voltage channel per bus are inoperable.

Required Action B.1 requires restoring all but one channel per bus to OPERABLE status. The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Completion Time should allow ample time to repair most failures and takes into account the low probability of an event requiring an LOP start occurring during this interval.

O O

4 1

1 1

required is and A.2 If the required channel is inoperable due to reasons other than one of the two relays being inoperable, A.2 the required O

due to one of the two relays being inoperable supply breakers to the emergency bus and a start of the DG if the remaining relay detects a loss or degraded voltage condition, as applicable 1

the affected portion of the required is DG required relay of a the other relay of the channel Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 15 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 15 of 74

Licensee Response/NRC Response/NRC Question Closure Id 4021 NRC Question Number KAB-073 Select Application NRC Question Closure

Response

Date/Time Closure Statement This question is closed and no further information is required at this time to draft the Safety Evaluation.

Response

Statement Question Closure Date 7/30/2010 Notification NRC/LICENSEE Supervision Charles Smoker Added By Kristy Bucholtz Date Added 7/30/2010 11:12 AM Modified By Date Modified Page 1 of 1 Kewaunee ITS Conversion Database 08/02/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=4021 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 16 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 16 of 74

ITS NRC Questions Id 2071 NRC Question Number KAB-075 Category Technical ITS Section 3.3 ITS Number 3.3.2 DOC Number JFD Number 12 JFD Bases Number Page Number(s) 212 and 218 NRC Reviewer Supervisor Rob Elliott Technical Branch POC Barry Marcus Conf Call Requested N NRC Question The markup of ITS 3.3.2, Function 6.e, Auxiliary Feedwater Trip of both Main Feedwater Pumps, (Attachment 1, Volume 8, page 212 of 517) includes Justification for Deviation (JFD) 12 (Attachment 1, Volume 8, page 218 of 517),

which discusses the adoption of the setpoint control program. However, because Function 6.e is actuated from breaker position contacts and there is no calibration surveillance required, there is no Trip of both Main Feedwater Pumps calculation in Technical Report EE-0116, Revision 6. Please explain how can this function be in accordance with the setpoint control program if there is no surveillance that monitors values under the setpoint control program?

Attach File 1 Attach File 2 Issue Date 5/25/2010 Added By Kristy Bucholtz Date Modified Modified By Date Added 5/25/2010 4:16 PM Notification NRC/LICENSEE Supervision Page 1 of 1 Kewaunee ITS Conversion Database 06/24/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=2071 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 17 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 17 of 74

Licensee Response/NRC Response/NRC Question Closure Id 3321 NRC Question Number KAB-075 Select Application Licensee Response

Response

Date/Time 5/27/2010 2:15 PM Closure Statement

Response

Statement JFD 12 is used to delete the Allowable Value column for all of the parameters in ISTS Table 3.3.2-1. It is written to adopt TSTF-493, Option B.

Thus, the JFD, which states that "KPS relocates the Technical Specification 3.3, "Instrumentation," Limiting Trip Setpoints, Nominal Trip Setpoints, and/or Allowable Values from the Technical Specifications to a licensee-controlled Setpoint Control Program," means that the KPS current Technical Specification Limiting Trip Setpoints, Nominal Trip Setpoints, and/or Allowable Values are being relocated to the Setpoint Control Program. While the ISTS Table 3.3.2-1 has a bracketed Allowable Value for the Trip of all Main Feedwater Pumps (ISTS Table 3.3.2-1 Function 6.g), this is because the type of instrument for this Function is a pressure switch (as described in the Bases), which can have an Allowable Value. For the KPS design, the trip is generated from a breaker position, which does not have an Allowable Value in the CTS. In the ISTS, these types of devices have an "NA" in the Allowable Value column. Furthermore, the only Surveillance listed for this Function is SR 3.3.2.5, a TADOT (TRIP ACTUATING DEVICE OPERATIONAL TEST). The only Surveillances in the ITS which reference the Setpoint Control Program are the CHANNEL OPERATIONAL TEST and CHANNEL CALIBRATION Surveillances (ITS SRs 3.3.2.4 and 3.3.2.5).

Therefore, the Auxiliary Feedwater Trip of Both main Feedwater Pumps, ITS Table 3.3.2-1 Function 6.e, is not in accordance with the Setpoint Control Program, and JFD 12 is not stating that it is in the Program. JFD 12, which is justifying why KPS is not adopting the Allowable Value column in the ISTS, is simply stating that the KPS Allowable Values for any instruments that have Allowable Values will be adequately controlled by the Setpoint Control Program, and that an Allowable Value column is not needed in the KPS ITS In addition, Section 3.1 of the KPS Setpoint Control Program (SCP) states:

"The SCP ensures the Nominal Trip Setpoint (NTSP), Allowable Value (AV), As-Found Tolerance (AFT), and As-Left Tolerance (ALT) (as applicable) are calculated using an NRC approved setpoint methodology for the applicable Functions in the following Technical Specifications:"

The SCP then lists LCO 3.3.1, LCO 3.3.2, LCO 3.3.5, etc. It follows this up with the Table Functions that are governed by the SCP, and Table Page 1 of 2 Kewaunee ITS Conversion Database 06/24/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=3321 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 18 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 18 of 74

3.3.2-1, Function 6.e, which does not have an applicable AV, is not applicable to the SCP.

Question Closure Date Attachment 1

Attachment 2

Notification NRC/LICENSEE Supervision Kristy Bucholtz Victor Cusumano Jerry Jones Bryan Kays Ray Schiele Added By Robert Hanley Date Added 5/27/2010 2:14 PM Modified By Date Modified Page 2 of 2 Kewaunee ITS Conversion Database 06/24/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=3321 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 19 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 19 of 74

Licensee Response/NRC Response/NRC Question Closure Id 3421 NRC Question Number KAB-075 Select Application NRC Question Closure

Response

Date/Time Closure Statement This question is closed and no further information is required at this time to draft the Safety Evaluation.

Response

Statement Question Closure Date 6/7/2010 Notification NRC/LICENSEE Supervision Added By Kristy Bucholtz Date Added 6/7/2010 7:19 AM Modified By Date Modified Page 1 of 1 Kewaunee ITS Conversion Database 06/24/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=3421 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 20 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 20 of 74

ITS NRC Questions Id 2081 NRC Question Number KAB-076 Category Technical ITS Section Attachment 2 BACKGROUND AND TECHNICAL ANALYSIS FOR ITS Number DOC Number JFD Number JFD Bases Number Page Number (s) 5 NRC Reviewer Supervisor Rob Elliott Technical Branch POC Adel El-Bassioni Conf Call Requested N NRC Question Low Flow in Both Loops:

In item 1 section 3.2 (page 5) of attachment 2, the failure to trip probability was estimated by doubling the value for an individual loop (as shown in table 3.1). Use of sensitivity analysis or other means is needed to enhance the confidence of the adopted approach and assure robust compliance with the conclusions of WCAP-10271 Supplement 1. Supplemental assessment is needed in this area.

Attach File 1 Attach File 2 Issue Date 5/28/2010 Added By Kristy Bucholtz Date Modified Modified By Date Added 5/28/2010 10:13 AM Notification NRC/LICENSEE Supervision Page 1 of 1 Kewaunee ITS Conversion Database 06/24/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=2081 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 21 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 21 of 74

Licensee Response/NRC Response/NRC Question Closure Id 3551 NRC Question Number KAB-076 Select Application Licensee Response

Response

Date/Time 6/18/2010 8:20 AM Closure Statement

Response

Statement The probability of failure of the flow instrumentation to detect low flow in an individual loop is as follows:

Q(loop) = A + B, where A is the probability of a failure of 2 of 3 channel failures in a single loop, and B is the probability of a common cause failure affecting both loops.

The probability of a failure of either loop to trip would consist of the probability of failure of one loop, plus the probability of a failure of the other loop, plus the probability of a common-cause failure of both loops. This is represented by:

Q(either loop) = 2A + B Twice the failure rate of one loop would be 2A + 2B, which is greater than 2A+B.

Therefore, doubling the failure rate for a single loop is conservative.

Question Closure Date Notification NRC/LICENSEE Supervision Kristy Bucholtz Victor Cusumano Jerry Jones Bryan Kays Ray Schiele Added By Robert Hanley Date Added 6/18/2010 8:21 AM Modified By Date Modified Page 1 of 1 Kewaunee ITS Conversion Database 06/24/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=3551 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 22 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 22 of 74

Licensee Response/NRC Response/NRC Question Closure Id 3761 NRC Question Number KAB-076 Select Application NRC Question Closure

Response

Date/Time Closure Statement This question is closed per Donnie Harrison, BC APLA. No further information is required at this time to draft the Safety Evaluation.

Response

Statement Question Closure Date 7/13/2010 Notification NRC/LICENSEE Supervision Added By Victor Cusumano Date Added 7/13/2010 12:22 PM Modified By Date Modified Page 1 of 1 Kewaunee ITS Conversion Database 07/13/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=3761 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 23 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 23 of 74

ITS NRC Questions Id 2091 NRC Question Number KAB-077 Category Technical ITS Section Attach 2 BACKGROUND AND TECHNICAL ANALYSIS FOR ADO ITS Number DOC Number JFD Number JFD Bases Number Page Number (s) 8 NRC Reviewer Supervisor Rob Elliott Technical Branch POC Adel El-Bassioni Conf Call Requested N NRC Question Commitment 8 (CCF):

In item 2 of page 8 (attachment 2), it was stated that DEK will add procedure direction to perform an extent of condition evaluation and perform additional testing for plausible common failure modes. Details are needed regarding the scope of consideration of CCF factors in this evaluation, and extent of use of applicable industry data information in the evaluation of CCF.

Attach File 1 Attach File 2 Issue Date 5/28/2010 Added By Kristy Bucholtz Date Modified Modified By Date Added 5/28/2010 10:15 AM Notification NRC/LICENSEE Supervision Page 1 of 1 Kewaunee ITS Conversion Database 06/24/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=2091 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 24 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 24 of 74

Licensee Response/NRC Response/NRC Question Closure Id 3651 NRC Question Number KAB-077 Select Application Licensee Response

Response

Date/Time 7/1/2010 2:25 PM Closure Statement

Response

Statement In item 2 of page 8 (attachment 2), it was stated that DEK will add procedure direction to perform an extent of condition evaluation and perform additional testing for plausible common failure modes. In follow up, the NRC requested details regarding the scope of consideration of CCF factors in this evaluation, and extend of use of applicable industry data information in the evaluation of CCF.

DEKs review of this question benchmarked the Dominion fleet and found that some other Dominion stations had previously adopted WCAP 10271.

Specifically, this review found that this condition (i.e., item 2, page 8, as referenced above) had been previously addressed in license amendment request correspondence supporting the issuance of Amendment No. 221 and Amendment No. 202 for North Anna Unit Nos. 1 and 2, respectively.

These amendments, and the supporting NRC Safety Evaluation, were issued on March 9, 2000. (ADAMS ML003691675)

Similarly, this condition (i.e., item 2, page 8, as referenced above) had been previously addressed in license amendment request correspondence supporting the issuance of Amendment No. 228 and Amendment No. 228 for Surry Unit Nos. 1 and 2, respectively. These amendments, and the supporting NRC Safety Evaluation, were issued on August 31, 2001.

(ADAMS ML012480506)

In both instances, the LARs listed failures that may be considered as plausible common cause failures and those that are not. Additionally, the staff of North Anna and Surry power stations stated that they would review and revise their existing programs/procedures to ensure plausible common cause failures are evaluated. The NRC Safety Evaluations recognized a licensee commitment to review the existing plant programs and procedures to evaluate plausible common cause failures prior to implementing the proposed TS changes.

Since 2000/2001 Dominion (previously VEPCO) has enhanced and standardized the Corrective Action Program evaluation processes discussed in the North Anna Power Station and Surry Power Station amendments cited above. Those evaluation processes include apparent Page 1 of 2 Kewaunee ITS Conversion Database 07/07/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=3651 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 25 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 25 of 74

cause evaluations, root cause evaluations, maintenance rule evaluations, common cause evaluations, any or all of which may call for the investigation of extent of condition and extent of cause and the consideration of industry OE and NPRDS/EPIX industry equipment failure data.

Since Kewaunee LAR 249 was submitted, August 24, 2009, Kewaunee has continued with the lengthy process evolution from a station-specific corrective action process to a Dominion fleet process. Kewaunee, as part of the Dominion nuclear fleet with the North Anna and Surry nuclear power stations, now shares the Dominion fleet processes and procedures that prescribe the conduct of cause evaluations.

Thus, DEK believes that the condition that prompted the commitment that is proposed in item 2 of page 8 (attachment 2 to LAR 249), and itemized as Commitment 8 (attachment 5 to LAR 249), has been adequately addressed and therefore that proposed commitment is hereby withdrawn.

Question Closure Date Attachment 1

Attachment 2

Notification NRC/LICENSEE Supervision Kristy Bucholtz Victor Cusumano Robert Hanley Jerry Jones Bryan Kays Ray Schiele Added By Robert Hanley Date Added 7/1/2010 2:24 PM Modified By Date Modified Page 2 of 2 Kewaunee ITS Conversion Database 07/07/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=3651 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 26 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 26 of 74

Licensee Response/NRC Response/NRC Question Closure Id 3771 NRC Question Number KAB-077 Select Application NRC Question Closure

Response

Date/Time Closure Statement This question is closed per Donnie Harrison, BC APLA. No further information is required at this time to draft the Safety Evaluation.

Response

Statement Question Closure Date 7/13/2010 Notification NRC/LICENSEE Supervision Added By Victor Cusumano Date Added 7/13/2010 12:23 PM Modified By Date Modified Page 1 of 1 Kewaunee ITS Conversion Database 07/13/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=3771 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 27 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 27 of 74

ITS NRC Questions Id 2101 NRC Question Number KAB-078 Category Technical ITS Section Submittal Attachment 2 ITS Number DOC Number JFD Number JFD Bases Number Page Number(s) 13 NRC Reviewer Supervisor Rob Elliott Technical Branch POC Adel El-Bassioni Conf Call Requested N NRC Question Changes in CDF Estimates:

In the last paragraph of page 13 (Section 3.5.1 of attachment 2) of the submittal, it was stated that the overall CDF for the internal events average maintenance model is 4.2 E-05/yr, and the external events CDF is 4.7E-05/yr. However, it was repeatedly mentioned in the submittal that the Kewaunee PRA is based on the IPE and the IPEEE studies. The Kewaunee IPE study reported 6.7 E-05 /yr for internal events CDF (including internal flooding), and the IPEEE study indicated that the fire contribution to external events CFF is 1.8 E-04 /yr. Although it was indicated in the submittal that the plant PRA was WOG peer reviewed and subjected to self assessment and independent reviews, in addition to the claimed considerable effort to incorporate the latest industry insights (as stated in Section 3.5.5.10 of attachment 2), no details were provided regarding the CDF value updates and the factors contributing to the improved CDF estimates. Furthermore, delta-CDF was reported to be less than 1.0 E-05/yr. Please provide details to assure robustness of this estimated value in order to assure acceptability according to RG1.174 criteria Attach File 1

Attach File 2

Issue Date 5/28/2010 Added By Kristy Bucholtz Date Modified Page 1 of 2 Kewaunee ITS Conversion Database 06/24/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=2101 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 28 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 28 of 74

Modified By Date Added 5/28/2010 10:17 AM Notification NRC/LICENSEE Supervision Page 2 of 2 Kewaunee ITS Conversion Database 06/24/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=2101 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 29 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 29 of 74

Licensee Response/NRC Response/NRC Question Closure Id 3561 NRC Question Number KAB-078 Select Application Licensee Response Response Date/Time 6/18/2010 8:35 AM Closure Statement Response Statement To preserve formatting the response to KAB-078 is attached.

Question Closure Date KAB-078 attachment.pdf (96KB)

Notification NRC/LICENSEE Supervision Kristy Bucholtz Victor Cusumano Jerry Jones Bryan Kays Ray Schiele Added By Robert Hanley Date Added 6/18/2010 8:36 AM Modified By Date Modified Page 1 of 1 Kewaunee ITS Conversion Database 06/24/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=3561 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 30 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 30 of 74



TableE1providestheevolutionoftheKewauneeinternaleventsPRAmodelfromtheIndividualPlant

Examination(IPE)tothepresent.



TableE1:KewauneePRAHistoricalSummary

Version

Description/ChangesfromPreviousModel

CDF

LERF

IPE

OriginalIPE

6.6E05

No

Change

RevisedIPE

6/1996

RevisedinResponsetoRAIs,includingnewHumanReliability

Analysis

1.1E04

No

Change

1/1997

Majorchangesincluded:

CreditedoperatoractiontorefillRWST

Modeledalternatecoolingforaircompressors

3.9E05

2.2E06

4/1998

Removedasymmetricmodeling

3.6E05

1.9E06

12/2001

ConvertedfromGRAFTERcodetoWinNUPRAcode

Incorporatedplantfailureandinitiatingeventdata

IncludedconsiderationofreplacementSGs

Reviewedin6/2002WestinghouseOwnersGrouppeerreview

4.1E05

4.8E06

8/2003

WOGsealLOCAmodelincorporated

ImportantHumanErrorProbabilitiesreevaluated

Level2successcriteriaupdatedforpoweruprate

MediumLOCAandISLOCAmodelsupdated

Steamlinebreakanalysisrevisedtoincludepressurizedthermal

shock

Quantitativeshutdownmodeladded

Numerouspeerreviewcommentsresolved

3.0E05

5.3E06

12/2004

Addedneedtostopsafetyinjectionfollowingsteamlinebreak

Addeddependenceofletdownoncomponentcoolingwater

Powerrecoveryand480VACbuscrosstiesadded

Successcriteriaupdatedtoincludepoweruprate

Revisedinternalfloodingmodelincorporated

7.2E04

5.0E06

K101A

6/2006

Inrcorporatednewinternalfloodingmodelwhichincludedplant

changestoaddressfloodingconcerns

Incorporatedreviseddieselgeneratorreliabilitydata

Incorporatedreactorcoolantsystemcooldownand

depressurizationfollowingRCPsealLOCAtoavoidcoredamage

2.7E04

5.7E06

Page1of4

Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 31 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 31 of 74

Version

Description/ChangesfromPreviousModel

CDF

LERF

K101AA

10/2006

IncorporatedfloodbarrierstoprotectRHRpumps

Incorporatedoperatoractionstoaddressfloodingofbattery

room,AFWroomandswitchgearroomventilation

Incorporatedprocedurechangesaddressingservicewater

isolation

Removedotherisolationconservatisms

1.3E04

7.0E06

K101AASAMA

11/2006

OnetimeonlymodelforSAMA.Updateswerecarriedthroughto

futurerevisionsasspecified

RestructuredLevel1eventtreestosupportrevisedLevel2

model

Revisedservicewatermodelforsomeinternalflooding

sequences

Incorporatedplannedinternalfloodingdesignchanges

7.7E05



9.5E06



K101AB

5/2007

UpdatetoK101AA

Revisedservicewatermodelforsomeinternalflooding

sequences

Note:internalfloodingmodificationsarenotinthismodelinany

form

1.1E04

5.7E06

KI07A

8/2007

Subjectedtoindependentreview1/2008

Updateddatabase

Updatedinternalfloodingmodeltoremoveconservatisms

RestructuredLevel1eventtreestosupportrevisedLevel2

model

Note:internalfloodingmodificationsarenotinthismodelinany

form

7.6E05

9.8E06

K107Aa

7/2008

Updatedmodeltoasinstalledconfigurationofinternal

floodingmodificationsincludedinKI01AASAMAmodel.

4.8E05

6.4E06

K107AaILRT

7/15/2008

Reevaluatedfewsignificantconservativeoperatoractions

4.2E05



4.9E06





Forthissubmittal,theILRTmodel(K107AaILRT)wasusedfortheinternaleventsportionoftherisk

analysis.



TheKPSexternaleventsPRAmodelwasdevelopedoriginallyaspartoftheKPSIPEEEsubmittal.Minor

updatestothemodelhavebeenperformedsincethesubmittalandaresummarizedinthetextbelow,

whichiscopiedfromtheSevereAccidentMitigationAlternatives(SAMA)assessmentintheKewaunee

LicenseRenewalsubmittal1.



1LetterfromLeslieN.Hartz(DominionEnergyKewaunee),toDocumentControlDesk(NRC),ResponsetoRequest

forAdditionalInformationRegardingSevereAccidentMitigationAlternativesForKewauneePowerStationLicense

RenewalApplication,March9,2009,ADAMSAccessionNumberML090690458

Page2of4

Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 32 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 32 of 74



TheKPSIPEEEinitiallyquantifiedtheriskfrominternalfires.FireriskwasevaluatedusingaPRAthat

incorporatedfeaturesoftheFIVEmethodology.Forexample,theFIVEmethodologywasusedto

determineinitiatingfrequenciesforfiresinthevariouszonesandthescreeningcriterionfromFIVE

(1.0E06peryear)wasusedintheanalysis.TheIPEEEmodelswererevisedinresponsetorequestsfor

additionalinformationfromtheNRC.Thecontrolroomandcablespreadingroomwereaddedasa

resultofaddressingNRCRAIs.



IntheIPEEE,allhumanerrorprobabilitiesfromthebaseLevel1PRAmodelweremultipliedby10for

useinthefiremodel.ThisapproachtoestimatingtheHEPsforfiresequenceswassubsequently

replacedbyamoreeventspecificmethodologyfromEPRITR105928,EPRIFirePRAImplementation

Guide.InitiatingeventfrequenciesandseverityfactorsfromEPRITR105928,EPRIFirePRA

ImplementationGuidewasalsoapplied.FireinducedaccidentsequenceshadacalculatedCDFof

1.8E04peryear.NorecommendedimprovementswereidentifiedintheIPEEE.



ThefirePRAmodelshavenotbeenupdated,ingeneral,sincetheIPEEESER.However,whentheplant

failuredataandHEPswereupdated,theseupdatescarriedthroughtothefiremodel.Finally,the

conservativemodelingviaCOMPBRNIIIe,whichwasusedintheIPEEE,wasreplacedbythemore

realisticMAGICcodeforAuxiliaryFeedwater(AFW)PumpRoomB,whichhadbeenthedominantrisk

contributor.ThetotalCDFandLERFfromfireinducedaccidentsequencesarenowcalculatedtobe

1.39E04and4.90E08respectively.



ThefirePRAmodelhasseveralconservatismsthataresummarizedhere.First,initiatingeventsreflect

olddata,whichdoesnottakeintoaccountimprovedhousekeepingpracticesimplementedsubsequent

totheIPEEE.Second,althoughcurrentproceduresallowrelianceonmultipletrainsofequipmentand

offsitepower,themodelusesthefirecopingstrategiesinplaceatthetimeoftheIPEEEsubmittal,

whichcreditedonlyonetrainanddidnotrelyonoffsitepower.Third,ifacabletrayisdamaged,itis

assumedthatallcableswithinthetrayaredamaged.Fourth,acomparisonbetweentheolder

COMPBRNIIIeresultsforAFWPumpRoomBandthecurrentMAGICresultsshowthatCOMPBRNIIIeis

highlyconservativeanddamageinotherareasislikelyoverestimated.Finally,forallareasexceptAFW

PumpRoomB,themostseverefireinaroomisassumedtoapplytotheentireinitiatingfrequencyof

theroom.



SubsequenttocompletionoftheIPEEEfiremodels,changestoplantproceduresweremadethat

significantlyreducedtheriskoffireinducedaccidentsequences.However,theplantfirePRAmodels

werenotupdatedtoincludetheeffectoftheseproceduralchanges.Anassessmentoftheeffectsofthe

procedurechangesonfireriskwasperformedanddeterminedthatexplicitmodelingoftheprocedure

changesintheIPEEEmodelswouldreducefireriskbyatleastafactoroffive.Thisfactorwasjustifiedin

theresponsetoQuestion3.bintheKewauneeLicenseRenewalsubmittal.Therefore,amore

appropriatevalueforfireinducedCDFwouldbe3.6E05peryear.



Page3of4

Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 33 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 33 of 74

Page4of4



SeismiceventswereevaluatedinitiallyaspartoftheKPSIPEEEusingaseismicPRA.TheIPEEEseismic

PRAmodelwasconservativeinthat,forcomponentswithaseismiccapacityofgreaterthanascreening

value,aconservativesurrogatevaluewasused.Thissurrogatevaluewasusedformostcomponentsin

theplant.Coredamagefrequency(CDF)fromseismiceventswascalculatedtobe1.1E05peryear.No

recommendedimprovementswereidentifiedintheIPEEEotherthanresolutionofsomeseismic

outliers,whichhavebeencorrected.



SubsequenttotheIPEEE,somesmallchangesweremadetothemodel.Existingseismicallyruggedair

accumulatorswereaddedtothemodel.Thischangeallowedforapostseismiceventairsupplyto

pressurizerpoweroperatedreliefvalves,therebyallowingcreditforprimaryfeedandbleed.The

conservativeHEPsfromtheIPEEEwerereplacedwithamorerealisticmodelthatadjustsHEPsbasedon

groundmotionandlocation(i.e.,controlroomorlocal).ThetotalCDFandLERFfromseismicinduced

accidentsequencesarenowcalculatedtobe1.0E05and5.2E06peryearrespectively.



TheotherexternaleventsanalysisoftheIPEEEdeterminedthateachoftheinitiatorsconsideredcould

bescreenedoutusingtheIPEEEscreeningcriterion(CDF>1E6).Thus,externaleventsotherthanfires

orseismicweredeterminedintheIPEEEtobenegligiblecontributorstooverallcoredamage.No

revisionsofthismethodologyhaveoccurred.Norecommendedimprovementswereidentifiedinthe

IPEEE.



ThetotalCDFduetoexternaleventsis3.6E5(Fire)+1.0E5(Seismic)+1.0E6(Other)foratotalof

4.7E5/year.



ThetotalLERFduetoexternaleventsis4.9E8(Fire)+5.2E6(Seismic)foratotalof5.2E6/year.



ThedeltaCDFwasdeterminedinWCAP153762tobe5.7E7/yrfor2outof4logicand1.1E6/yrfor2

outof3logic.SinceKewauneehassomesignalswith2outof4logicandotherswith2outof3logic,

thehigher,moreconservativevaluewasused.TheapprovedWCAP15376methodologyistocalculate

ageneric,boundingdeltaCDFandcompareplantspecificparameterstothegenericparametersto

verifythatthegenericanalysisboundstheplantspecificanalysis.Attachment3oftheKewaunee

ImprovedTechnicalSpecificationsubmittal3showsthatthegenericassessmentboundsKewaunee.





2WCAP15376PARev.1,RiskInformedAssessmentoftheRTSandESFASSurveillanceTestIntervalsandReactor

TripBreakerTestandCompletionTimes,March,2003.

3LetterfromLeslieN.Hartz(DominionEnergyKewaunee),toDocumentControlDesk(NRC),LicenseAmendment

Request249,KewauneePowerStationConversiontoImprovedTechnicalSpecifications,August24,2009,ADAMS

AccessionNumberML092440371

Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 34 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 34 of 74

Licensee Response/NRC Response/NRC Question Closure Id 3911 NRC Question Number KAB-078 Select Application Licensee Response

Response

Date/Time 7/19/2010 1:25 PM Closure Statement

Response

Statement Based upon a phone conversation with the NRC, DEK is providing additional detail to the original response. This detail is underlined for ease of review and the footnotes were removed. This response supersedes the previous response to KAB-078 posted on June 18, 2010. To preserve formatting the revision 2 response to KAB-078 is attached.

Question Closure Date KAB-078 Attachment Rev 2 (2).pdf (35KB)

Notification NRC/LICENSEE Supervision Kristy Bucholtz Jerry Jones Bryan Kays Ray Schiele Added By Robert Hanley Date Added 7/19/2010 1:24 PM Modified By Date Modified Page 1 of 1 Kewaunee ITS Conversion Database 07/20/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=3911 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 35 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 35 of 74

Response to KAB-078:

Table E-1 provides the evolution of the Kewaunee internal events PRA model from the Individual Plant Examination (IPE) to the present.

Table E-1: Kewaunee PRA Historical Summary Version Description/Changes from Previous Model CDF LERF IPE Original IPE 6.6E-05 No Change Revised IPE 6/1996 Revised in Response to RAIs, including new Human Reliability Analysis 1.1E-04 No Change 1/1997 Major changes included:

- Credited operator action to refill RWST

- Modeled alternate cooling for air compressors 3.9E-05 2.2E-06 4/1998 Removed asymmetric modeling 3.6E-05 1.9E-06 12/2001

- Converted from GRAFTER code to WinNUPRA code

- Incorporated plant failure and initiating event data

- Included consideration of replacement SGs

- Reviewed in 6/2002 Westinghouse Owners Group peer review 4.1E-05 4.8E-06 8/2003

- WOG seal LOCA model incorporated

- Important Human Error Probabilities reevaluated

- Level 2 success criteria updated for power uprate

- Medium LOCA and ISLOCA models updated

- Steam line break analysis revised to include pressurized thermal shock

- Quantitative shutdown model added

- Numerous peer review comments resolved 3.0E-05 5.3E-06 12/2004

- Added need to stop safety injection following steam line break

- Added dependence of letdown on component cooling water

- Power recovery and 480 VAC bus cross-ties added

- Success criteria updated to include power uprate

- Revised internal flooding model incorporated 7.2E-04 5.0E-06 K101A 6/2006

-Inrcorporated new internal flooding model which included plant changes to address flooding concerns

- Incorporated revised diesel generator reliability data

- Incorporated reactor coolant system cooldown and depressurization following RCP seal LOCA to avoid core damage 2.7E-04 5.7E-06 K101AA 10/2006

- Incorporated flood barriers to protect RHR pumps

- Incorporated operator actions to address flooding of battery room, AFW room and switchgear room ventilation

- Incorporated procedure changes addressing service water isolation

- Removed other isolation conservatisms 1.3E-04 7.0E-06 K101AASAMA 11/2006 One time only model for SAMA. Updates were carried through to future revisions as specified

- Restructured Level 1 event trees to support revised Level 2 model

- Revised service water model for some internal flooding sequences

- Incorporated planned internal flooding design changes 7.7E-05 9.5E-06 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 36 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 36 of 74

Version Description/Changes from Previous Model CDF LERF K101AB 5/2007 Update to K101AA

- Revised service water model for some internal flooding sequences Note: internal flooding modifications are not in this model in any form 1.1E-04 5.7E-06 KI07A 8/2007 Subjected to independent review 1/2008

- Updated database

- Updated internal flooding model to remove conservatisms

- Restructured Level 1 event trees to support revised Level 2 model Note: internal flooding modifications are not in this model in any form 7.6E-05 9.8E-06 K107Aa 7/2008 Updated model to as-installed configuration of internal flooding modifications included in KI01AASAMA model.

4.8E-05 6.4E-06 K107AaILRT 7/15/2008 Re-evaluated few significant conservative operator actions 4.2E-05 4.9E-06 For this submittal, the ILRT model (K107AaILRT) was used for the internal events portion of the risk analysis.

The KPS external events PRA model was developed originally as part of the KPS IPEEE submittal. Minor updates to the model have been performed since the submittal and are summarized in the text below, which is copied from the Severe Accident Mitigation Alternatives (SAMA) assessment in the Kewaunee License Renewal submittal (Reference 5.18).

The KPS IPEEE initially quantified the risk from internal fires. Fire risk was evaluated using a PRA that incorporated features of the FIVE methodology. For example, the FIVE methodology was used to determine initiating frequencies for fires in the various zones and the screening criterion from FIVE (1.0E-06 per year) was used in the analysis. The IPEEE models were revised in response to requests for additional information from the NRC. The control room and cable spreading room were added as a result of addressing NRC RAIs.

In the IPEEE, all human error probabilities from the base Level 1 PRA model were multiplied by 10 for use in the fire model. This approach to estimating the HEPs for fire sequences was subsequently replaced by a more event-specific methodology from EPRI TR-105928, EPRI Fire PRA Implementation Guide. Initiating event frequencies and severity factors from EPRI TR-105928, EPRI Fire PRA Implementation Guide was also applied. Fire-induced accident sequences had a calculated CDF of 1.8E-04 per year. No recommended improvements were identified in the IPEEE.

The fire risk in the IPEEE was dominated by fire scenarios (such as those in the relay room, cable spreading room, and safeguards alley) for which the Appendix R fire procedures were employed. These fires contributed 62% of the fire CDF in the IPEEE. These fires would require operators to manually shut down the plant, isolate any systems potentially affected by the fire, and manually load necessary equipment. Therefore, the risk of these fires would not be affected by RPS and ESFAS equipment.

The fire PRA models have not been updated, in general, since the IPEEE SER. However, when the plant failure data and HEPs were updated, these updates carried through to the fire model. Finally, the conservative modeling via COMPBRN-IIIe, which was used in the IPEEE, was replaced by the more realistic MAGIC code for Auxiliary Feedwater (AFW) Pump Room B, which had been the dominant risk contributor. The total CDF and LERF from fire-induced accident sequences are now calculated to be 1.39E-04 and 4.90E-08 respectively.

The fire PRA model has several conservatisms that are summarized here. First, initiating events reflect old data, which does not take into account improved housekeeping practices implemented subsequent to the IPEEE.

Second, although current procedures allow reliance on multiple trains of equipment and offsite power, the Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 37 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 37 of 74

model uses the fire coping strategies in place at the time of the IPEEE submittal, which credited only one train and did not rely on offsite power. Third, if a cable tray is damaged, it is assumed that all cables within the tray are damaged. Fourth, a comparison between the older COMPBRN-IIIe results for AFW Pump Room B and the current MAGIC results show that COMPBRN-IIIe is highly conservative and damage in other areas is likely overestimated. Finally, for all areas except AFW Pump Room B, the most severe fire in a room is assumed to apply to the entire initiating frequency of the room.

Subsequent to completion of the IPEEE fire models, changes to plant procedures were made that significantly reduced the risk of fire-induced accident sequences. However, the plant fire PRA models were not updated to include the effect of these procedural changes. An assessment of the effects of the procedure changes on fire risk was performed and determined that explicit modeling of the procedure changes in the IPEEE models would reduce fire risk by at least a factor of five. This factor was justified in the response to Question 3.b in Reference 5.18. Therefore, a more appropriate value for fire-induced CDF would be 3.6E-05 per year.

Seismic events were evaluated initially as part of the KPS IPEEE using a seismic PRA. The IPEEE seismic PRA model was conservative in that, for components with a seismic capacity of greater than a screening value, a conservative surrogate value was used. This surrogate value was used for most components in the plant. Core damage frequency (CDF) from seismic events was calculated to be 1.1E-05 per year. No recommended improvements were identified in the IPEEE other than resolution of some seismic outliers, which have been corrected.

Subsequent to the IPEEE, some small changes were made to the model. Existing seismically rugged air accumulators were added to the model. This change allowed for a post-seismic-event air supply to pressurizer power operated relief valves, thereby allowing credit for primary feed and bleed. The conservative HEPs from the IPEEE were replaced with a more realistic model that adjusts HEPs based on ground motion and location (i.e., control room or local). The total CDF and LERF from seismic-induced accident sequences are now calculated to be 1.0E-05 and 5.2E-06 per year respectively.

The other external events analysis of the IPEEE determined that each of the initiators considered could be screened out using the IPEEE screening criterion (CDF > 1E-6). Thus, external events other than fires or seismic were determined in the IPEEE to be negligible contributors to overall core damage. No revisions of this methodology have occurred. No recommended improvements were identified in the IPEEE.

The total CDF due to external events is 3.6E-5 (Fire) + 1.0E-5 (Seismic) + 1.0E-6 (Other) for a total of 4.7E-5/year.

The total LERF due to external events is 4.9E-8 (Fire) + 5.2E-6 (Seismic) for a total of 5.2E-6/year.

The delta-CDF was determined in WCAP-15376 (Reference 5.3) to be 5.7E-7/yr for 2 out of 4 logic and 1.1E-6/yr for 2 out of 3 logic. Since Kewaunee has some signals with 2 out of 4 logic and others with 2 out of 3 logic, the higher, more conservative value was used. The approved WCAP-15376 methodology is to calculate a generic, bounding delta-CDF and compare plant-specific parameters to the generic parameters to verify that the generic analysis bounds the plant-specific analysis. Attachment 3 of the Kewaunee Improved Technical Specification submittal (Reference 5.19) shows that the generic assessment bounds Kewaunee.

Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 38 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 38 of 74

Licensee Response/NRC Response/NRC Question Closure Id 4031 NRC Question Number KAB-078 Select Application NRC Question Closure

Response

Date/Time Closure Statement This question is closed and no further information is required at this time to draft the Safety Evaluation.

Response

Statement Question Closure Date 8/3/2010 Notification NRC/LICENSEE Supervision Charles Smoker Added By Kristy Bucholtz Date Added 8/3/2010 2:49 PM Modified By Date Modified Page 1 of 1 Kewaunee ITS Conversion Database 08/03/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=4031 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 39 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 39 of 74

ITS NRC Questions Id 2111 NRC Question Number KAB-079 Category Technical ITS Section submittal Attachment 2 ITS Number DOC Number JFD Number JFD Bases Number Page Number(s)

NRC Reviewer Supervisor Rob Elliott Technical Branch POC Adel El-Bassioni Conf Call Requested N NRC Question Changes in LERF Estimates:

It was repeatedly mentioned in the submittal that the Kewaunee PRA is based on the IPE and the IPEEE studies. The Kewaunee IPE study reported an estimate for internal events LERF of 9.5 E-06 /yr. However, section 3.5.3 of attachment 2 of the submittal stated a LERF estimate of 4.8 E-06 /yr for internal events and 5.2 E-06 /yr for external events (which was not estimated in the IPEEE study). Please provide details regarding contributors to the current improved estimates of LERF.

Furthermore, in section 3.5.3 delta-LERF was estimated to be less than 1.0 E-07/yr. Details are needed regarding the appropriate estimated value as well as its robustness in order to assure acceptability according to RG1.174 criteria Attach File 1 Attach File 2 Issue Date 5/28/2010 Added By Kristy Bucholtz Date Modified Modified By Date Added 5/28/2010 10:19 AM Notification NRC/LICENSEE Supervision Page 1 of 1 Kewaunee ITS Conversion Database 06/24/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=2111 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 40 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 40 of 74

Licensee Response/NRC Response/NRC Question Closure Id 3571 NRC Question Number KAB-079 Select Application Licensee Response

Response

Date/Time 6/18/2010 8:35 AM Closure Statement

Response

Statement See response to KAB-078 for LERF discussion.

The delta-LERF was determined in WCAP-15376[1] to be 3.1E-8/yr for 2 out of 4 logic and 5.7E-8/yr for 2 out of 3 logic. Since Kewaunee has some signals with 2 out of 4 logic and others with 2 out of 3 logic, the higher, more conservative value was used.

The approved WCAP-15376 methodology is to calculate a generic, bounding delta-LERF and compare plant-specific parameters to the generic parameters to verify that the generic analysis bounds the plant-specific analysis. Attachment 3 of the Kewaunee Improved Technical Specification submittal[2] shows that the generic assessment bounds Kewaunee.

[1] WCAP-15376-P-A Rev. 1, Risk-Informed Assessment of the RTS and ESFAS Surveillance Test Intervals and Reactor Trip Breaker Test and Completion Times, March, 2003.

[2] Letter from Leslie N. Hartz (Dominion Energy Kewaunee), to Document Control Desk (NRC), License Amendment Request 249, Kewaunee Power Station Conversion to Improved Technical Specifications, August 24, 2009, ADAMS Accession Number ML092440371 Question Closure Date Attachment 1

Attachment 2

Notification NRC/LICENSEE Supervision Kristy Bucholtz Jerry Jones Bryan Kays Ray Schiele Added By Robert Hanley Date Added 6/18/2010 8:40 AM Modified By Date Modified Page 1 of 1 Kewaunee ITS Conversion Database 06/24/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=3571 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 41 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 41 of 74

Licensee Response/NRC Response/NRC Question Closure Id 3781 NRC Question Number KAB-079 Select Application NRC Question Closure

Response

Date/Time Closure Statement This question is closed per Donnie Harrison, BC APLA. No further information is required at this time to draft the Safety Evaluation.

Response

Statement Question Closure Date 7/13/2010 Notification NRC/LICENSEE Supervision Added By Victor Cusumano Date Added 7/13/2010 12:24 PM Modified By Date Modified Page 1 of 1 Kewaunee ITS Conversion Database 07/13/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=3781 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 42 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 42 of 74

ITS NRC Questions Id 2121 NRC Question Number KAB-080 Category Technical ITS Section submittal Attachment 2 ITS Number DOC Number JFD Number JFD Bases Number Page Number (s) 19 NRC Reviewer Supervisor Rob Elliott Technical Branch POC Adel El-Bassioni Conf Call Requested N NRC Question Human Error Probability (HEP) Modeling:

In section 3.5.5.5 (page 19 of attachment 2) it was stated that Areas of PRA model fidelity with respect to the as built as operated plant, and realistic estimation of human error failure probabilities were made. More details are needed regarding the scope, extent, and basis of the changes. Were sensitivity studies performed?

Please provide discussions about the impact of HEP changes on the risk estimates evaluated in this study.

Attach File 1 Attach File 2 Issue Date 5/28/2010 Added By Kristy Bucholtz Date Modified Modified By Date Added 5/28/2010 10:20 AM Notification NRC/LICENSEE Supervision Page 1 of 1 Kewaunee ITS Conversion Database 06/24/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=2121 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 43 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 43 of 74

Licensee Response/NRC Response/NRC Question Closure Id 3581 NRC Question Number KAB-080 Select Application Licensee Response

Response

Date/Time 6/18/2010 8:40 AM Closure Statement

Response

Statement Three human error probabilities were recalculated using the SPAR-H model. Table E-2 documents these.

Table E-2: HEPs Re-evaluated Using SPAR The HI 27A-OR2----RDHE is a dependent HI, which means it assumed failure of previous HIs. It is therefore quantified using the THERP dependency model. In both the base case and the SPAR-H case, low dependency is assumed.

The conclusions of the report are not sensitive to these HEP changes. The result of these new HEPs is that CDF decreased from 4.8E-5/yr in the K107Aa model to 4.2E-5/yr in the K107AaILRT model. LERF decreased from 6.4E-6/yr to 4.9E-6/yr. If these HEP improvements are not credited, the total internal events plus external events CDF is 9.5E-5/yr, the total LERF is 1.2E-5/yr and results are still within the acceptable region of Regulatory Guide 1.174.

Human Interaction Description Base HEP SPAR HEP 06--OC4------HE Cooldown After SGTR Using ECA-3.1/3.2 1.9E-1 4.1E-3 27A-OR2----RDHE Refill RWST after SGTR or SLOCA 4.4E-1 5.0E-2 34--RHR------HE Establish RHR in Cooldown Mode 8.2E-2 1.0E-3 Question Closure Date Attachment 1

Attachment 2

Notification NRC/LICENSEE Supervision Kristy Bucholtz Victor Cusumano Jerry Jones Bryan Kays Ray Schiele Page 1 of 2 Kewaunee ITS Conversion Database 06/24/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=3581 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 44 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 44 of 74

Added By Robert Hanley Date Added 6/18/2010 8:43 AM Modified By Date Modified Page 2 of 2 Kewaunee ITS Conversion Database 06/24/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=3581 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 45 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 45 of 74

Licensee Response/NRC Response/NRC Question Closure Id 3901 NRC Question Number KAB-080 Select Application Licensee Response

Response

Date/Time 7/19/2010 12:55 PM Closure Statement

Response

Statement Based upon discussions with the NRC, DEK is providing additional detail to the original response. This detail is underlined for ease of review. The information in this response supersedes the original response posted on June 18, 2010.

Three human error probabilities were recalculated using the SPAR-H model. Table E-2 documents these.

Table E-2: HEPs Re-evaluated Using SPAR The first HI (06--OC4------HE) represents operators depressurizing the reactor coolant system (RCS) to atmospheric pressure in a steam generator tube rupture after failure to isolate the ruptured generator and depressurize the reactor coolant system below ruptured steam generator pressure. The HEP calculated for the K107Aa model was 1.9E-1. Of this HEP, the primary portion (1.8E-1 or 95%) is in the execution portion. This was modeled as 16 distinct switch manipulations summed together. This is not consistent with current HRA methodology, with which the cognitive portion is considered as a whole. In the SPAR-H calculation, the cognitive portion is 1E-4. The applicable multipliers are expansive time, high stress, symptom oriented procedures. The execution portion is 4E-3. The applicable multipliers are high stress and moderately complex.

The second HI (27A-OR2----RDHE) is a dependent HI. It assumes previous operator failure to isolate the ruptured generator and depressurize the RCS below ruptured steam generator pressure and failure to subsequently depressurize the RCS to atmospheric pressure. Operators are directed to emergency Operating procedure ES-1.3, Transfer to Containment Sump Recirculation upon reaching an RWST level of 37%. There is also an alarm and the alarm response procedure sends them to ES-1.3 as well. At this point operators are directed to ECA-1.1, Loss of Emergency Coolant Recirculation immediately if the water level in containment is not high enough to support recirculation, which it would not be in a tube rupture. Due to the Human Interaction Description Base HEP SPAR HEP 06--OC4------HE Cooldown After SGTR Using ECA-3.1/3.2 1.9E-1 4.1E-3 27A-OR2----

RDHE Refill RWST after SGTR 1.4E-1 5.0E-2 34--RHR------HE Establish RHR in Cooldown Mode 8.2E-2 1.0E-3 Page 1 of 3 Kewaunee ITS Conversion Database 07/20/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=3901 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 46 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 46 of 74

low flow in a tube rupture, there would be a large amount of time available to perform recirculation. Low dependency is assumed, based on the large amount of time before the refueling water storage tank empties and the multiple paths into the procedure.

The probability for 27A-OR2----RDHE was arrived at by taking the independent probability for RWST refill (9.6E-2) and enter it into the THERP (Reference 5.50) equation for low dependency (1+19*HEP)/20. In this case, the dependent HEP would be (1+19*9.6E-2)/20 or 1.4E-1. In the independent probability, 9.5E-2 or 99%

of the HEP was due to the execution portion. Similar to 06--OC4------HE, this was modeled as 14 distinct switch manipulations summed together. This is not consistent with current HRA methodology, with which the cognitive portion is considered as a whole. In the SPAR-H calculation, the cognitive portion is 5E-5. The applicable multipliers are expansive time, high stress, high experience/training, symptom oriented procedures. The execution portion is 4E-4. The applicable multipliers are time available greater than 5x the required time, high stress and moderately complex. Then the new HEP is entered in the THERP equation for low dependency, the dependent HEP would be (1+19*4.5E-4)/20 or 5.0E-2.

The third HI (34--RHR------HE) represents operators establishing RHR in a transient once a long term source of water to auxiliary feedwater (AFW) such as service water or condensate storage tank refill is unavailable. The HEP calculated for the K107Aa model was 8.2E-2. Of this HEP, the primary portion (7.9E-2 or 96%) is in the execution portion. Like the others, its was modeled as several distinct switch manipulations summed together. In the SPAR-H calculation, the cognitive portion is 2.5E-5. The applicable multipliers are expansive time, high experience/training, symptom oriented procedures. The execution portion is 1E-3.

The applicable multipliers are moderately complex and high experience/training.

The conclusions of the report are not sensitive to these HEP changes. The result of these new HEPs is that CDF decreased from 4.8E-5/yr in the K107Aa model to 4.2E-5/yr in the K107AaILRT model. LERF decreased from 6.4E-6/yr to 4.9E-6/yr. If these HEP improvements are not credited, the total internal events plus external events CDF is 9.5E-5/yr, the total LERF is 1.2E-5/yr and results are still within the acceptable region of Regulatory Guide 1.174.

Question Closure Date Attachment 1

Attachment 2

Notification NRC/LICENSEE Supervision Kristy Bucholtz Jerry Jones Bryan Kays Ray Schiele Added By Robert Hanley Date Added 7/19/2010 12:54 PM Page 2 of 3 Kewaunee ITS Conversion Database 07/20/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=3901 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 47 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 47 of 74

Modified By Date Modified Page 3 of 3 Kewaunee ITS Conversion Database 07/20/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=3901 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 48 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 48 of 74

Licensee Response/NRC Response/NRC Question Closure Id 4041 NRC Question Number KAB-080 Select Application NRC Question Closure

Response

Date/Time Closure Statement This question is closed and no further information is required at this time to draft the Safety Evaluation.

Response

Statement Question Closure Date 8/3/2010 Notification NRC/LICENSEE Supervision Charles Smoker Added By Kristy Bucholtz Date Added 8/3/2010 2:51 PM Modified By Date Modified Page 1 of 1 Kewaunee ITS Conversion Database 08/03/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=4041 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 49 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 49 of 74

ITS NRC Questions Id 2131 NRC Question Number KAB-081 Category Technical ITS Section Submittal Attachment 2 ITS Number DOC Number JFD Number JFD Bases Number Page Number(s) 25 NRC Reviewer Supervisor Rob Elliott Technical Branch POC Adel El-Bassioni Conf Call Requested N NRC Question Failure Data:

Item 1 in section 3.5.9 states that the component failure data of the WCAP -15376 report was reviewed against the Kewaunee-specific data. The plant-specific failure probability for the input logic relays (7.33 E-06) was found to be less than that reported in the WCAP report. Was this plant-specific failure probability based on plant specific experience only, or was applicable industry experience used? In case this estimate was subject to uncertainties, were sensitivity evaluations performed?

Attach File 1 Attach File 2 Issue Date 5/28/2010 Added By Kristy Bucholtz Date Modified Modified By Date Added 5/28/2010 10:22 AM Notification NRC/LICENSEE Supervision Page 1 of 1 Kewaunee ITS Conversion Database 06/24/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=2131 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 50 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 50 of 74

Licensee Response/NRC Response/NRC Question Closure Id 3591 NRC Question Number KAB-081 Select Application Licensee Response

Response

Date/Time 6/18/2010 8:45 AM Closure Statement

Response

Statement The failure probability of 7.33E-06 for the input logic relays was used in the PRA Model version 8/2003, and it reflects industry data. It came from an EGG-SSRE-8875 value of 3E-7/hr for spurious operation of a relay with a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> mission time. No plant-specific data was used so no sensitivities are needed.

Question Closure Date Notification NRC/LICENSEE Supervision Kristy Bucholtz Jerry Jones Bryan Kays Ray Schiele Added By Robert Hanley Date Added 6/18/2010 8:45 AM Modified By Date Modified Page 1 of 1 Kewaunee ITS Conversion Database 06/24/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=3591 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 51 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 51 of 74

Licensee Response/NRC Response/NRC Question Closure Id 3791 NRC Question Number KAB-081 Select Application NRC Question Closure

Response

Date/Time Closure Statement This question is closed per Donnie Harrison, BC APLA. No further information is required at this time to draft the Safety Evaluation.

Response

Statement Question Closure Date 7/13/2010 Notification NRC/LICENSEE Supervision Added By Victor Cusumano Date Added 7/13/2010 12:24 PM Modified By Date Modified Page 1 of 1 Kewaunee ITS Conversion Database 07/13/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=3791 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 52 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 52 of 74

ITS NRC Questions Id 2191 NRC Question Number KAB-082 Category Technical ITS Section 3.3 ITS Number 3.3.2 DOC Number JFD Number JFD Bases Number Page Number (s) 213 NRC Reviewer Supervisor Rob Elliott Technical Branch POC Add Name Conf Call Requested N NRC Question On page 213 of Attachment 1, volume 8, table 3.3.2-1 indicates the surveillance requirement 3.3.2.2 is required for Function 7.a, turbine building service water header isolation automatic actuation logic and actuation relays. However, the CTS requires calibration and test during each refueling cycle, please provide a comparison of SR 3.3.2.2 and the current calibration and test, including the testing frequency.

Attach File 1 Attach File 2 Issue Date 7/6/2010 Added By Kristy Bucholtz Date Modified Modified By Date Added 7/6/2010 6:02 AM Notification NRC/LICENSEE Supervision Page 1 of 1 Kewaunee ITS Conversion Database 07/08/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=2191 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 53 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 53 of 74

Licensee Response/NRC Response/NRC Question Closure Id 3661 NRC Question Number KAB-082 Select Application Licensee Response

Response

Date/Time 7/6/2010 7:20 AM Closure Statement

Response

Statement During the procedure development phase, KPS noted that the ACTUATION LOGIC TEST (SR 3.3.2.2) for ITS Table 3.3.2-1 Function 7.a, is required every 92 days on a Staggered Test Basis. However, the Turbine Building Service Water Header Isolation is actuated through a slave relay from the ESFAS Automatic Actuation Logic and Actuation Relays Function 1.b. As stated previously by KPS in the response to KAB-052, slave relays are not normally tested online, since their testing results in actuation of the associated components. Therefore, KPS currently tests the slave relays on an 18 month frequency. In the original ITS submittal, KPS attempted to include the standard frequency for an ACTUATION LOGIC TEST for all of these tests, even if they were not at this frequency in our CTS. However, due to this testing constraint, KPS is revising the ACTUATION LOGIC TEST frequency for ITS Table 3.3.2-1 Function 7.a. ITS SR 3.3.2.8 is being added to perform this test every 18 months for this Function only. Note that since this Function is derived, in part, from the same features tested as required by ITS Table 3.3.2-1 Function 1.b, the majority of the actuation components (e.g., the SI logic portions), will continue to be tested every 92 days on a Staggered Test Basis (per SR 3.3.2.2), as required to meet Table 3.3.2-1 Function 1.b requirements. A draft markup regarding this change is attached. This change will be reflected in the supplement to this section of the ITS conversion amendment.

Question Closure Date Attachment 1 KAB-082 Markup.pdf (1MB)

Attachment 2

Notification NRC/LICENSEE Supervision Kristy Bucholtz Robert Hanley Jerry Jones Bryan Kays Ray Schiele Added By Robert Hanley Date Added 7/6/2010 7:20 AM Modified By Page 1 of 2 Kewaunee ITS Conversion Database 07/08/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=3661 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 54 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 54 of 74

Date Modified Page 2 of 2 Kewaunee ITS Conversion Database 07/08/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=3661 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 55 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 55 of 74

TABLE TS 4.1-1 MINIMUM FREQUENCIES FOR CHECKS, CALIBRATIONS AND TEST OF INSTRUMENT CHANNELS Amendment No. 183 Page 7 of 7 6/20/2005 CHANNEL DESCRIPTION CHECK CALIBRATE TEST REMARKS

43. AFW Pump Low Discharge Pressure Trip Not Applicable Each refueling cycle Quarterly (a)

(a) Verification of relay setpoints not required.

44. Axial Flux Difference (AFD)

Weekly Verify AFD within limits for each OPERABLE excore channel

45. Service Water Turbine Header Isolation Logic Trip (SW 4 A/B)

Not Applicable Each refueling cycle Each refueling cycle

46. AFW Pump Low Suction Pressure Trip Not Applicable Each refueling cycle Quarterly (a)

(a) Verification of relay setpoints not required.

ITS ITS 3.3.2 Page 14 of 15 See ITS 3.7.5 See ITS 3.2.3 A06 COT SR 3.3.2.6 SR 3.3.2.4 Table 3.3.2-1, Function 7.b See ITS 3.7.5 M15 Add proposed SR 3.3.2.1, SR 3.3.2.4, and SR 3.3.2.6 for Functions 4.d, and 4.e M14 Add proposed SR 3.3.2.3 and SR 3.3.2.6 for Functions 6.d M09 Add proposed SR 3.3.2.5 for Functions 1.a, 2.a, 3.a, and 4.a M16 Add proposed SR 3.3.2.7 for Function 8 A01 M18 Add proposed SR 3.3.2.2 for Function 7.a 8

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DISCUSSION OF CHANGES ITS 3.3.2, ENGINEERED SAFETY FEATURE ACTUATION SYSTEM (ESFAS)

INSTRUMENTATION Condition, considering the OPERABLE status of the redundant systems or features. This includes the capacity and capability of remaining systems or features, a reasonable time for repairs or replacement, and the low probability of a DBA occurring during the allowed Completion Time. Allowing 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> to be in MODE 4 ensures a unit shutdown is commenced and completed within a reasonable period of time upon failure to restore the applicable ESFAS instrumentation to OPERABLE status within the allowed Completion Time. This change is designated as more restrictive because less time is allowed for the unit to reach MODE 4 in the ITS than is allowed to reach MODE 5 in the CTS.

M18 CTS does not include an ACTUATION LOGIC TEST for the Turbine Building Service Water Header Isolation Logic. ITS Table 3.3.2-1 Function 7.a, Automatic Actuation Logic and Actuation Relays, requires performance of ITS SR 3.3.2.2, which is an ACTUATION LOGIC TEST every 92 days on a STAGGERED TEST BASIS. This changes the CTS by specifying a new Surveillance Requirement.

The purpose of ITS SR 3.3.2.2 is to periodically verify the actuation logic is OPERABLE, with respect to the Turbine Building Service Water Header Isolation logic. This change is acceptable since it will help ensure that the turbine building header is isolated following an accident if the header pressure falls below a predetermined setpoint. This changes is designated as more restrictive because a new Surveillance Requirement is being added to the CTS.

RELOCATED SPECIFICATIONS None REMOVED DETAIL CHANGES LA01 (Type 4 - Removal of LCO, SR, or other TS Requirement to the TRM, USAR, ODCM, NFQAPD, CLRT Program, IST Program, ISI Program, or Setpoint Control Program) CTS 3.5.a states that Setting Limits for instrumentation which initiate operation of the engineered safety features shall be as stated in Table TS 3.5-1. CTS Table TS 3.5-1 contains Setting Limits for Engineered Safety Features initiation instruments. ITS 3.3.2 does not contain Setting Limits for ESFAS initiation instruments. This changes the CTS by moving the Setting Limits for the ESFAS instrumentation to the Setpoint Control Program.

The removal of these Setting Limits is acceptable because this type of information is not necessary to be included in the Technical Specifications to provide adequate protection of public health and safety. The ITS still maintains the requirement for the number of required channels and the appropriate Condition to enter if a required channel is inoperable. In addition, this change is acceptable because the removed information will be adequately controlled in Setpoint Control Program. Changes to the Setpoint Control Program are made under 10 CFR 50.59, which ensures that changes are properly evaluated. This change is designated as a less restrictive removal of detail change because Kewaunee Power Station Page 20 of 31 8

18 months 8

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ESFAS Instrumentation 3.3.2 WOG STS 3.3.2-7 Rev. 3.0, 03/31/04 SURVEILLANCE REQUIREMENTS

---

NOTE----------------------------------------------------------

Refer to Table 3.3.2-1 to determine which SRs apply for each ESFAS Function.

SURVEILLANCE FREQUENCY SR 3.3.2.1 Perform CHANNEL CHECK.

12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> SR 3.3.2.2 Perform ACTUATION LOGIC TEST.

92 days on a STAGGERED TEST BASIS SR 3.3.2.3

---

NOTE-------------------------------

The continuity check may be excluded.

Perform ACTUATION LOGIC TEST.

31 days on a STAGGERED TEST BASIS

---

REVIEWERS NOTE---------------------------------

The Frequency remains at 31 days on a STAGGERED TEST BASIS for plants with a Relay Protection System.

SR 3.3.2.4 Perform MASTER RELAY TEST.

92 days on a STAGGERED TEST BASIS SR 3.3.2.5 Perform COT.

184 days SR 3.3.2.6 Perform SLAVE RELAY TEST.

[92] days SR 3.3.2.7

---

NOTE-------------------------------

Verification of relay setpoints not required.

Perform TADOT.

[92] days CTS 4

3 Table TS 4.1-1, Channel Descriptions 7, 11.a, 11.b, 18.a, 18.b, 18.c Table TS 4.1-1, Channel Description 26, DOC M18 Table TS 4.1-1, Channel Descriptions 7, 11.a, 11.b, 18.a, 18.b, 18.c, and 35 DOC M14 4.1.a 7

5 5

5 5

All changes are unless otherwise noted 1

in accordance with the Setpoint Control Program 12 6

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ESFAS Instrumentation 3.3.2 WOG STS 3.3.2-8 Rev. 3.0, 03/31/04 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.2.8

---

NOTE-------------------------------

Verification of setpoint not required for manual initiation functions.

Perform TADOT.

[18] months SR 3.3.2.9

---

NOTE-------------------------------

This Surveillance shall include verification that the time constants are adjusted to the prescribed values.

Perform CHANNEL CALIBRATION.

[18] months SR 3.3.2.10

---

NOTE-------------------------------

Not required to be performed for the turbine driven AFW pump until [24] hours after SG pressure is

 [1000] psig.

Verify ESFAS RESPONSE TIMES are within limit.

[18] months on a STAGGERED TEST BASIS SR 3.3.2.11

---

NOTE-------------------------------

Verification of setpoint not required.

Perform TADOT.

Once per reactor trip breaker cycle CTS 5

6 7

DOC M09 Table TS 4.1-1, Channel Descriptions 7, 11.a, 11.b, 18.a, 18.b, and 18.c DOC M17 5

5 5

All changes are unless otherwise noted 3

9 12 in accordance with the Setpoint Control Program 15 6

6 INSERT 1A DOC M18 4

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3.3.2 Insert Page 3.3.2-8 INSERT 1A SR 3.3.2.8 Perform ACTUATION LOGIC TEST.

18 months DOC M18 CTS 4

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3.3.2 Insert Page 3.3.2-15 INSERT 2

7. Turbine Building Service Water Header Isolation

a.

Automatic Actuation Logic and Actuation Relays 1(e),2(e),3(e) 2 trains J

SR 3.3.2.2

b.

Service Water Pressure -

Low 1(e),2(e),3(e) 2 J

SR 3.3.2.4 SR 3.3.2.6 Coincident with Safety Injection Refer to Function 1 (Safety Injection) for all initiation functions and requirements.

INSERT 3 (e)

Except when one turbine building service water header isolation valve is closed and de-activated.

4 3.3.e.1, 3.3.e.1.A.3, DOC M18 Table TS 4.1-1 #45, 3.3.e.1, 3.3.e.1.A.3 CTS 4

3.3.e.1.A.3 8

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JUSTIFICATION FOR DEVIATIONS ITS 3.3.2, ENGINEERED SAFETY FEATURE ACTUATION SYSTEM (ESFAS)

INSTRUMENTATION Kewaunee Power Station Page 1 of 5

1.

The ISTS contains bracketed information and/or values that are generic to all Westinghouse vintage plants. The brackets are removed and the proper plant specific information/value is provided. This is acceptable since the generic specific information/value is revised to reflect the current plant design.

2.

The Reviewer's Note has been deleted. The information is for the NRC reviewer to be keyed into what is needed to meet this requirement. This is not meant to be retained in the final version of the plant specific submittal.

3.

Changes are made (additions, deletions, and/or changes) to the ISTS that reflect the plant specific nomenclature, number, reference, system description, analysis or licensing basis description. Where a deletion has occurred, subsequent alpha-numeric designators have been changed for any applicable affected ACTIONS, SURVEILLANCE REQUIREMENTS and FUNCTIONS.

4.

An additional Function, Function 7, Turbine Building Service Water Header Isolation, has been added to the ESFAS Instrumentation Specification to be consistent with the current licensing basis (CTS 3.3.e). The Surveillance Requirement included for the Automatic Actuation Logic and Actuation Relays (Function 7.a) is an ACTUATION LOGIC TEST (SR 3.3.2.2). Surveillance Requirements included for the Service Water Pressure - Low (Function 7.b) are a CHANNEL OPERATIONAL TEST (SR 3.3.2.4) and a CHANNEL CALIBRATION (SR 3.3.2.6). In addition, ACTION J has been added to provide compensatory measure to be taken when there are less than the number of required channels OPERABLE. This function provides automatic isolation of the non-safety (Turbine Building) service water header by closing the open Turbine Building Header isolation valve on receipt of a coincident low service water header pressure signal and a SI signal. This provides a means of isolating non-safety related cooling loads from the safety related cooling loads following an accident to assure adequate cooling is available to the safety related equipment.

5.

The ISTS contains a Surveillance Requirement (SR) for a MASTER RELAY TEST every 92 days on a STAGGERED TEST BASIS (ITS SR 3.3.2.4) and an SR for a SLAVE RELAY TEST every 92 days (ISTS SR 3.3.2.6). These Surveillance Requirements are not included in the KPS ITS.

This is acceptable because in response to Generic Letter 96-01 Testing of Safety-Related Logic Circuits KPS verified that the appropriate relays, contacts, and wiring runs were being tested for overlap. The results of this effort were changes and enhancements to KPS procedures to ensure every aspect of the Safety Related Logic Circuits were being tested. The Master and Slave relays that can be checked online without affecting safety and reliability are checked during the Actuation Logic Test (ALT). The remaining portions of the circuits that cannot be checked during the Actuation Logic Test are checked by various other procedures when plant conditions allow for the safe and reliable testing of these portions. All of this was documented in the KPS response to Generic Letter 96-01.

KPS design does not allow for monthly or quarterly testing of the Master Relays and Slave Relays in a separate test. Kewaunee design does not include special test circuitry that would allow convenient testing of all relays. To successfully test 8

Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 62 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 62 of 74

B 3.3.2 Insert Page B 3.3.2-32a INSERT 12

7. Turbine Building Service Water Header Isolation The Service Water (SW) System is designed to provide redundant cooling water for cooling safety related and non-safety related equipment throughout the plant. The SW System consists of four SW pumps, four traveling screens, four rotating SW strainers, and interconnecting piping. The normal source of water for the SW System is Lake Michigan through a submerged multiple inlet structure. The SW System is designed with two redundant headers, each of which is served by two SW pumps. In the event of an accident resulting in Safety Injection (SI) initiation, the two redundant headers are separated by automatically closing the SW header isolation valves. Train specific service water isolation to the non-safety related equipment in the Turbine Building will occur upon a SI sequence concurrent with low service water header pressure. This ensures that safety related equipment will receive sufficient flow under all conditions.

a. Turbine Building Service Water Header Isolation - Automatic Actuation Logic and Actuation Relays Automatic actuation logic and actuation relays consist of the same features and operate in the same manner as described for ESFAS Function 1.b.

b. Service Water Pressure - Low Coincident with Safety Injection This function provides automatic isolation of the non-safety (Turbine Building) service water header by closing the open Turbine Building Header isolation valve on receipt of a coincident low service water header pressure signal and a SI signal. This provides a means of isolating non-safety related cooling loads from the safety related cooling loads following an accident to assure adequate cooling is available to the safety related equipment.

The automatic isolation of SW to non-essential load design provides independent and redundant closure signals to the SW-4A (B) valves: A-train to SW-4A and B-train to SW-4B. The closure signals are developed from the SI sequence signal coincident with low SW header pressure on the corresponding A-train and B-train SW headers. Using low header pressure as the coincident signal is appropriate because it indicates that SW supply to the safety related loads will not be adequate unless the SW supply to the non-essential load is isolated.

1 the logic necessary to actuate each of the two trains. The logic for each train includes

, as well as the slave relay fed from the ESFAS Function 1.b and the Service Water Pressure - Low input Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 63 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 63 of 74

Engineered Safety Feature Actuation System (ESFAS) Instrumentation B 3.3.2 WOG STS B 3.3.2-54 Rev. 3.0, 03/31/04 BASES SURVEILLANCE REQUIREMENTS (continued)

WCAP-14036-P, Revision 1, "Elimination of Periodic Protection Channel Response Time Tests," (Ref. 14) provides the basis and methodology for using allocated signal processing and actuation logic response times in the overall verification of the protection system channel response time.

The allocations for sensor, signal conditioning, and actuation logic response times must be verified prior to placing the component in operational service and re-verified following maintenance that may adversely affect response time. In general, electrical repair work does not impact response time provided the parts used for repair are of the same type and value. Specific components identified in the WCAP may be replaced without verification testing. One example where response time could be affected is replacing the sensing assembly of a transmitter.

ESF RESPONSE TIME tests are conducted on an [18] month STAGGERED TEST BASIS. Testing of the final actuation devices, which make up the bulk of the response time, is included in the testing of each channel. The final actuation device in one train is tested with each channel. Therefore, staggered testing results in response time verification of these devices every [18] months. The [18] month Frequency is consistent with the typical refueling cycle and is based on unit operating experience, which shows that random failures of instrumentation components causing serious response time degradation, but not channel failure, are infrequent occurrences.

This SR is modified by a Note that clarifies that the turbine driven AFW pump is tested within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after reaching [1000] psig in the SGs.

SR 3.3.2.11 SR 3.3.2.11 is the performance of a TADOT as described in SR 3.3.2.8, except that it is performed for the P-4 Reactor Trip Interlock, and the Frequency is once per RTB cycle. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable TADOT of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions. This Frequency is based on operating experience demonstrating that undetected failure of the P-4 interlock sometimes occurs when the RTB is cycled.

The SR is modified by a Note that excludes verification of setpoints during the TADOT. The Function tested has no associated setpoint.

7 5

13 5

5 INSERT 18 5

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INSERT 18 SR 3.3.2.8 is the performance of an ACTUATION LOGIC TEST. The Turbine Building Service Water Header Isolation relay logic is tested every 18 months. For the portion of the logic common to the ESFAS, Function 1.b ACTUATION LOGIC TEST, the train being tested is placed in the test condition, thus preventing inadvertent actuation, and all possible SI logic combinations are tested for each protection function. For the portion of the logic not tested as part of the ESFAS Function 1.b ACTUATION LOGIC TEST (e.g., the slave relays), actuation of the end devices may occur. The Frequency of every 18 months is based on the refueling outage cycle, since the slave relay cannot be tested at power without resulting in actuation of affected components.

5 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 65 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 65 of 74

Licensee Response/NRC Response/NRC Question Closure Id 3841 NRC Question Number KAB-082 Select Application NRC Question Closure

Response

Date/Time Closure Statement This question is closed and no further information is required at this time to draft the Safety Evaluation.

Response

Statement Question Closure Date 7/16/2010 Notification NRC/LICENSEE Supervision Added By Kristy Bucholtz Date Added 7/16/2010 10:44 AM Modified By Date Modified Page 1 of 1 Kewaunee ITS Conversion Database 07/19/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=3841 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 66 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 66 of 74

ITS NRC Questions Id 2201 NRC Question Number KAB-083 Category Technical ITS Section 3.3 ITS Number 3.3.7 DOC Number JFD Number JFD Bases Number Page Number (s) 459 NRC Reviewer Supervisor Rob Elliott Technical Branch POC Add Name Conf Call Requested N NRC Question On page 459 of Attachment 1, volume 8, table 3.3.7-1 indicates the surveillance requirement 3.3.7.3 is required for Function 1, CRPAR system automatic actuation logic and actuation relays. However, the CTS requires calibration during each refueling cycle and testing quarterly, please provide a comparison of SR 3.3.7.3 and the current calibration and test, including the testing frequency.

Attach File 1 Attach File 2 Issue Date 7/6/2010 Added By Kristy Bucholtz Date Modified Modified By Date Added 7/6/2010 6:03 AM Notification NRC/LICENSEE Supervision Page 1 of 1 Kewaunee ITS Conversion Database 07/08/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=2201 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 67 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 67 of 74

Licensee Response/NRC Response/NRC Question Closure Id 3671 NRC Question Number KAB-083 Select Application Licensee Response

Response

Date/Time 7/6/2010 7:20 AM Closure Statement

Response

Statement During the procedure development phase, KPS noted that the ACTUATION LOGIC TEST (SR 3.3.7.3) for ITS Table 3.3.7-1 Function 1, is required every 92 days on a Staggered Test Basis. However, the CRPAR System SI initiation signal is actuated through a slave relay from the ESFAS Automatic Actuation Logic and Actuation Relays, Table 3.3.2-1 Function 1.b. As stated previously by KPS in the response to KAB-052, slave relays are not normally tested online, since their testing results in actuation of the associated components. Therefore, KPS currently tests the slave relays on an 18 month frequency (as part of CTS 4.17.a.2). In the original ITS submittal, KPS attempted to include the standard frequency for an ACTUATION LOGIC TEST for all of these tests, even if they were not at this frequency in our CTS. However, due to this testing constraint, KPS is revising the ACTUATION LOGIC TEST frequency for ITS Table 3.3.7-1 Function 1 to perform this test every 18 months. Note that since this Function is derived,in part, from the features tested as required by ITS Table 3.3.2-1 Function 1.b, the majority of the actuation components (e.g.,

the SI logic portions), will continue to be tested every 92 days on a Staggered Test Basis (per SR 3.3.2.2), as required to meet Table 3.3.2-1 Function 1.b requirements. A draft markup regarding this change is attached. This change will be reflected in the supplement to this section of the ITS conversion amendment.

Question Closure Date Attachment 1 KAB-083 Markup.pdf (1MB)

Attachment 2

Notification NRC/LICENSEE Supervision Kristy Bucholtz Jerry Jones Bryan Kays Ray Schiele Added By Robert Hanley Date Added 7/6/2010 7:23 AM Modified By Date Page 1 of 2 Kewaunee ITS Conversion Database 07/08/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=3671 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 68 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 68 of 74

Modified Page 2 of 2 Kewaunee ITS Conversion Database 07/08/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=3671 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 69 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 69 of 74

CREFS Actuation Instrumentation 3.3.7 WOG STS 3.3.7-3 Rev. 3.0, 03/31/04 PAR System SURVEILLANCE REQUIREMENTS

---

NOTE-----------------------------------------------------------

Refer to Table 3.3.7-1 to determine which SRs apply for each CREFS Actuation Function.

SURVEILLANCE FREQUENCY SR 3.3.7.1 Perform CHANNEL CHECK.

12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> SR 3.3.7.2 Perform COT.

92 days SR 3.3.7.3 Perform ACTUATION LOGIC TEST.

31 days on a STAGGERED TEST BASIS SR 3.3.7.4 Perform MASTER RELAY TEST.

31 days on a STAGGERED TEST BASIS

---

REVIEWERS NOTE----------------------------------

The Frequency of 92 days on a STAGGERED TEST BASIS is applicable to the actuation logic processed through the Relay or Solid State Protection System.

SR 3.3.7.5

---

NOTE------------------------------

This Surveillance is only applicable to the actuation logic of the ESFAS Instrumentation.

Perform ACTUATION LOGIC TEST.

92 days on a STAGGERED TEST BASIS CTS PAR System 9

5 7

3 6

4.1.a, Table TS 4.1-1, Channel Description 19 4.1.a, Table TS 4.1-1, Channel Description 19 DOC M04 1

1 10 in accordance with the Setpoint Control Program.

18 months 6

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JUSTIFICATION FOR DEVIATIONS ITS 3.3.7, CONTROL ROOM POST ACCIDENT RECIRCULATION (CRPAR) SYSTEM ACTUATION INSTRUMENTATION Kewaunee Power Station Page 2 of 4

5.

Changes are made to the ISTS that reflect the adoption of proposed Revision 4 of TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions".

Three options are provided when adopting TSTF-493. Kewaunee Power Station (KPS) has elected to implement TSTF-493 via the use of a Setpoint Control Program (SCP). Under this option, KPS relocates the Technical Specification Section 3.3, "Instrumentation," Limiting Trip Setpoints, Nominal Trip Setpoints, and/or Allowable Values from the Technical Specifications to a licensee-controlled SCP. The requirements for the SCP are described in ITS Chapter 5, "Administrative Controls," of the Technical Specifications. Therefore, the TRIP SETPOINT column has been deleted from Table 3.3.7-1 of the ITS. In addition, this option requires that each instrument surveillance requirement which verifies a LSSS (both SL and non-SL LSSSs) contain a requirement to perform the surveillance test in accordance with the SCP. Thus, the phrase "in accordance with the Setpoint Control Program" has been added to ITS SR 3.3.7.2 and SR 3.3.7.6.

6.

The ISTS contains a Surveillance Requirement (SR) for an ACTUATION LOGIC TEST (ISTS SR 3.3.7.3) for the Automatic Actuation Logic and Actuation Relays Function. The SR Frequency is every 31 days on a STAGGERED TEST BASIS.

The ISTS also contains an ACTUATION LOGIC TEST (ISTS SR 3.3.7.5) for the Automatic Actuation Logic and Actuation Relays Function. The specified Frequency is every 92 days on a STAGGERED TEST BASIS. ISTS SR 3.3.7.5 was added to the ISTS as part of the incorporation of TSTF-411, which, in part, increases the surveillance test interval (STI) for the actuation logic and master relays. The basis for the increase in the STI is WCAP-15376-P, Revision 0, which is consistent with the Nuclear Regulatory Commission's (NRC) approach for using probabilistic risk assessment in risk-informed decisions on plant-specific changes to the current licensing basis as presented in Regulatory Guides 1.174, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Current Licensing Basis," and 1.177, "An Approach for Plant-Specific, Risk-Informed Decision making: Technical Specifications." KPS has elected to adopt the specific ISTS changes authorized by the results of WCAP-15376-P, Revision 0. Therefore, ISTS SR 3.3.7.5 (ITS SR 3.3.7.3) has been adopted for testing of the Automatic Actuation Logic and Actuation Relays Function.

7.

The Reviewer's Note has been deleted. The information is to alert the NRC reviewer to what is needed to meet this requirement. This information is not meant to be retained in the final version of the plant specific submittal.

8.

The design of the KPS CRPAR System is such that there is not a means to perform a manual initiation of the CRPAR System using a single pushbutton. The System is manually started using control switches for the various components.

Manual initiation of the CRPAR System consists of a manual start of the CRPAR fans by the control room operator via two three-position control switches in the control room (one switch for each train with the switch positions being ON/AUTO/OFF, spring return to AUTO). Therefore, ISTS Table 3.3.7-1 Function 1, Manual Initiation, has not been included in the KPS ITS. This is consistent with the KPS CTS, which does not include a Manual Initiation Function for the CRPAR System. The design of the KPS CRPAR Actuation Instrumentation However, the Frequency of the SR has been changed to 18 months (ITS SR 3.3.7.3). At KPS, the SI signal to the CRPAR System is from a slave relay, not a master relay. As discussed in JFD 9, many slave relays cannot be tested on line.

This includes the one that sends the SI start signal to the CRPAR System.

Thus, the Frequency for this test is changed to 18 months. Note that the SI signal logic, excluding the slave relay, is required to be tested as part of the ACTUATION LOGIC TEST in SR 3.3.2.2.

Thus the majority of the test is being performed every 92 days on a STAGGERED TEST BASIS, consistent with WCAP-15376-P.

Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 71 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 71 of 74

CREFS Actuation Instrumentation B 3.3.7 WOG STS B 3.3.7-2 Rev. 3.0, 03/31/04 PAR System BASES LCO The LCO requirements ensure that instrumentation necessary to initiate the CREFS is OPERABLE.

1.

Manual Initiation The LCO requires two channels OPERABLE. The operator can initiate the CREFS at any time by using either of two switches in the control room. This action will cause actuation of all components in the same manner as any of the automatic actuation signals.

The LCO for Manual Initiation ensures the proper amount of redundancy is maintained in the manual actuation circuitry to ensure the operator has manual initiation capability.

Each channel consists of one push button and the interconnecting wiring to the actuation logic cabinet.

2.

Automatic Actuation Logic and Actuation Relays The LCO requires two trains of Actuation Logic and Relays OPERABLE to ensure that no single random failure can prevent automatic actuation.

Automatic Actuation Logic and Actuation Relays consist of the same features and operate in the same manner as described for ESFAS Function 1.b., SI, in LCO 3.3.2. The applicable MODES and specified conditions for the CREFS portion of these functions are different and less restrictive than those specified for their SI roles. If one or more of the SI functions becomes inoperable in such a manner that only the CREFS function is affected, the Conditions applicable to their SI function need not be entered. The less restrictive Actions specified for inoperability of the CREFS Functions specify sufficient compensatory measures for this case.

3.

Control Room Radiation The LCO specifies two required Control Room Atmosphere Radiation Monitors and two required Control Room Air Intake Radiation Monitors to ensure that the radiation monitoring instrumentation necessary to initiate the CREFS remains OPERABLE.

For sampling systems, channel OPERABILITY involves more than OPERABILITY of channel electronics. OPERABILITY may also require correct valve lineups, sample pump operation, and filter motor operation, as well as detector OPERABILITY, if these supporting features are necessary for trip to occur under the conditions assumed by the safety analyses.

PAR System PAR System PAR System 1

2 one 4

4 4

All changes are unless otherwise noted 1

Vent Monitor Vent and include the slave relays that send the SI signal to the CRPAR System.

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CREFS Actuation Instrumentation B 3.3.7 WOG STS B 3.3.7-7 Rev. 3.0, 03/31/04 PAR System BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.3.7.4 SR 3.3.7.4 is the performance of a MASTER RELAY TEST. The MASTER RELAY TEST is the energizing of the master relay, verifying contact operation and a low voltage continuity check of the slave relay coil. Upon master relay contact operation, a low voltage is injected to the slave relay coil. This voltage is insufficient to pick up the slave relay, but large enough to demonstrate signal path continuity. This test is performed every 31 days on a STAGGERED TEST BASIS. The Frequency is acceptable based on instrument reliability and industry operating experience.

[ SR 3.3.7.5 SR 3.3.7.5 is the performance of an ACTUATION LOGIC TEST. The train being tested is placed in the bypass condition, thus preventing inadequate actuation. Through the semiautomatic tester, all possible logic combinations, with and without applicable permissives, are tested for each protection function. In addition, the master relay coil is pulse tested for continuity. This verifies that the logic modules are OPERABLE and there is an intact voltage signal path to the master relay coils. This test is performed ever 92 days on a STAGGERED TEST BASIS. The Surveillance interval is justified in Reference 1.

The SR is modified by a Note stating that the Surveillance is only applicable to the actuation logic of the ESFAS Instrumentation. ]

[ SR 3.3.7.6 SR 3.3.7.6 is the performance of a MASTER RELAY TEST. The MASTER RELAY TEST is the energizing of the master relay, verifying contact operation and a low voltage continuity check of the slave relay coil. Upon master relay contact operation, a low voltage is injected to the slave relay coil. This voltage is insufficient to pick up the slave relay, but large enough to demonstrate signal path continuity. This test is performed every 92 days on a STAGGERED TEST BASIS. The Surveillance interval is justified in Reference 1.

The SR is modified by a Note stating that the Surveillance is only applicable to the master relays of the ESFAS Instrumentation. ]

4 2

2 4

4 1

test 1

inadvertent 3

3 every 3

For the portion of the logic common to ESFAS, Function 1.b ACTUATION LOGIC TEST, the and all SI For the portion of the logic not tested as part of the ESFAS Function 1.b ACTUATION LOGIC TEST (i.e., the slave relay), actuation of the end devices may occur.

The Frequency of 18 months is based on the refueling outage cycle, since the slave relay cannot be tested at power without resulting in actuation of affected components.

4 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 73 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 73 of 74

Licensee Response/NRC Response/NRC Question Closure Id 3851 NRC Question Number KAB-083 Select Application NRC Question Closure

Response

Date/Time Closure Statement This question is closed and no further information is required at this time to draft the Safety Evaluation.

Response

Statement Question Closure Date 7/16/2010 Notification NRC/LICENSEE Supervision Added By Kristy Bucholtz Date Added 7/16/2010 10:45 AM Modified By Date Modified Page 1 of 1 Kewaunee ITS Conversion Database 07/19/2010 http://www.excelservices.com/rai/index.php?requestType=areaItemPrint&itemId=3851 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 74 of 74 Enclosure (8 of 8), Q&A to Attachment 1, Volume 8 (Section 3.3) 74 of 74