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:	Arthur Burritt Reactor Projects Branch 3
To:	Joyce T Public Service Enterprise Group
BURRITT AL
References
IR-11-004
Download: ML113140561 (43)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION

REGION I

475 ALLENOALE ROAD KING OF PRUSSIA. PENNSYLVANIA 19406-1415 November 10,2OI1 Mr. Thomas President and Chief Nuclear Officer PSEG Nuclear LLC - N09 P.O. Box 236 Hancocks Bridge, NJ 08038 SUBJECT: HOPE CREEK GENERATING STATION - NRC INTEGRATED INSPECTION REPORT 05000354/201 1 004

Dear Mr. Joyce:

On September 30, 2011, the U. S. Nuclear Regulatory Commission (NRC) completed an inspection at the Hope Creek Generating Station. The enclosed inspection report documents the 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 and compliance with the Commission's rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

The report documents two findings of very low safety significance (Green). One of the findings was determined to involve a violation of NRC requirements. Additionally, a licensee-identified violation, 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 your corrective 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 NCV in 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: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region l; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident lnspector at the Hope Creek Generating Station. In addition, if you disagree with the cross-cutting aspect assigned to any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region l, and the NRC Resident Inspector at the 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 be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.qov/readinq-rm/adams.html (the Public Electronic Reading Room).

Arthur L. Burritt, Chief Reactor Projects Branch 3 Division of Reactor Projects Docket No: 50-354 License No: NPF-57 Enclosure: I nspection Report 05000354/201 1 004 w/Attachment: Supplemental Information cc w/encl: Distribution via ListServ

SUMMARY OF FINDINGS

lR 0500035412011004;071A1i2011 - 0913012011; Hope Creek Generating Station; Maintenance

Effectiveness and Operability Evaluations.

This report covers a three-month period of inspection by resident inspectors, and announced inspections by reactor engineers and a regional radiation specialist. Two Green findings were identified. 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 may be Green or be assigned a severity level after NRC management review. The NRC's program for 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 drive sustainable improvements in the 00-K-107 service air compressor's reliability as required by PM program procedure WC-AA-111. Specifically, PSEG did not change the PM frequency of the degraded compressor outlet check valve (H0KA-0KAV-004) nor evaluate the use of materials less susceptible to corrosion after several recent performances of the 18-month PM found excessive corrosion and rust on the valve internals. Consequently, this check valve failed closed due to corrosion, tripped the air compressor, and caused a service and instrument air headers pressure transients followed by an automatic start of the EIAC. After the May 12,2011, failure, PSEG refurbished H0KA-0KAV-004's internals with new carbon 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).

This finding is more than minor because it was associated with the equipment performance attribute of the Initiating Events cornerstone and affected the cornerstone objective of limiting the likelihood of events that upset plant stability and challenge critical safety functions at power. Specifically, the failure to adequately maintain the degraded compressor outlet check valve in the service air header increased the likelihood of a plant trip. The inspectors evaluated this finding using IMC 0609, Attachment 4, "Phase 1 - lnitial Screening and Characterization of Findings," Table 4a, and determined the finding to be of very low safety significance (Green) because the finding does not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment would not be available. The finding has a cross-cutting aspect in the area of human performance, work control component; because PSEG did not appropriately coordinate work activities by incorporating actions to ensure that maintenance scheduling is more preventive than reactive. 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 required reactive maintenance following a trip of the 00-K-107 air compressor. (H.3(b)) (Section 1R12)

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 high pressure coolant injection (HPCI) design under post-accident conditions. Specifically,

PSEG did not evaluate the impact of elevated temperature in the HPCI room on the operability of the HPCI system during a postulated design basis small break loss of coolant accident (SBLOCA) coincident with a loss of offsite power (LOOP) and a single failure of the A emergency diesel generator (EDG). PSEG determined through subsequent evaluation that HPCI was operable but non-conforming because there was a potentialfor HPCI system to isolate unnecessarily on high differential temperature during the extreme winter low temperatures. PSEG plans to implement a design change to reduce the setpoints of the HPCI room coolers so that the initial HPCI room temperature is maintained at a lower temperature before extreme winter conditions. The violation was entered into the CAP as notifications 205 1 81 24 and 205201 06.

The performance deficiency was more than minor because it was associated with the design control attribute of the Mitigating Systems cornerstone and affected the cornerstone objective of ensuring the reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, PSEG had not evaluated HPCI operability using actual HPCI room temperatures during normal operating conditions, and as a result, HPCI's reliability during the most limiting accident conditions was not assured during extreme winter low 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 issue screened to very low safety significance (Green). The finding had a cross-cutting aspect in the area of problem identification and resolution, corrective action component, because PSEG did not thoroughly evaluate a prior problem such that the problem resolution addressed the causes and the extent of condition. Specifically, PSEG's evaluation for notification 20381041, HPCI Operability During Station Blackout (SBO) Conditions, did not identify 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 not identify that the actual HPCI room temperature was beyond the HPCI design document assumption 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 the inspectors. Corrective actions taken or planned by PSEG have been entered into PSEG's corrective action program. This violation and corrective action tracking number are listed in Section 4OA7 of this report.

REPORT DETAILS

Summarv of Plant Status The Hope Creek Generating Station operated at or near full rated thermal power (RTP) for the duration of the inspection period with the following exceptions. On selected occasions required by atmospheric conditions, reactor power was reduced in small increments to clear condenser vacuum concerns and then subsequently returned to full RTP when atmospheric conditions allowed. On July 22,2011, operators performed an unplanned power reduction from 94 percent to 80 percent RTP in response to increasing temperatures in the station auxiliary cooling system that was caused by grassing in the station service water (SW) system. The grassing issue was cleared and reactor power was increased the same day to the limits allowed by condenser vacuum. On September 9, 2011, a planned power reduction to approximately 76 percent RTP was conducted to support turbine valve testing, control rod scram time testing and a control rod pattern sequence change. The reactor was returned to full RTP on September 10, 2Q11, and the reactor remained near or at full RTP for the remainder of the inspection period.

1. REACTOR SAFEW

Cornerstones: Initiating Events, Mitigating Systems, Barrler Integrity, and Emergency Preparedness

==1R01 Adverse Weather Protection (71111.01 - 1 lmminent sample, 1 Ext Fld sample)

=

.1 Readiness for lmpendinq Adverse Weather Conditions===

a. Inspection Scope

The inspectors completed one impending adverse weather preparation sample. The inspectors reviewed PSEG's preparations for the onset of hot weather on July 12,2011.

The inspectors reviewed the implementation of adverse weather preparation procedures before the onset of and during adverse weather conditions. The inspectors walked down the EDGs and station service water (SW) to ensure system availability. The inspectors verified that operator actions defined in PSEG's adverse weather procedure maintained the readiness of essential systems. The inspectors discussed readiness and staff availability for adverse weather response with operations and work control personnel.

Documents reviewed are listed in the Attachment.

b.

Findinss No findings were identified.

.2 Readiness to Cope with External Floodinq

a. Inspection Scope

During September 2011 , the inspectors performed an inspection of the external flood protection measures for Hope Creek. The inspectors reviewed the updated final safety analysis 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-related equipment to identify areas that may be affected by flooding. The inspectors also reviewed the limiting conditions for operations and the surveillance requirements in technical specification (TS) 314.7.3, "Flood Protection." The review was focused on the power block flood doors listed in TS Table 3.7.3-1, "Perimeter Flood Doors." The inspectors reviewed the PM activities performed on these doors with the responsible system engineer. The inspectors also conducted a walkdown of the accessible portions of all these doors with the responsible system engineer to verify that the doors were in conformance with the design basis requirements in the UFSAR, the TS, and plant procedures and drawings. Additionally, the inspectors reviewed the abnormal operating procedure, HC.OP-AB.MISC-0001, "Acts of Nature," for mitigating external flooding during severe weather to determine if PSEG had planned and established adequate measures to protect against externalflooding events. Documents reviewed are listed in the Attachment.

b. Findinqs No findings were identified.

==1R04 Equipment Aliqnment (71111 .A4 - 2 samples;

==71111.04S - 1 sample)

.1 PartialWalkdowns

==

a. Inspection Scope

==

The inspectors completed two partialwalkdown inspection samples. The inspectors performed partial system walkdowns for the systems listed below to verify each system's operability when redundant or diverse trains and components were inoperable. The inspectors completed walkdowns to determine whether there were discrepancies in the system'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, and support equipment were in the correct position to support system operation. The inspectors also verified that PSEG had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the CAP. Documents reviewed are 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 2 b. Findinqs No findings were identified.

,2 Complete Walkdown

a. Inspection Scope

The inspectors performed one complete walkdown inspection of the A EDG. The inspectors used PSEG procedures and other documents to verify proper system alignment and functional capability. The inspectors independently verified the alignment and status of the A EDG system breakers, valves, switches, and associated support systems. The walkdown also included checks that fuel oil levels were normal, system parameters were within established ranges, and equipment deficiencies were appropriately identified and entered into the CAP for resolution. Documents reviewed are listed in the Attachment.

b.

Findinqs No findings were identified.

==1R05 Fire Protection (71111.05Q - 5 samples;7111 1

=

.1 Fire Protection - Tours===

a. lnspection Scope The inspectors completed five quarterly fire protection inspection samples. The inspectors conducted tours of the areas listed below to assess the material condition and operational status of fire protection features. The inspectors verified that combustibles and ignition sources were controlled in accordance with PSEG's administrative procedures; fire detection and suppression equipment was available for use; that passive fire barriers were maintained in good material condition; and that compensatory measures for out of service, degraded, or inoperable fire protection equipment were implemented in accordance with PSEG's fire plan. The areas toured are listed below with their associated pre-fire plan designator. Documents reviewed are listed in the

.

.

FRH-Il-532, lower relay room

.

FRH-Il-412, reactor core isolation cooling pump room r FRH-Il-413, HPCI pump room

.

FRH-Il-433, A&C safety auxiliary cooling system (SACS) pump room

.

FRH-ll-432, B&D SACS pump room b. Findinos No findings were identified.

.2 Fire Protection - Drill Observation

a. Inspection Scope

The inspectors observed an unannounced fire brigade drill scenario conducted on August 7, 2011, that involved a simulated electrical fire in the D 1E Switchgear Room on the 130' elevation in the diesel generator area of the Auxiliary Building. The inspectors also observed the participation of the operators in the main control room. The inspectors evaluated the readiness of the plant fire brigade to fight fires. The inspectors verified that PSEG personnel identified deficiencies, openly discussed them in a self-critical manner during post-drill critique activities, and took appropriate corrective actions as required. The inspectors evaluated specific attributes as follows:

.

Proper wearing of turnout gear and self-contained breathing apparatus

.

Proper use and layout of fire hoses

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Employment of appropriate fire-fighting techniques

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Sufficient fire-fighting equipment brought to the scene

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Effectiveness of command and control

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Search for victims and propagation of the fire into other plant areas

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Ventilation control and smoke removal operations

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Utilization of pre-planned strategies

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Adherence to the pre-planned drill scenario

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Drill objectives met The inspectors also evaluated the fire brigade's actions to determine whether these actions were in accordance with PSEG's pre-fire plans and fire-fighting strategies.

Documents reviewed are listed in the Attachment.

b. Findinqs No findings were identified.

==1R06 Flood Protection Measures (71111.06 - 1 Int Fld sample)

Internal Floodinq Review a.==

Inspection Scope The inspectors completed one flood protection measures inspection sample. The inspectors reviewed selected risk-important plant design features and PSEG procedures intended to protect the plant and its safety-related equipment from internal flooding events. Specifically, the inspectors focused on internal flood mitigation features for the 130' elevation of the auxiliary building, which contains class 1E switchgear, breakers, and control panels for all four EDGs. The inspectors reviewed flood analysis and design documents, including the UFSAR, engineering calculations, and abnormaloperating procedures. The inspectors observed the condition of wall penetrations, watertight doors, flood alarm switches, and drains to assess their readiness to contain flow from an internal flood in accordance with the design basis. Documents reviewed are listed in the

.

b. Findinqs No findings were identified.

1R11 Licensed Operator Requalification Proqram

a. Inspection Scope

On August 15,2011, the inspectors completed one quarterly licensed operator requalification program inspection sample. The inspectors observed operators in the plant's simulator during licensed operator requalification training to verify that operator performance was adequate and that evaluators were identifying and documenting crew performance problems. The inspectors also verified that performance errors were discussed in the crew's post-scenario critiques. The inspectors focused on the control room supervisor's satisfactory completion of critical tasks. The inspectors also observed operator implementation of abnormal and emergency operating procedures. The inspectors discussed the training, simulator scenarios, and critiques with the operators, shift supervision, and the training instructors. Documents reviewed are listed in the

. 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. Findinos No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors completed one maintenance effectiveness inspection sample. For the equipment performance issue listed below, the inspectors evaluated items such as:

appropriate work practices; identifying and addressing common cause failures; scoping in accordance with 10 CFR 50.65(b) of the Maintenance Rule; characlerizing reliability issues for performance; classification and reclassification in accordance with 10 CFR 50.sa(a)(1) or (a)(2); and appropriateness of performance criteria for structures, systems, and components (SSCs)/functions classified as (a)(2) and/or appropriateness and adequacy of goals and corrective actions for SSCs/functions classified as (aX1).

Documents reviewed are listed in the Attachment.

.

Service air compressor failures b. Findinqs

Introduction.

A self-revealing finding was identified because of the PMOC did not drive sustainable improvements in the 00-K-107 service air compressor's reliability as required by PM program procedure WC-AA-111. Specifically, PSEG did not change the PM frequency of the degraded compressor outlet check valve (H0KA-0KAV-004) nor evaluate the use of materials less susceptible to corrosion after several recent performances of the 18-month PM found excessive corrosion and rust on the valve internals. Consequently, this check valve failed closed due to corrosion, tripped the air compressor, and caused a service and instrument air headers pressure transients followed 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 are important to safety because they supply instrument air header pressure. A loss of instrument air at Hope Creek can cause an automatic scram by affecting control rod movement and/or spurious feedwater and condensate system valve operation. The service air compressors are each operated 50 percent of the time and normally swapped every 18 months to minimize cycling and to conduct PM.

On May 12,2011, PSEG conducted a planned swap from the 10-K-107 service air compressor to the 00-K-107 service air compressor. During the swap, service and instrument air header pressures dropped unexpectedly from approximately 100 psig to 84 and 81 psig, respectively, and when the 10-K-107 service air compressor was stopped 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 the automatic start of the emergency instrument air compressor (EIAC) and entry into abnormal operating procedure HC.OP-AB.COMP-0001. The EIAC promptly restored service and instrument air header pressures to normal.

PSEG determined that the cause of the instrument and air system transient was that the outlet check valve (H0KA-0KAV-004) for the 00-K-107 service air compressor was corroded shut. PSEG concluded that H0KA-0KAV-004 was corroded because it was located 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 exposed to, they had previously considered modifying H0KA-0KAV-004 by replacing the carbon steel internals with stainless steel. However, to date, no engineering change request was submitted to initiate the modification process for this material change.

Based on a review of the PM program, the inspectors determined that vendor documents for the H0KA-0KAV-004 recommend at least an every two-year open and inspect PM, but after the valve was found corroded shut in May 2002, PSEG had increased the inspection frequency to every six months. In April 2004, PSEG changed the PM frequency from every six months to every 18 months. The basis for the change was that, after two years of inspections performed every six months, PSEG had neither identified significant corrosion buildup on the valve nor experienced a corrosion-related failure 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 completed before the May 2011 valve failure found excessive rust and severe corrosion on the H0KA-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, technicians submitted 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) is responsible for driving sustainable improvements in equipment reliability and plant performance through improvements in the PM program." At the time of the May 2011 H0KA-0KAV-004 failure to open, PCR 80101517 had not been reviewed by the PMOC and no action had been taken to address the identified design issues - inappropriate valve internal materials given the wetted air to which the valve was exposed. The inspectors noted that PSEG missed these three opportunities to shorten the PM periodicity and prevent the H0KA-0KAV-004 check valve failure and subsequent 00-K-107 service air compressor trip. The inspectors concluded that PSEG's lack of action relative to maintaining service air system component reliability through PM program improvements led to the May 2011 H0KA-0KAV-004 failure.

After the May '12,2011, failure, PSEG refurbished H0KA-0KAV-004's internals with new carbon 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).

Analvsis. The PMOC's failure to drive sustainable improvements in the 00-K-107 air compressor'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 and correct. Specifically, after several recent performances of the 18-month PM found excessive corrosion and rust on the valve internals, PSEG did not either change the PM frequency of the degraded compressor outlet check valve (H0KA-0KAV-004) or change the material used in the valve's internals to one less susceptible to corrosion.

Consequently, this check valve failed closed due to corrosion, tripped the air compressor, and caused a service and instrument air headers pressure transients followed by an automatic start of the EIAC.

This finding is more than minor because it was associated with the equipment performance attribute of the Initiating Events cornerstone and affected the cornerstone objective of limiting the likelihood of events that upset plant stability and challenge critical safety functions at power. Specifically, the failure to adequately maintain the compressor outlet check valve increased the likelihood of a plant trip. The inspectors evaluated this finding using IMC 0609, Attachment 4, "Phase 1 - Initial Screening and Characterization of Findings," Table 4a, and determined the finding to be of very low safety significance (Green) because the finding does not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment would not be available. The finding has a cross-cutting aspect in the area of human performance, work control component; because PSEG did not appropriately coordinate work activities by incorporating actions to ensure that maintenance scheduling is more preventive than reactive. Specifically, PSEG did not shorten the PM interval or change the materials used in the valve internals before the valve failed shut and required reactive maintenance 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 no violation of regulatory requirements occurred. Because this finding does not involve a violation and has very low safety significance, it is identified as a finding. (FlN 05000354/2011004-0l, Inadequate Gorrective Actions Associated with a Known Degraded Gondition of the 00-K-107 Service Air Compressor Outlet Check Valve (H0KA-oKAV-o04))

1R13 Maintenance Risk Assessments and Emerqent Work Control

a. Insoection Scope The inspectors completed four maintenance risk assessment and emergent work control inspection samples. The inspectors reviewed on-line risk management evaluations through direct observation and document reviews for the following four plant configurations:

.

C EDG and Salem Unit 3 out-of-service during week of July 11 o 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 1 o Online risk was elevated from green to yellow on August 26, in response to a severe weather warning (Hurricane lrene) and PSEG reviewed scheduled work to confirm that no work would be performed that woufd increase the risk of a LOOP The inspectors reviewed the applicable risk evaluations, work schedules, and control room logs for these configurations to verify that concurrent planned and emergent maintenance and test activities did not adversely affect the plant risk already incurred with these configurations. PSEG's risk management actions were reviewed during shift luryover meetings, control room tours, and plant walkdowns. The inspectors also used PSEG's on-line risk monitor (Equipment Out of Service workstation) to gain insights into the risk associated with these plant configurations. Finally, the inspectors reviewed notifications documenting problems associated with risk assessments and emergent work evaluations. Documents reviewed are listed in the Attachment.

b.

Findinqs No findings were identified.

1R15 Operabilitv Evaluations

a. Inspection Scope

The inspectors reviewed three issues to assess the technical adequacy of the operability determinatlons or operability screenings, the use and control of compensatory measures, and compliance with the licensing and design bases. As applicable, associated adverse condition monitoring plans, engineering technicalevaluations, and operational and technical decision making documents were also reviewed. The inspectors verified these processes were performed in accordance with the applicable administrative procedures and were consistent with NRC guidance. Specifically, the inspectors referenced procedure OP-AA-108-115, "Operability Determinations,'; and NRC IMC Part 9900, "Operability Determinations & Functionality Assessments for Resolutions of Degraded or Nonconforming Conditions Adverse to Quality or Safety."

The inspectors also used the TS, the technical requirements manual, and the UFSAR as references during these reviews. Additionally, the inspectors reviewed other PSEG identified safety-related equipment deficiencies during this report period and assessed the adequacy of their operability screenings. Documents reviewed are listed in the

. The following degraded equipment issues were reviewed:

.

HPCI non-conforming due to increase in room temperature o A Chilled Water Pump degraded due to low flow trip

.

HPCI degraded due to F028 & F029 valve steam leaks b.

Findinqs lntroduction. 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, PSEG did not ensure the adequacy of HPCI design under post-accident conditions, Specifically, PSEG did not evaluate the impact of elevated temperature in the HPCI room on the operability of the HPCI system during a postulated design basis SBLOCA coincident with a LOOP and a single failure of the A emergency diesel generator (EDG).

Descriotion. The design function of the HPCI system is to maintain reactor vessel inventory following the postulated SBLOCA. As stated in Hope Creek UFSAR section 6.3, HPCIwas designed to remain operable during its most limiting accident, a SBLOCA and LOOP with the single failure of an EDG. Because both HPCI room coolers are powered by the A EDG, when the A EDG is assumed as the single failure, the system design requires HPCI to be operable without either room cooler.

During plant walkdowns between May 15, 2011, and July 26, 2Q11, the inspectors observed the HPCI room temperature was between 114'F and 116'F degrees as read at the HPCI isolation system instrument panel. During a HPCI steam line break, HPClwill isolate if instruments sense high room temperature (>160'F) or high differential temperature 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," states that HPCI room temperature during normal plant operations should be between 60'F to 100'F. Considering that HPCI room temperature was between 114"F and 116oF, the inspectors determined that PSEG did not have a design calculation that demonstrated that HPCI would not isolate due to either high room temperature or high room ventilation differential temperature during the most limiting accident.

PSEG initiated notifications 20518124 and 20520106 and performed an operability evaluation to verify HPCI operability during the most limiting accident. This evaluation concluded that HPCI operability could be challenged during extreme winter low temperatures because the very low HPCI room ventilation supply temperatures and post accident room heat up combined with the higher initial room temperature could cause the system to isolate on high differential temperature. To address this condition, PSEG plans to implement a design change to reduce the setpoints for the HPCI room coolers to lower the normal ambient HPCI room temperature. This will reduce the differential temperature between the ventilation supply and the room temperature and is expected to prevent HPCI from isolating during extreme winter low temperatures when HPCI room ventilation supply temperature is very low. The modification is currently scheduled to be implemented prior to the onset of winter weather conditions.

The inspectors identified prior opportunities for PSEG to identify this non-conforming condition. In August 2008, the inspectors questioned HPCI operability during SBO conditions (LOOP and loss of all EDGs) as documented in notification 20381041.

Specifically, a HPCI room heat up calculation, GR-0022, Revision 3, Loss of Ventilation during SBO, assumed a maximum initial ambient HPCI room temperature of 104"F. In 2008, the inspectors observed actual room conditions greater than 104"F (notification 20381041). As corrective actions for this issue, PSEG conducted troubleshooting to identify the cause of the elevated temperature, but were unsuccessful. At that point, PSEG initiated action to revise GR-0022 and performed an operability evaluation that determined the acceptable starting HPCI room temperature during SBO conditions could be as high as 1 13"F. No additional action or evaluations were performed. Although PSEG appropriately evaluated the impact of the elevated normal operating HPCI room temperature on the SBO HPCI room heat up calculation, PSEG did not evaluate the impact of the elevated temperature on the HPCI systems response during other design basis accidents. The site's operability evaluation procedure required an extent of condition review be performed for conditions evaluated through that process.

The inspectors reviewed PSEG procedure, LS-AA-125, "Corrective Action Program,"

which defines extent of condition as the extent to which the identified condition has the potential to impact other plant processes, equipment, or human performance in the same manner as identified in the condition report. The inspectors found that in 2008, in response to the identified higher than normal HPCI room temperature, PSEG's extent of condition review determined that no other safety systems were constrained by initial room temperature heat up concerns. However, this extent of condition review narrowly focused on SBO conditions and, therefore, did not identify the impact of the initial ambient HPCI room temperature on other accident conditions, such as a SBLOCA and LOOP with the single failure of an EDG. Also, the inspectors noted that PSEG did not conduct a casual evaluation for notification 20381041 to determine why the actual HPCI room temperatures were above the initial HPCI room temperature assumed in the HPCI room design basis heat up calculation. The inspectors concluded that a casual evaluation 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 the design of the HPCI system under the most limiting accident conditions described in Hope Creek UFSAR section 6.3 after concerns regarding HPCI room temperature were identified by inspectors in 2008 was a performance deficiency. The performance deficiency was more than minor because it was associated with the design control attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective of ensuring the reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, PSEG had not evaluated HPCI operability using actual HPCI room temperatures during normal operating conditions, and as a result, HPCI's reliability during the most limiting accident conditions was not assured during extreme winter low temperatures. Also, this issue was similar to Example 3j of IMC 0612, Appendix E, "Examples of Minor lssues," because the condition resulted in reasonable doubt of the operability of the component, and additional analysis and compensatory actions were necessary to ensure HPCI operability during all environmental conditions.

The inspectors reviewed this condition using IMC 0609, Attachment 4, and in consultation with a Region I SRA, concluded that although this event constituted a deterministic safety functional failure, the HPCI system was likely capable of performing its significance determination process safety function, given the numerous postulated equipment failures and specific system configurations that would have to occur to cause the deterministic system failure. Therefore, each of the relevant questions in the 4 table would be answered no and this issue screened to very low safety significance (Green).

The finding had a cross-cutting aspect in the area of problem identification and resolution, corrective action component, because PSEG did not thoroughly evaluate a prior problem such that the problem resolution addressed the extent of condition.

Specifically, PSEG's evaluation for notification 20381041 , "HPCI Operability during SBO Conditions," did not identify the impact of actual HPCI room temperature during normal operating conditions on other accident conditions, such as a SBLOCA and LOOP with the single failure of an EDG. Therefore, PSEG did not identify that the HPCI room temperature was beyond the HPCI design document assumption of 60'F to 100"F.

(P.1(c))

Enforcement.

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 by the performance of design reviews, by the use of alternate or simplified calculational methods, 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 the adequacy of the HPCI system design under the most limiting accident conditions described in Hope Creek UFSAR section 6.3, by the use of alternate or simplified calculational 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 system would remain operable during a SBLOCA and LOOP with a single failure of an EDG after inspectors identified that the actual HPCI room normal operating condition temperature was greater than 104"F. PSEG determined through subsequent evaluation that HPCI was operable but non-conforming because there was a potentialfor HPCI system to isolate unnecessarily on high differential temperature during the extreme winter low temperatures. This issue was entered into CAP as notifications 2Q518124 and 20520106, and PSEG plans to implement a design change to reduce the setpoints of the HPCI room coolers so that the initial HPCI room temperature is maintained at a lower temperature before extreme winter conditions. Because this violation was of very low safety significance (Green) and has been entered into the CAP this violation is being treated 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 A EDG Failure)

1R18 Plant Modifications

a. Inspection Scope

The inspectors completed a review of one temporary modification package for the D CW pump hydraulic control unit plug due to a large hydraulic fluid leak on the pump discharge pressure indicator (TCCP 4HT-11-016). The inspectors verified that the design bases, licensing bases, and performance capability of the CW pump were not degraded by this temporary modification. The inspectors also verified the post modification testing was adequate to ensure the SSCs would function properly. The 10 CFR 50.59 evaluation associated with this temporary modification was also reviewed.

Documents reviewed are listed in the Attachment.

b. Findinos No findings were identified.

1R19 Post-Maintenance Testinq

a. Inspection Scope

The inspectors completed seven post-maintenance testing inspection samples. The inspectors reviewed the post-maintenance tests for the maintenance items listed below to verify that procedures and test activities ensured system operability and functional capability following completion of maintenance. The inspectors reviewed applicable test procedures to verify that they tested all safety functions potentially affected by the associated maintenance activities. The inspectors verified that for each potentially affected safety function the acceptance criteria stated in the procedure was consistent with the UFSAR and other design documentation. The inspectors witnessed completion of the testing or reviewed the completed test results to confirm acceptance criteria were met and verified satisfactory restoration of all safety functions affected by the maintenance activities. Documents reviewed are listed in the Attachment.

o A control area chilled water pump logic module replacement after pump trip on July 5 o 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 27 r A EDG intercooler pump replacement on August 3 o A fuel pool cooling pump corrective maintenance on August 7

.

B EDG lube oil keep-warm pump replacement on September 13 b. Findinqs No findings were identified.

==1R22 Surveillance Testins (71111.22 - 3 Routine samples, 1 IST sample)

a. Inspection Scope

==

The inspectors completed four surveillance testing (ST) inspection samples. The inspectors witnessed performance of and/or reviewed test data for the risk-significant STs listed below to verify that the SSCs tested satisfied TSs, UFSAR, and procedure requirements. 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 for the application; and that tests were performed as written with applicable prerequisites satisfied. Upon ST completion, the inspectors confirmed that equipment was returned to the status specified to perform its safety function. Documents reviewed are listed in the

.

r HPCI inservice test on July 7 o D EDG monthly surveillance test on July 25 r A standby liquid pump surveillance test on September 1 o B RHR pump inservice test run on September 13 b. Findinos No findings were identified.

lEPO Drill Evaluation (71114.00 - 1 drill/ev sample)

a. Inspection Scope

The inspectors observed the classification and notification aspects of a licensed operator requalification 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 reviewed the conduct of the simulator exercise to identify any weaknesses and deficiencies in classification 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 in the calculation of the DEP Pl. The inspectors verified that training evaluators captured the results for the DEP Pl. The inspectors also verified that any weaknesses or deficiencies were captured and discussed during the critique of the training exercise, in order to properly identify and correct any weaknesses. Documents reviewed are listed in the Attachment. Emergency action level (EAL) # 8.2.2.a -Unplanned Loss of Most or All Control Room Annunciators and Significant Transient is in Progress or Compensatory Indicators are Unavailable - was classified during this training exercise:

b.

Findinqs No findings were identified.

2RS1 Radioloqical Hazard Assessment and Exposure Controls

a. Inspection Scope

The inspectors reviewed PSEG performance indicators (Pl) for the Occupational Exposure Cornerstone for follow-up. The inspectors reviewed the results of radiation protection program audits. The inspectors reviewed reports of operational occurrences related to occupational radiation safety since the last inspection.

The inspectors verified that any transactions involving nationally tracked sources were reported in accordance with 10 CFR 20.2207 .

During tours of the facility and review of ongoing work, the inspectors evaluated ambient radiological conditions. The inspectors verified that existing conditions were consistent with posted surveys, radiation work permits (RWPs), and worker briefings, as applicable.

During job performance observations, the inspectors verified the adequacy of radiological controls, such as required surveys, radiation protection job coverage, and contamination controls. The inspectors evaluated PSEG's means of using electronic personnel dosimeters in high noise areas as high radiation area (HRA) monitoring devices. The inspectors verified that radiation monitoring devices were placed on the individual's body consistent with the method that PSEG was employing to monitor dose from external radiation sources. The inspectors verified that the dosimeter was placed in the 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 inspectors reviewed the application of dosimetry to effectively monitor exposure to personnel. The inspectors verified that PSEG controls were adequate.

The inspectors reviewed RWPs for work within airborne radioactivity areas with the potential for individual worker internal exposures. The inspector evaluated airborne radioactive controls and monitoring, including potentials for significant airborne contamination. For these selected airborne radioactive material areas, the inspectors verified barrier integrity and temporary high-efficiency particulate air ventilation system operation.

The inspectors conducted selective inspections of posting and physical controls for HRAs and very HRAs, to the extent necessary, to verify conformance with the Occupational Pl.

The inspectors observed radiation worker performance with respect to stated radiation protection work requirements. The inspectors determined that workers were aware of the significant radiological conditions in their workplace and the RWP controls/limits and that their performance reflected the level of radiological hazards present.

The inspectors reviewed radiological problem reports since the last inspection that found the cause of the event to be human performance errors. The inspectors determined that there was no observable pattern traceable to a similar cause. The inspectors determined that this perspective matched the corrective action approach taken by PSEG to resolve the reported problems. The inspectors discussed with the radiation protection manager any problems with the corrective actions planned or taken.

b. Findinqs No findings were identified.

2RS2 Occupational As Low as Reasonablv Achievable (ALARA) Plannino & Controls

a. Inspection Scope

The inspectors verified that PSEG's planning identified appropriate dose mitigation features, commensurate with the risk of the work activity, alternate mitigation features, and defined reasonable dose goals. The inspectors verified that PSEG's ALARA assessment had taken into account decreased worker efficiency from use of respiratory protective devices andlor heat stress mitigation equipment. The inspectors determined that PSEG's work planning considered the use of remote technologies as a means to reduce dose and the use of dose reduction insights from industry operating experience and plant-specific lessons learned. The inspectors verified the integration of ALARA requirements into work procedures and RWP documents.

The inspectors compared the results achieved with the intended dose established in PSEG's ALARA planning for these work activities. The inspectors compared the person-hour estimates provided by maintenance planning and other groups to the radiation protection group with the actual work activity time requirements and evaluated the accuracy of these time estimates. The inspectors determined the reasons for any inconsistencies between intended and actual work activity doses. The inspectors focused on those work activities with planned or accrued exposure greater than five person-rem.

The inspectors determined that post-job reviews were conducted and that identified problems were entered into PSEG's CAP.

The inspectors verified that problems associated with ALARA planning and controls were being identified by PSEG at an appropriate threshold and were properly addressed for resolution in their CAP.

b. Findinqs No findings were identified.

2RS3 ln-Pfant Airborne Radioactivitv Control and Mitiqation

a. Insoection Scope The inspectors verified that PSEG provided respiratory protective devices such that occupational doses are ALARA. As available, the inspectors selected work activities where respiratory protection devices were used to limit the intake of radioactive materials, and verified that PSEG performed an evaluation concluding that further engineering controls were not practical and that the use of respirators was ALARA. The inspectors verified that PSEG had established means to verify that the level of protection provided by the respiratory protection devices during use was at least as good as that assumed in PSEG's work controls and dose assessment.

The inspectors verified that respiratory protection devices used to limit the intake of radioactive materials are certified by the National Institute for Occupational Safety and Health/Mine Safety and Health Administration (NIOSH/MSHA) or had been approved by the NRC. The inspectors selected work activities where respiratory protection devices were used and verified that the devices were used consistent with their NIOSH/MSHA certification.

The inspectors reviewed records of air testing for supplied-air devices and self-contained breathing apparatus (SCBA) bottles. The inspectors verified that air used in these devices meet or exceeded Grade D quality. The inspectors verified that plant breathing air supply systems met the minimum pressure and airflow requirements for the devices in use.

The inspectors selected individuals qualified/assigned to use respiratory protection devices 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 device as appropriate. The inspectors verified that these individuals knew how to safely use the device 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 the plant or stocked for issuance for use and observed the physical condition of the device components and reviewed records of routine inspection for each. The inspectors selected a sampling of the devices and reviewed records of maintenance on the vital components. The inspectors verified that onsite personnel assigned to repair vital components had received vendor-provided training.

Based on the Final Safety Assessment Report, TSs, and emergency operating procedure requirements, the inspectors reviewed the status and surveillance records of the SCBA staged in-plant for used during emergencies. The inspectors observed PSEG's capability for refilling and transporting SCBA air bottles to and from the control room and operations support center during emergency conditions.

The inspectors selected individuals on control room shift crews and individuals from designated departments currently assigned emergency duties and determined that control room operators and other emergency response and radiation protection personnel were trained and qualified in the use of SCBAs. The inspectors determined that 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 that would interfere with the sealing of the mask to the face. The inspectors also verified that vision correction did not penetrate the face seal.

The inspectors reviewed the past two years of maintenance records for SCBA units used to support operator activities during accident conditions and designated as "ready for service." The inspectors verified that any maintenance or repairs on an SCBA unit's vital components were performed by an individual, or individuals, certified by the manufacturer of the device to perform the work. The inspectors reviewed the onsite maintenance procedures governing vital component work, and identified any inconsistencies with the SCBA manufacturer's recommended practices. For those SCBAs designated as "ready for service," the inspectors ensured that the required, periodic air cylinder hydrostatic testing was documented and up to date, and the retest air cylinder markings required by the U.S. Department of Transportation were in place.

b. Findinqs No findings were identified.

4OA1 Performance Indicator (Pl) Verification (71151-

1 sample)

.1 Review of Safetv Svstem Functional Failures (SSFFS) Pl

a. Inspection Scope

The 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 ,2010 through June 30, 2011. The Pl definitions and the guidance contained in Nuclear Energy Institute 99-02, "Regulatory Assessment Indicator Guideline," Revision 6, and procedure LS-AA-2080, "Monthly Data Elements for NRC SSFFs," Revision 5, were used to verify that procedure and reporting requirements were met.

The inspectors reviewed licensee event reports (LERs) issued during the referenced timeframe for SSFFs. Documents reviewed are listed in the Attachment. The inspectors also compared graphical representations from the most recent Pl report to the raw data to verify that the data was correctly reflected in the report.

b. Findinqs No findings were identified.

4c.42 Problem ldentification and Resolution (71152 - 2 Reviews samples)

.1 Routine Review of ltems Entered into the CAP

a. Inspection Scope

As required by lP 71 152, "ldentification and Resolution of Problems," and in order to help identify repetitive equipment failures or specific human performance issues for follow-up, the inspectors performed a daily screening of all items entered into PSEG's CAP. This was accomplished by reviewing the description of each new notification and attending management review committee meetings.

b.

Findinqs No findings were identified.

.2 Annual Sample: Corrective Actions for EDG Room Cooler Recirculation Fan Trips

a. Inspection Scope

Each of the four EDG rooms is provided with two safety-related room cooler recirculation fans and two cooling coil assemblies. Under normal operating conditions, these recirculation fans and cooling coil assemblies are fully redundant, each capable of providing 100 percent of the cooling requirement for its respective EDG room. During periods of operation when the ultimate heat sink (UHS) temperature is above 80"F, and based 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. When positioned to "auto," the backup fan is designed to start on elevated room temperature concurrent with an EDG start or a low flow condition on the auto-lead fan (given a start demand). Since January 2010, PSEG identified 12 unexpected recirculation fan trips (2 on A V412fan,8 on B Y412fan, and 2 on CY412 fan), with recent trips occurring on July 28, 201 1 (notification 20519905 on A) and August 1, 2011 (notification 2Q520452 on B). This inspection focused on PSEG's problem identification, evaluation, and resolution associated 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 corrective actions. 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., the planned D EDG start on August 22), to assess their operating performance with respect to design basis requirements and system specifications. The inspectors performed walkdowns of the EDG rooms, accessible portions of the EDG recirculation fan trains, recirculation fan 480V motor control center breakers, and the recirculation fan alarm and control panels (including an internal visual inspection of the four recirculation fan relay cabinets). The inspectors performed these walkdowns to independently assess the material condition, operating environment, potential operator challenges, maintenance practices, and configuration control. The inspectors also reviewed temperature switch and flow control switch calibration results, fan train corrective and preventive maintenance records, operating logs, fan control logic diagrams, engineering evaluations, laboratory analysis reports, related industry operating experience (OE), and EDG room temperature trend data to assess the adequacy of PSEG's corrective actions and to ensure TS compliance. The inspectors also discussed recirculation fan performance and operational alignments with the system engineer, senior reactor operators, and equipment operators to review the design and system functional requirements, as well as obtain historical performance and trend data.

The inspectors reviewed a sample of EDG recirculation fan problems that PSEG identified and entered into the CAP since October 2007. The inspectors reviewed these issues to verify an appropriate threshold for identifying issues and to evaluate the effectiveness of corrective actions. In addition, the inspectors reviewed corrective action notifications written on issues identified during the inspection to verify adequate problem identification and incorporation of the problem into the CAP. Documents reviewed are listed in the Attachment.

b. Findinqs and Observations No findings were identified. The inspectors concluded that, in general, PSEG had taken timely and appropriate action in accordance with the Hope Creek TSs, operating and alarm response procedures, and PSEG's CAP. The inspectors determined that PSEG's associated ACEs were sufficiently thorough and based on the best available information, controlled troubleshooting, testing (including independent laboratory analysis), sound engineering judgment, and relevant industry OE. PSEG's assigned corrective actions were aligned with the identified casual factors, adequately tracked, appropriately documented, and completed as scheduled.

However, during an internal visual inspection of the associated safety-related EDG recirculation fan alarm and relay cabinets (A-E C483), the inspectors noted several minor configuration control and housekeeping issues. Specifically, the inspectors noted no 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, some debris, and missing and/or displaced air filter/debris screens in two cabinets. PSEG promptly initiated corrective action notifications (205230 1 2, 20523532, 20523533, 20523534, and 20523535) for these issues. ln accordance with the guidance in Inspection Manual Chapter (lMC) 0612, Appendix B "lssue Screening" and Appendix E, "Examples of Minor lssues." the inspectors determined none of the performance deficiencies identified during the cabinet inspections were more than minor because, based upon the material conditions observed by the inspectors, the operability of the associated equipment was not affected by the minor configuration control and housekeeping issues.

.3 Annual Sample: Technical Riqor of Vendor Enoineerinq Evaluations

a. Inspection Scope

This inspection focused on PSEGs'problem identification, evaluation, and resolution associated with technical rigor of vendor produced engineering evaluations. The inspectors reviewed a PSEG Nuclear Oversight (NOS) performance review from October 2010 to January 2011 that identified a declining trend in engineering technical rigor and notification 20494454, NOS Evaluation Hope Creek Engineering Technical Rigor, documented this deficiency. The inspectors reviewed NOS Elevation Notice NOHl 1-002, dated January 26, 2011, that specifically addressed this issue as a condition adverse to quality. The inspectors reviewed the ACE and a sample of corrective actions to evaluate the effectiveness of corrective actions and to ensure that they addressed the cause of this declining trend in vendor produced engineering evaluations. The following corrective actions were reviewed: conduct a needs analysis for knowledge gaps in the implementation of error prevention tools with regard to engineering technical products, improve Fundamentals Management System (FMS)tasks list to include other engineering products associated with technical rigor, establish an engineering technical rigor prevention of events triangle and establish the thresholds and criteria, and implement the owner's acceptance review of external technical product review checklist.

The inspectors reviewed several Design Change Packages (DCPs) to assess engineering rigor. Specifically, the inspectors reviewed DCP 80103378, lnstall 1E Service Water Cable Vault Dewatering System for Manholes 102, 103, and 105, and DCP 80102874, Hope Creek Reactor Feed Pump Turbine Lube Oil Single Point Vulnerability Mitigation. The inspectors reviewed a sample of corrective action notifications written on engineering rigor type deficiencies from January 2411 b September 2011. The inspectors performed a review of PSEG's FMS tool that provides feedback to PSEG engineering personnel and vendors concerning reviews of engineering documents, including engineering evaluations. The inspectors reviewed PSEG engineering internal departmental report for 2no cycle of 2011. Documents reviewed are listed in the Attachment.

b. Findinqs and Observations No findings were identified. Specific examples lacking technical rigor identified by NRC inspectors were: RHR leaking heat exchanger (HX) evaluation; safety system gas accumulation evaluation; and primary containment isolation valve evaluation. All of these issues resulted in NRC identified findings.

The PSEG cause and effect analysis identified the following casual factors (CFs) for this problem: CF #1, ineffective use of error mitigation tools and techniques, and CF #2, improper technical process usage. The apparent causes were insufficient oversight and accountability and less than adequate understanding of the criteria used to determine the correct technical process. PSEG implemented 18 corrective actions to address this issue, some of which included training on an industry guidance document titled "Principles for Maintaining an Effective Technical Conscience and Focus FMS Observations on Technical Rigor." The inspectors noted that the ACE was sufficiently thorough and the corrective actions were aligned with the CFs, appropriately documented, adequately tracked, and being completed as scheduled.

The inspectors found that approximately 304 documented FMS observations of engineering technical rigor were performed by PSEG engineering supervisors between January 26,2011, and September 27,2Q11, compared to only 12 FMS observations of engineering technical rigor between September 1, 2010, and January 26,2011. The inspectors concluded that constructive comments provided appropriate feedback to the engineer that produced the engineering document. No deficiencies were identified in the DCPs reviewed and the inspectors noted that in PSEG engineering internal departmental report fot 2"o cycle of 2011, technical rigor in engineering showed an improving trend.

The inspectors concluded, therefore, that, in general, PSEG had taken timely and appropriate action in accordance with their CAP to address engineering technical rigor for vendor produced evaluations. The inspectors acknowledged that significant steps were taken by PSEG to address the issue. However, the NRC inspectors also identified two examples of inadequate engineering technical rigor related to NRC submittals.

r Incorrect information appears to have been submitted to the NRC in the license amendment for the EDG allowed outage time extension. Specifically, the submittal referenced and specified High Pressure Coolant Injection/Reactor Core lsolation Cooling final Station Blackout Operating temperatures in a non-active calculation.

The active calculation would result in increased temperatures. Notification 20518067 was written to document this deficiency.

o Discrepancies were found in the Final Feedwater Temperature Reduction safety analysis report vs. PSEG amendment request. Notification 20523860 was written to address this deficiency.

Based on these two examples, the inspectors concluded that the scope of the reviews PSEG conducted in response to notification20494454, did not encompass NRC-related documents like TS amendments or requests for additional information. However, for the two examples discussed above, the inspectors did not identify findings because, in each case, the associated licensing activity had not become a part of the current licensing and design basis and, as stated above, PSEG had entered the issues into the corrective action 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 Requirement

Not Met In 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 TS surveillance requirem ent 4.7

.1.1. b. The inspectors' review of this LER was documented

in NRC Inspection Report (lR) 0500035412010004. In Supplement 01 of this LER (0500035412010-001-01), PSEG identified that extent of condition reviews identified an additional pair of SACS HX bypass valves (EG-HV-2S17N8) had also not been adequately tested in accordance with TS surveillance requirement 4.7

.1.1. b. These

issues were entered into the CAP under notification 20470714. Corrective actions completed under Order 70111202 included testing the valves under TS surveillance requirement 4.7.1.1.b before returning them to operation and reviewing other automatic SACS and station SW valves for extent of condition. No other missed surveillances were identified. The enforcement aspects associated with the closure of this LER and Supplement 01 were discussed and documented in Section 4OA7 of lR 0500035412010004. No new issues of concern were identified by the NRC during its review of the new information provided by PSEG in this supplement. This LER is closed.

.2 (Closed) LER 05000354/2010-002-00 and LER 05000354/2010-002-01 , As-Found

Values for Safety Relief Valve Lift Setpoints Exceed Technical Specification Allowable Between November 2 and November 29,2010, PSEG received test results indicating that the as-found lift setpoints for 6 of 14 main steam SRVs failed to open within the required TS actuation pressure setpoint tolerance. TS 3.4.2.1 provides an allowable pressure band of +/-3 percent for each SRV. All six of the SRVs opened above the required 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. The apparent cause for the G SRV setpoint failure was related to misaligned internal parts caused by uneven loading in the pilot spring. These issues were placed into the CAP under notifications 20483383 and 2Q525076. The pilot assembly for each of the 14 SRVs was replaced with a fully tested spare assembly. Additionally, this LER stated a PSEG proposal to replace the SRVs is being considered through the plant modification process. Although this LER reports the inoperability of six SRVs, this event did not result in a loss of system safety function based on engineering analyses. These analyses 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 LERs are closed.

.3 (Closed) LER 05000354/2011-001-00, HPCI Operation Credit in UFSAR Scenario not

Supported by Existing Documentation Hope Creek Engineering identified a condition when the HPCI system would potentially not fulfill its safety function. The HPCI room ventilation differential temperature trip setpoint of 70'F, which is intended to isolate HPCI in the event of a steam leak, has the potential to isolate HPCI prematurely during extreme winter temperatures. This premature system isolation could impact the ability of HPCI to fulfill its design function during one of the accident scenarios listed in UFSAR Table 6.3-6, specifically the assumed single failures listed is the loss of an EDG coincident with a LOCA and a LOOP.

A PSEG engineering assessment determined that HPCI was not challenged by maximum room differential temperatures during warm ambient operating temperatures.

However, the ability of HPCI to perform its design function during assumed single failure of 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)was not fully evaluated. As a result of a July 28,2011 assessment, PSEG entered this issue into the GAP (notifications 20518124 and 20520106). The inspectors concluded that this event was classified as a safety system functional failure. The inspectors' review of this LER and the related enforcement action is documented in section 1 R15.

.4 Event Notice #47192: Notification of an Unusual Event Due to Seismic Event

Inspection Scope On August 23,2011, PSEG personnel informed the resident inspectors located in the main control room that an event notification report was planned to meet the requirements of 10 CFR 50.72(a)(1)(i), "Emergency Declared." Specifically, at 1400 hours0.0162 days <br />0.389 hours <br />0.00231 weeks <br />5.327e-4 months <br />, Hope Creek and Salem generation stations declared a common site Unusual Event in accordance with EAL 9.5.1.a due to an earthquake felt by onsite personnel within the protected area. Hope Creek continued operating at full RTP. All emergency cooling systems were available and in standby alignment. PSEG conducted multiple walkdowns 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 result of the event and use of the applicable abnormal operating procedures. The inspectors performed independent walkdowns of control room instrument panels and risk significant SSCs for indications of adverse impact or off-normal conditions. The areas walked down 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 and HXs. Documents reviewed are listed in the Attachment.

b. Findinqs No findings were identified.

.5 Hurricane lrene: Preparations and Response

a. Inspection Scope

From August 23 to August 27,2011, the inspectors reviewed PSEG's activities to prepare for the potential arrival of Hurricane lrene. PSEG personnel implemented the actions specified by procedure OP-AA-108-1 1 1-1001 , "Severe Weather and Natural Disaster Guidelines." The inspectors observed activities that included: securing or removing outside equipment to preclude windborne missiles; closure of watertight doors; just-in-time training for plant shutdown and start-up; sandbagging of selected non-safety related access points; and increased staffing of emergency response organization personnel with preparations for sequestering.

On August 27,2011, inspectors responded to the Hope Creek site due to the expected arrival 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 had staffed but not activated the Operations Support Center (OSC). PSEG considered the enforcement discretion guidance in NRC Enforcement Guidance Memorandum (EGM)09-008, "EGM - Dispositioning Violations of NRC Requirements for Work Hour Controls Before and lmmediately After a Hurricane Emergency Declaration," dated September 24,2009, and sequestered essential site personnel. The inspectors monitored plant activities in the main control room and the OSC and monitored selected plant parameters, including: actual and projected onsite weather conditions; offsite power status; key safety equipment status; intake conditions; plant equipment issues; security posture and equipment issues; and emergency planning considerations. Documents reviewed are listed in the Attachment.

b.

Findinss No findings were identified.

4OA5 Other Activities

Operation of an Independent Spent Fuel Storaqe Installation (lSFSl) at Operatinq Plants (60855.1)

The inspectors verified by direct observation and independent evaluation that PSEG had performed loading activities at the ISFSI in a safe manner and in compliance with applicable procedures. The inspectors toured the ISFSI and reviewed radiological surveys performed during the past 12 months.

4OAO Meetinqs, includinq Exit On October 13,2Q11, the inspectors presented inspection results to Mr. J. Perry, Station Vice President, and other members of his staff. The inspectors asked PSEG whether any materials examined during the inspection were proprietary. No proprietary information was identified.

4C.A7 Licensee-ldentified Violations The following violation of very low safety significance (Green) was identified by the licensee and is a violation of NRC requirements which meets the criteria of the NRC Enforcement 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 13 of the 14 SRVs open within +/-3 percent of the specified code safety valve function lift 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 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Contrary to this requirement, PSEG identified between November 2 and November 29,2010, that six of the 14 SRVs were determined to have their as-found setpoints 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 spare assembly. ln addition as discussed in Section 4OA3, PSEG determined that the apparent cause for 5 of the 6 SRV setpoint failures was corrosion bonding/sticking of the pilot disc. Therefore PSEG is also currently evaluating replacing the SRVs with a design 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 PSEG determined, through engineering analyses that, given a design bases event, postulated piping stresses would not have exceeded allowable limits with 6 of 14 SRVs inoperable and the SRVs would have functioned to prevent a reactor vessel over-pressurization. Therefore, this finding was of very low safety significance (Green) based on a Phase 1 SDP screening, because it did not represent an actual loss of system safety function, and was not potentially risk significant for external events. 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/Closed

05000354/2011004-01 FIN Inadequate Corrective Actions Associated With a Known Degraded Condition of the 00-K-107 Service Air Compressor Outlet Check Valve (H0KA-0KAV-004) (Section 1R12)

05000354/2011004-02 NCV HPCI Operability during SBLOCA/LOOP with the A EDG Failure (Section 1R15)

Closed

05000354/201 0-001 -01 LER Technical Specification Surveillance Requirement Not Met (Section 4OA3.1)

05000354/201 0-002-00 and LER As-Found Values for Safety Relief Valve Lift

05000354/2010-002-01 Setpoints Exceed Technical Specification Allowable (Section 4OA3.2)

05000354/201 1-001-00 LER HPCI Operation Credit in UFSAR Scenario not Supported by Existing Documentation (Section 4OA3.3)