IR 05000354/2011004

lR 05000354-11-004; 07/01/2011 - 09/30/2011; Hope Creek Generating Station; Maintenance Effectiveness and Operability Evaluations

ML113140561
Person / Time
Site:	Hope Creek
Issue date:	11/10/2011
From:	Burritt A L Reactor Projects Branch 3
To:	Joyce T P Public Service Enterprise Group
BURRITT AL
References
IR-11-004
Download: ML113140561 (43)

Text

November 10,2OI1Mr. Thomas P. JoycePresident and Chief Nuclear OfficerPSEG Nuclear LLC - N09P.O. Box 236Hancocks Bridge, NJ 08038

SUBJECT: HOPE CREEK GENERATING STATION - NRC INTEGRATED INSPECTIONREPORT 05000354/201 1 004

Dear Mr. Joyce:

On September 30, 2011, the U. S. Nuclear Regulatory Commission (NRC) completed aninspection at the Hope Creek Generating Station. The enclosed inspection report documentsthe inspection results discussed on October 13,2011, with Mr. Perry, Station Vice President,and other members of your staff.The inspection examined activities conducted under your license as they relate to safety andcompliance with the Commission's rules and regulations and with the conditions of your license.The inspectors reviewed selected procedures and records, observed activities, and interviewedpersonnel.The report documents two findings of very low safety significance (Green). One of the findingswas determined to involve a violation of NRC requirements. Additionally, a licensee-identifiedviolation, which was determined to be of very low safety significance, is listed in this report.However, because of their very low safety significance and because they were entered into yourcorrective action program (CAP), the NRC is treating these findings as non-cited violations(NCVs) consistent with Section 2.3.2.a of the NRC Enforcement Policy. lf you contest any NCVin this report, you should provide a response within 30 days of the date of this inspection report,with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: DocumentControl Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region l;the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC20555-0001; and the NRC Resident lnspector at the Hope Creek Generating Station. Inaddition, if you disagree with the cross-cutting aspect assigned to any finding in this report, youshould provide a response within 30 days of the date of this inspection report, with the basis foryour disagreement, to the Regional Administrator, Region l, and the NRC Resident Inspector atthe Hope Creek Generating Station.In accordance with Title 10 of the Code of Federal Regulations (CFR) 2.390 of the NRC's"Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will beavailable electronically for public inspection in the NRC Public Document Room or from the T. JoycePublicly Available Records (PARS) component of NRC's document system (ADAMS). ADAMSis accessible from the NRC Web site at http://www.nrc.qov/readinq-rm/adams.html (the PublicElectronic Reading Room).Docket No:License No:

Enclosure:

cc w/encl:Arthur L. Burritt, ChiefReactor Projects Branch 3Division of Reactor Projects50-354NPF-57I nspection Report 05000354/201 1 004

w/Attachment:

Supplemental InformationDistribution via ListServ

SUMMARY OF FINDINGS

lR 0500035412011004;071A1i2011 - 0913012011; Hope Creek Generating Station; MaintenanceEffectiveness and Operability Evaluations.This report covers a three-month period of inspection by resident inspectors, and announcedinspections by reactor engineers and a regional radiation specialist. Two Green findings wereidentified. The significance of most findings is indicated by their color (Green, White, Yellow,Red) using Inspection Manual Chapter (lMC) 0609, "Significance Determination Process"(SDP). The cross-cutting aspect of a finding is determined using the guidance in IMC 0310,"Components Within the Cross-Cutting Areas." Findings for which the SDP does not apply maybe Green or be assigned a severity level after NRC management review. The NRC's programfor overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 4, dated December 2006.

Cornerstone: lnitiating Events.

Green.

A self-revealing finding was identified because of the PMOC did not drivesustainable improvements in the 00-K-107 service air compressor's reliability as required byPM program procedure WC-AA-111. Specifically, PSEG did not change the PM frequencyof the degraded compressor outlet check valve (H0KA-0KAV-004) nor evaluate the use ofmaterials less susceptible to corrosion after several recent performances of the 18-monthPM found excessive corrosion and rust on the valve internals. Consequently, this checkvalve failed closed due to corrosion, tripped the air compressor, and caused a service andinstrument air headers pressure transients followed by an automatic start of the EIAC. Afterthe May 12,2011, failure, PSEG refurbished H0KA-0KAV-004's internals with new carbonsteel components and plans to replace the 00-K-107 and 10-K-107 compressors'outletcheck valves with stainless steel valves that are less susceptible to corrosion (Orders60097323 and 60097371).This finding is more than minor because it was associated with the equipment performanceattribute of the Initiating Events cornerstone and affected the cornerstone objective oflimiting the likelihood of events that upset plant stability and challenge critical safetyfunctions at power. Specifically, the failure to adequately maintain the degradedcompressor outlet check valve in the service air header increased the likelihood of a planttrip. The inspectors evaluated this finding using IMC 0609, Attachment 4, "Phase 1 - lnitialScreening and Characterization of Findings," Table 4a, and determined the finding to be ofvery low safety significance (Green) because the finding does not contribute to both thelikelihood of a reactor trip and the likelihood that mitigation equipment would not beavailable. The finding has a cross-cutting aspect in the area of human performance, workcontrol component; because PSEG did not appropriately coordinate work activities byincorporating actions to ensure that maintenance scheduling is more preventive thanreactive. Specifically, PSEG did not implement a recommended increase (PCR 80101517)in the frequency of a PM for H0KA-0KAV-004 before the valve failed shut and requiredreactive maintenance following a trip of the 00-K-107 air compressor. (H.3(b)) (Section1R12)

4

Cornerstone: Mitigating Systems.

Green.

The inspectors identified a non-cited violation (NCV) of 10 CFR 50, Appendix B,Criterion lll, "Design Control," in that, PSEG did not ensure the adequacy of the highpressure coolant injection (HPCI) design under post-accident conditions. Specifically,PSEG did not evaluate the impact of elevated temperature in the HPCI room on theoperability of the HPCI system during a postulated design basis small break loss of coolantaccident (SBLOCA) coincident with a loss of offsite power (LOOP) and a single failure of theA emergency diesel generator (EDG). PSEG determined through subsequent evaluationthat HPCI was operable but non-conforming because there was a potentialfor HPCI systemto isolate unnecessarily on high differential temperature during the extreme winter lowtemperatures. PSEG plans to implement a design change to reduce the setpoints of theHPCI room coolers so that the initial HPCI room temperature is maintained at a lowertemperature before extreme winter conditions. The violation was entered into the CAP asnotifications 205 1 81 24 and 205201 06.The performance deficiency was more than minor because it was associated with the designcontrol attribute of the Mitigating Systems cornerstone and affected the cornerstoneobjective of ensuring the reliability of systems that respond to initiating events to preventundesirable consequences. Specifically, PSEG had not evaluated HPCI operability usingactual HPCI room temperatures during normal operating conditions, and as a result, HPCI'sreliability during the most limiting accident conditions was not assured during extreme winterlow temperatures. The inspectors reviewed this condition using IMC 0609, Attachment 4,and in consultation with a Region I senior reactor analyst (SRA), concluded that this issuescreened to very low safety significance (Green). The finding had a cross-cutting aspect inthe area of problem identification and resolution, corrective action component, becausePSEG did not thoroughly evaluate a prior problem such that the problem resolutionaddressed the causes and the extent of condition. Specifically, PSEG's evaluation fornotification 20381041, HPCI Operability During Station Blackout (SBO) Conditions, did notidentify the impact of the actual initial HPCI room temperature on other accident conditions,such as a SBLOCA and LOOP with the single failure of an EDG and, therefore, did notidentify that the actual HPCI room temperature was beyond the HPCI design documentassumption that temperature should be between 60"F and 100'F. (P.1(c)) (Section 1 R15)

Other Findings

A violation of very low safety significance identified by PSEG was reviewed by theinspectors. Corrective actions taken or planned by PSEG have been entered into PSEG'scorrective action program. This violation and corrective action tracking number are listed inSection 4OA7 of this report.Enclosure 5

REPORT DETAILS

Summarv of Plant StatusThe Hope Creek Generating Station operated at or near full rated thermal power (RTP) for theduration of the inspection period with the following exceptions. On selected occasions requiredby atmospheric conditions, reactor power was reduced in small increments to clear condenservacuum concerns and then subsequently returned to full RTP when atmospheric conditionsallowed. On July 22,2011, operators performed an unplanned power reduction from 94 percentto 80 percent RTP in response to increasing temperatures in the station auxiliary cooling systemthat was caused by grassing in the station service water (SW) system. The grassing issue wascleared and reactor power was increased the same day to the limits allowed by condenservacuum. On September 9, 2011, a planned power reduction to approximately 76 percent RTPwas conducted to support turbine valve testing, control rod scram time testing and a control rodpattern sequence change. The reactor was returned to full RTP on September 10, 2Q11, andthe reactor remained near or at full RTP for the remainder of the inspection period.1. REACTOR SAFEWCornerstones: Initiating Events, Mitigating Systems, Barrler Integrity, andEmergency Preparedness1R01 Adverse Weather Protection (71111.01 - 1 lmminent sample, 1 Ext Fld sample).1 Readiness for lmpendinq Adverse Weather Conditionsa. Inspection ScopeThe inspectors completed one impending adverse weather preparation sample. Theinspectors reviewed PSEG's preparations for the onset of hot weather on July 12,2011.The inspectors reviewed the implementation of adverse weather preparation proceduresbefore the onset of and during adverse weather conditions. The inspectors walked downthe EDGs and station service water (SW) to ensure system availability. The inspectorsverified that operator actions defined in PSEG's adverse weather procedure maintainedthe readiness of essential systems. The inspectors discussed readiness and staffavailability for adverse weather response with operations and work control personnel.Documents reviewed are listed in the Attachment.b. FindinssNo findings were identified..2 Readiness to Cope with External Floodinqa. Inspection ScopeDuring September 2011 , the inspectors performed an inspection of the external floodprotection measures for Hope Creek. The inspectors reviewed the updated final safetyanalysis report (UFSAR) Chapters 2.4.2, "Floods," and 3.4, "Water Level (Flood)Design," which depicted the design flood levels and protection areas containing safety-Enclosure 6related equipment to identify areas that may be affected by flooding. The inspectorsalso reviewed the limiting conditions for operations and the surveillance requirements intechnical specification (TS) 314.7.3, "Flood Protection." The review was focused on thepower block flood doors listed in TS Table 3.7.3-1, "Perimeter Flood Doors." Theinspectors reviewed the PM activities performed on these doors with the responsiblesystem engineer. The inspectors also conducted a walkdown of the accessible portionsof all these doors with the responsible system engineer to verify that the doors were inconformance with the design basis requirements in the UFSAR, the TS, and plantprocedures and drawings. Additionally, the inspectors reviewed the abnormal operatingprocedure, HC.OP-AB.MISC-0001, "Acts of Nature," for mitigating external floodingduring severe weather to determine if PSEG had planned and established adequatemeasures to protect against externalflooding events. Documents reviewed are listed inthe Attachment.b. FindinqsNo findings were identified.

1R04 Equipment Aliqnment (71111 .A4 - 2 samples; 71111.04S - 1 sample)

.1 PartialWalkdownsa. Inspection ScopeThe inspectors completed two partialwalkdown inspection samples. The inspectorsperformed partial system walkdowns for the systems listed below to verify each system'soperability when redundant or diverse trains and components were inoperable. Theinspectors completed walkdowns to determine whether there were discrepancies in thesystem's alignment that could impact the function of the system, and therefore,potentially increase risk. The inspectors reviewed applicable operating procedures,walked down system components, and verified that selected breakers, valves, andsupport equipment were in the correct position to support system operation. Theinspectors also verified that PSEG had properly identified and resolved equipmentalignment problems that could cause initiating events or impact the capability ofmitigating systems or barriers and entered them into the CAP. Documents reviewedare listed in the Attachment.r C residual heat removal (RHR) pump while D RHR out-of-service on July 26. B, C, D EDG while A EDG out-of-service on August 2FindinqsNo findings were identified.Complete WalkdownInspection ScopeThe inspectors performed one complete walkdown inspection of the A EDG. Theinspectors used PSEG procedures and other documents to verify proper systemalignment and functional capability. The inspectors independently verified the alignmentEnclosureb.a.,2 7and status of the A EDG system breakers, valves, switches, and associated supportsystems. The walkdown also included checks that fuel oil levels were normal, systemparameters were within established ranges, and equipment deficiencies wereappropriately identified and entered into the CAP for resolution. Documents reviewedare listed in the Attachment.b. FindinqsNo findings were identified.

1R06 Flood Protection Measures (71111.06 - 1 Int Fld sample)Internal Floodinq Reviewa. Inspection ScopeThe inspectors completed one flood protection measures inspection sample. Theinspectors reviewed selected risk-important plant design features and PSEG proceduresintended to protect the plant and its safety-related equipment from internal floodingevents. Specifically, the inspectors focused on internal flood mitigation features for the130' elevation of the auxiliary building, which contains class 1E switchgear, breakers,and control panels for all four EDGs. The inspectors reviewed flood analysis and designdocuments, including the UFSAR, engineering calculations, and abnormaloperatingprocedures. The inspectors observed the condition of wall penetrations, watertightdoors, flood alarm switches, and drains to assess their readiness to contain flow from aninternal flood in accordance with the design basis. Documents reviewed are listed in theAttachment.b. FindinqsNo findings were identified.1R11 Licensed Operator Requalification Proqram (71111.11Q - 1 sample)a. Inspection ScopeOn August 15,2011, the inspectors completed one quarterly licensed operatorrequalification program inspection sample. The inspectors observed operators in theplant's simulator during licensed operator requalification training to verify that operatorperformance was adequate and that evaluators were identifying and documenting crewperformance problems. The inspectors also verified that performance errors wereEnclosure

9discussed in the crew's post-scenario critiques. The inspectors focused on the controlroom supervisor's satisfactory completion of critical tasks. The inspectors also observedoperator implementation of abnormal and emergency operating procedures. Theinspectors discussed the training, simulator scenarios, and critiques with the operators,shift supervision, and the training instructors. Documents reviewed are listed in theAttachment. The simulated events observed during this one scenario are listed below:. Recirculation pump trip;. Fuel cladding failure; and. A stuck open safety/relief valve (SRV).b. FindinosNo findings were identified.

1R12 Maintenance Effectiveness (71111.12Q - 1 samples)a. Inspection ScopeThe inspectors completed one maintenance effectiveness inspection sample. For theequipment performance issue listed below, the inspectors evaluated items such as:appropriate work practices; identifying and addressing common cause failures; scopingin accordance with 10 CFR 50.65(b) of the Maintenance Rule; characlerizing reliabilityissues for performance; classification and reclassification in accordance with 10 CFR50.sa(a)(1) or (a)(2); and appropriateness of performance criteria for structures,systems, and components (SSCs)/functions classified as (a)(2) and/or appropriatenessand adequacy of goals and corrective actions for SSCs/functions classified as (aX1).Documents reviewed are listed in the Attachment.. Service air compressor failuresb. FindinqsIntroduction. A self-revealing finding was identified because of the PMOC did not drivesustainable improvements in the 00-K-107 service air compressor's reliability as requiredby PM program procedure WC-AA-111. Specifically, PSEG did not change the PMfrequency of the degraded compressor outlet check valve (H0KA-0KAV-004) norevaluate the use of materials less susceptible to corrosion after several recentperformances of the 18-month PM found excessive corrosion and rust on the valveinternals. Consequently, this check valve failed closed due to corrosion, tripped the aircompressor, and caused a service and instrument air headers pressure transientsfollowed by an automatic start of the EIAC.Description. Hope Creek has two 100 percent capacity service air compressors(00-K-107 and 10-K-107). The service air compressors are not safety-related, but areimportant to safety because they supply instrument air header pressure. A loss ofinstrument air at Hope Creek can cause an automatic scram by affecting control rodmovement and/or spurious feedwater and condensate system valve operation. Theservice air compressors are each operated 50 percent of the time and normally swappedevery 18 months to minimize cycling and to conduct PM.Enclosure

10On May 12,2011, PSEG conducted a planned swap from the 10-K-107 service aircompressor to the 00-K-107 service air compressor. During the swap, service andinstrument air header pressures dropped unexpectedly from approximately 100 psig to84 and 81 psig, respectively, and when the 10-K-107 service air compressor wasstopped the 00-K-107 service air compressor tripped on high discharge pressure.Lowering air pressure (<85 psig) at the emergency instrument air receiver resulted in theautomatic start of the emergency instrument air compressor (EIAC) and entry intoabnormal operating procedure HC.OP-AB.COMP-0001. The EIAC promptly restoredservice and instrument air header pressures to normal.PSEG determined that the cause of the instrument and air system transient was that theoutlet check valve (H0KA-0KAV-004) for the 00-K-107 service air compressor wascorroded shut. PSEG concluded that H0KA-0KAV-004 was corroded because it waslocated upstream of the system air dryers and the valve internals were carbon steel.PSEG noted in its cause evaluation that, due to the wetted environment it was exposedto, they had previously considered modifying H0KA-0KAV-004 by replacing the carbonsteel internals with stainless steel. However, to date, no engineering change requestwas submitted to initiate the modification process for this material change.Based on a review of the PM program, the inspectors determined that vendordocuments for the H0KA-0KAV-004 recommend at least an every two-year open andinspect PM, but after the valve was found corroded shut in May 2002, PSEG hadincreased the inspection frequency to every six months. In April 2004, PSEG changedthe PM frequency from every six months to every 18 months. The basis for the changewas that, after two years of inspections performed every six months, PSEG had neitheridentified significant corrosion buildup on the valve nor experienced a corrosion-relatedfailure of the valve. The inspectors identified that since PSEG extended the PM interval,each of the three performances (2006, 2008, and 2010) of the 18-month PM completedbefore the May 2011 valve failure found excessive rust and severe corrosion on theH0KA-0KAV-004 outlet check valve's disc and internals (Order 20470895). In addition,on May 23,2010, due to the excessive rust found during the April 2010 PM, technicianssubmitted a PM change request (PCR 80101517) that recommended moving the 18-month PM back to six months.Hope Creek procedure WC-AA-111, "Predefined Process for PM Change Requests,"states, in part, the "PMOC (Preventive Maintenance Oversight Committee) isresponsible for driving sustainable improvements in equipment reliability and plantperformance through improvements in the PM program." At the time of the May 2011H0KA-0KAV-004 failure to open, PCR 80101517 had not been reviewed by the PMOCand no action had been taken to address the identified design issues - inappropriatevalve internal materials given the wetted air to which the valve was exposed. Theinspectors noted that PSEG missed these three opportunities to shorten the PMperiodicity and prevent the H0KA-0KAV-004 check valve failure and subsequent00-K-107 service air compressor trip. The inspectors concluded that PSEG's lack ofaction relative to maintaining service air system component reliability through PMprogram improvements led to the May 2011 H0KA-0KAV-004 failure.After the May '12,2011, failure, PSEG refurbished H0KA-0KAV-004's internals with newcarbon steel components and plans to replace the 00-K-107 and 10-K-107 compressors'outlet check valves with stainless steel valves that are less susceptible to corrosion(Orders 60097323 and 60097371).Enclosure 11Analvsis. The PMOC's failure to drive sustainable improvements in the 00-K-107 aircompressor's reliability through improvements in the PM program as required by WC-AA-111 was a performance deficiency that was within PSEG's ability to foresee andcorrect. Specifically, after several recent performances of the 18-month PM foundexcessive corrosion and rust on the valve internals, PSEG did not either change the PMfrequency of the degraded compressor outlet check valve (H0KA-0KAV-004) or changethe material used in the valve's internals to one less susceptible to corrosion.Consequently, this check valve failed closed due to corrosion, tripped the aircompressor, and caused a service and instrument air headers pressure transientsfollowed by an automatic start of the EIAC.This finding is more than minor because it was associated with the equipmentperformance attribute of the Initiating Events cornerstone and affected the cornerstoneobjective of limiting the likelihood of events that upset plant stability and challenge criticalsafety functions at power. Specifically, the failure to adequately maintain thecompressor outlet check valve increased the likelihood of a plant trip. The inspectorsevaluated this finding using IMC 0609, Attachment 4, "Phase 1 - Initial Screening andCharacterization of Findings," Table 4a, and determined the finding to be of very lowsafety significance (Green) because the finding does not contribute to both the likelihoodof a reactor trip and the likelihood that mitigation equipment would not be available. Thefinding has a cross-cutting aspect in the area of human performance, work controlcomponent; because PSEG did not appropriately coordinate work activities byincorporating actions to ensure that maintenance scheduling is more preventive thanreactive. Specifically, PSEG did not shorten the PM interval or change the materialsused in the valve internals before the valve failed shut and required reactivemaintenance following a trip of the 00-K-107 air compressor. (H.3(b))Enforcement. The service air compressor is not a safety-related component and noviolation of regulatory requirements occurred. Because this finding does not involve aviolation and has very low safety significance, it is identified as a finding. (FlN05000354/2011004-0l, Inadequate Gorrective Actions Associated with a KnownDegraded Gondition of the 00-K-107 Service Air Compressor Outlet Check Valve(H0KA-oKAV-o04))1R13 Maintenance Risk Assessments and Emerqent Work Control (71111.13 - 4 samples)a. Insoection ScopeThe inspectors completed four maintenance risk assessment and emergent work controlinspection samples. The inspectors reviewed on-line risk management evaluationsthrough direct observation and document reviews for the following four plantconfigurations:. C EDG and Salem Unit 3 out-of-service during week of July 11o Emergent failure of C HPCI logic power and C EDG out-of-service on July 15. Emergent failure of A EDG and Salem Unit 3 out-of-service on August 1o Online risk was elevated from green to yellow on August 26, in response to a severeweather warning (Hurricane lrene) and PSEG reviewed scheduled work to confirmthat no work would be performed that woufd increase the risk of a LOOPEnclosure 12b.The inspectors reviewed the applicable risk evaluations, work schedules, and controlroom logs for these configurations to verify that concurrent planned and emergentmaintenance and test activities did not adversely affect the plant risk already incurredwith these configurations. PSEG's risk management actions were reviewed during shiftluryover meetings, control room tours, and plant walkdowns. The inspectors also usedPSEG's on-line risk monitor (Equipment Out of Service workstation) to gain insights intothe risk associated with these plant configurations. Finally, the inspectors reviewednotifications documenting problems associated with risk assessments and emergentwork evaluations. Documents reviewed are listed in the Attachment.FindinqsNo findings were identified.Operabilitv Evaluations (71111.15 - 3 samples)Inspection ScopeThe inspectors reviewed three issues to assess the technical adequacy of the operabilitydeterminatlons or operability screenings, the use and control of compensatorymeasures, and compliance with the licensing and design bases. As applicable,associated adverse condition monitoring plans, engineering technicalevaluations, andoperational and technical decision making documents were also reviewed. Theinspectors verified these processes were performed in accordance with the applicableadministrative procedures and were consistent with NRC guidance. Specifically, theinspectors referenced procedure OP-AA-108-115, "Operability Determinations,'; andNRC IMC Part 9900, "Operability Determinations & Functionality Assessments forResolutions of Degraded or Nonconforming Conditions Adverse to Quality or Safety."The inspectors also used the TS, the technical requirements manual, and the UFSAR asreferences during these reviews. Additionally, the inspectors reviewed other PSEGidentified safety-related equipment deficiencies during this report period and assessedthe adequacy of their operability screenings. Documents reviewed are listed in theAttachment. The following degraded equipment issues were reviewed:. HPCI non-conforming due to increase in room temperatureo A Chilled Water Pump degraded due to low flow trip. HPCI degraded due to F028 & F029 valve steam leaksFindinqslntroduction. The inspectors identified a finding of very low safety significance (Green)involving a NCV of 10 CFR 50, Appendix B, Criterion lll, "Design Control," in that, PSEGdid not ensure the adequacy of HPCI design under post-accident conditions,Specifically, PSEG did not evaluate the impact of elevated temperature in the HPCIroom on the operability of the HPCI system during a postulated design basis SBLOCAcoincident with a LOOP and a single failure of the A emergency diesel generator (EDG).

1R15 a.b.Enclosure

13Descriotion. The design function of the HPCI system is to maintain reactor vesselinventory following the postulated SBLOCA. As stated in Hope Creek UFSAR section6.3, HPCIwas designed to remain operable during its most limiting accident, a SBLOCAand LOOP with the single failure of an EDG. Because both HPCI room coolers arepowered by the A EDG, when the A EDG is assumed as the single failure, the systemdesign requires HPCI to be operable without either room cooler.During plant walkdowns between May 15, 2011, and July 26, 2Q11, the inspectorsobserved the HPCI room temperature was between 114'F and 116'F degrees as read atthe HPCI isolation system instrument panel. During a HPCI steam line break, HPClwillisolate if instruments sense high room temperature (>160'F) or high differentialtemperature in the room ventilation (>70'F between HPCI room ventilation supply(reactor building air temperature) and exhaust temperatures (HPCI room temperature)).HPCI design document PN0-E41-4010-0072, "High Pressure Coolant Injection," statesthat HPCI room temperature during normal plant operations should be between 60'F to100'F. Considering that HPCI room temperature was between 114"F and 116oF, theinspectors determined that PSEG did not have a design calculation that demonstratedthat HPCI would not isolate due to either high room temperature or high room ventilationdifferential temperature during the most limiting accident.PSEG initiated notifications 20518124 and 20520106 and performed an operabilityevaluation to verify HPCI operability during the most limiting accident. This evaluationconcluded that HPCI operability could be challenged during extreme winter lowtemperatures because the very low HPCI room ventilation supply temperatures and postaccident room heat up combined with the higher initial room temperature could causethe system to isolate on high differential temperature. To address this condition, PSEGplans to implement a design change to reduce the setpoints for the HPCI room coolersto lower the normal ambient HPCI room temperature. This will reduce the differentialtemperature between the ventilation supply and the room temperature and is expectedto prevent HPCI from isolating during extreme winter low temperatures when HPCI roomventilation supply temperature is very low. The modification is currently scheduled to beimplemented prior to the onset of winter weather conditions.The inspectors identified prior opportunities for PSEG to identify this non-conformingcondition. In August 2008, the inspectors questioned HPCI operability during SBOconditions (LOOP and loss of all EDGs) as documented in notification 20381041.Specifically, a HPCI room heat up calculation, GR-0022, Revision 3, Loss of Ventilationduring SBO, assumed a maximum initial ambient HPCI room temperature of 104"F. In2008, the inspectors observed actual room conditions greater than 104"F (notification20381041). As corrective actions for this issue, PSEG conducted troubleshooting toidentify the cause of the elevated temperature, but were unsuccessful. At that point,PSEG initiated action to revise GR-0022 and performed an operability evaluation thatdetermined the acceptable starting HPCI room temperature during SBO conditions couldbe as high as 1 13"F. No additional action or evaluations were performed. AlthoughPSEG appropriately evaluated the impact of the elevated normal operating HPCI roomtemperature on the SBO HPCI room heat up calculation, PSEG did not evaluate theimpact of the elevated temperature on the HPCI systems response during other designbasis accidents. The site's operability evaluation procedure required an extent ofcondition review be performed for conditions evaluated through that process.Enclosure 14The inspectors reviewed PSEG procedure, LS-AA-125, "Corrective Action Program,"which defines extent of condition as the extent to which the identified condition has thepotential to impact other plant processes, equipment, or human performance in thesame manner as identified in the condition report. The inspectors found that in 2008, inresponse to the identified higher than normal HPCI room temperature, PSEG's extent ofcondition review determined that no other safety systems were constrained by initialroom temperature heat up concerns. However, this extent of condition review narrowlyfocused on SBO conditions and, therefore, did not identify the impact of the initialambient HPCI room temperature on other accident conditions, such as a SBLOCA andLOOP with the single failure of an EDG. Also, the inspectors noted that PSEG did notconduct a casual evaluation for notification 20381041 to determine why the actual HPCIroom temperatures were above the initial HPCI room temperature assumed in the HPCIroom design basis heat up calculation. The inspectors concluded that a casualevaluation could have identified that the room was not within the HPCI design document,PN0-E41-4010-0072, assumed normal room temperature of 60'F to 100"F.Analvsis. The inspectors concluded that the failure to adequately verify or check thedesign of the HPCI system under the most limiting accident conditions described inHope Creek UFSAR section 6.3 after concerns regarding HPCI room temperature wereidentified by inspectors in 2008 was a performance deficiency. The performancedeficiency was more than minor because it was associated with the design controlattribute of the Mitigating Systems Cornerstone and affected the cornerstone objective ofensuring the reliability of systems that respond to initiating events to prevent undesirableconsequences. Specifically, PSEG had not evaluated HPCI operability using actualHPCI room temperatures during normal operating conditions, and as a result, HPCI'sreliability during the most limiting accident conditions was not assured during extremewinter low temperatures. Also, this issue was similar to Example 3j of IMC 0612,Appendix E, "Examples of Minor lssues," because the condition resulted in reasonabledoubt of the operability of the component, and additional analysis and compensatoryactions were necessary to ensure HPCI operability during all environmental conditions.The inspectors reviewed this condition using IMC 0609, Attachment 4, and inconsultation with a Region I SRA, concluded that although this event constituted adeterministic safety functional failure, the HPCI system was likely capable of performingits significance determination process safety function, given the numerous postulatedequipment failures and specific system configurations that would have to occur to causethe deterministic system failure. Therefore, each of the relevant questions in theAttachment 4 table would be answered no and this issue screened to very low safetysignificance (Green).The finding had a cross-cutting aspect in the area of problem identification andresolution, corrective action component, because PSEG did not thoroughly evaluate aprior problem such that the problem resolution addressed the extent of condition.Specifically, PSEG's evaluation for notification 20381041 , "HPCI Operability during SBOConditions," did not identify the impact of actual HPCI room temperature during normaloperating conditions on other accident conditions, such as a SBLOCA and LOOP withthe single failure of an EDG. Therefore, PSEG did not identify that the HPCI roomtemperature was beyond the HPCI design document assumption of 60'F to 100"F.(P.1(c))Enclosure 15Enforcement. 10 CFR 50, Appendix B, Criterion lll, "Design Control," requires, in part,that measures be provided for verifying or checking the adequacy of design, such as bythe performance of design reviews, by the use of alternate or simplified calculationalmethods, or by the performance of a suitable testing program. Contrary to the above,between August 20, 2Q08, and August 2, 2011 , PSEG did not verify or check theadequacy of the HPCI system design under the most limiting accident conditionsdescribed in Hope Creek UFSAR section 6.3, by the use of alternate or simplifiedcalculational methods, or by the performance of a suitable testing program. Specifically,PSEG did not perform adequate design reviews or testing to verify that the HPCI systemwould remain operable during a SBLOCA and LOOP with a single failure of an EDGafter inspectors identified that the actual HPCI room normal operating conditiontemperature was greater than 104"F. PSEG determined through subsequent evaluationthat HPCI was operable but non-conforming because there was a potentialfor HPCIsystem to isolate unnecessarily on high differential temperature during the extremewinter low temperatures. This issue was entered into CAP as notifications 2Q518124and 20520106, and PSEG plans to implement a design change to reduce the setpointsof the HPCI room coolers so that the initial HPCI room temperature is maintained at alower temperature before extreme winter conditions. Because this violation was of verylow safety significance (Green) and has been entered into the CAP this violation is beingtreated as an NCV, consistentwith Section2.3.2.a of the NRC Enforcement Policy.(NCV 05000354/2011-004-02, HPCI Operability during SBLOCA/LOOP with the AEDG Failure)1R18 Plant Modifications (71111.18 - 1 sample)a. Inspection ScopeThe inspectors completed a review of one temporary modification package for the D CWpump hydraulic control unit plug due to a large hydraulic fluid leak on the pumpdischarge pressure indicator (TCCP 4HT-11-016). The inspectors verified that thedesign bases, licensing bases, and performance capability of the CW pump were notdegraded by this temporary modification. The inspectors also verified the postmodification testing was adequate to ensure the SSCs would function properly. The10 CFR 50.59 evaluation associated with this temporary modification was also reviewed.Documents reviewed are listed in the Attachment.b. FindinosNo findings were identified.

1R19 Post-Maintenance Testinq (71111.19 - 7 samples)a. Inspection ScopeThe inspectors completed seven post-maintenance testing inspection samples. Theinspectors reviewed the post-maintenance tests for the maintenance items listed belowto verify that procedures and test activities ensured system operability and functionalcapability following completion of maintenance. The inspectors reviewed applicable testprocedures to verify that they tested all safety functions potentially affected by theassociated maintenance activities. The inspectors verified that for each potentiallyaffected safety function the acceptance criteria stated in the procedure was consistentEnclosure

16with the UFSAR and other design documentation. The inspectors witnessed completionof the testing or reviewed the completed test results to confirm acceptance criteria weremet and verified satisfactory restoration of all safety functions affected by themaintenance activities. Documents reviewed are listed in the Attachment.o A control area chilled water pump logic module replacement after pump trip on July 5o C EDG rectifier replacement on July 14. C channel of HPCI isolation logic replacement after power failure on July 15. D RHR minimum flow check valve replacement on July 27r A EDG intercooler pump replacement on August 3o A fuel pool cooling pump corrective maintenance on August 7. B EDG lube oil keep-warm pump replacement on September 13b. FindinqsNo findings were identified.

1R22 Surveillance Testins (71111.22 - 3 Routine samples, 1 IST sample)a. Inspection ScopeThe inspectors completed four surveillance testing (ST) inspection samples. Theinspectors witnessed performance of and/or reviewed test data for the risk-significantSTs listed below to verify that the SSCs tested satisfied TSs, UFSAR, and procedurerequirements. The inspectors verified that test acceptance criteria were clear,demonstrated operational readiness, and were consistent with design documentation;that test instrumentation had current calibrations and the correct range and accuracy forthe application; and that tests were performed as written with applicable prerequisitessatisfied. Upon ST completion, the inspectors confirmed that equipment was returned tothe status specified to perform its safety function. Documents reviewed are listed in theAttachment.r HPCI inservice test on July 7o D EDG monthly surveillance test on July 25r A standby liquid pump surveillance test on September 1o B RHR pump inservice test run on September 13b. FindinosNo findings were identified.lEPO Drill Evaluation (71114.00 - 1 drill/ev sample)a. Inspection ScopeThe inspectors observed the classification and notification aspects of a licensed operatorrequalification training examination scenario in the Hope Creek simulator on August 15,2011. The scenario was conducted, in part, to provide drill and exercise performance(DEP) opportunities for the DEP performance indicator (Pl). The inspectors reviewedthe conduct of the simulator exercise to identify any weaknesses and deficiencies inEnclosure

17classification and notification activities. The inspectors observed the evaluation,classification, and notification of the simulated events to ensure they were accurate,timely, and were done in accordance with Hope Creek Emergency Classification Guide.The inspectors verified that the drill evaluators correctly counted the drill's contribution inthe calculation of the DEP Pl. The inspectors verified that training evaluators capturedthe results for the DEP Pl. The inspectors also verified that any weaknesses ordeficiencies were captured and discussed during the critique of the training exercise, inorder to properly identify and correct any weaknesses. Documents reviewed are listedin the Attachment. Emergency action level (EAL) # 8.2.2.a -Unplanned Loss of Most orAll Control Room Annunciators and Significant Transient is in Progress or CompensatoryIndicators are Unavailable - was classified during this training exercise:b. FindinqsNo findings were identified.2. RADIATION SAFEWCornerstone: Radiation Safety - Public and Occupational2RS1 Radioloqical Hazard Assessment and Exposure Controls (71124.01)a. Inspection ScopeThe inspectors reviewed PSEG performance indicators (Pl) for the OccupationalExposure Cornerstone for follow-up. The inspectors reviewed the results of radiationprotection program audits. The inspectors reviewed reports of operational occurrencesrelated to occupational radiation safety since the last inspection.The inspectors verified that any transactions involving nationally tracked sources werereported in accordance with 10 CFR 20.2207 .During tours of the facility and review of ongoing work, the inspectors evaluated ambientradiological conditions. The inspectors verified that existing conditions were consistentwith posted surveys, radiation work permits (RWPs), and worker briefings, as applicable.During job performance observations, the inspectors verified the adequacy ofradiological controls, such as required surveys, radiation protection job coverage, andcontamination controls. The inspectors evaluated PSEG's means of using electronicpersonnel dosimeters in high noise areas as high radiation area (HRA) monitoringdevices. The inspectors verified that radiation monitoring devices were placed on theindividual's body consistent with the method that PSEG was employing to monitor dosefrom external radiation sources. The inspectors verified that the dosimeter was placed inthe location of highest expected dose or that PSEG was properly employing an NRC-approved method of determining effective dose equivalent.For high-radiation work areas with significant dose rate gradients, the inspectorsreviewed the application of dosimetry to effectively monitor exposure to personnel. Theinspectors verified that PSEG controls were adequate.Enclosure 18The inspectors reviewed RWPs for work within airborne radioactivity areas with thepotential for individual worker internal exposures. The inspector evaluated airborneradioactive controls and monitoring, including potentials for significant airbornecontamination. For these selected airborne radioactive material areas, the inspectorsverified barrier integrity and temporary high-efficiency particulate air ventilation systemoperation.The inspectors conducted selective inspections of posting and physical controls forHRAs and very HRAs, to the extent necessary, to verify conformance with theOccupational Pl.The inspectors observed radiation worker performance with respect to stated radiationprotection work requirements. The inspectors determined that workers were aware ofthe significant radiological conditions in their workplace and the RWP controls/limits andthat their performance reflected the level of radiological hazards present.The inspectors reviewed radiological problem reports since the last inspection that foundthe cause of the event to be human performance errors. The inspectors determined thatthere was no observable pattern traceable to a similar cause. The inspectorsdetermined that this perspective matched the corrective action approach taken by PSEGto resolve the reported problems. The inspectors discussed with the radiation protectionmanager any problems with the corrective actions planned or taken.b. FindinqsNo findings were identified.2RS2 Occupational As Low as Reasonablv Achievable (ALARA) Plannino & Controls(71124.02)a. Inspection ScopeThe inspectors verified that PSEG's planning identified appropriate dose mitigationfeatures, commensurate with the risk of the work activity, alternate mitigation features,and defined reasonable dose goals. The inspectors verified that PSEG's ALARAassessment had taken into account decreased worker efficiency from use of respiratoryprotective devices andlor heat stress mitigation equipment. The inspectors determinedthat PSEG's work planning considered the use of remote technologies as a means toreduce dose and the use of dose reduction insights from industry operating experienceand plant-specific lessons learned. The inspectors verified the integration of ALARArequirements into work procedures and RWP documents.The inspectors compared the results achieved with the intended dose established inPSEG's ALARA planning for these work activities. The inspectors compared the person-hour estimates provided by maintenance planning and other groups to the radiationprotection group with the actual work activity time requirements and evaluated theaccuracy of these time estimates. The inspectors determined the reasons for anyinconsistencies between intended and actual work activity doses. The inspectorsfocused on those work activities with planned or accrued exposure greater than fiveperson-rem.Enclosure b.19The inspectors determined that post-job reviews were conducted and that identifiedproblems were entered into PSEG's CAP.The inspectors verified that problems associated with ALARA planning and controlswere being identified by PSEG at an appropriate threshold and were properly addressedfor resolution in their CAP.FindinqsNo findings were identified.ln-Pfant Airborne Radioactivitv Control and Mitiqation (71124.03)Insoection ScopeThe inspectors verified that PSEG provided respiratory protective devices such thatoccupational doses are ALARA. As available, the inspectors selected work activitieswhere respiratory protection devices were used to limit the intake of radioactivematerials, and verified that PSEG performed an evaluation concluding that furtherengineering controls were not practical and that the use of respirators was ALARA. Theinspectors verified that PSEG had established means to verify that the level of protectionprovided by the respiratory protection devices during use was at least as good as thatassumed in PSEG's work controls and dose assessment.The inspectors verified that respiratory protection devices used to limit the intake ofradioactive materials are certified by the National Institute for Occupational Safety andHealth/Mine Safety and Health Administration (NIOSH/MSHA) or had been approved bythe NRC. The inspectors selected work activities where respiratory protection deviceswere used and verified that the devices were used consistent with their NIOSH/MSHAcertification.The inspectors reviewed records of air testing for supplied-air devices and self-containedbreathing apparatus (SCBA) bottles. The inspectors verified that air used in thesedevices meet or exceeded Grade D quality. The inspectors verified that plant breathingair supply systems met the minimum pressure and airflow requirements for the devicesin use.The inspectors selected individuals qualified/assigned to use respiratory protectiondevices and verified that they had been deemed fit to use the device(s) by a physician.The inspectors observed them donning, removing, and functionally checking the deviceas appropriate. The inspectors verified that these individuals knew how to safely use thedevice and how to properly respond to any device malfunction or unusual occurrence.The inspectors also reviewed training curricula for users of the devices.The inspectors chose respiratory protection devices staged and ready for use in theplant or stocked for issuance for use and observed the physical condition of the devicecomponents and reviewed records of routine inspection for each. The inspectorsselected a sampling of the devices and reviewed records of maintenance on the vitalcomponents. The inspectors verified that onsite personnel assigned to repair vitalcomponents had received vendor-provided training.2RS3a.Enclosure 20Based on the Final Safety Assessment Report, TSs, and emergency operatingprocedure requirements, the inspectors reviewed the status and surveillance records ofthe SCBA staged in-plant for used during emergencies. The inspectors observedPSEG's capability for refilling and transporting SCBA air bottles to and from the controlroom and operations support center during emergency conditions.The inspectors selected individuals on control room shift crews and individuals fromdesignated departments currently assigned emergency duties and determined thatcontrol room operators and other emergency response and radiation protectionpersonnel were trained and qualified in the use of SCBAs. The inspectors determinedthat personnel assigned to refill bottles were trained and qualified for that task.The inspectors verified that appropriate mask sizes and types were available for use.The inspectors selected on-shift operators and verified that they had no facial hair thatwould interfere with the sealing of the mask to the face. The inspectors also verified thatvision correction did not penetrate the face seal.The inspectors reviewed the past two years of maintenance records for SCBA units usedto support operator activities during accident conditions and designated as "ready forservice." The inspectors verified that any maintenance or repairs on an SCBA unit's vitalcomponents were performed by an individual, or individuals, certified by themanufacturer of the device to perform the work. The inspectors reviewed the onsitemaintenance procedures governing vital component work, and identified anyinconsistencies with the SCBA manufacturer's recommended practices. For thoseSCBAs designated as "ready for service," the inspectors ensured that the required,periodic air cylinder hydrostatic testing was documented and up to date, and the retestair cylinder markings required by the U.S. Department of Transportation were in place.b. FindinqsNo findings were identified.4.

4OA1 Performance Indicator (Pl) Verification (71151- 1 sample)Cornerstone: Mitiqatinq Svstems

.1 Review of Safetv Svstem Functional Failures (SSFFS) Pla. Inspection ScopeThe inspectors reviewed PSEG's submittals for the SSFF Pl for Hope Creek (MS05).For the functional failures, the inspectors looked at the period from the July 1 ,2010through June 30, 2011. The Pl definitions and the guidance contained in NuclearEnergy Institute 99-02, "Regulatory Assessment Indicator Guideline," Revision 6, andprocedure LS-AA-2080, "Monthly Data Elements for NRC SSFFs," Revision 5, wereused to verify that procedure and reporting requirements were met.The inspectors reviewed licensee event reports (LERs) issued during the referencedtimeframe for SSFFs. Documents reviewed are listed in the Attachment. The inspectorsEnclosure b.21also compared graphical representations from the most recent Pl report to the raw datato verify that the data was correctly reflected in the report.FindinqsNo findings were identified.Problem ldentification and Resolution (71152 - 2 Reviews samples)Routine Review of ltems Entered into the CAPInspection ScopeAs required by lP 71 152, "ldentification and Resolution of Problems," and in order tohelp identify repetitive equipment failures or specific human performance issues forfollow-up, the inspectors performed a daily screening of all items entered into PSEG'sCAP. This was accomplished by reviewing the description of each new notification andattending management review committee meetings.FindinqsNo findings were identified.Annual Sample: Corrective Actions for EDG Room Cooler Recirculation Fan TripsInspection ScopeEach of the four EDG rooms is provided with two safety-related room cooler recirculationfans and two cooling coil assemblies. Under normal operating conditions, theserecirculation fans and cooling coil assemblies are fully redundant, each capable ofproviding 100 percent of the cooling requirement for its respective EDG room. Duringperiods of operation when the ultimate heat sink (UHS) temperature is above 80"F, andbased on the SACS alignment, both recirculation fans are required or procedurally-driven SACS valve realignments are needed to allow single fan operation. The auto-lead fan is designed to start on elevated room temperature or an EDG start. Whenpositioned to "auto," the backup fan is designed to start on elevated room temperatureconcurrent with an EDG start or a low flow condition on the auto-lead fan (given a startdemand). Since January 2010, PSEG identified 12 unexpected recirculation fan trips (2on A V412fan,8 on B Y412fan, and 2 on CY412 fan), with recent trips occurring onJuly 28, 201 1 (notification 20519905 on A) and August 1, 2011 (notification 2Q520452 onB). This inspection focused on PSEG's problem identification, evaluation, and resolutionassociated with the EDG recirculation fan trips and potential reliability challenges.The inspectors reviewed PSEG's associated apparent cause evaluation (ACEs),troubleshooting plans, extent-of-condition reviews, and short and long term correctiveactions. The inspectors observed several of the EDG recirculation fans while in service,after they had started on elevated room temperature or following an EDG start (i.e., theplanned D EDG start on August 22), to assess their operating performance with respectto design basis requirements and system specifications. The inspectors performedwalkdowns of the EDG rooms, accessible portions of the EDG recirculation fan trains,recirculation fan 480V motor control center breakers, and the recirculation fan alarm and4c.42.1a.b..2a.Enclosure 22control panels (including an internal visual inspection of the four recirculation fan relaycabinets). The inspectors performed these walkdowns to independently assess thematerial condition, operating environment, potential operator challenges, maintenancepractices, and configuration control. The inspectors also reviewed temperature switchand flow control switch calibration results, fan train corrective and preventivemaintenance records, operating logs, fan control logic diagrams, engineeringevaluations, laboratory analysis reports, related industry operating experience (OE), andEDG room temperature trend data to assess the adequacy of PSEG's corrective actionsand to ensure TS compliance. The inspectors also discussed recirculation fanperformance and operational alignments with the system engineer, senior reactoroperators, and equipment operators to review the design and system functionalrequirements, as well as obtain historical performance and trend data.The inspectors reviewed a sample of EDG recirculation fan problems that PSEGidentified and entered into the CAP since October 2007. The inspectors reviewed theseissues to verify an appropriate threshold for identifying issues and to evaluate theeffectiveness of corrective actions. In addition, the inspectors reviewed corrective actionnotifications written on issues identified during the inspection to verify adequate problemidentification and incorporation of the problem into the CAP. Documents reviewed arelisted in the Attachment.b. Findinqs and ObservationsNo findings were identified. The inspectors concluded that, in general, PSEG had takentimely and appropriate action in accordance with the Hope Creek TSs, operating andalarm response procedures, and PSEG's CAP. The inspectors determined that PSEG'sassociated ACEs were sufficiently thorough and based on the best available information,controlled troubleshooting, testing (including independent laboratory analysis), soundengineering judgment, and relevant industry OE. PSEG's assigned corrective actionswere aligned with the identified casual factors, adequately tracked, appropriatelydocumented, and completed as scheduled.However, during an internal visual inspection of the associated safety-related EDGrecirculation fan alarm and relay cabinets (A-E C483), the inspectors noted severalminor configuration control and housekeeping issues. Specifically, the inspectors notedno functional lighting in any of the cabinets, an old deficiency tag (dated 9/3/1995)hanging in one cabinet stating that bulbs were replaced and lights still do not work, somedebris, and missing and/or displaced air filter/debris screens in two cabinets. PSEGpromptly initiated corrective action notifications (205230 1 2, 20523532, 20523533,20523534, and 20523535) for these issues. ln accordance with the guidance inInspection Manual Chapter (lMC) 0612, Appendix B "lssue Screening" and Appendix E,"Examples of Minor lssues." the inspectors determined none of the performancedeficiencies identified during the cabinet inspections were more than minor because,based upon the material conditions observed by the inspectors, the operability of theassociated equipment was not affected by the minor configuration control andhousekeeping issues.Enclosure

.323 Annual Sample: Technical Riqor of Vendor Enoineerinq EvaluationsInspection ScopeThis inspection focused on PSEGs'problem identification, evaluation, and resolutionassociated with technical rigor of vendor produced engineering evaluations. Theinspectors reviewed a PSEG Nuclear Oversight (NOS) performance review fromOctober 2010 to January 2011 that identified a declining trend in engineering technicalrigor and notification 20494454, NOS Evaluation Hope Creek Engineering TechnicalRigor, documented this deficiency. The inspectors reviewed NOS Elevation NoticeNOHl 1-002, dated January 26, 2011, that specifically addressed this issue as acondition adverse to quality. The inspectors reviewed the ACE and a sample ofcorrective actions to evaluate the effectiveness of corrective actions and to ensure thatthey addressed the cause of this declining trend in vendor produced engineeringevaluations. The following corrective actions were reviewed: conduct a needs analysisfor knowledge gaps in the implementation of error prevention tools with regard toengineering technical products, improve Fundamentals Management System (FMS)tasks list to include other engineering products associated with technical rigor, establishan engineering technical rigor prevention of events triangle and establish the thresholdsand criteria, and implement the owner's acceptance review of external technical productreview checklist.The inspectors reviewed several Design Change Packages (DCPs) to assessengineering rigor. Specifically, the inspectors reviewed DCP 80103378, lnstall 1EService Water Cable Vault Dewatering System for Manholes 102, 103, and 105, andDCP 80102874, Hope Creek Reactor Feed Pump Turbine Lube Oil Single PointVulnerability Mitigation. The inspectors reviewed a sample of corrective actionnotifications written on engineering rigor type deficiencies from January 2411 bSeptember 2011. The inspectors performed a review of PSEG's FMS tool that providesfeedback to PSEG engineering personnel and vendors concerning reviews ofengineering documents, including engineering evaluations. The inspectors reviewedPSEG engineering internal departmental report for 2no cycle of 2011. Documentsreviewed are listed in the Attachment.Findinqs and ObservationsNo findings were identified. Specific examples lacking technical rigor identified by NRCinspectors were: RHR leaking heat exchanger (HX) evaluation; safety system gasaccumulation evaluation; and primary containment isolation valve evaluation. All ofthese issues resulted in NRC identified findings.The PSEG cause and effect analysis identified the following casual factors (CFs) for thisproblem: CF #1, ineffective use of error mitigation tools and techniques, and CF #2,improper technical process usage. The apparent causes were insufficient oversight andaccountability and less than adequate understanding of the criteria used to determinethe correct technical process. PSEG implemented 18 corrective actions to address thisissue, some of which included training on an industry guidance document titled"Principles for Maintaining an Effective Technical Conscience and Focus FMSObservations on Technical Rigor." The inspectors noted that the ACE was sufficientlythorough and the corrective actions were aligned with the CFs, appropriatelydocumented, adequately tracked, and being completed as scheduled.a.b.Enclosure

24The inspectors found that approximately 304 documented FMS observations ofengineering technical rigor were performed by PSEG engineering supervisors betweenJanuary 26,2011, and September 27,2Q11, compared to only 12 FMS observationsof engineering technical rigor between September 1, 2010, and January 26,2011. Theinspectors concluded that constructive comments provided appropriate feedback to theengineer that produced the engineering document. No deficiencies were identified inthe DCPs reviewed and the inspectors noted that in PSEG engineering internaldepartmental report fot 2"o cycle of 2011, technical rigor in engineering showed animproving trend.The inspectors concluded, therefore, that, in general, PSEG had taken timely andappropriate action in accordance with their CAP to address engineering technical rigorfor vendor produced evaluations. The inspectors acknowledged that significant stepswere taken by PSEG to address the issue. However, the NRC inspectors also identifiedtwo examples of inadequate engineering technical rigor related to NRC submittals.r Incorrect information appears to have been submitted to the NRC in the licenseamendment for the EDG allowed outage time extension. Specifically, the submittalreferenced and specified High Pressure Coolant Injection/Reactor Core lsolationCooling final Station Blackout Operating temperatures in a non-active calculation.The active calculation would result in increased temperatures. Notification 20518067was written to document this deficiency.o Discrepancies were found in the Final Feedwater Temperature Reduction safetyanalysis report vs. PSEG amendment request. Notification 20523860 was written toaddress this deficiency.Based on these two examples, the inspectors concluded that the scope of the reviewsPSEG conducted in response to notification20494454, did not encompass NRC-relateddocuments like TS amendments or requests for additional information. However, for thetwo examples discussed above, the inspectors did not identify findings because, in eachcase, the associated licensing activity had not become a part of the current licensing anddesign basis and, as stated above, PSEG had entered the issues into the correctiveaction program for evaluation and correction. In addition, as of the date of this report,both issues were resolved.4OA3 Event Follow-up (71153 - 5 samples).1 (Closed) LER 05000354/2010-001-01. Technical Specification Surveillance RequirementNot MetIn LER 05000354/2010-001-00, PSEG reported that two SACS HX bypass valves (EG-HV-2457NB) were not adequately tested in accordance with the requirements of TSsurveillance requirem ent 4.7

.1.1. b. The inspectors' review of this LER was documentedin NRC Inspection Report (lR) 0500035412010004. In Supplement 01 of this LER(0500035412010-001-01), PSEG identified that extent of condition reviews identified anadditional pair of SACS HX bypass valves (EG-HV-2S17N8) had also not beenadequately tested in accordance with TS surveillance requirement 4.7 .1.1.b. Theseissues were entered into the CAP under notification 20470714. Corrective actionscompleted under Order 70111202 included testing the valves under TS surveillancerequirement 4.7.1.1.b before returning them to operation and reviewing other automaticSACS and station SW valves for extent of condition. No other missed surveillanceswere identified. The enforcement aspects associated with the closure of this LER andEnclosure

===.225 Supplement 01 were discussed and documented in Section

4OA7 oflR 0500035412010004. No new issues of concern were identified by the NRCduring its review of the new information provided by PSEG in this supplement. ThisLER is closed.(Closed) LER 05000354/2010-002-00 and LER 05000354/2010-002-01 , As-FoundValues for Safety Relief Valve Lift Setpoints Exceed Technical Specification AllowableBetween November 2 and November 29,2010, PSEG received test results indicatingthat the as-found lift setpoints for 6 of 14 main steam SRVs failed to open within therequired TS actuation pressure setpoint tolerance. TS 3.4.2

.1 provides an allowablepressure band of +/-3 percent for each SRV. All six of the SRVs opened above therequired pressure band. PSEG determined that the apparent cause for the A, C, K, L,and P SRV setpoint failures was corrosion bonding/sticking of the pilot disc. Theapparent cause for the G SRV setpoint failure was related to misaligned internal partscaused by uneven loading in the pilot spring. These issues were placed into the CAPunder notifications 20483383 and 2Q525076. The pilot assembly for each of the 14SRVs was replaced with a fully tested spare assembly. Additionally, this LER stated aPSEG proposal to replace the SRVs is being considered through the plant modificationprocess. Although this LER reports the inoperability of six SRVs, this event did notresult in a loss of system safety function based on engineering analyses. Theseanalyses showed that the SRVs would have functioned to prevent a reactor vessel over-pressurization and that postulated piping stresses would not exceed allowable limits.The enforcement aspects of this finding are discussed in Section 4OA7. These LERsare closed.(Closed) LER 05000354/2011-001-00, HPCI Operation Credit in UFSAR Scenario notSupported by Existing DocumentationHope Creek Engineering identified a condition when the HPCI system would potentiallynot fulfill its safety function. The HPCI room ventilation differential temperature tripsetpoint of 70'F, which is intended to isolate HPCI in the event of a steam leak, has thepotential to isolate HPCI prematurely during extreme winter temperatures. Thispremature system isolation could impact the ability of HPCI to fulfill its design functionduring one of the accident scenarios listed in UFSAR Table 6.3-6, specifically theassumed single failures listed is the loss of an EDG coincident with a LOCA and aLOOP.A PSEG engineering assessment determined that HPCI was not challenged bymaximum room differential temperatures during warm ambient operating temperatures.However, the ability of HPCI to perform its design function during assumed single failureof an EDG coincident with a LOCA and a LOOP during extreme winter temperatures(i.e., which would result in the maximum room inlet to outlet differential temperature)wasnot fully evaluated. As a result of a July 28,2011 assessment, PSEG entered this issueinto the GAP (notifications 20518124 and 20520106). The inspectors concluded that thisevent was classified as a safety system functional failure. The inspectors' review of thisLER and the related enforcement action is documented in section 1 R15.Event Notice #47192: Notification of an Unusual Event Due to Seismic EventInspection Scope.3.4Enclosure===

b..5a.26On August 23,2011, PSEG personnel informed the resident inspectors located inthe main control room that an event notification report was planned to meet therequirements of 10 CFR 50.72(a)(1)(i), "Emergency Declared." Specifically, at 1400hours, Hope Creek and Salem generation stations declared a common site UnusualEvent in accordance with EAL 9.5.1.a due to an earthquake felt by onsite personnelwithin the protected area. Hope Creek continued operating at full RTP. All emergencycooling systems were available and in standby alignment. PSEG conducted multiplewalkdowns of safety-related areas with no significant anomalies noted. At 1930 hours0.0223 days <br />0.536 hours <br />0.00319 weeks <br />7.34365e-4 months <br />,Hope Creek and Salem terminated their Notification of Unusual Event.The inspectors responded to the seismic disturbance felt onsite on August 23,2011.The inspectors observed control room operators response to alarms received as a resultof the event and use of the applicable abnormal operating procedures. The inspectorsperformed independent walkdowns of control room instrument panels and risk significantSSCs for indications of adverse impact or off-normal conditions. The areas walkeddown included the EDGs, fuel storage tanks and transfer pumps, switchgear rooms,safety-related ventilation fans, SW pumps, intake structure, seismic monitoring panel,reactor building (including 132'blowout panel), emergency core cooling systems,hydraulic control units, standby liquid control, and safety auxiliary cooling pumps andHXs. Documents reviewed are listed in the Attachment.FindinqsNo findings were identified.Hurricane lrene: Preparations and ResponseInspection ScopeFrom August 23 to August 27,2011, the inspectors reviewed PSEG's activities toprepare for the potential arrival of Hurricane lrene. PSEG personnel implemented theactions specified by procedure OP-AA-108-1 1 1-1001 , "Severe Weather and NaturalDisaster Guidelines." The inspectors observed activities that included: securing orremoving outside equipment to preclude windborne missiles; closure of watertight doors;just-in-time training for plant shutdown and start-up; sandbagging of selected non-safetyrelated access points; and increased staffing of emergency response organizationpersonnel with preparations for sequestering.On August 27,2011, inspectors responded to the Hope Creek site due to the expectedarrival of Hurricane lrene within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The inspectors noted that PSEG hadstaffed but not activated the Operations Support Center (OSC). PSEG considered theenforcement discretion guidance in NRC Enforcement Guidance Memorandum (EGM)09-008, "EGM - Dispositioning Violations of NRC Requirements for Work Hour ControlsBefore and lmmediately After a Hurricane Emergency Declaration," dated September24,2009, and sequestered essential site personnel. The inspectors monitored plantactivities in the main control room and the OSC and monitored selected plantparameters, including: actual and projected onsite weather conditions; offsite powerstatus; key safety equipment status; intake conditions; plant equipment issues; securityposture and equipment issues; and emergency planning considerations. Documentsreviewed are listed in the Attachment.Enclosure 27b. FindinssNo findings were identified.4OA5 Other ActivitiesOperation of an Independent Spent Fuel Storaqe Installation (lSFSl) at Operatinq Plants(60855.1)The inspectors verified by direct observation and independent evaluation that PSEG hadperformed loading activities at the ISFSI in a safe manner and in compliance withapplicable procedures. The inspectors toured the ISFSI and reviewed radiologicalsurveys performed during the past 12 months.4OAO Meetinqs, includinq ExitOn October 13,2Q11, the inspectors presented inspection results to Mr. J. Perry, StationVice President, and other members of his staff. The inspectors asked PSEG whetherany materials examined during the inspection were proprietary. No proprietaryinformation was identified.4C.A7 Licensee-ldentified ViolationsThe following violation of very low safety significance (Green) was identified by thelicensee and is a violation of NRC requirements which meets the criteria of the NRCEnforcement Policy, for being dispositioned as a NCV:o In Modes 1 , 2, and 3, Hope Creek TS 3.4.2.1 , "Safety Relief Valves," requires that 13of the 14 SRVs open within +/-3 percent of the specified code safety valve functionlift settings or else be in Mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in Mode 4 within the next 24hours. Contrary to this requirement, PSEG identified between November 2 andNovember 29,2010, that six of the 14 SRVs were determined to have their as-foundsetpoints in excess of the TS allowable tolerance, thus leaving eight operable SRVs.PSEG replaced the pilot assembly for each of the 14 SRVs with a fully tested spareassembly. ln addition as discussed in Section 4OA3, PSEG determined that theapparent cause for 5 of the 6 SRV setpoint failures was corrosion bonding/sticking ofthe pilot disc. Therefore PSEG is also currently evaluating replacing the SRVs with adesign not susceptible to corrosion bonding through the plant modification process.PSEG entered this issue into their CAP as notifications 20483383 and 20525076.This TS violation was associated with the Mitigating Systems cornerstone but PSEGdetermined, through engineering analyses that, given a design bases event,postulated piping stresses would not have exceeded allowable limits with 6 of 14SRVs inoperable and the SRVs would have functioned to prevent a reactor vesselover-pressurization. Therefore, this finding was of very low safety significance(Green) based on a Phase 1 SDP screening, because it did not represent an actualloss of system safety function, and was not potentially risk significant for externalevents. The LERs associated with the event are documented in Section 4C.43.2.ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

J. Perry, Hope Creek Site Vice President

D. Lewis, Hope Creek Plant Manager

E. Carr, Operations Director

M. Gaffney, Regulatory Assurance Manager

M. Reed, Shift Operations Superintendent

K. Knaide, Work Management Director

P. Duca, Senior Engineer, Regulatory Assurance

C. Johnson, Senior Engineer

W. Kopchick, Engineering Director

E. Cassuilli, Plant Engineering Manager

F. Mooney, Maintenance Director

A. Shabazian, Maintenance Rule Coordinator

J. Shelton, Environmental Affairs - Nuclear

H. Trimble, Radiation Protection Manager

R. Kocher, System Engineer

W. Schmidt, Instrumentation and Controls Supervisor

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened/Closed05000354/2011004-01FIN05000354/2011004-02

Closed

05000354/201 0-001 -0105000354/201 0-002-00 and

05000354/LER-2010-002-0105000354/201 1-001-00NCVLERLERInadequate Corrective Actions AssociatedWith a Known Degraded Condition of the00-K-107 Service Air Compressor OutletCheck Valve (H0KA-0KAV-004) (Section1R12)HPCI Operability during SBLOCA/LOOPwith the A EDG Failure (Section 1R15)Technical Specification SurveillanceRequirement Not Met (Section 4OA3.1)As-Found Values for Safety Relief Valve LiftSetpoints Exceed Technical SpecificationAllowable (Section 4OA3.2)HPCI Operation Credit in UFSAR Scenarionot Supported by Existing Documentation(Section 4OA3.3)LERAttachment

A-2

LIST OF DOCUMENTS REVIEWED

In addition to the documents identified in the body of this report, the inspectors reviewed thefollowing documents and records:Hope Creek Generating Station UFSARTechnical Specification Action Statement LogHCGS NCO Narrative Logs

Section 1R01: Adverse Weather ProtectionProceduresHC.OP-AB.BOP-0004, Grid Disturbances, Revision 1 8OP-AA-108-111-1001, Severe Weather and Natural Disaster Guidelines, Revision 6HC.OP-AB.MISC-0001, Acts of Nature, Revision 18OP-AA-1 01-1 12-1Q02, On-Line Risk Assessment, Revision 5HC.MD-PM.ZZ-0007, Missile Resistant and Watertight Doors

PMHC.MD-GP.ZZ-Q037 , Plant Bulkhead Doors OverhaulHC.OP-ST.ZZ-0003, Reactor Building/Secondary Containment Integrity Verification MonthlyPreventive Maintenance PlansPM019715,PM112M Clean, Inspect Plant DoorsPMO19747, PM/12M Clean, f nspect Plant DoorsPMO19810, PMll2M Clean, Inspect Plant DoorsPM01 8797 ,6M Lube Radiation Shielding Door S13DrawinqsA-0702-0, Door & Hardware Schedule, Pressure-Tight Doors, Revision 17A-0703-0, Door & Hardware Schedule, Pressure-Tight Doors, Revision 104-0203-0, General Plant Floor Plan, Level 3 - Elevation 102'-0"A-0202-0, General Plant Floor Plan, Level 2 - ElevationTT'-0"Notifications20524508, Entry into

AB.MISC-0001 for Tide Level 95 Feet20524597, Entry into

AB.MISC-0001 for Tide Level 95 Feet20524759,

HC.OP-AB.MISC-0001 Entry High River Level20524933,

AB.MISC-0001 Condition A & B >95 Feet20527105, Entered AB,MISC-0001 Condition A & B20527 239, Entered AB. M I

SC-000

120527 432, Entered

HC.OP-AB. M

ISC-000120527457, Entered

HC.OP-AB.MISC-0001 Condition A & B20527564,

AB.MISC-0001 Entry Due to High River Level20527618, Entered

HC.OP-AB.MISC-0001 Condition A & B20527761, Entered

AB.MISC-0001 Condition A & B20526019, PM Required for TS Door 331582Q529694, Unit 2 Watertight Door InspectionsAttachment

A-3

Section 1R04: Equipment AlisnmentProceduresER-HC-310-1009,

HCGS System Functional Level Maintenance Rule Scoping Document,Revision 7HC.OP-AB.BOP-0006, Main Condenser Vacuum, Revision 14HC.OP-SO.DA-0001, Circulating Water System Operation, Revision 52HC.OP-SO.BC-0001, Residual Heat Removal System Operation, Revision 49HC.OP-SO.KJ-0001, Emergency Diesel Generator Operation, Revision 59Notifications20514273

20517023

20517089 2Q517214Orders60097699 8010192720520292DrawinqsM-09-1, P&lD Circulating Water, Revision 41M-51-1, P&lD Residual Heat Removal, Revision 41M-30-1, Sheet 1, Diesel Engine Auxiliary Systems Fuel Oil, Revision 26M-30-1, Sheet 2, Diesel Engine Auxiliary Systems Intercooler and Injection Cooling, JacketWater, Crank Case Vacuum Air Intake, Exhaust and Vibration Monitoring Systems,Revision 20M-30-1, Sheet 3, Diesel Engine Auxiliary Systems Starting Air and Lubricating Oil, Revision 19

Section 1R05: Fire Protection MeasuresProceduresFRH-Il-532, Lower Control Equipment Room, Revision 6FRH-Il-412,

RCIC Pump & Turbine Room, Revision 3FRH-Il-413, HPCI Pump & Turbine Room, Revision 3FRH-ll-433, A SACS Heat Exchanger & Pump Room, Revision 4FRH-Il-432, B SACS Heat Exchanger & Pump Room, Revision 3FRH-Il-541, Class 1E Switchgear Rooms, Elevation 130'-0"FP-AA.014, Fire Protection Training Program, Revision 0Other DocumentsFP-AA.O14, Fire Drill Form 4, Hope Creek Diesel Building 130' Elevation, Room 5411 (SAP#52e04340)Notification

20527569, Incomplete Coverage for Portable Radios

Section 1R06: Flood Protection MeasuresProcedureqOP-HC-103-102-1005, High Energy and lnternal Flooding Barrier Control Program, Revision 1FRH-Il-541, Class 1E Switchgear Rooms, Elevation 130'-0"Notifications20508557 20508558Attachment

A-4Orders60096728 70123806DrawinqsM-33-0, Sheet 1, Low Volume & Oily Waste Water TreatmentM-97-0, Sheet 2, Bldg & Equipment Drains, - Aux. Bldg Control & Diesel Areas Oily, Normal &ChemicalWaste SystemsA-5654-0, Aux. Bldg Control/Diesel Floor Plan at El124'1130'Calculations19-11, Moderate Energy Line Break Analysis for Elevations 137'1146'1150', 155'3Y163'6," and178', Revision 019-18, Maximum Flood Levels in Control & Diesel Generator Areas, Revision 6EG-0046, STACS Operation, Revision 7

Section 1R11: Licensed Operator Requalification ProqramProceduresOP-AA-1, Conductof Operations, Revision 1OP-AA-1 03-102, Watchstanding Practices, Revision 8OP-AA-101-1 1

1-1002, Operations Fundamentals, Revision 4OP-AA-101-1 1

1-1004, Operations Standards, Revision 3OP-AA-101-1 1 1-101, Operations Philosophy Handbook, Revision 5Other DocumentsSimulator Scenario Guide-683, Trip of PCP, RR Runaway/Trip, Fuel Clad Failure, Loss of8D483, Stuck Open SRV, dated 81912011

Section 1R12: Maintenance EffectivenessProceduresEPRI

TR-106857, Preventive Maintenance BasisER-AA-400-1001, Check Valve Monitoring and Preventive/Predictive Maintenance Program,Revision 8ER-HC-310-1009, HCGS System Functional Level Maintenance Rule Scoping Document,Revision 7HC.MD-PM.KA-OAjAT), Service Air Compressor Preventive Maintenance, Revision 9HC.OP-AB.COMP-0001, Instrument and/or Service Air, Revision 4LS-AA-120, lssue ldentification and Screening Process, Revision 10MA-AA-7 1 6-21 0, Performance Centered Maintenance Process, Revision 7MA-AA-71 6-210-1001, PCM Templates, Revision 1 1MA-AA-71 6-230, Predictive Maintenance Program, Revision 6WC-AA-111, Predefine Process, Revision 6Notifications (.NRC identified)20458465

20470895

20510356

20510973

20516747 2051674720517712*Orders30126129

30144535 3016738830192666

60097323 70080085Attachment

A-570112378

70124136 70124136Other DocumentsMaintenance Plan 25042PCR 801 01517

Section 1Rl3: Maintenance Risk Assessments and Emerqent Work GontrolProceduresHC.OP-AB.MISC-0001, Acts of Nature, Revision 18OP-AA-101-112-1002, On-Line Risk Assessment, Revision 5WC-AA-101, On-Line Work Management Process, Revision 19Other DocumentsHCGS

PRA Risk Evaluation for Work Week 1128, Revision 0Operator Narrative Logs for

812612011,

812712011, and 812812011Section 1 R15: Operabilitv EvaluationsCalculations10855-D3.38, Design, Installation and Test Specification for High Pressure Coolant InjectionSystem for the Hope Creek Generating Station, Revision 910855-N0-E41-4010-97 (1)-1, High Pressure Coolant lnjection System Design Specification,Revision 010855-N0-E41-40101387 (1)-1, HPCI System Design Specification Data Sheet, Revision 5PN0-E41-4010-0072 (1)-10, High Pressure Coolant lnjection, Revision 10DE-PS.ZZ-OO10, HCGS Separation Review Data Sheet, Revision 1E-5.1, HC Class 1E 250VDC Station Battery & Charger Sizing, Revision 8GR-0022, Loss of Ventilation during Station Blackout (SBO), Revision 3GR-0022, Loss of Ventilation during Station Blackout (SBO), Revision 2SC-SK-0006, HPCI&RCIC Pump Room & Steam Pipe Routing Area Ambient Temperature,Revision 6SC-SK-0040, RCIC & HPCI Pump Rooms

411014111 Delta T, Revision 511-85, Leak Detection Temperature Setpoints, Revision 11't-0066, HCGS FRVS Drawdown and Long-Term Post-LOCA Reactor Building Temperatures -EPU, Revision IProceduresER-AA-390-1001, Control Room Envelope Habitability Program lmplementation, Revision 1LS-AA-125, Corrective Action Program, Revision 14HC.IC-CC.SK-0003, HPCI- Division 1 Steam Leak Detection Temperature Monitor lSKXR-11501, Revision 18HC.OP-AB.ZZ-0135, Station BlackouUloss of Offsite Power/Diesel Generator Malfunction,Revision 33HC.OP-FT.GJ-0001, AK400 Control Area Chilled Water System Venting - Monthly, Revision 1HC.OP-FT.GJ-0003, AK403 lE Panel Room Chilled Water System Venting - MonthlyHC.OP-IS.GJ -0001, 'A' Control Area Chilled Water Pump In-service Test, Revision 29HC.OP-lS.GJ-0003, 'A'Safety Related Panel Room Chilled Water Pump In-service Test,Revision 41HC.OP-SO.GJ-0001, A(B)K400 Control Area Chilled Water System Operation, Revision 52Attachment

A-6HC.OP-SO.GJ-0001, A(B)K400 Control Area Chilled Water System Operation, Revision 52HC.OP-ST.GK-0001, 'A' Control Room Emergency Filtration System Functional Test,Revision 13HC.OP-ST.GK-0002, Control Room Emergency Filtration System lsolation Actuation FunctionalTest, Revision 13HC.OP-ST.GU-0001, FRVS Operability Test (All Fans Method), Revision 37HC.OP-ST.GU-0003, FRVS Operability Test (Four Recirculation Fans One Vent Fan Method),Revision 4Notifications (.NRC identified)20376444

20376886

20396161

20396188

20481909 2048610820501058

20516990 2052270820521711, GEH Parl21 Failure to Include Seismic20526053, HPCI Steam Supply Valve Leaking By20526006, HPCI Room Cooler Drains Clogged20525331, Reevaluate HPCI Steam Leak20524928, HPCI STM Drain

LV-F054 Leaks By20521777*,HPCl

HV-F028 Leak by20514298., NRC identified issue with temp alarms20520106*, HPCI Room Temperature Operability Challenge20518841*, HPCI Operability Determination20519206., ECCS Room Coolers20518291*, Eval Cal Range of HPCI RM Temp (NRC)20518124., UFSAR Table 6.3-6 Statement is Unsubstantiated2051 4104*, HPCI Mission Time/Operability20523099., NRC Resident ldentified Questions20523094., NRC Resident ldentified Questions20381041*, Higher InitialTemperatures in HPCI and RCIC than SBO20525385., HPCI Delta T lsolation Tech Spec Change20525583., HPCI Long Term DTTech Spec Change20527423., HPCI Room Temp lssue Evaluation Level20529330., HPCI Room Cooler Setpoint Change20529205", HPCI Standby Room Cooler Setpoint Change20527282., Ensure SSFF Entry into INPO CDEOrders20408313

30178413 7004602470111708 8010450570126660, HPCI Operability Evaluation70087284

70093083 7009320380104863, HPCI Room Cooler Setpoint Change60098044, Adverse Condition Monitoring and Contingency Plan - Monitoring of Steam Leak onHl

FD-FD-HV-F02970126793,Interim Use-As-ls Disposition for HPCI Room Temperature and Ventilation AirTemperature Difference across the RoomDrawinqsM-90-1, Aux Bldg Control Area Chilled Water System Control Area Chillers, Revision 0Other Documents\fFD PJ200-1123,862 System Aux Bldg ControlArea Chilled Water Pump AP400, Revision 8Attachment

A-7WD PJ200-1140,862 System Aux Bldg ControlArea Chilled Water Pump AP400, Revision 11\/ID PM723-121, Instruction Manual Centrifugal Refrigeration Machine, Revision 29Hope Creek Control Room Narrative Logs for night shift on August 16,201111-005, HPCI Operability Evaluation, Revision 011-005, HPCI Operability Evaluation, Revision 111-005, HPCI Operability Evaluation, Revision 2LR-N1

1-0294, Licensee Event Report 2011-001 HPCI Operation Credit in UFSAR Scenario notSupported by Existing Documentation, Revision

060098044, Adverse Condition Monitoring and Contingency Plan - Monitoring of Steam Leak onHl FD-FD-HV-F029

==Section 1R18: Plant ModificationsProceduresHC.OP-SO.DA-0001, Circulating Water System Operation, Revision 52Notifications20518634Orders60097945

80104589 80104652DrawinqsM-09-1, P&lD Circulating Water, Revision 41P-0076-0/001, Equipment Location Circulating Water Structure, Revision 17CalculationsD3.8 - Design, lnstallation and Testing Specifications for Circulating Water Pumps, Revision 050.59 Reviews. Screenings and EvaluationsHC-11-016,==

TCCP 11-016/80104652, Revision 0Section 1 Rl 9: Post-Maintenance TestinsProceduresHC.MD-FT.KJ-0004, Emergency Diesel Generator Voltage Regulator Testing/Calibration,Revision 3HC.OP-AB.ZZ-0147, DC System Grounds, Revision 4HC.OP-AB.ZZ-0150, 125 VDC System Malfunction, Revision 6HC.OP-IS.BJ-0101 , High Pressure Coolant Injection System Valves - Inservice Test, Revision62HC.OP-ST.KJ-0005, Integrated Emergency Diesel Generator 1AG400 Test (18M), Revision 36HC.OP-ST.KJ-0001, Emergency Diesel Generator Operability Test, Revision 74HC.OP-IS.BC-0004, D Residual Heat Removal Pump In-Service Test, Revision 35HC.OP-FT.EC-0001, A Fuel Pool Cooling Pump ( P211) FunctionalTest, Revision 10HC.OP-SO.KJ-0001, Emergency Diesel Generators Operation, Revision 59MA-AA-716-012, Post Maintenance Testing, Revision 16Notifications20517896

20517970 2051958720519729

20520292 20431270Attachment

20520943 20520292Orders30209971 600876706009826750142356

50140680

30106229 6008586360076802-20, Replace Bailey Modules FPC ChannelA60097527-20 & 30, 1A-P-211, Perform A Fuel Pool Cooling Pump RepairsDrawinqs10855-J-200, HPClAlarms and Status Channel 'C', Revision 0J-55-0, 1E Circuit Ch C, Sht. 13, Revision 0E41-1040, HPCI System, Sht. 4 and 6, Revision 0Section 1 R22: Surveillance TestinqCalculationsBH-0003, Standby Liquid Control System Discharge Piping Pressure Drop and Transport Time,Revision 3Completed SurveillancesH C.

OP-ST.

KJ-0004, Emergency Diesel Generator Opera bility T est, 7 l 25 l 201 1HC.OP-lS.BJ-0001, HPCI Main and Booster Pump Set - Inservice Test, 71712011HC.OP-IS.BH-0003, Standby Liquid Control Pump - Inservice Test,91112011HC.OP-IS.BC-0003, B Residual Heat Removal Pump - Inservice Test,9/1312011Notifications (.NRC identified)20486124

20519551* 2Q525567*20524273* - Calculation

BH-0003 Revision RequestOrders5Q142229

50140350

50141577 50142024DrawinqsM-51-1, Sheet 2, Residual Heat RemovalOther DocumentsBC-0056, RHR Hydraulic Analysis, Revision 56

Section 1EP6: Drill EvaluationForm

EP-AA-1 25-1002-F0 1, DEP Observation Checklist, dated 81 1 51201 1

Section 2RS1: Radioloqical Hazard Assessment and Exposure GontrolsNotifications20521717 20523125Attachment

A-9

Section 2RS3: In-Plant Radioactivitv Control and MitisationOther DocumentsN

RP 1 009BD05, I nspecVRepair Respiratory Protection Eq uipmentNRP2007BA06, Perform Air Quality Checks non Breathing AirTRI Air Testing, Inc. Compressed Air Certifications, dated

811612011 and 212512011Section 4OAl : Performance Indicator VerificationProceduresLS-AA-2001, Collecting and Reporting of NRC Performance Indicator Data, Revision 1 1Other DocumentsLER 0500035412U0-402-00 & -01, As Found Values for Safety Relief Valve Lift SetpointsExceed Technical Specification Allowable, event date October 25,2010LER 0500035412010-003-00, RHR Shutdown Cooling Suction Relief Valve Missed Surveillance,event date November 01 ,2010

Section 4OA2: Problem ldentification and ResolutionProceduresHC.OP-AB.HVAC-0001,

HVAC, Revision 5HC.OP-AB.ZZ-0135, Station Blackout/Loss of Offsite Power/Diesel Generator Malfunction,Revision 33HC.OP-AR.GM-0001, Diesel Area HVAC Local Control Panel 1EC483, Revision 6HC.OP-AR.KJ-0007, Diesel Generator Remote Engine Control Panel 1DC423, Revision 22HC.OP-SO.EG-0001, Safety and Turbine Auxiliaries Cooling Water System Operation,Revision 44HC.OP-SO.GM-0001, Diesel Area Ventilation System Operation, Revision 17HC.OP-SO.KJ-0001, Emergency Diesel Generators Operation, Revision 59OP-HC.108-1 15-1001 , Operability Assessment and Equipment Control Program, Revision 14LA-AA-1 17, Written Communications, Revision 10LS-AA-120, lssue ldentification and Screening Process, Revision 10LS-AA-125, Corrective Action Program (CAP) Procedure, Revision 13LS-AA-125-1001, Root Cause Evaluation Manual, Revision 8LS-AA-125-1003, Apparent Cause Evaluation Manual, Revision 10LS-AA-125-1004, Effectiveness Review Manual, Revision 3CC-AA-103-1003, Owners Acceptance Review of External Configuration Change Packages,Revision 5CC-AA-103-1008, Owners Acceptance Review of External Technical Products, Revision 0CC-AA-309-1 01, Engineering Technical Evaluations, Revision 10HU-AA-1212,Technical Task Risk/Rigor Assessment, Pre-Job Brief, lndependent Third PartyReview, and Post-Job Brief, Revision 5Notifications203425062045391920475383204925762052112820523012203870492Q4657162Q4754502050598220522799205235272039646420474590204755762051 91 9020522810205235322039698520474691204757212051 99052052285120523533204145232047534320478844205203192052297320523534204212972047536720479702205204522052297520523535Attachment

20523536

20494454

20497959

20498038

20498858 2049912420501558

20506195

20506384

20518067

20523094 2052309920523860Orders30110249 3013110960059222 6009158160096377 6009815230150050

30150308

30161908 3021046360091792

60091793

60091827 60092265Drawinqs1761770, Sheet 3, Elect. Schematic Engine Control, Revision 14E-0486-0, Electrical Schematic Diagram Diesel Gen. RM Recirc System Fans, Revision 12H-88-0, Sheet 5, Aux. Building - DieselArea Diesel Gen. Room Recirc. System (DRR),Revision 14J-105-0, Sheet 5, Logic Diagram Sequencer Fan Out, Revision 8M-88-1, Aux. Building - Diesel Area Control Diagram, Revision 15CalculationsE-9, Standby Class 1E Diesel Generator Sizing, Revision 8EG-0047, Attachment 13, Single EDG Room Cooler Performance Evaluation, Revision 5Evaluations and Laboratorv Reports70076024 (Op 010), B EDG Recirc Fan Trip and Diesel Recirculation (412) Fan Low Flow TripsApparent Cause Evaluation, dated 11241200870093256 (Op 018), Spurious Trips of 480 VAC MasterPact Breakers on Advance Protection(AP) Technical Evaluation, dated 21131200970113315 (Op 030), 1B-V-412 Fan Trip and Diesel Recirculation (412) Fan Low Flow TripsEquipment Apparent Cause Evaluation, dated 101141201070113315 (Op 120), Add Scope to 36M Diesel Recirculation Fan Inspection PMs, Revision 0701 13661 (Op 030), 1C-V-412 EDG Recirculation Fan Trip Equipment Apparent CauseEvaluation, dated 12121 1201070113661 (Op 190), Nuclear Logistics lnc. Failure Analysis Report

FA-04214166-1, dated31081201180102292, Simulate the Closure of the 52HH 1-1T Contact of the C EDG Recirc Fan 1GY41250.59 Review, Revision

080103945 (Op 010), A EDG Recirc Ventilation Fan AV412 Failed to Start Technical Evaluation,dated 411912011C Diesel Inoperable due to C and G 412 Diesel Recirc Fan Trips Prompt Investigation,Revision 0TCCP No.10-035, Jumper 52HH 1-1T Contact of the C EDG Recirc Fan 1GV412 TemporaryConfiguration Change Package, Revision 0Preventive Maintenance, Functional Tests. and Calibrations30131109, lnstrument Calibration Data Report, dated 6131200930135508, Instrument Calibration Data Report, dated 11151200930150050, Instrument Calibration Data Report, dated 2191201030150308, Instrument Calibration Data Report, dated 3191201030161908, Instrument Calibration Data Report, dated 61161201030161967, Instrument Calibration Data Report, dated 2131201130162280, Instrument Calibration Data Report, dated

2141201 1Attachment

A-11HC.IC-DC.ZZ-0057, Device/Equipment Calibration Dwyer Differential Pressure Switch Series1600, 1800, and 1900, performed

21612008,

112812009, and 31812011HC.IC-GP.ZZ-0002, Bimetal and Capillary Tube Thermometers, performed

21612008,

112812009,and 71812009HC.IC-GP.22-0067, General Instrument Calibration, performed

21612008,

112812009, and7t8t2009HC.MD-GP.ZZ-0020, HVAC Cooling/Heating Unit and Coil Inspection and Cleaning, performed2t5t2008HC.MD-GP.ZZ-0110, Buffalo Forge Axial Fans, Inspection, Repair and Vane Adjustment,performed

21612008 and 1128120Q9Other Documents10855-D3.51 , Design, Installation and Test Specification for Auxiliary Building, Diesel GeneratorArea Heating, Ventilation, and Cooling Systems for the Hope Creek Generating Station,Revision 710855-M-018, Technical Specification for Standby Diesel Generators for the Hope CreekGenerating Station, Revision

770127326, 1N1B-V-412 EDG Recirc Fan Breaker Trips Equipment Apparent Cause EvaluationCharter, dated 8117 1201 1A3105, DG D Room 5304 Temp Analog Point Alarm Limits, dated 8122111Diesel Generator Room (5304, 5305, 5306 & 5307) Temperature Trend,

21312011 - 812512011Fundamentals Management System (FMS) Computer Based Tool

Section 4OA3: Event FollowupProceduresHC.OP-SO.SG-0001, Seismic Instrumentation System Operation, Revision 6HC.OP-AB.MISC-0001, Acts of Nature, Revision 18OP-AA-108-1 1

1-1001, Severe Weather and Natural Disaster Guidelines, Revision 6NRC Incident Response Procedure

091001 , Appendix l, Resident Inspectors HurricaneResponse GuidanceNotifications20522851, Earthquake, Unusual Event, Common Site20523222, Evaluate Triaxial Recorder Plate Data20522915, Procedure Needed to Evaluate Data20523132, Insulation Damage Found During UE Walkdown20522863, Replace Scratch Plates in Earthquake20522954, Earthquake experienced at PSEG Nuclear20522801, Seismic Event Observations20522972, Remove Seismic Record Plates20523123, HPCI Snubber Clamp20523034, DWFD Flow Rate of Rise Alarm20522897 , Earthquake Oil Sample 1D-P-502-Mtr20522878, Earthquake Oil Sample 1A-P-102-Mtr20522942,

HCU 14-51 Alarm20522945,

HCU 22-27 Alarm20522947,

HCU 54-31 Alarm20522948,

HCU 54-15 Alarm20523178, Entered

AB.MISC-O1 For Hurricane WarningAttachment

20523289, Sequestering Personnel per Fatigue Rule20523281, Watertight Door Seal Deflated20522818, Perform Shoreline and Dike System Inspection20523215, Lessons Learned from Severe Weather Prep20523339, HWCI Out of Service iaw

HC.OP-AB.MISC-00120523386, Hydrogen Water Chemistry Alternate Path20523624, Hi - Hi Strainer DP Alarm on D SSW Pump2Q522904, Review Step H for Potential Revision20523267, Hurricane Support20523693, Post Hurricane lrene Lessons Learned20525076, SRV Setpoint Drift Root Cause Evaluation20483383, SRVs A & L Fail Setpoint Testing20497937, Leakage from "R" SRV20520106, HPCI Room Temperature Operability Challenge20528533, New Procedure Request20528532,

HC.OP-SO.SG-0001 Revision RequestOrders80104762, Seismic Instrumentation Response to Seismic Event on August 23,201170115711, SRVs A & L Fail Setpoint Testing70119769, Leakage from "R" SRV7Q128407, SRV Setpoint Drift Root Cause EvaluationOther DocumentsPSEG Letter,

LR-N11-0267, from P. Duke (PSEG) to USNRC, regarding "Work Hour ControlsBefore and After a Hurricane Emergency Declaration, dated August 27,2011LR-N1

1-0294, Licensee Event Report 2011-001 HPCI Operation Credit in UFSAR Scenario notSupported by Existing Documentation, Revision 0Section 4OA5: Other ActivitiesOther DocumentsISFSI Yard Surveys, dated

11312011,21812011,212212011,31812011,41212011,61712011, and81212011Quarterly Hi-Storm Survey, dated 21812011

LIST OF ACRONYMS

Apparent Cause EvaluationAgency-wide Documents Access and Management SystemAs Low as Reasonably AchievableCorrective Action ProgramCasual FactorCode of Federal RegulationsCirculating WaterDesign Change PackageDrill and Exercise PerformanceACEADAMSALARACAPCFCFRCWDCPDEPAttachment

EALEDG [[EGMEIACFMSHPCIHRAHXrMcIRISFSILERLOOPMSHANCVNIOSHNOSNRCOEoscPIPMPMOCPSEGRHRRTPRWPSACSSBLOCASBOSCBASDPSRASRVSSCSSFFSTSWTSUFSARUHSA-13Emergency Action LevelEmergency Diesel GeneratorEnforcement Guidance MemorandumEmergency Instrument Air CompressorFundamentals Management SystemHigh Pressure Coolant InjectionHigh Radiation AreaHeat ExchangerInspection Manual Chapterlnspection Reportlndependent Spent Fuel Storage InstallationLicensee Event ReportLoss of Offsite PowerMine Safety and Health AdministrationNon-cited ViolationNational Institute for Occupational Safety and HealthNuclear OversightNuclear Regulatory CommissionOperating ExperienceOperations Support CenterPerformance IndicatorPreventive MaintenancePreventive Maintenance Oversight CommitteePublic Service Enterprise Group Nuclear LLCResidual Heat RemovalRated Thermal PowerRadiation Work PermitSafety Auxiliary Cooling SystemSmall Break Loss of Coolant AccidentStation BlackoutSelf-Contained Breathing ApparatusSignificance Determination ProcessSenior Reactor AnalystSafety Relief ValveStructures, Systems, and ComponentsSafety System Functional FailureSurveillance TestingService WaterTech nical SpecificationUpdated Final Safety Analysis ReportUltimate Heat SinkAttachment]]