IR 05000354/2012007

IR 05000354-12-007; 7/30/2012 - 8/30/2012; Hope Creek Generating Station; Component Design Bases Inspection

ML12286A120
Person / Time
Site:	Hope Creek
Issue date:	10/12/2012
From:	Doerflein L Engineering Region 1 Branch 2
To:	Joyce T Public Service Enterprise Group
References
IR-12-007
Download: ML12286A120 (35)

Text

October 12, 2012

SUBJECT:

HOPE CREEK GENERATING STATION - NRC COMPONENT DESIGN BASES TNSPECTTON REPORT 05000354/2012007

Dear Mr. Joyce:

August 30, 2012

SUBJECT:

HOPE CREEK GENERATING STATION - NRC COMPONENT DESIGN BASES I NS PECTI ON REPORT 05000354/201 2007

Dear Mr. Joyce:

On August 30,2012, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at the Hope Creek Generating Station. The enclosed inspection report documents the inspection results, which were discussed on August 30, 2012, with Mr. John Perry, Site 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.

In conducting the inspection, the team examined the adequacy of selected components to mitigate postulated transients, initiating events, and design basis accidents. The inspection involved field walkdowns, examination of selected procedures, calculations and records, and interviews with station personnel.

Based on the results of this inspection, no findings were identified.

In accordance with 10 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 the public inspection in the NRC Public Docket Room or from the Publicly Available Records component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http:/iwww.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RN Lawrence T. Doerflein, Chief Engineering Branch 2 Division of Reactor Safety Docket No. 50-354 License No. NPF-57 DOCUMENT NAME: G:\\DRS\\Engineering Branch 2\\Schoppy\\HQ CDBI 201207 -docx ADAMS ACCESSION NUMBER: ML12286A120 X suNslReview X

Non-Sensitive n

Sensitive X

Publicly Available tr Non-PubliclyAvailable OFFICE RI/DRS RI/DRP RI/DRS NAME

.JSchoppy

"ABurritULC LDoerflein DATE 10t1112 10t5t12 10t12112

• aaa ararri CIAL RECORD COPY see prevlous concurrence

Enclosure:

I nspection Report 050003541 20 1 2007 MAttachment. Supplemental lnformation

REGION I==

50-354 NPF-57 05000354/2012007 PSEG Nuclear LLC Hope Creek Generating Station P.O. Box 236 Hancocks Bridge, NJ 08038 July 30 - August 30,2012 J. Schoppy, Senior Reactor Inspector, Division of Reactor Safety (DRS),

Team Leader J. Brand, Reactor lnspector, DRS D. Kern, Senior Reactor Inspector, DRS J. Rady, Reactor Inspector, DRS O. Mazzoni, NRC Electrical Contractor T. Tinkel, NRC Mechanical Contractor Lawrence T. Doerflein, Chief Engineering Branch 2 Division of Reactor Safety Enclosure

SUMMARY OF FINDINGS

lR 0500035412012007;713012012 - 813012012: Hope Creek Generating Station; Component

Design Bases Inspection.

The report covers the Component Design Bases Inspection conducted by a team of four U.S. Nuclear Regulatory Commission (NRC) inspectors and two NRC contractors. 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.

No findings were identified.

REPORT DETAILS

1. REACTOR SAFEW

Cornerstones: lnitiating Events, Mitigating Systems, and Barrier Integrity

==1R21 Component Desisn Bases lnspection (lP 71 111.21)

==

.1 Inspection Sample Selection Process

The team selected risk significant components for review using information contained in the Hope Creek Probabilistic Risk Assessment (PRA) model and the U. S. Nuclear Regulatory Commission's (NRC) Standardized Plant Analysis Risk (SPAR) model for the Hope Creek Generating Station (HCGS). Additionally, the team referenced the Risk-lnformed Inspection Notebook for the Hope Creek Generating Station (Revision 2.1a) in the selection of potential components for review. In general, the selection process focused on components that had a Risk Achievement Worth (RAW) factor greater than 1.3 or a Risk Reduction Worth (RRW) factor greater than 1.005. The components selected were associated with both safety-related and non-safety related systems, and included a variety of components such as pumps, breakers, strainers, diesel engines, relays, motors, and valves.

The team initially compiled a list of components based on the risk factors previously mentioned. Additionally, the team reviewed the previous component design bases inspection (CDBI) reports (0500035412009007 and 05000354/20006015) and excluded the majority of those components previously inspected. The team then performed a margin assessment to narrow the focus of the inspection to 16 components and 4 operating experience (OE) items. The team selected a torus vent valve for large early release fraction (LERF) implications. The team's evaluation of possible low design margin included consideration of original design issues, margin reductions due to modifications, or margin reductions identified as a result of material condition/equipment reliability issues. The assessment also included items such as failed performance test results, corrective action history, repeated maintenance, Maintenance Rule (aX1) status, operability reviews for degraded conditions, NRC resident inspector insights, system health reports, and industry OE. Finally, consideration was also given to the uniqueness and complexity of the design and the available defense-in-depth margins.

The inspection performed by the team was conducted as outlined in NRC Inspection Procedure (lP) 71 111.21. This inspection effort included walkdowns of selected components; interviews with operators, system engineers, and design engineers; and reviews of associated design documents and calculations to assess the adequacy of the components to meet design basis, licensing basis, and risk-informed beyond design basis requirements. Summaries of the reviews performed for each component and OE sample are discussed in the subsequent sections of this report. Documents reviewed for this inspection are listed in the Attachment.

.2.1.1 B Residual Heat Removal Svstem Suction Strainer

a. Inspection Scope

The team reviewed applicable portions of the Updated Final Safety Analysis Report (UFSAR), the configuration baseline document (CBD), and drawings to identify system and component design requirements for the residual heat removal (RHR) system, the B RHR suction strainer, and the B RHR pump. The team reviewed procurement design specifications and drawings for the strainer to identify detailed characteristics that affect flow during normal and design basis accident (DBA) conditions. The team reviewed calculations and vendor test reports to verify that the strainer was capable of required flow without exceeding established head loss limits for both debris free and debris loaded conditions. The team also reviewed calculations to verify that adequate net positive suction head (NPSH) was available for the B RHR pump for worst case flow and suppression pool conditions and that unacceptable vortexing or air entrainment would not occur.

The team reviewed applicable emergency operating procedures (EOPs) to identify system operating parameters during periods of degraded emergency core cooling system (ECCS) performance. The team reviewed in-service test (lST) surveillance procedures for the RHR system to verify that design basis head/flow requirements were correctly translated into the procedures. The team interviewed the RHR system engineer to discuss details of the ECCS suction strainer modification for the currently installed RHR strainers. The team reviewed the corrective action program (CAP)database, system health reports, and margin management reports to identify applicable failures, adverse trends, or abnormal performance and to ensure any such issues were being properly addressed.

b.

Findinos No findings were identified.

.2.1.2 125Vdc Switchsear 10D440. Distribution Panel 10DD417 and Fuse Box

a. Inspection Scope

The team reviewed bus loading calculations to verify that the 125Vdc switchgear had sutficient capacity to support its required loads under worst case accident loading conditions. The team reviewed cable sizing calculations to ensure that cables were adequately sized for load and service conditions. The team reviewed 125Vdc short circuit calculations to verify that protective devices were applied within their ratings and appropriate fault values were used in protective relaying calculations. The team reviewed breaker coordination studies to determine whether equipment was protected and protective devices featured selective coordination. The team reviewed maintenance procedures and schedules for the 125Vdc switchgear to ensure that equipment was being properly maintained. The team reviewed preventive maintenance (PM) and corrective action documents to determine if there were any adverse operating trends. In addition, the team performed a visual inspection of the 125Ydc switchgear, distribution panel, and fuse box to assess the material condition of the equipment.

b.

Findinqs No findings were identified.

.2.1.3 Safetv Auxiliaries Coolinq Svstem and Reactor Auxiliaries Coolinq Svstem Service

Water lsolation Valve (EAHV-2204)

a. Inspection Scope

The team inspected safety auxiliaries cooling system (SACS) and reactor auxiliaries cooling system (RACS) service water (SW) isolation valve EAHV-2204 to verify that it was capable of performing its design function. Motor-operated valve (MOV) EAHV-2204 is designed to isolate SW to the non-safety related RACS heat exchangers (HXs)following an accident or RACS room flooding in order to ensure an adequate SW supply to the safety-related SACS HXs. The team reviewed the UFSAR, calculations, and procedures to identify the design basis requirements of the valve. The team also reviewed accident system alignments, valve testing procedures, and valve specifications to verify that component operation and capability was consistent with the design and licensing bases assumptions. The team reviewed periodic diagnostic test results and stroke test documentation to verify that acceptance criteria were met and consistent with the design basis. Additionally, the team verified the valve safety function was maintained in accordance with Generic Letter (GL) 89-10 guidance by reviewing torque switch settings, performance capability, and design margins. The team reviewed degraded voltage conditions and voltage drop calculations to confirm that the MOV would have sufficient voltage and power available to perform its safety function at the worst case degraded voltage conditions.

The team interviewed the MOV program engineer to gain an understanding of maintenance issues and overall reliability of the valve. The team conducted a walkdown to assess the material condition of the valve, and to verify the installed valve configuration was consistent with design basis assumptions and plant drawings. The team also reviewed corrective action documents to verify that PSEG appropriately identified and resolved deficiencies and properly maintained the valve.

In addition, the team evaluated operator actions to recognize and mitigate a SW pipe break in the RACS room located in the reactor building. Specifically, operator critical tasks included:

o Recognize condition

. Direct response in accordance with alarm response procedure r Determine cause

. Confirm flooding o lsolate source The team conducted a step-by-step walkthrough of time-critical flood mitigation strategies with a plant equipment operator. In addition, the team independently walked down accessible portions of the reactor building to assess the material condition of the associated structures, systems and components (SSCs) with particular focus on potential high volume internal flood sources. The team independently assessed procedure quality, flood barrier material condition, and the operators' ability to perform the required actions to locally isolate the postulated rupture. The team reviewed corrective action notifications (NOTFs), maintenance history, internalflood analyses, and inspection results and performed independent in-field observations to assess potential internalflood vulnerabilities and to ensure that PSEG maintained appropriate configuration control of critical design features.

b.

Findinqs No findings were identified.

.2.1.4 D 4.16kV Vital Bus Offsite Power ln-feed Breakers

a. Inspection Scope

The team inspected the Class 1E 4.16kV breakers supplying offsite power to the D vital bus to verify their ability to meet the design basis requirements in response to transient and accident events, including automatic bus transfers included in the design to ensure continuity of power to the Class 1E equipment connected to the bus. The team reviewed electrical drawings, component calculations, and system calculations to verify that calculation inputs and assumptions were accurate and justified, The team evaluated the voltage and load capability of the 4.16kV breakers, by review of the plant wide system calculations, to verify that the minimum acceptable voltage was adequately calculated. The team verified that the breakers were properly designed to carry their assigned full load current under normal conditions and during DBA events. The team verified that breaker and bus protective relays were properly set to protect the connected loads against abnormal fault conditions, and that spurious tripping would not take place. The team verified that the protective relay setpoints were properly translated into system procedures and tests. The team reviewed the applicable sections of the Hope Creek UFSAR and Technical Specifications (TSs) to verify that PSEG operated and maintained the breakers and protective features as designed. The team conducted several detailed walkdowns to visually inspect the physical/material condition of the switchgear and its support systems, to check the adequacy of environmental conditions, to assess potential seismic issues, and to ensure adequate configuration control. The team also reviewed the maintenance and operating history of the 4.16kV breakers, associated corrective action NOTFs, the system health report, and surveillance test results to determine if there were any adverse operating trends and to ensure that PSEG adequately identified and addressed any adverse conditions.

b, Findinqs No findings were identified.

.2.1.5 Hiqh Pressure Coolant Iniection Svstem Iniection Valve (BJ-HV-F006)

a. Inspection Scope

The team reviewed applicable portions of the UFSAR, the CBD, and drawings to identify the design basis requirements for the high pressure coolant injection (HPCI) system and the injection valve; a flex-wedge gate MOV. The team reviewed vendor manuals to identify design conditions for the valve and actuator and identify any vendor recommendations for lubrication. The team reviewed design characteristics for the valve to determine the potentialfor pressure locking and thermal binding. The team reviewed calculations for valve stem thrust, motor operator actuator characteristics, and weak link analysis to determine whether the actuator and valve were capable of operation under worst-case line pressure and differential pressure (D/P) conditions. The team reviewed system operating procedures and EOPs to identify required valve positions during operation and accident conditions. The team reviewed IST surveillance procedures and test results to determine whether design basis stroke times were enveloped by test acceptance criteria.

The team interviewed the PSEG MOV engineer and a MOV technical specialist to review PSEG's MOV program including diagnostic testing, aging management, and MOV lubrication practices. The team interviewed the system engineer to discuss system configurations for conducting surveillance testing and to verify valve design temperature enveloped expected system temperatures during normal and accident conditions. The team reviewed corrective action NOTFs, system health reports, and margin management reports to identify applicable failures, adverse trends, or abnormal performance and to ensure any such issues were being properly addressed. The team also reviewed corrective action NOTFs and work order history to identify whether issues such as thermal binding were properly evaluated to prevent recurrence. The team performed a walkdown of the valve and adjacent area to assess the material condition, operating environment, and configuration control.

b.

Findinos No findings were identified.

.2.1.6 D 4kV Bus (104404) Loss of Voltaoe Relavs (127A)

a.

lnspection Scope The team reviewed the design of the 4kV bus under-voltage (UV) protection scheme to determine whether it would cause the bus transfer to the alternate offsite power supply or automatic separation of the bus from the offsite power supply during accident loading concurrent with loss-of-grid voltage as designed. This included review of UV relay setpoint calculations, motor starting and running voltage calculations, and motor control center (MCC) control circuit voltage drop calculations. The team reviewed UV relay test procedures and results to determine whether the relays were performing as required by the design bases and Technical Specifications (TSs). The team reviewed protective relaying schemes and calculations to determine whether equipment such as motors and cables were adequately protected, and to determine whether protective devices featured proper selective tripping coordination. The team reviewed maintenance procedures to determine whether equipment was being properly maintained. The team reviewed corrective action documents and maintenance records to determine whether there were any adverse operating trends. Finally, the team performed a visual inspection of the 4kV safety buses to assess material condition and the presence of hazards.

b.

Findinss No findings were identified.

.2.1.7 Torus Vent Valve l GSHV-1 154'1

a.

lnspection Scope The team inspected torus vent valve lGSHV-11541to verify that the valve was capable of supporting the functional requirement to provide controlled containment pressure relief via the torus hardened vent path as credited in the HCGS PRA. This pressure relief path is commonly referred to as the hard torus vent (HTV). Instrument air is the normal supply to actuate lGSHV-11541, but it is not seismically qualified. A seismically qualified nitrogen gas supply and a local manual operating station are installed to provide operators with two methods to operate the HTV if instrument air is not available following a seismic event. The team reviewed the UFSAR, drawings, and procedures to identify the functional requirements of the valve. The team reviewed design calculations, including the backup nitrogen gas actuator supply volume, seismic qualifications, and system operating parameters to verify that the design basis had been appropriately translated into specifications and procedures. The team reviewed PRA modeling of the HTV function with the PRA engineer to verify that the backup nitrogen supply and manual operator capabilities were properly addressed.

The team reviewed EOPs which direct operation of the HTV, reviewed operator training lesson plans, and performed a field walkdown with an operator to assess the material condition of lGSHV-11541and to verify that procedures and operator knowledge were sufficient to successfully operate the HTV. The walkdown included verification of local b.

manual operation of lGSHV-11541. The team also reviewed performance centered maintenance (PCM) templates, vendor manuals, maintenance work orders, PM documents, and selected corrective action documents from the last three years to evaluate whether appropriate corrective and preventive maintenance was performed.

The team performed additional independent walkdowns of the accessible portions of the torus vent path (from the torus to the external vent discharge) to assess the material condition, structural supports, potential hazards, and configuration control.

Findinqs No findings were identified.

1E 480V Motor Control Center 108222 lnspection Scope The team inspected the Class 1E MCC 109.222 to verify its ability to meet the design basis requirements in response to transient and accident events to ensure continuity of power to the Class 1E equipment connected to the MCC. The team reviewed electrical drawings, component calculations, and system calculations to verify that calculation inputs and assumptions were accurate and justified. The team evaluated the voltage and load capability of MCC 108222, by review of the plant wide system calculations, to verify that the minimum acceptable voltage was adequately calculated and translated into proper setting for the degraded grid protection relays. The team verified that the MCC breakers were properly designed to carry their assigned full load current under normal conditions and during DBA events. The team verified that breaker control system would provide adequate voltage to all connected loads, and that circuit protection was properly selected to protect the connected loads against abnormal fault conditions, and that spurious tripping would not take place. The team verified that protective setpoints were properly translated into system procedures and tests. The team conducted several detailed walkdowns to visually inspect the physical/material condition of the switchgear and its support systems, to check the adequacy of environmental conditions, to identify potential seismic ll/l issues, and to ensure adequate configuration control. The team also reviewed the maintenance and operating history of the MCC breakers and support equipment, associated corrective action NOTFs, the system health report, and applicable breaker functional tests to determine if there were any adverse operating trends and to ensure that PSEG adequately identified and addressed any adverse conditions.

Findinqs No findings were identified.

2.1.8 a.

.2.1.9 a.

I B Residual Heat Removal Minimum Flow ControlValve (BC-HV-F007B)

Inspection Scope The team inspected the B RHR pump minimum flow control MOV (BC-HV-F0078) to verify that it was capable of performing its design function. The valve is normally open to ensure pump minimum flow requirements are met at low flow conditions and also has a safety function to automatically close at higher flows to protect the B RHR pump from reaching run-out conditions. The team reviewed the UFSAR, calculations, and procedures to identify the design basis requirements of the valve. The team also reviewed accident system alignments, valve testing procedures, and valve specifications to verify that component operation and capability was consistent with the design and licensing bases assumptions. The team reviewed periodic diagnostic test results and stroke test documentation to verify that acceptance criteria were met and consistent with the design basis. Additionally, the team verified the valve safety function was maintained in accordance with GL 89-10 guidance by reviewing torque switch settings, performance capability, and design margins. The team also reviewed degraded voltage conditions and voltage drop calculations to confirm that the MOV would have sufficient voltage and power available to perform its safety function at the worst case degraded voltage conditions.

The team interviewed the MOV program engineer to gain an understanding of maintenance issues and overall reliability of the valve. The team conducted a walkdown to assess the material condition of the valve, and to verify that the installed valve configuration was consistent with design basis assumptions and plant drawings. The team also reviewed corrective action documents to verify that PSEG appropriately identified and resolved deficiencies and properly maintained the valve. In addition, the team performed a review of the valve interlock design and testing to ensure that the valve and other associated RHR system components would function as designed under the most limiting design basis conditions, including a single failure of a valve or power supply.

Findinos No findings were identified.

.2.1.1 0 Portable Batterv Charoer Power Supplv (Baldor Generator)

Inspection Scope The HCGS PRA model credits the Baldor portable generator during a long-term loss of AC power event. PSEG developed procedure HC.OP-AM.TSC-0004, "Alternate Power Supply to 1E 1251250vdc," to align the portable generator to provide 480Vac power to welding receptacles in the emergency diesel generator (EDG)/control building to provide AC power to the 1251250Vdc battery chargers. The team reviewed equipment sizing calculations to verify that the portable battery charger power supply had sufficient capacity to support its required loads under worst case accident loading. The team b.

reviewed cable sizing calculations to ensure that cables were adequately sized for load and service conditions. The team interviewed operations personnel and reviewed procedure HC.OP-AM.TSC-0004 to ensure that the portable battery charger power supply could supply adequate 480Vac power to the 1251250Vdc battery chargers. The team performed a walkdown of the procedure with PSEG technicians and evaluated the available time margins to perform the actions. The team also walked down the associated portable battery charger power supply storage area, the safety-related battery and battery charger rooms, and the associated welding receptacles in the EDG/control building to assess the material condition of the SSCs within those areas.

The team reviewed corrective action documents and PM procedures to verify that issues identified were properly evaluated and corrected.

b.

Findinss No findings were identified.

.2.1.1 1Hioh Pressure Coolant Iniection Svstem Turbine

a.

lnspection Scope The team reviewed applicable portions of the UFSAR, the CBD, and drawings to identify design basis requirements for the HPCI system and its steam turbine that drives the attached HPCI main and booster pumps. The team reviewed a PSEG calculation for suppression pool heat-up in response to a small break loss-of-coolant accident (SBLOCA) to identify the HPCI turbine mission time and maximum suppression pool water temperature during the HPCI credited DBA. The team reviewed EOPs to identify licensing basis accident scenarios requiring HPCI operation with suction on the condensate storage tank (CST) or the suppression pool. The team reviewed procurement specifications and design data sheets to identify continuous and shortterm water temperature limits for HPCI turbine lube oil cooling and other HPCI system components.

The team reviewed the vendor manual and the Electric Power Research Institute (EPRI)

Terry turbine maintenance guideline for recommendations on maximum allowed bearing oiltemperatures. The team reviewed PSEG's associated calculation to verify existing heat transfer margin in the turbine lube oil cooler. The team reviewed design basis documents, drawings, and calculations to determine whether the turbine lube oil cooling system was capable of maintaining acceptable bearing oil temperatures during worst-case normal and accident conditions.

The team reviewed HPCI operating procedures to verify instructions for checking turbine oil levels and oiltemperatures. The team reviewed IST surveillance procedures to ensure the HPCI system was capable of meeting specified test requirements. The team reviewed work orders to verify that components essential to turbine operation such as the exhaust system vacuum breakers were tested to ensure proper operation. The team interviewed the system engineer to discuss system performance and details of the last complete overhaul of the turbine. The team reviewed corrective action NOTFS, system health reports, and margin management reports to identify applicable failures, adverse trends, or abnormal performance and to ensure any such issues were being properly addressed. The team performed several walkdowns of the turbine and associated HPCI pump room to assess the material condition, operating environment, and configuration control.

b.

Findinss No findings were identified.

.2.1.1 2 D Emeroencv Diesel Generator (Electrical)

a. Inspection Scope

The team inspected the D EDG to verify its ability to meet the design basis requirements in response to transient and accident events to ensure continuity of power to the Class 1E equipment connected to the EDG. The team reviewed electrical drawings, component calculations, and system calculations to verify that calculation inputs and assumptions were accurate and justified. The team evaluated the voltage and load capability of D EDG, by review of the EDG loading calculations, to verify that the EDG had sufficient margin to start and supply its assigned loads. The team verified that the relaying protection was properly selected and set to protect the connected loads against abnormal fault conditions, and that spurious tripping would not take place. The team verified that protective setpoints were properly translated into system procedures and tests. The team reviewed the maintenance and operating history of the D EDG and its support equipment, associated corrective action NOTFs, the system health report, and surveillance test results to determine if there were any adverse operating trends and to ensure that PSEG adequately identified and addressed any adverse conditions. The team conducted several detailed walkdowns to visually inspect the physical/material condition of the D EDG and its support systems, to check the adequacy of environmental conditions, to identify potential seismic issues, and to ensure adequate configuration control.

b.

Findinqs No findings were identified.

.2.1.1 3 D Emerqencv Diesel Generator (Mechanical)

a. Inspection Scope

The team inspected the D EDG to verify it was capable of meeting its design basis requirements. The design function of the D EDG is to provide standby power to the D channel safety-related loads (4.16 kV, 480 V, and 2081120 V) upon loss of both the normal and alternate offsite power supplies. The team reviewed selected sections of the UFSAR, EDG system design calculations, and recent plant modifications to verify that the EDG design assumptions and operating requirements were properly identified, evaluated, and maintained. The team also reviewed implementation of TS Amendment No. 188, which extended the EDG allowed outage time to 14 days under certain conditions. This TS amendment became effective on May 5, 2011. The team performed interviews and reviewed procedures, training, and selected operator logs to determine whether operators had properly assessed Salem Unit 3 gas turbine generator availability when determining on-line maintenance risk and TS limiting condition of operation applicability for periods when any of the four HCGS EDGs were inoperable.

The team reviewed vendor manuals, corrective and preventive maintenance records, completed surveillance test records, lube oil analysis documents, and operator logs to determine whether EDG operational performance was properly monitored and whether EDG maintenance was performed consistent with manufacturer recommendations and industry OE. Activities reviewed included the last three 24-month maintenance overhauls, the last 24-month operability run, and the last three monthly TS operability tests for the D EDG. The team also reviewed historical weather records for the last five years to verify ambient temperature limits for EDG operability, as stated in the UFSAR, had not been exceeded.

The team interviewed the EDG system engineer and plant operators; reviewed PCM templates, the most recent EDG system health report, and applicable corrective action documents; and performed several walkdowns of the D EDG and associated support equipment to assess material condition, potential vulnerability to hazards such as flooding, configuration control, and PSEG's use of the CAP to identify, evaluate, and correct conditions adverse to quality. During EDG walkdowns, the team also assessed the functionality of essential support equipment and EDG standby readiness including jacket water and lube oil keep warm temperatures, fuel oil system integrity and storage volumes, air start system integrity and air receiver pressures, and EDG room ventilation system and room temperatures.

b.

Findinos No findings were identified.

.2.1.1 4Automatic Depressurization Svstem Looic

a. Inspection Scope

The team reviewed the automatic depressurization system (ADS) logic to verify that it was capable of meeting its design basis and TS requirements. The team reviewed applicable portions of the UFSAR, the CBD, and drawings to identify the design basis requirements for the ADS logic. The team also reviewed schematic diagrams and calculations for ADS initiation to ensure that the ADS valves would actuate based on the correct input conditions. The team reviewed completed surveillance tests to ensure that the ADS logic and valve circuits would respond appropriately during accident or transient conditions. The team reviewed the CAP database and system health reports to determine if there were any adverse operating trends. The team reviewed completed maintenance and calibration records to verify that the associated reactor pressure and level instrumentation were being properly maintained. The team also conducted several control room walkdowns to visually inspect the material condition of the ADS valve instrumentation and indication, and to ensure adequate configuration control.

Additionally, the team reviewed corrective action documents to verify that PSEG appropriately identified and resolved any ADS related deficiencies.

b.

Findinqs No findings were identified.

.2.1.1 5 D Station Service Water Svstem Pump

a. Inspection Scope

The team reviewed applicable portions of the UFSAR, the CBD, drawings, and the vendor manual to identify design basis requirements for the SW system and design characteristics for the D SW pump; a single-stage centrifugal deep well pump. The team evaluated vendor pump curves for the originally installed pumps to determine whether use of these curves was appropriate for the installed replacement pump. The team reviewed calculations for pump flows during normal operation and accident scenarios to verify that adequate NPSH was available for worst case flow with minimum river water level and maximum river water temperature. The team reviewed system operating procedures to determine whether design basis conditions were reflected in procedures. The team reviewed SW pump IST surveillance procedures to verify that specified acceptance limits for D/P head were consistent with design basis requirements for system head/flow. The team reviewed surveillance test results to ensure that SW pump performance was consistent with the IST acceptance criteria. The team also reviewed IST engineer trend data for pump D/P to verify that SW pump performance was being monitored for signs of possible degradation.

The team interviewed the SW system engineer and discussed system performance, operating history, and SW pump replacement activities. The team reviewed the work order history for the most recent D SW pump replacement to identify and evaluate the installation of new wear rings purchased under a non-safety grade procurement process. The team reviewed PSEG's internal response to NRC Information Notice (lN)2007-05, "Vertical Deep Draft Pump Shaft and Coupling Failures," to determine whether PSEG's actions were appropriate. System health reports were reviewed to identify instances of Maintenance Rule (aX1) status and margin management reports were reviewed to identify failures or abnormal performance of the pump. The team reviewed corrective action NOTFS, system health reports, and margin management reports to identify applicable failures, adverse trends, or abnormal performance and to ensure any such issues were being properly addressed. The team performed severalwalkdowns of the D SW pump and the SW intake structure to assess the material condition, operating environment, and configuration control.

b.

Findinss No findings were identified.

2.1.16 B Residual Heat Removal Pump Motor

a. Inspection Scope

The team inspected the B RHR pump motor to verify its ability to meet the design basis requirements in response to transient and accident events to ensure continuity of service under normal and DBA conditions. The team reviewed electrical drawings, component calculations, and system calculations to verify that calculation inputs and assumptions were accurate and justified. The team evaluated the voltage and load capability of the B RHR pump motor to verify that the motor had sufficient margin to power the B RHR pump during normal and accident conditions, including degraded voltage. The team verified that the 1

.15 percent motor service factor and design

environmental conditions were appropriately accounted for in the motor rating and protection, and that the protection was properly selected, set to protect the motor against abnormal fault conditions, and set to preclude spurious tripping. The team verified that protective setpoints were properly translated into system procedures and tests. The team verified that the D RHR motor replacement, completed in April 2009, was adequately performed and that the replacement motor was equivalent to the original motor (form, fit, and function). The team reviewed the motor cable sizing calculations to ensure that they adequately considered the maximum loading, voltage drop, and short circuit conditions. The team reviewed the maintenance and operating history of the B RHR pump motor, associated corrective action NOTFs, the system health report, and RHR surveillance test results to determine if there were any adverse operating trends and to ensure that PSEG adequately identified and addressed any adverse conditions. The team walked down the B RHR pump motor and support equipment to visually inspect the physical/material condition, to check the adequacy of environmental conditions, to identify potential seismic issues, and to ensure adequate configuration control.

b.

Findinss No findings were identified.

.2.2 Review of Industry Operatinq Experience and Generic lssues (4 samples)

The team reviewed selected OE issues for applicability at the Hope Creek Generating Station. The team performed a detailed review of the OE issues listed below to verify that PSEG had appropriately assessed potential applicability to site equipment and initiated corrective actions when necessary.

.2.2.1 NRC Information Notice 2007-01: Recent Operatinq Experience Concerninq Hvdrostatic

Barriers

a. Inspection Scope

NRC lN 2007-0l discussed potential problems pertaining to water leaking into areas containing safety-related equipment due to deficient hydrostatic barriers. These deficient barriers were degraded, missing, and/or composed of non-watertight materials such as fire stop (e.9., silicone foam). The team evaluated internal and externalflood protection measures for the EDG rooms, auxiliary building, reactor building, and SW intake structure to assess potential flood vulnerabilities. The team walked down the areas to assess operational readiness of various features in place to protect redundant safety-related components and vital electric power systems from flooding. These features included equipment drains, door seals, backflow check valves, flood detection and alarms, flood barriers, and wall and floor penetration seals.

The team also reviewed engineering evaluations, calculations, alarm response procedures, preventive and corrective maintenance history, operator training, and corrective action NOTFs associated with flood protection equipment and measures.

Finally, the team interviewed PSEG personnel regarding their knowledge of indications, procedures, and required actions associated with several postulated internal and external flood scenarios.

b.

Findinos No findings were identified.

.2.2.2 Operatinq Experience Smart Sample FY 2008-01 - Neoative Trend and Recurrinq

Events Involvinq Emeroencv Diesel Generators a.

lnspection Scope NRC Operating Experience Smart Sample (OpESS) FY 2008-01 is directly related to NRC lN 2007-27, "Recurring Events Involving Emergency Diesel Generator Operability."

The team reviewed PSEG's evaluation of lN 2007-27 and their associated corrective actions. The team also reviewed PSEG's evaluation of NRC lN 2009-14, "Painting Activities and Cleaning Agents Render EDGs and Other Plant Equipment Inoperable" and PSEG evaluation 70111708 regarding EDG long{erm reliability. The team independently walked down the four EDGs on several occasions to inspect for indications of vibration-induced degradation on EDG piping and tubing and for any type of leakage (air, fuel oil, lube oil, jacket water). The team also reviewed PSEG's EDG system health reports, EDG corrective action NOTFs and work orders, leakage database, and surveillance test results to verify that PSEG appropriately dispositioned EDG deficiencies. The team also directly observed portions of the A EDG monthly surveillance on July 30 and the B EDG monthly surveillance on August 13 and performed pre and post-run walkdowns to ensure PSEG maintained appropriate configuration control and identified deficiencies at a low threshold. Additionally, the team reviewed maintenance records of the biennial maintenance work performed on the D EDG in July 2012 to assess the material condition of the EDG and its support systems.

b, Findinqs No findings were identified.

.2.2.3 Operatinq Experience Smart Sample FY 2010-01 - Recent lnspection Experience for

Components Installed Bevond Vendor Recommended Service Life

a. Inspection Scope

NRC OpESS FY 2010-01 is directly related to NRC lN 2012-06, "lneffective Use of Vendor Technical Recommendations." The team reviewed PSEG's evaluation of lN 2012-06, and their associated corrective actions to assess whether PSEG was aware of and had properly implemented industry and vendor recommendations for selected safety-related components. For cases where PSEG deviated from the recommended maintenance practices, the team reviewed the associated technical evaluation to determine whether the basis for PSEG's maintenance practices was reasonable.

Components selected for this review included seven mechanical expansion joints in the SW, core spray, and EDG systems and medium voltage power cables which transit underground cable vaults for the four SW pumps' ln 2Q10 and 2011, age-related electrolytic capacitor failures caused events at several nuclear power plants. The team independently reviewed PCM templates for safety-related EDG voltage regulator (VR) cabinets and 120 volt vital inverters containing electrolytic capacitors, warehouse operations proced ures, shelf-life proced u res, warehouse storage procedures, vendor manuals, and various industry guidelines for maintenance and testing of electrolytic capacitors to verify that the electrolytic capacitors were properly maintained to support reliable equipment operation. Additionally, the inspectors inierviewed station personnel and performed plant walkdowns to verify that the maintenance and storage of components containing electrolytic capacitors was appropriate. The team reviewed EDG VR control chassis age and replacement plans, EDG room temperatures, and EDG VR operating performance to assess longterm reliability and potential challenges to this essential support equipment' b.

Findinqs No findings were identified.

.2.2.4 NRC Information Notice 2010-09: lmportance of Understandins Circuit Breaker Control

Power Indications a.

Inspection Scooe NRC lN 2010-09 discussed potential problems pertaining to circuit breaker control power indication issues that could result in degraded circuit breaker protection and control. The team reviewed PSEG's evaluation and disposition of the lN. The team reviewed PSEG's applicable procedures for inspection and verification of circuit breaker control power indication, and the Maintenance Rule scoping criteria for circuit breaker failures and loss of control power (fuse failures). The team performed several walkdowns of safety-related buses and MCCs to assess the adequacy of the circuit breaker control power indication, the material condition of the SSCs, and PSEG's config uration control.

b.

Findinqs No findings were identified.

OTHER ACTIVITIES

4OA2 fdentification and Resolution of Problems (lP 71152)

The team reviewed a sample of problems that PSEG had previously identified and entered into the CAP. The team reviewed these issues to verify an appropriate threshold for identifying issues and to evaluate the effectiveness of corrective actions.

In addition, NOTFs written on issues identified during the inspection were reviewed to verify adequate problem identification and incorporation of the problem into the corrective action system. The specific corrective action documents that were sampled and reviewed by the team are listed in the Attachment.

b.

Findinqs No findings were identified.

40,46 Meetinos. includins Exit On August 30,2012, the team presented the inspection results to Mr. John Perry, Site Vice President, and other members of PSEG management. The team verified that no proprietary information was documented in the report.

Supplemental lnformation ATTACHMENT

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

PSEG Personnel

J. Boyer, Mechanical Design Engineering Manager

D. Bush, System Engineer

V. Chandra, Mechanical Design Engineer

E. Ciemiewicz, MOV Specialist

S. Connelly, System Engineer

J. Dower, Operations Supervisor

P. Duca, Senior Engineer, Regulatory Assurance

A. Ghose, Design Engineer Civil Structural

Y. Ghotok, System Engineer

C. Johnson, MOV Component Engineer

M. Kelly, PM engineer

K. Knaide, Engineering Director

P. Koppel, Preventive Maintenance Program Coordinator

E. Maloney, Principal Nuclear Engineer (lSl)

C. Matos, Risk Engineer

M. Moore, Senior Reactor Operator

J. Perry, Hope Creek Site Vice President

L. Powell, Technical Analyst Design Engineering

V. Rubinetti, Design Engineer Civil Structural

D. Schiller, Design Engineer Electrical

C. Serata, Manager, Operations Support

G. Stith, Design Engineering Manager

M. Wharton, Electrical Engineer

K. Wichman, System Engineer

M. Zimmerman, Design Engineer Civil Structural

LIST OF ITEMS

OPENED, CLOSED AND DISCUSSED

Open and

Closed

None