UNITED STATESNUCLEAR REGULATORY COMMISSION

REGION I

475 ALLENDALE ROADK|NG OF PRUSS|A. PA 19406-1415

April 4, 20lI

Mr. Thomas JoycePresident and Chief Nuclear OtficerPSEG Nuclear LLC - N09P.O. Box 236Hancock's Bridge, NJ 08038

SUBJECT: SALEM NUCLEAR GENERATING STATION, UNIT NOS. 1 AND 2 .NRC COMPONENT DESIGN BASES INSPECTION REPORT0500027 2t20 1 1 007 AN D 0s00 03 1 I | 20 1 1 007

Dear Mr. Joyce:

On February 18, 2011, the U.S. Nuclear Regulatory Commission (NRC) completed aninspection at the Salem Nuclear Generating Station, Unit Nos. 1 and 2. The enclosedinspection report documents the inspection results, which were discussed on February 18,2011, with Mr. Edward Eilola, Plant Manager, and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety andcompliance with the Commission's rules and regulations and with the conditions of your license.In conducting the inspection, the team examined the adequacy of selected components andoperator actions to mitigate postulated transients, initiating events, and design basis accidents.The inspection involved field walkdowns, examination of selected procedurei, calculations andrecords, and interviews with station personnel.

This report documents three NRC-identified findings that were of very low safety significance(Green). These findings were determined to involve violations of NRC requirementi. However,because of the very low safety significance of the violations and because they were entered intoyour corrective action program, the NRC is treating these findings as non-cited violations (NCV)consistent with Section 2.3.2 of the NRC Enforcement Policy. lf you contest any NCV in thisreport, you should provide a response within 30 days of the date of this inspection report, withthe basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: DocumentControl Desk, Washington, D.C. 20555-0001, with copies to the Regional Administrator,Region l; the Director, Otfice of Enforcement, U.S. Nuclear Regulatory Commission,Washington, D.C. 20555-0001; and the NRC Resident Inspector at the Salem NuclearGenerating Station. ln addition, if you disagree with the cross-cutting aspect assigned to anyfinding in this report, you should provide a response within 30 days oJ tne date of lhis inspeciionreport, with the basis of your disagreement, to the Regional Administrator, Region l, and iheNRC Resident Inspector at Salem Nuclear Generating Station.

T. Joyce 2

ln accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, itsenclosure, and your response (if any) will be available electronically for the public inspection inthe NRC Public Docket Room or from the Publicly Available Records component of NRC'sdocument system (ADAMS). ADAMS is accessible from the NRC Web site athttp://www.nrc.qov/readinq-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

vO/o,-**--

Lawrence T. Doerflein, ChiefEngineering Branch 2Division of Reactor Safety

Docket Nos: 50-272;50-311License Nos: DPR-70; DPR-75

Enclosure: Inspection Report 0500027212011007 and 0500031112011007w/Attachment: Supplemental Information

cc Mencl: Distribution via ListServ

T. Joyce 2ln accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its9nd914e. and your.response (if any) will be available electronicaliy for tirl public inspection inthe NRC Public Docket Room or from the Publicly Available Records corpon"nt of NRC'sdocument system (ADAMS). ADAMS is accessible from the NRC web siie athttp://www.nrc.oov/readino-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RN

Lawrence T. Doerflein, ChiefEngineering Branch 2Division of Reactor Safety

Docket Nos: 50-272: 50-311License Nos: DPR-70: DpR-25

Enclosure: I nspection Report 0500021 2120 1 1 oo7 and 05000 31 1 t2ot 1 oo7w/Attachment: Supplemental Information

cc Mencl: Distribution via ListServ

W. Dean, RA (RIORAMAIL Resource)D. Lew, DRA (RIORAMA|L Resource)D. Roberts, DRP (RiDRPMAIL ResourceiJ. Clifford, DRP (RIDRPMA|L Resource)P. Wilson, DRS (RlDRSMail Resource)! lveeralk9dy, DRS (RlDRSMait Resource)A. Burritt, DRPL. Cline, DRPA. Turilin, DRPC. Douglas, DRPJ. Schoppy, DRSL. Doerflein, DRS

in the box: 'C' = Copy without

D. Schroeder, DRP, SRIP. McKenna, DRP, RlK. McKenzie, DRP, OAJ. Trapp, RIOEDOD. Bearde. DRSR. Powell, DRPRidsNrrPMSalem ResourceRidsNrrDorlLpll -2 ResourceROPreports Resource

l9l9!.Fyr"y qgtp!_e!9: LTe- (Reviewer's Initiars) ADAMS Acc # ML11os401e3DocUMENT NAME: G:unstengnneering Branch 2\schoirpy\satem cDBt 201 1 007.docAfter declaring this documen! "An oticiat ngeicy Record" it wilifiJ rerelseo to the pubtic.

OFFICIAL RECORD COPYU.S. NUCLEAR REGULATORY COMMISSION

Docket Nos:

License Nos:

Report No:

Licensee:

Facility:

Location:

Inspection Dates:

lnspectors:

Approved By:

REGION I

50-272,50-311

DPR-70, DPR-75

0500027 21201 1 007 and 0500031 1 1201 1007

PSEG Nuclear LLC (PSEG)

Salem Nuclear Generating Station, Unit Nos. 1 and 2

P.O. Box 236Hancocks Bridge, NJ 08038

January 24 - February 18,2011

J. Schoppy, Senior Reactor Inspector, Division of Reactor Safety (DRS),Team Leader

K. Mangan, Senior Reactor Inspector, DRSR. Montgomery, Division of Reactor Projects (Trainee)D. Orr, Senior Reactor Inspector, DRSM. Orr, Reactor lnspector, DRSC. Edwards, Mechanical ContractorG. Skinner, Electrical Contractor

Lawrence T. Doerflein, ChiefEngineering Branch 2Division of Reactor Safety

Enclosure

SUMMARY OF FINDINGS

lR 0500027212011007 and 0500031 112011007:0112412011 - 0211812011; Salem Unit Nos' 1and 2; Component Design Bases Inspection.

The report covers the Component Design Bases Inspection conducted by a team of four NRCinspectors and two NRC contractors. Three findings of very low risk significance (Green) wereidentified, all of which were considered to be non-cited violations. The significance of mostfindings is indicated by their color (Green, White, Yellow, Red) using NRC Inspection ManualChapter (lMC) 0609, "significance Determination Process" (SDP). Cross-cutting aspectsassociated with findings are determined using IMC 0310, "Components Within the Cross-Cutting Areas." Findings for which the SDP does not apply may be Green or be assigned aseverity level after NRC management review. The NRC's program for overseeing the safeoperation of commercial nuclear power reactors is described in NUREG-1649, "Reactor

Oversight Process," Revision 4, dated December 2006.

Gornerstone: Mitigating Systems

. Green: The team identified a finding of very low safety significance involving a non-citedviolation of 10 CFR 50, Appendix B, Criterion lll, "Design Control," because PSEG hadnot verified the adequacy of the design for the DVR voltage setpoint. Specifically,PSEG had not performed calculations for motor starting and running conditions, and foroperation of other safety-related equipment based on voltages afforded by the degradedvoltage relays. PSEG entered this issue into their corrective action program andperformed preliminary calculations to demonstrate reasonable assurance of operability.

The finding is more than minor because it is associated with the design control attributeof the Mitigating Systems Cornerstone and adversely affected the cornerstone objectiveof ensuring the availability, reliability, and capability of systems that respond to initiatingevents to prevent undesirable consequences. The team evaluated the finding inaccordance with IMC 0609, Attachment 0609.04, Phase 1 - Initial Screening andCharacterization of Findings, Table 4afor the Mitigating Systems Cornerstone. Theteam determined that the finding was of very low safety significance because it was adesign deficiency confirmed not to result in loss of operability.

The team determined that this finding has a cross-cutting aspect in the area of Problemldentification and Resolution, Operating Experience Component, because PSEG did notensure that relevant internal and external operating experience was collected,evaluated, and communicated to affected internal stakeholders in a timely manner.Specifically, PSEG did not adequately evaluate a similar finding documented in a HopeCreek Generating Station NRC component design bases inspection report in November2009 (NCV 050035412009007-03) and missed an opportunity in their internal responseto NRC Information Notice 2Q08-02, "Findings ldentified During Component DesignBases Inspections," issued in March 2008. (lMC 0310' Aspect P.2(a))(Section 1R21.2.1.1)

Enclosure

. Green. The team identified a finding of very low safety significance (Green) involving anon-cited violation of Salem Unit 1 Technical Specification (TS) SurveillanceRequirement (SR) 4.8.2.5.2.n Specifically, the team identified that PSEG did notperform a battery capacity test of the 1B 28VDC battery within 12 months of theprevious performance test that showed signs of degradation (battery capacity asmeasured on October 28,2008, dropped more than 10 percent compared to theApril 26, 2004, performance test). PSEG promptly entered TS 4.0.3 and completed allTS 4.0.3 requirements for a surveillance not performed within its specified frequency.Additionally PSEG entered the issue into their corrective action program to evaluate thecasual factors for long{erm corrective action and scheduled the 1B 28VDC batteryperformance test during the next scheduled Salem Unit 1 shutdown.

The finding is more than minor because it is associated with the human performanceattribute of the Mitigating Systems Cornerstone and adversely affected the cornerstoneobjective of ensuring the availability, reliability, and capability of systems that respond toinitiating events to prevent undesirable consequences. Specifically, the availability ofthe 1B 28VDC battery was not ensured by performing additional surveillance testing tomonitor for battery degradation. The team evaluated the finding in accordance withIMC 0609, Attachment 0609.04, Phase 1 - Initial Screening and Characterization ofFindings, Table 4afor the Mitigating Systems Cornerstone. The team determined thatthe finding was of very low safety significance because it was a qualification deficiencyconfirmed not to result in loss of operability.

The team determined that this finding has a cross-cutting aspect in the area of HumanPerformance, Work Practices Component, because PSEG personnel did not followprocedure requirements during the 1B 28VDC battery performance dischargesurveillance test. Specifically, personnel did not follow step 5.12.21 ofSC.MD-FT.28D-0003 which required technicians to mark the surveillance data sheet"Yes" for "Battery Degraded," notify supervision, and initiate a corrective actionnotification if the calculated battery performance capacity drop was greater than10 percent. (lMC 0310, Aspect H.4(b)) (Section 1R21.2.1.2)

Cornerstone: Barrier lntegrity

o Green. The team identified a finding of very low safety significance (Green) involving anon-cited violation of 10 CFR 50, Appendix B, Criterion XVl, "Corrective Action,"because PSEG did not identify and correct a condition adverse to quality. Specifically,PSEG did not identify and correct the degraded condition of the Unit 1 and Unit 2 controlroom emergency air conditioning system (CREACS) common suction expansion joints

because they did not implement appropriate preventive maintenance (PM) per theirperformance-centered maintenance (PCM) template. PSEG placed the finding and theassociated issues in its corrective action program. In response to the identified controlroom envelope (CRE) breach, operators promptly entered TS 3.7.6 and initiatedmitigation actions. PSEG affected prompt repairs, performed an appropriate postmaintenance test, declared the CRE fully operable, and exited the TS limiting conditionfor operation action statement.

Enclosure

The finding is more than minor because it is associated with the barrier performanceattribute of the Barrier Integrity Cornerstone and adversely affected the cornerstoneobjective of providing reasonable assurance that physical design barriers protect thecontrol room operators from radionuclide releases caused by accidents or events. Thefinding was evaluated in accordance with IMC 0609, Attachment 4, Table 4a for thecontainment barrier. Since the finding had the potential to impact more than theradiological barrier function, a Region 1 Senior Reactor Analyst (SRA) performed aPhase 3 analysis. The SRA determined that the dominant sequence involved asufficient degradation of the CREACS barrier that would allow sufficient in-leakage toforce an evacuation of the control room during a fire or toxic gas event. The areas withthe degradation were in room 15615 and 25615 for Units 1 and 2, respectively. TheSRA evaluated these areas and determined that the potential impact due to in-leakagethrough the degraded barrier from fire and toxic gas would be negligible. The SRA alsoreviewed the results of recent CRE in-leakage testing conducted in September 2010.The condition of the expansion joint tearing and wear could reasonably be assumed tohave existed during the September testing. This testing also confirmed that the total in-leakage in these areas was small. Based on the above factors, the SRA determinedthe finding was of very low safety significance (Green).

The team determined that this finding has a cross-cutting aspect in the area of HumanPerformance, Work Control Component, because PSEG did not plan work activities tosupport long-term equipment reliability by ensuring that maintenance scheduling wasmore preventive than reactive. Specifically, PSEG did not implement appropriate PMson the CREACS filter expansion joints necessitating several reactive correctivemaintenance activities. (lMC 0310, Aspect H.3(b)) (Section 1R21 .2.1 .3)

Other Findinqs

None

IV

Enclosure

REPORT DETAILS

1. REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R21 Component Desiqn Bases Inspection (lP 71111.21)

.1 Inspection Sample Selection Process

The team selected risk significant components and operator actions for review usinginformation contained in the Salem Probabilistic Risk Assessment (PRA) and theU. S. Nuclear Regulatory Commission's (NRC) Standardized Plant Analysis Risk(SPAR) modelfor the Salem Generating Station. Additionally, the team referenced theRisk-lnformed Inspection Notebook for the Salem Generating Station (Revision 2.1a) inthe selection of potential components and operator actions for review. In general, theselection process focused on components and operator actions that had a RiskAchievement Worth (RAW) factor greater than 1.3 or a Risk Reduction Worth (RRW)factor greater than 1.005. The components and actions selected were associated withboth safety-related and non-safety related systems, and included a variety ofcomponents such as pumps, breakers, ventilation fans, diesel engines, batteries, andvalves.

The team initially compiled a list of components and operator actions based on the riskfactors previously mentioned. Additionally, the team reviewed the previous componentdesign bases inspection (CDBI) reports (05000272 & 311120008007 and 05000272 &31112006006) and excluded the majority of those components previously inspected.The team then performed a margin assessment to narrow the focus of the inspection to17 components and 5 operating experience (OE) items. The team selected a mainsteam isolation valve (MSIV) for large early release fraction (LERF) implications. Theteam's evaluation of possible low design margin included consideration of originaldesign issues, margin reductions due to modifications, or margin reductions identified asa result of material condition/equipment reliability issues. The assessment also includeditems such as failed performance test results, corrective action history, repeatedmaintenance, Maintenance Rule (aXl ) status, operability reviews for degradedconditions, NRC resident inspector insights, system health reports, and industry OE.Finally, consideration was also given to the uniqueness and complexity of the designand the available defense-in-depth margins.

The inspection performed by the team was conducted as outlined in NRC InspectionProcedure (lP) 71 111.21. This inspection effort included walkdowns of selectedcomponents; interviews with operators, system engineers, and design engineers; andreviews of associated design documents and calculations to assess the adequacy of thecomponents to meet design basis, licensing basis, and risk-informed beyond designbasis requirements.

Enclosure

2

Summaries of the reviews performed for each component and OE sample, and thespecific inspection findings identified are discussed in the subsequent sections of thisreport. Documents reviewed for this inspection are listed in the Attachment.

.2 Results of Detailed Reviews

.2.1 Detailed Component and Operator Action Reviews (17 samples)

.2.1.1 1C - 460V Vital Bus (1SWGR1CX)

a. Inspection ScopeThe team reviewed bus loading calculations to determine whether the 460V system hadsufficient capacity to support its required loads under worst case accident loading andgrid voltage conditions. The team reviewed the design of the degraded voltageprotection scheme to determine whether it afforded adequate voltage to safety-relateddevices at all voltage distribution levels, including the 460V vital buses. This includedreview of degraded voltage relay (DVR) setpoint calculations, motor starting and runningvoltage calculations, and motor control center (MCC) control circuit voltage dropcalculations. The team reviewed procedures and completed surveillances for calibrationof the DVRs to determine whether acceptance criteria were consistent with designcalculations, and to determine whether the relays were performing satisfactorily. Theteam reviewed calculations for overcurrent protection devices to determine whetherequipment was adequately protected, whether loads were subject to spurious tripping,and whether protective devices featured selective tripping coordination. The teamreviewed operating procedures to determine whether the limits and protocols formaintaining offsite voltage were consistent with design calculations. The team reviewedvendor manuals, maintenance schedules, maintenance procedures, and completedwork orders to determine whether PSEG adequately maintained the 1C 460V vital busand its associated circuit breakers. The team reviewed corrective action documents andmaintenance records to determine whether there were any adverse operating trends. Inaddition, the team performed a visual inspection of the 1C 460V vital bus to assess thematerial condition and the presence of hazards.

b. Findinqslntroduction: The team identified a finding of very low safety significance (Green)irwolving a non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion lll, DesignControl, because PSEG had not adequately verified the adequacy of the design for theDVR voltage setpoint. Specifically, PSEG had not performed calculations for motorstarting and running conditions, and for operation of other safety-related equipmentbased on voltages afforded by the DVRs.

Description: NRC Letter dated June 2, 1977, required installation of the DVRs. Theletter required the DVR voltage to be determined from an analysis of the voltagerequirements of Class 1E loads at all onsite system distribution levels, and requiredinciusion of the setpoints in Technical Specifications (TSs). Technical Specification

Enclosure

3

Table 3.3-4 item 7.b. specified an allowable value of > 94 percent for the DVRs. Thisallowable value corresponded to an analytical limit (actual minimum bus voltage thatcould occur without transfer to the emergency diesel generators) of 93.2 percent, asdocumented in a PSEG license amendment request dated March 28,1994. The teamdetermined that PSEG had not adequately determined the DVR setpoints by analyzingthe voltage it afforded safety-related equipment. In some cases, PSEG's voltagecalculations used bus voltage based on the minimum voltage afforded by the non-safetyrelated load tap changers installed on the station power transformers. In other cases,PSEG used voltage based on the TS specified DVR allowable value, rather than thedesign analytical limit. Finally, PSEG omitted some types of safety-related equipmentfrom the voltage analyses.

Specifically, the team determined that PSEG based motor starting calculations onminimum bus voltage afforded by the non-safety related load tap changer rather thanminimum bus voltage afforded by the DVR setpoints specified in TSs. CalculationES-15.008 analyzed motor starting voltage during loss-of-coolant accident (LOCA) blockloading. Similarly, calculation ES-15.014 performed an analysis of motor startingvoltage both during LOCA block loading, and also for starting individual motors duringsteady state conditions. These calculations also determined the effect of the transientvoltage dips that occur on the safety buses during motor starting to determine whetherthere were any deleterious effects of transient low voltage on other equipment alreadyconnected to the safety-related buses. Both of these calculations used a bus voltage of4210V (approximately 101 .2 percent of nominal bus voltage of 4160V), rather thanvoltage based on the analytical limit of 93.2 percent supported by TSs. As a result, theexisting calculations of record for motor starting were non-conservative by approximatelyI percent. The team was concerned that during block loading, motors and otherequipment would not have adequate voltage to start, and adverse effects includingdelayed operation of equipment, and overcurrent device tripping could occur. Inresponse, PSEG performed preliminary calculations to assess the effect of degradedvoltage during block loading and determined that motors would start in sufficient time tosatisfy the assumptions of the accident analysis, and that tripping of overcurrentprotective devices would not occur. PSEG documented this concern in their correctiveaction program (CAP) as notification (NOTF) 20494513.

The team also determined that calculations for motor running voltage were non-conseryative and that justifications for motors when voltages were outside their ratingswere not consistent with the Updated Final Safety Analysis Report (UFSAR)commitments. PSEG determined the running motor voltage at degraded voltage incalculation ES-15.008. Although the calculation methodology for analyzing runningmotors was not explicitly described in the calculation, the "Results" section reported thatmotor starting was analyzed with a 4kY safety bus voltage of 94 percent. This valuewas non conservative relative to the minimum voltage that could occur on the safety busrepresented by the analytical limit of 93.2 percent. Also, calculation ES-15.008,Section 2.3.1 stated that the minimum steady state voltage criteria for running motorswas 90 percent, and that motors not meeting this criteria were evaluated in EngineeringEvaluation S-C-EE-230-E4C-0-0753. The engineering evaluation concluded thatrunning voltages slightly below 90 percent were acceptable based on available thermal

Enclosure

4

life. The team noted that this approach was not consistent with UFSAR Section 8.3,which stated that the onsite distribution system has been shown by analysis and test topossess sufficient capacity and capability to automatically start and subsequentlyoperate all safety loads within their voltage ratings for anticipated transients andaccidents. ln addition, UFSAR Section 8.3.1.2 stated that the minimum allowable tripvalue and trip setpoint of the DVRs were derived using the 90 percent minimum motorterminal voltage requirement. The team noted that the setpoints specified insurveillance procedure 31.MD-FT.4kV-0002 were adequate to ensure a minimum busvoltage of 94 percent, consistent with the analytical approach, and that the justification

in Engineering Evaluation S-C-EE-230-E4C-0-0753 appeared to provide reasonableassur-ance of operability for the affected loads without 90 percent rated voltage. PSEGdocumented this concern in their CAP via corrective action NOTF 20497060.

The team also noted that calculations ES-15,008 and ES-15.004 did not includeminimum voltage acceptance criteria or evaluate steady state and transient voltage fornon-motor loads such as vital inverters and battery chargers. In response, PSEGperformed preliminary calculations and determined that these components would havetheir minimum required voltage except for brief periods during block loading conditions.These were deemed acceptable because of the ability of the affected equipment andbuses to automatically transfer to backup power supplies. PSEG documented thisconcern in their CAP via corrective action NOTF 20497062.

The team noted that PSEG personnel missed several opportunities to identify thisdesign control performance deficiency and engage their CAP that may have precluded

NRC identification in February 2011. Specifically, these opportunities involved internaland external OE associated with degraded voltage calculations and included (1) asimilar finding documented in a Hope Creek Generating Station (HCGS) NRCcomponent design bases inspection (CDBI) report in November 2009(NCV 05000354/2009007-03, Inadequate Design Control for 4 kV Bus DegradedVoltage Relay Bases), and (2) NRC lnformation Notice (lN) 2008-02, "Findings ldentifiedDuring Component Design Bases Inspections," issued in March 2008.

Analvsis: The team determined that the failure to properly verify the adequacy of thevolta& setpoint for the DVRs was a performance deficiency that was reasonably withinPSEG's ability to foresee and prevent. The finding was determined to be more thanminor because it was similar to example 3.j. of NRC IMC 0612, Appendix E, Examplesof Minor lssues, in that based on PSEG's existing non-conservative calculations, theteam had a reasonable doubt of operability of the safety-related motors until PSEGperformed additional analYses.

Additionally, the finding was associated with the design control attribute of the MitigatingSystems Cornerstone and adversely affected the cornerstone objective of ensuring theavailability, reliability, and capability of systems (safety-related loads powered from vitalbusses) that respond to initiating events to prevent undesirable consequences. The

Enclosure

5

team evaluated the finding in accordance with IMC 0609, Attachment 0609.04,Phase 1 - Initial Screening and Characterization of Findings, Table 4afor the MitigatingSystems Cornerstone. The team determined the finding was of very low safetysignificance because it was a design deficiency confirmed not to result in loss ofoperability.

The team determined that this finding had a cross-cutting aspect in the area of Problemldentification and Resolution, Operating Experience Component, because PSEG did notensure that relevant internal and external OE was collected, evaluated, andcommunicated to affected internal stakeholders in a timely manner. Specifically, PSEGdid not adequately evaluate a similar finding documented in a HCGS NRC CDBI reportin November 2009 (NCV 050035412009007-03) and missed an opportunity in theirinternal response to NRC lN 2008-02, "Findings ldentified During Component DesignBases Inspections," issued in March 2008. (lMC 0310, Aspect P.2(a))

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 bythe performance of design reviews, by the use of alternate or simplified calculationalmethods, or by the performance of a suitable testing program, and to ensure that thedesign is correctly translated into specifications, drawings, procedures, and instructions.Contrary to the above, as of February 1,2011, PSEG's design control measures did notverify the adequacy of the design for the DVR voltage setpoint. Specifically, PSEG hadnot performed calculations for motor starting and running conditions, and for operationof other safety-related equipment based on voltages afforded by the DVRs. Becausethis violation is of very low safety significance and has been entered into PSEG's CAP(NOTFs 2Q494513,20497060, and2Q497062), it is being treated as a NCV consistentwith Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000272;0500031 112011007-01, Inadequate Calculations for Degraded Voltage RelayVoltage Setpoint)

.2.1.2 1B 28 Volt Direct Current Batterv

a. Inspection ScopeThe team inspected the 1B 28 volt direct current (VDC) battery to verify that it wascapable of meeting its design basis requirements for a LOCA concurrent with a loss-of-offsite power (LOOP) or a station blackout (SBO) event. The team reviewedmaintenance activity and TS surveillance results to verify that the capacity and conditionof the 1B 28VDC battery was adequately maintained. The team reviewed calculationsand vendor information to verify that the 181 and 1B.2 battery chargers were of sufficientcapacity to restore the charge on the 1B 28VDC battery after a design bases LOOPevent occurred. The team reviewed the TS surveillance test results that demonstratedthe full load capabilities of the 181 and 182 battery chargers against TS surveillancerequirements (SRs) and design basis calculations to verify that the surveillance testresults were satisfactory. The team reviewed 2BVDC battery sizing calculations todetermine whether adequate voltage and charge was available to support theassociated loads.

Enclosure

b.

6

The team verified that modifications to the 28VDC system were appropriately evaluatedfor impact to the 1B 28VDC battery. The team also reviewed corrective actiondocuments and system health reports and interviewed the system engineer to determinewhether there were any adverse operating trends or existing issues affecting 28VDCbattery reliability. Finally, the team performed a visual examination of the 1B 28VDCbattery, as well as the 1A,2A, and 28 28VDC batteries to assess the material conditionand the presence of potential hazards to the 28VDC batteries.

Findinqs

lntroduction: The team identified a finding of very low safety significance (Green)involving a non-cited violation of Salem Unit 1 TS SR 4.8.2.5.2.h. Specifically, the teamidentified that PSEG did not perform a battery capacity test of the 1B 28VDC batterywithin 12 months of the previous performance test that showed signs of degradation.

Description: The team reviewed the results of surveillance test SC.MD-FT.28D-0003,28 Volt Station Batteries Performance Discharge Test Using BCT-2000 with WindowsSoftware and Associated Surveillance Testing, performed on October 28, 2008. Thepurpose of the surveillance test was to fulfill requirements of TS SR 4.8.2.5.2.h. anddemonstrate battery capacity was at least 80 percent of the manufacturer's rating.Additionally, the surveillance instructions require a comparison to the previous batteryperformance discharge test to determine signs of battery degradation. TechnicalSpecification SR 4.8.2.5.2.h. states that degradation is indicated when the batterycapacity drops more than 10 percent of rated capacity from its capacity on the previousperformance test. Step 5.12.21 of SC.MD-FT.28D-0003, Revision 2, required thetechnicians to mark the surveillance data sheet "Yes" for "Battery Degraded," notifysupervision, and initiate a corrective action notification if the calculated value wasgreater than 10 percent. Technicians had calculated the 1B 28VDC battery capacity as1 19 percent during the previous battery capacity test performed on April 26, 2004. Thecalculated capacity on October 28,20Q8, was 102.2 percent. The technicianscalculated a 16.8 percent drop, but contrary to procedure instructions, did not mark thesurveillance data sheet as "Yes" to "Battery Degraded" and did not initiate a correctiveaction notification.

On February 7,2011, the team notified PSEG that they had not performed the TSrequired surveillance testing of the 18 28VDC battery. PSEG promptly entered TS 4.0.3for a surveillance not performed within its specified frequency. Consistent with TS 4.0.3requirements, PSEG performed a risk evaluation and determined that the batteryperformance test could be delayed until the Fall2011 Salem Unit 1 refuel outage.PSEG also performed a review of all previous 1B 28VDC battery performance testresults and weekly and quarterly battery surveillance results and determined that the1B 28VDC battery remained operable even though the October 28,2008, performancetest had a capacity drop of greater than 10 percent. The team reviewed PSEG'sassociated risk and operability evaluations and determined that they were reasonable.PSEG entered this issue into their CAP as NOTF 20495611. PSEG corrective actions

Enclosure

7

included scheduling the 1B 28VDC battery performance test during the next scheduledSalem Unit 1 shutdown and evaluating causal factors to support the development oflong-term corrective actions.

Analvsis: The team determined that the failure to perform TS SR 4.8.2.5.2.h was aperformance deficiency that was reasonably within PSEG's ability to foresee andprevent. Specifically, prior to October 2009, PSEG personnel had opportunities toidentify that they needed to perform a battery performance test at least once per12 months when the 1B 28VDC battery showed signs of degradation on October 28,2008, because battery capacity dropped more than 10 percent of rated capacity from itsprevious performance test on April 26,2004. The team noted that the finding was notsufficiently similar to any of the examples in NRC IMC 0612, Appendix E, Examples ofMinor lssues. The finding was more than minor because it was associated with thehuman performance attribute of the Mitigating Systems Cornerstone and adverselyaffected the cornerstone objective of ensuring the availability, reliability, and capability ofsystems that respond to initiating events to prevent undesirable consequences.Specifically, the availability of the 1B 28VDC battery was not ensured by performingadditional surveillance testing to monitor for battery degradation. The team evaluatedthe finding in accordance with IMC 0609, Attachment 0609.04, Phase 1 - InitialScreening and Characterization of Findings, Table 4afor the Mitigating SystemsCornerstone. The team determined the finding was of very low safety significancebecause it was a qualification deficiency confirmed not to result in loss of operability.

The team determined that this finding had a cross-cutting aspect in the area of HumanPerformance, Work Practices Component, because PSEG personnel did not followprocedure requirements during the 1B 28VDC battery performance dischargesurveillance test. Specifically, personnel did not follow step 5.12.21 of SC.MD-FT.28D-0003 which required technicians to mark the surveillance data sheet "Yes" for "Battery

Degraded," notify supervision, and initiate a corrective action notification if the calculatedbattery performance capacity drop was greater than 10 percent. (lMC 0310, AspectH.4(b))

Enforcement: Salem Unit 1 TS SR 4.8.2.5.2.h requires that PSEG verify, at least oncepo lZ months, during shutdown, if the battery shows signs of degradation. On October28,2Q08, the 1B 28VDC battery showed signs of degradation because its batterycapacity dropped more than 10 percent of rated capacity from its capacity on theprevious performance test. Contrary to SR 4.8.2.5.2.h, on October 28, 2009, PSEGfailed to meet SR 4.8.2.2.h and had not performed a subsequent battery performance

test of the 1B 28VDC battery. On February 8,2011, PSEG completed SR 4.0.3 actionsfor the missed surveillance, which included justification for continued operability until theUnit 1 Fall2011 refuel outage to test the battery. Because this violation was of very lowsafety significance and was entered into PSEG's CAP (NOTF 20495611), it is beingtreated as a NCV consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCVOSOOO272I2O11OO7-02, Failure to Perform a TS Required Battery Performance Test)

Enclosure

8

.2.1.3 No. 21 Control Room Emerqencv Air Conditioninq Svstem Supplv Fan

a. Inspection ScopeThe team inspected the No. 21 control room emergency air conditioning system(CREACS) supply fan to verify its capability to meet design basis requirements. TheCREACS is initiated following receipt of a safety injection (Sl) or high radiation actuationsignal for areas inside the control room envelope (CRE). lt must provide a protectedenvironment from which operators can control the reactor unit during airbornechallenges from radioactivity, hazardous chemicals, and fire byproducts such as firesuppression agents and smoke during both normal and accident conditions. The No. 21supply fan, as well as each of the other fans, must be individually capable of providing100 percent of the required CRE pressurization air to 1/8 inches of water gaugepressure. The team also reviewed the CREACS fan support systems to ensure thatthey would function as designed under transient and accident conditions. The supportsystems included the associated system high efficiency particulate air (HEPA) filter,cooling coils, isolation dampers, ducting, component expansion joints, and mechanicalsupports.

The team reviewed the UFSAR, TSs, design basis documents, drawings, supportingcalculations and procedures to identify the design basis requirements of the fan andsystem. The team reviewed recently completed system walkdown reports andsurveillance tests to ensure the capability of the system had been maintained. Theteam discussed the design, operation, and maintenance of the CREACS with theengineering staff to gain an understanding of the performance history, maintenance andoverall health of the fan and other system components. The team reviewed correctiveaction documents to determine if there were any adverse trends associated with the fanand to assess PSEG's capability to evaluate and correct problems. The teamperformed field walkdowns of the system and observed leak-check smoke tests toindependently assess the material condition and to verify that the system configurationwas consistent with the design basis assumptions, system operating procedures, andplant drawings.

The team also evaluated the manual operator actions to realign the control areaventilation (CAV) system given a failure of the control room air conditioning system.Specifically, the team inspected operator critical tasks including recognizing loss of airconditioning to the control room and performing steps to align control room ventilationdampers and fans in order to provide sufficient air flow through the CRE to ensureequipment temperature limits are not exceeded. The team interviewed licensedoperators, observed a walkthrough of the procedure and reviewed associated alarmresponse procedures to assess the likelihood of cognitive or execution errors. The teamevaluated the available time margins to perform the actions to verify the reasonablenessof PSEG's procedures and risk assumptions. The team also reviewed room heat-upcalculations and a test performed to determine heat-up rates in various portions of theCRE used to evaluate the adequacy of the ventilation alignment followingimplementation of the procedure.

Enclosure

b.

I

Findinqs

lntroduction: The team identified a finding of very low safety significance (Green)involving a non-cited violation of 10 CFR 50, Appendix B, Criterion XVl, "CorrectiveAction," because PSEG did not identify and correct a condition adverse to quality.Specifically, PSEG did not identify and correct the degraded condition of the Unit 1 andUnit 2 CREACS common suction expansion joints because they did not implementappropriate PMs per their performance-centered maintenance (PCM) template.

Description: During a walkdown of the Unit 2 CREACS fans on February 10,2011, theteam identified a small tear (approximately 1.5 inches in length) in the expansion jointbetween the CREACS filter housing and the cooling coil. The small openingrepresented a CRE breach and was of particular concern as it was downstream of theHEPA filter and immediately upstream of the common suction to both Unit 2 CREACSfans. This deficiency potentially impacted both Salem operating units as the redundantUnit 1 and Unit 2 CREACS trains supply filtered air under accident conditions to acommon control room. In response, PSEG personnel initiated corrective actionNOTF 20496285. Operators promptly entered TS 3.7.6 for this CRE breach andinitiated mitigation actions. On February 10, maintenance installed a patch on the filterhousing expansion joint covering the tear and two other wear spots. On the morning ofFebruary 11, operations reviewed and accepted the repair and engineering performed asatisfactory smoke test to validate the repairs while CAV was aligned for accidentpressurized mode of operation in accordance with 52.OP-ST.SSPS-0010. Operatorsexited TS 3.7.6 and declared the CRE operable.

During a post-repair and extent-of-condition walkdown of the Unit 1 and Unit 2 CREACStrains on the afternoon of February 11,2011, the team identified several wear spots andthree additional small breaches on the Unit 1 and Unit 2 filter housing expansion joints.In response, PSEG personnel initiated NOTFs 20496388 and 20496387 for the Unit 1and Unit 2 expansion joint issues, respectively. PSEG determined that the additionalwear spots and small openings were enveloped by their existing technical evaluationperformed in response to the identified unplanned breach on February 10 and theresults of their CRE tracer gas testing performed in September 2010. The team foundPSEG's evaluation reasonable. Notwithstanding, PSEG prioritized the repair of theseadditional degraded locations and maintenance patched both Unit 1 and Unit 2CREACS filter housing expansion joints by February 15,2011. Following this repaireffort, the team performed additionalwalkdowns on the Unit 1 and Unit 2 CREACStrains and did not identify any additional deficiencies.

PSEG determined that the individual inlet and outlet expansion joints for each respectiveUnit 1 and Unit 2 CREACS fan all had existing 2-year PM recurring tasks to performinspection and repairs, as necessary. However, PSEG had not created similar PM tasksfor the larger common filter housing expansion joints (one for each unit) contrary to theguidance in their expansion joint PCM template (NOTF 20496357). In addition, theexpansion joint PCM template noted that a review of industry OE showed that the meantime to failure for rubber expansion joints is 12 to 15 years. Based on the team'squestions, PSEG concluded that the filter housing expansion joints were most likely

Enclosure

10

manufactured in 1975 and installed during initial construction. The team concluded thathad PSEG created the expansion joint PM in January 2007 in accordance with theirPCM template guidance, they would have likely identified the condition duringinspections and/or replaced the dated expansion joints. The team noted that PSEG hadseveral opportunities to identify the missing PMs since January 2007 including (1) inJune 2008, a PSEG self-assessment identified that there were no active PMs to inspectthe expansion joints at the inleUoutlet of the CREACS fans and created a 2-year PM;(2) in July 2009, PSEG inspected the No. 21 and No. 22 CREACS fan expansion joints(PMs 30170606 and 30170607) which are located in close proximity to the degradedUnit 2 expansion joint; and (3) in June 2010, PSEG performed PM template reviews oncritical heating, ventilation and air conditioning (HVAC) expansion joints. Uponidentification of the issue in February 2011, engineering promptly initiated a PM changerequest (PMCR). The PSEG PM Oversight Committee Chair reviewed and approvedthe associated PMCR. The PMCR prescribed an initial expansion joint replacement,followed by recurring periodic inspections, and an 18-year scheduled replacement(70119543). PSEG targeted the first-call replacements for the next availablemaintenance windows. PSEG also initiated corrective action NOTFs to perform extent-of-condition inspections from the inside of the expansion joint plenums (20496442 and20496443).

The team noted that PSEG personnel missed several opportunities to identify thedegraded condition of the Unit 1 and Unit 2 expansion joints and engage their CAP thatmay have precluded NRC identification in February 2011. Specifically, theseopportunities included (1) an Unit 2 filter unit inspection on July 26, 2010(WO 50121539), (2) walkdowns associated with tracer gas testing in September 2010,(3) system engineering walkdowns of the Unit 1 and Unit 2 CREACS rooms onDecember 29,2010, and (4) engineering extent-of-condition walkdowns onFebruary 10,2011. Based on the time dependent nature of the expansion joint wear(long-term aging and cyclic fatigue of the expansion boot), the team concluded that thedegraded condition most likely existed since July 26,2010.

Analvsis: The team determined that the failure to identify and correct the degradedcondition of the CREACS expansion joints was a performance deficiency that wasreasonably within PSEG's ability to foresee and prevent. Specifically, PSEG had notimplemented appropriate PMs for the CREACS common suction expansion joints pertheir expansion joint performance-centered maintenance (PCM) template. The teamnoted that the finding was not similar to any of the examples in NRC IMC 0612,Appendix E, Examples of Minor lssues. The finding was more than minor because itwas associated with the barrier (door, dampers, seals) performance attribute of theBarrier Integrity Cornerstone and adversely affected the cornerstone objective ofproviding reasonable assurance that physicaldesign barriers (the CRE in this case)protect the control room operators from radionuclide releases caused by accidents orevents. The finding was evaluated in accordance with IMC 0609, Attachment 4,Table 4a for a containment barrier. Since the finding had the potential to impact morethan the radiological barrier function, a Region I Senior Reactor Analyst (SRA)performed a Phase 3 analysis. The SRA determined that the dominant sequenceinvolved a sufficient degradation of the CREACS barrier that would allow sufficient in-leakage to force an evacuation of the control room during a fire or toxic gas event. The

Enclosure

11

areas with the degradation were in room 15615 and 25615 for Units 1 and 2,respectively. The SRA evaluated these areas and determined that the potential impactdue to in-leakage through the degraded barrier from fire and toxic gas would benegligible. The SRA also reviewed the results of recent CRE in-leakage testingconducted in September 2010. The condition of the expansion joint tearing and wearcould reasonably be assumed to have existed during the September testing. Thistesting also confirmed that the total in-leakage in these areas was small. Based on theabove factors, the SRA determined the finding was of very low safety significance(Green).

This finding had a cross-cutting aspect in the area of Human Performance, WorkControl Component, because PSEG did not plan work activities to support long{ermequipment reliability by ensuring that maintenance scheduling was more preventive thanreactive. Specifically, PSEG did not implement appropriate PMs on the CREACS filterexpansion joints necessitating several reactive corrective maintenance (CM) activities.(lMC 0310, Aspect H.3(b))

Enforcement: 10 CFR 50, Appendix B, Criterion XVl, "Corrective Action," requires, inpart, that measures shall be established to assure that conditions adverse to quality,such as failures, malfunctions, deficiencies, deviations, defective material andequipment, and non-conformances are promptly identified and corrected. Contrary tothe above, PSEG did not promptly identify and correct the degraded condition of theUnit 1 and Unit 2 expansion joints that existed from approximately July 26, 2010, toFebruary 11,2011. Because this violation was of very low safety significance (Green)and has been entered into PSEG's CAP (NOTFs 20496357,20496387,20496388), it isbeing treated as an NCV consistent with Section 2.3.2 of the NRC Enforcement Policy.(NCV 05000272;0500031112011007-03, Failure to ldentify and Correct a ConditionAdverse to Quality Affecting the CREACS Expansion Joints)

.2.1.4 21 Service Water Pump (2SWE1)

a. Inspection ScopeThe team inspected 21 service water (SW) pump to verify its ability to meet the designbasis requirements in response to transient and accident events, including supply ofcooling water to the reactor safeguard and auxiliary equipment under all credibleseismic, flood, drought and storm conditions. The team reviewed the SW systemhydraulic model and the design basis hydraulic analyses/calculations to verify thatPSEG properly considered the required total dynamic head (TDH), required net positivesuction head (NPSH), and the potential for vortex formation under all design basisaccidenVevent conditions. The team reviewed the SW pump in-service test (lST)procedures, recent test results, and trends in test data to verify that pump performanceremained consistent with design basis requirements. The team also reviewed the ISTreference values for flow rate and TDH to verify appropriate correlation to accidentanalyses conditions, taking into account setpoint tolerances and instrumentinaccuracies.

Enclosure

12

The team reviewed the SW pump motor bearing oil cooler inspection and performancemonitoring procedures, including tesUinspection results, to verify compliance withlicensing commitments under the Generic Letter (GL) 89-13, "Service Water SystemProblems Affecting Safety-Related Equipment," program plan. The team reviewed themaintenance and functional history of the 21 SW pump by sampling corrective actionreports, system health reports, and PM/CM records. The team reviewed theeffectiveness of traveling screen/strainer design features and adverse conditionoperating procedures for limiting potential adverse effects of ice and river grass on theSW pumps/system. The team also conducted several detailed walkdowns to visuallyinspect the physical/material condition of the SW pump and its support systems,including control room instrumentation and indication, and to ensure adequateconfig u ration control.

b. FindingsNo findings were identified.

.2.1.5 Unit 1 Turbine Driven Auxiliarv Feedwater Pump

a. Inspection ScopeThe team inspected the Unit 1 turbine driven auxiliary feed water (TDAFW) pump toverify that it was capable of meeting its design basis requirements. The team reviewedapplicable portions of the UFSAR and design basis documents to identify the designbasis requirements for the pump and associated steam turbine. The team reviewedcalculations and surveillance test procedures to determine if the turbine and pump werecapable of achieving design basis head/flow requirements during design basisconditions and that test acceptance criteria were consistent with these requirements.The team reviewed the hydraulic calculations associated with system flow rate andpressure as well as the NPSH calculation for the pump to ensure that the requiredperformance could be achieved. The team also reviewed design calculations for theTDAFW pump enclosure to determine if it was capable of mitigating the effects of a highenergy line break (HELB) event. Additionally, the team reviewed calculations for roomhealup to assess if the assumptions in the calculation were acceptable and to ensurethat equipment in the room did not exceed design temperature limits. Finally, the teamdetermined if operator actions credited during SBO events for the TDAFW pump couldbe performed within the time constraints assumed in the design calculation and SalemPRA.

The team interviewed design and system engineers in order to review the design andsystem functional requirements, as well as obtain historical test performance results. lnaddition, the team reviewed corrective action documents to assess failures ornonconforming issues, and to determine if PSEG appropriately identified, evaluated, andcorrected deficiencies. The team performed severalwalkdowns of the TDAFW pumpand support systems to assess the material condition of the equipment and determine ifthe equipment configuration was in accordance with drawings and design assumptions.Finally, the team performed a review of the emergency operating procedures (EOPs)

Enclosure

13

associated with post-accident pump operation to ensure the pump would be operated inaccordance with its design requirements.

b. FindinosNo findings were identified.

.2.1.6 1C Emergencv Diesel Generator

a. lnspection ScopeThe team inspected the 1C emergency diesel generator (EDG) and its associated fueloil, lube oil, starting air, intake, exhaust, and jacket water cooling systems to ensure theycould perform their respective design basis function in response to transient andaccident events, including a LOOP. The team reviewed the UFSAR, TSs, design basiscalculations, vendor documents, and procedures to identify the design basis,maintenance, and operational requirements for the engine and its support systems. Theteam reviewed fuel oil consumption calculations to ensure TS requirements were metunder design basis loading conditions. The team reviewed the design specification forthe starting air system, as well as air start test results, the normal operating pressureband, air compressor actuation setpoint and the TS limit for operability to verify that thestarting air system was properly sized and could meet its design function for successivestarts. The team reviewed EDG surveillance test results, operating procedures andmaintenance work packages to determine the overall health of the EDG engine and itsmechanical support systems.

The team performed several field walkdowns of all six EDGs (three EDGs per unit) toindependently assess the material condition and the operating environment of the EDGsand associated electrical equipment. During the walkdowns, the team compared localand remote EDG control switch positions, breaker position indicating lights, and systemalignments to design and licensing basis assumptions to verify the adequacy of PSEG'sconfiguration control. The team interviewed system engineers and operators toevaluate past performance and operation of the EDGs. The team reviewed systemhealth reports and corrective action documents to determine if there was any adverseequipment operating trends and to ensure problems were properly identified andcorrected. Additionally, the team observed portions of the 28 and 2C EDG tests inFebruary 2011 during their respective 24-hour endurance runs and hot-restartsurveillance tests, and conducted pre and post-operation walkdowns to ensure properoperation and assess material condition.

b. FindinosNo findings were identified.

Enclosure

14

.2.1.7 1B 28VDC Bus

a. lnspection ScopeThe team inspected the 1B 28VDC bus and associated distribution panels to verify thatthey were capable of meeting their design basis requirements. The team reviewedcontrolled drawings and several calculations to determine if the associated loads would

reliably operate under worst case conditions. Calculations reviewed included voltagedrop, short circuit, breaker coordination, and component study calculations. The team

reviewed PM activities associated with the 1B 28VDC bus and associated distributionpanels to ensure that PSEG properly maintained the equipment and identified anyadverse trends or deficient conditions. The team also reviewed a test and replacementprogram for aging molded case circuit breakers (MCCBs) against industry standards toveriiy that PSEG adequately maintained the reliability of the 28VDC MCCBS, as well as

a large population of MCCBs used in other Salem electrical distribution systems, Theteam also reviewed corrective action documents and system health reports, andinterviewed the system engineer to determine whether there were any adverseoperating trends or existing issues affecting the 28VDC bus and distribution systemreliability. Finally, the team performed a visual examination of the 1B 28VDC bus anddistribution panels, as well as the 1A,2A, and 28 28VDC buses and associateddistribution panels, to assess the material condition and the presence of potential

hazards to the 28VDC distribution systems.

b. FindinqsNo findings were identified.

2.1.8 Residual Heat Removal/Safetv Iniection Cross-tie Valve (12SJ45)

a. Inspection ScopeThe team inspected motor operated valve (MOV) 12SJ45 to verify its ability to meet its

design basis requirements, including isolation of the cross-tie between the residual heatremoval (RHR) and Sl pumps until needed during long-term recirculation in response totransient and accident conditions. The team reviewed calculations for required thrust,maximum differential pressure, and valve weak link analysis. The team revieweddiagnostic testing and IST surveillance results, including stroke time and availablethrust, to verify that acceptance criteria were met and performance degradation could beidentified. The team reviewed documentation to verify that valve motor design wasconsistent with the environmental qualification (EQ) basis for limiting conditions. Theteam reviewed the maintenance and functional history of the cross-tie valve by samplingcorrective action reports, the system health report, and PM/CM records. The team alsoconducted several detailed walkdowns to visually inspect the physical/material conditionof the valve and its support systems, including control room indication, and to ensure

adequate configuration control.

Enclosure

15

b. FindinqsNo findings were identified.

.2.1.9 1D 1 15V Vital Instrument Bus (1DlS181 1YA)

a. Inspection ScooeThe team reviewed calculations for 1 15V vital bus loading to determine whether the vitalinverters were being applied within their load ratings. The team reviewed calculationsfor 115V system voltage drop contained in design change documents, and preliminaryvoltage calculations for circuits estimated to be the most limiting, to determine whether1 15V vital system loads were being applied within their required voltage ratings. Theteam reviewed system health documents and corrective action histories to determinewhether there had been any adverse operating trends, including obsolescence issues.The team reviewed maintenance schedules and completed work packages to determinewhether equipment, including the vital inverter supplying the bus, was being properlymaintained. ln addition, the team performed a visual inspection of the 1D 1 15V vital busto assess material condition and the presence of hazards'

b. FindinosNo findings were identified.

.2.1.10 21 Diesel Fuel Oil Transfer Pump Motor

a. Inspection ScopeThe team inspected the No. 21 diesel fuel oil transfer pump (DFOTP) motor to verify itwas capable of meeting its design basis requirements to supply fuel to the 2A, 28, and2C EDG day tanks. The team reviewed controlled electrical drawings, motor nameplatedata, vendor electrical contactor and overload data, and a mechanical calculation todetermine that the motor would reliably operate under worst case conditions and supportthe 21DFOTP. The team reviewed PM activities associated with the 21 DFOTP motorand breaker to ensure that PSEG properly maintained the equipment and identified anyadverse trends or deficient conditions. The team also reviewed corrective actiondocuments and system health reports and interviewed the system engineer to determinewhether there were any adverse operating trends or existing issues affecting the21 DFOTP motor reliability. Finally, the team performed a visual examination of the21 DFOTP motor and associated MCC, as well as the 22,11, and 12 DFOTP motorsand associated MCCs to assess the material condition and the presence of potentialhazards to the Unit 1 and Unit 2 DFOTPS and motors.

b. FindinqsNo findings were identified.

Enclosure

16

.2.1.11Residual Heat Removal Heat Exchanqer Component Coolinq Water Outlet lsolationMotor Operated Valve No. 22CC16

a. Inspection ScopeThe team inspected the Unit 2No.22 RHR heat exchanger (HX) component coolingwater (CCW) outlet isolation MOV (22CC16) to verify its capability to perform itsrequired design basis functions. The 22CC16 valve is a normally closed valve whichopens on an auto-open signal tied to a safety injection or refueling water storage tank(RWST) low levelsignal. The team reviewed the UFSAR, TSs, design basisdocuments, drawings, and procedures to identify the design basis requirements of thevalve. The team reviewed periodic MOV diagnostic test results and stroke-timing testdata to verify acceptance criteria were met. The team verified that the MOV safetyfunctions, performance capability, torque switch configuration and design margins wereadequately monitored and maintained in accordance with GL 89-10 guidance. Theteam reviewed MOV weak link calculations to ensure the ability of the valve to remainstructurally functional while stroking under design basis conditions. The team verifiedthat the valve analysis used the maximum differential pressure expected across thevalve during worst case operating conditions. Additionally, the team reviewed motordata, degraded voltage conditions, and voltage drop calculation results to confirm thatthe MOV would have sufficient voltage and power available to perform its safety functionat degraded voltage conditions.

The team discussed the design, operation, and maintenance of the MOV with theengineering staff to gain an understanding of the performance history, maintenance andoverall component health of the valve. On February 8,2011, the team directly observedtechnicians modify the 22CC16 valve stem and install a state-of-the-art Quick StemSystem (OSS) strain gage, and observed the post-maintenance stroke time and torquesurveillance testing. The team reviewed the test data and discussed it with theengineering staff to confirm that the valve's design basis functions and operating marginwere adequately maintained. The team also conducted walkdowns of both units' RHRHX CCW outlet valves to assess the material condition of the MOVs, and to verify theinstalled configurations were consistent with the plant drawings, design and licensingbasis. Finally, the team reviewed corrective action NOTFs and system health reports toverify that PSEG appropriately identified and resolved deficiencies and maintained theMOVs properly.

b. FindinqsNo findings were identified.

.2.1.12 Main Steam lsolation Valve (22MS167)

a. Inspection ScopeThe team inspected steam piston-operated valve 22M5167 to verify its ability to meet itsdesign basis requirements, including containment isolation of the main steam piping in

Enclosure

17

response to transient and accident events. The team reviewed IST procedures andresults for valve stroke time to verify that the acceptance criteria were met andperformance degradation could be identified. The team reviewed the maintenance andfunctional history of the vatve by sampling corrective action reports, the system healthreport, and PM/CM records. The team reviewed a recently completed modificationpackage to the piston operator for the valve to confirm that design basis for the valvewas m-aintained. The team also conducted severalwalkdowns to visually inspect thephysical/material condition of the valve and its support systems, including control roominstrumentation and indication, and to ensure adequate configuration control.

b. FindinqsNo findings were identified.

.2.1.1321 Residual Heat Removal Pump 4KV Breaker (S24KV-2AD1AX7D)

a. Inspection ScopeThe team reviewed bus load flow calculations to determine whether the 21 RHR pump

4KV breaker was applied within its specified capacity ratings under worst case accidentloading and grid voltage conditions. The team reviewed schematic diagrams andcalculations for the breaker to determine whether equipment operation was consistentwith the design bases. The team reviewed calculations for protective device settings todetermine whether the pump motor was adequately protected, whether it was subject tospurious tripping, and whether the breaker was selectively coordinated with upstreamdevices. The team reviewed maintenance schedules, vendor data, and procedures forbreaker routine maintenance and overhauls to determine whether scheduledmaintenance activities were consistent with vendor recommendations. The teamreviewed recent corrective action documents and completed maintenance and testingrecords to determine whether there were any adverse operating trends. In addition, theteam performed a visual inspection of the 2A 4160V vital bus to confirm overcurrent tripdevice settings for the 21 RHR pump 4KV breaker, and to assess the material conditionand the presence of hazards.

b. FindinqsNo findings were identified.

.2.1.1412A Component Coolinq Water Heat Exchanoer Service Water lnlet Valve (12SW376)

lnstrument Air Controller

a. lnspection ScopeThe No. 12ACCW HX SW inlet valve (12SW376) is an air operated valve (AOV), withno manual operation capability, and has a risk-important function to open for RHRcooling and a risk-important function to close during a LOCA concurrent with a LOOP.The te-am inspected the 12SW376 instrument air (lA) controls to verify that it was

Enclosure

18

capable of meeting its design basis requirements to supply cooling water to the RHRHXs and to isolate, when required, to maximize cooling water to the EDGs andcontainment fan cooling units (CFCUs). The team reviewed lA drawings, vendormanuals for all associated pneumatic controllers, and AOV diagnostic testing results toverify that 12SW376 would operate reliably and to verify that the AOV was performing

with acceptable pneumatic margin. The team reviewed PM activities associated with12SW376 to ensure that PSEG properly maintained the valve and identified any adversetrends or deficient conditions. The team also reviewed corrective action documents andsystem health reports; and interviewed the AOV engineer, instrument and controlstechnicians, and system engineers to determine whether there were any adverseoperating trends or existing issues affecting 12SW376 reliability. Finally, the teamperformed a visual examination of 12SW376 and the associated lA controls to assessthe material condition and the presence of potential hazards.

b. FindinqsNo findings were identified.

2.1.15 Batterv Charqer Portable Diesel Generator

a. lnspection ScopeThe team evaluated the manual operator actions to align the dedicated portable dieselgenerator to the 125 volt and 28 volt battery chargers during a SBO. The teamdetermined if this action could be appropriately credited by reviewing the critical operatortasks including diesel starting requirements, breaker realignment requirements, andtemporary cable installation. The team interviewed licensed and non-licensedoperators, reviewed associated operating procedures and observed operators perform a

walk though of the procedure to assess PSEG's ability to perform the required actionsand to determine the likelihood of cognitive or execution errors. The team evaluated theavailable time margins to perform the actions to verify the reasonableness of PSEG'soperating procedures and risk assumptions. The team also walked down the associatedbattery rooms, battery chargers, switching panels, diesel generator and standby cablesto assess PSEG's configuration control and the material condition of the associatedstructures, systems and components (SSCs). Finally, the team reviewed themodification package developed to install and test the equipment required for this action

to determine if design basis requirements for the installed SSCs were maintained, and

testing of the equipment installed by the modification was adequate to conclude that thelineup would perform as intended.

b. FindinqsNo findings were identified.

Enclosure

19

.2.1.161C Emerqencv Diesel Generator Room Area Ventilation Fan (1VH27)

a. Inspection ScopeThe team reviewed calculations for sizing the fan and motor to determine whether theventilation scheme was adequate to maintain the EDG room within its requiredtemperature limits. The team reviewed calculations for overcurrent protective devicesettings to determine whether the fan motor was adequately protected, whether it wassubject to spurious tripping, and whether its breaker was selectively coordinated withupstream devices. The team reviewed electrical schematic diagrams to determinewhether the control scheme for the fan and its associated dampers was consistent withthe design bases. The team reviewed vendor data, maintenance schedules, and taskdescriptions to determine whether PSEG properly maintained the equipment. Inaddition, the team performed a visual inspection of the 1C EDG room area ventilationfan and its environs to assess the material condition and the presence of hazards.

b. FindinqsNo findings were identified.

2.1.17

a.

.2.2

b.

Switchqear and Penetration Area Ventilation Supplv Fan (1VHE1012)

lnspection Scope

The team inspected the No. 12 switchgear and penetration area ventilation (SPAV)supply fan to verify its ability to meet design basis requirements, including supply of re-circulated and/or outside air to maintain acceptable levels of temperature for the

switchgear and penetration areas, in response to transient and accident conditions. Theteam reviewed the maintenance and functional history of the fan by sampling correctiveaction reports, the system health report, and PM/CM records. The team reviewed inputsand assumptions used in Gothic modeling of the SPAV system to verify that they wereconsistent with physical conditions in the plant. The team also conducted severaldetailed walkdowns to visually inspect the physical/material condition of the fan and itssupport systems, including control room instrumentation and indication, and to ensureadequate configuration control.

Findinqs

No findings were identified.

Review of IndustrV Operating Experience and Generic lssues (5 samples)

The team reviewed selected OE issues for applicability at Salem Unit 1 and 2. Theteam performed a detailed review of the OE issues listed below to verify that PSEG hadappropriately assessed potential applicability to site equipment and initiated correctiveactions when necessary.

Enclosure

20

.2.3.1 Operatino Experience Smart Sample FY 2008-01 - Neoative Trend andRecurrinq Events Involvinq Emerqencv Diesel Generators

a. Inspection ScoPeNRC Operating Experience Smart Sample (OpESS) FY 2008-01 is directly related toNRC lN 2OO7-27, "Recurring Events lnvolving Emergency Diesel Generator Operability."The team reviewed PSEG's evaluation of lN 2007-27 and their associated correctiveactions. The team reviewed PSEG's EDG system health reports, EDG NOTFs andwork orders, leakage database, and surveillance test results to verify that PSEG

appropriately dispolitioned EDG concerns. Additionally, the team independently walkeddown ihe Uriit t and Unit 2 EDGs on several occasions to inspect for indications ofvibration-induced degradation on EDG piping and tubing and for any type of leakage(air, fuel oil, lube oil, andlorjacket water). The team also directly observed the 2B and2C EDG monthly surveillance runs in February 2011, and performed pre and post-run

walkdowns on the EDGs, as well as the 1B and 1C EDGs, to ensure PSEG maintainedappropriate configuration control and identified deficiencies at a low threshold.

b. FindinqsNo findings were identified.

RC lnforma.2.3.2

a.

Breakers

lnspection Scope

The team evaluated PSEG's applicability review and disposition of NRC lN 2007-34.The NRC issued this lN to inform licensees about OE regarding low, medium, and high

voltage circuit breakers, including problems with:

o Deficient fit-up with cubicleso Inadequate or excessive tolerances and gapsr Worn or misadjusted operating linkageso lnadequate or inappropriate maintenance practiceso Configuration control errorsr Deficiencies from original design and refurbishment. Design changesThe team reviewed maintenance schedules, vendor data, and procedures for mediumand low voltage breaker routine maintenance and overhauls to determine whetherscheduled maintenance activities were consistent with vendor recommendations' The

team reviewed recent corrective action documents and completed maintenance and

testing records to determine whether there were any adverse operating trends. lnaddition, the team conducted interviews with engineering personnel to assessknowledge of industry trends and OE.

Enclosure

21

b. FindinqsNo findings were identified.

.2.3.3 NRC lnformation Notice 2008-09: Turbine-Driven Auxiliary Feedwater Pump Bearinqlssues

a. lnspection ScopeThe team evaluated PSEG's applicability review and disposition of NRC lN 2008-09.The NRC issued the lN to alert licensees of issues with TDAFW pumps, as they relateto the importance of having accurate maintenance instructions and effective post-maintenance testing. The team reviewed PSEG's evaluation of their TDAFW pumpmaintenance procedures. The team also reviewed bearing temperature operatingprofiles, corrective action documents, and maintenance procedures related to theTDAFW pumps to determine if Salem was susceptible to the issues stated in the lN.The team also performed severalwalkdowns of the Unit 1 and Unit 2 TDAFW pumps toassess the material condition of the equipment, including independently observing thegovernor and bearing oil levels and condition for indications of excessive leakage and/oroverheating. On January 27,2011, the team performed a posf lST walkdown of theNo. 13 TDAFW pump to assess the material condition of the pump and oil systems.

b. FindinqsNo findings were identified.

.2.3.4

a.

Spurious Safetv Iniection Actuation and Reactor Tdp

Inspection Scope

The team evaluated PSEG's applicability review and disposition of NRC lN 2009-03.The lN was issued to inform licensees about OE regarding unique solid state protection

system (SSPS) failures that cause spurious Sl actuations and cannot be overridden withcontrol room panel override switches. The team reviewed PSEG's evaluation of theoperation and maintenance issues associated with the SSPS OE. Specifically, the teamreviewed corrective action documents and abnormaloperating procedure (AOP)S1.OP-AB.SSP-0001, Local Reset of ESF Actuation, and interviewed the systemengineer to validate that PSEG (1) established a PM program for SSPS electroniccards, (2) developed an AOP to reset spurious Sl signals locally if the control roomswitches were ineffective, and (3) maintained a life-cycle for SSPS electronic cards.

Findinqs

No findings were identified.

Enclosure

b.

22

.2.3.5

a.

Stem Lubricant

Inspection Scope

The team evaluated PSEG's applicability review and disposition of NRC lN 2010-03.The NRC issued the lN to inform licensees of recent failures and corrective actions forMOVs because of degraded lubricant on the valve stem and actuator stem nut threadedarea. The team reviewed corrective action documents and maintenance procedures toensure that PSEG adequately maintained applicable MOVs to preclude the degradedconditions described in the lN. The team conducted several risk-informed walkdowns ofaccessible MOVs to independently assess the material condition of MOV valve stem and

actuator stem nut threaded areas and reviewed the PM history for a sample of valves.

Findinqs

No findings were

OTHER ACTIVITIES

ldentification and Resolution of Problems (lP 71152)

The team reviewed a sample of problems that PSEG had previously identified andentered into the CAP. The team reviewed these issues to verify an appropriatethreshold for identifying issues and to evaluate the effectiveness of corrective actions.In addition, the team reviewed corrective action NOTFs written on issues identifiedduring the inspection to verify adequate problem identification and incorporation of theproblem into the CAP. The specific corrective action documents that were sampled andreviewed by the team are listed in the attachment.

Findinqs

No findings were identified.

Meetinqs. Includinq Exit

On February 18, 2011, the team presented the inspection results to Mr. Edward Eilola,Plant Manager, and other members of PSEG management. The team reviewedproprietary information and returned the associated documents to PSEG at the end of

ihe inspection. The team verified that no proprietary information is documented in thereport.

Enclosure

b.

4.

4c42

40A6

b.

A-1

ATTACHMENT

SUPPLEM ENTAL INFORMATION

KEY POINTS OF CONTACT

PSEG Personnel

M. CraMord, Acting Mechanical Design ManagerE. Eilola, Plant ManagerD. Johnson, MOV Program OwnerK. King, Senior Engineer, Mechanical DesignW. Kittle, IST Program OwnerD. Kolasinski, System ManagerG. Luh, Principal Engineer, Mechanical DesignG. Pahwa, GL 89-13 Program OwnerF. Priestly, Senior Reactor OperatorL. Rajkowski, Engineering DirectorT. Ram, System EngineerB. Thomas, Senior Compliance EngineerM. Winkelspecht, System Manager

NRC Personnel

D. SchroederC. Cahill

Open and Closjd

Q5AQO27 2; 050003 1 1 I 20 1 1 007 -0 1

0500027212011007-02

050Q027 2: 050003 1 1 | 201 1 007 -03

Senior Resident InspectorSenior Reactor Analyst

LIST OF ITEMS OPENED, CLOSED AND DISCUSSED

NCV

NCV

NCV

Inadequate Calculations forDegraded Voltage Relay VoltageSetpoint (Section 1R21 .2.1 .1)

Failure to Perform a TS RequiredBattery Performance Test (Section1R21.2.1.2)

Failure to ldentify and Correct aCondition Adverse to QualityAffecting the CREACS ExpansionJoints (Section 1R21.2.1.3)

Attachment

A-2

LIST OF DOCUMENTS REVIEWED

Audits and Self-Assessments70109034-60, Salem NRC Component Design Basis Inspection Focused Area Self

Assessment, dated 11 1911080102344-40, Motor Operated Valve Setup Margin NOS Performance Assessment, dated

9t7t10

CalculationsA-5-500-E4C-0-1930, 500 kV and 4.16kV Systems Voltage Drop due to Unit Trip, Rev. 2ES-3.001, 28VDC Short Circuit and System Voltage Drop Calculation, Rev. 6ES-3.002, 28 Volt DC Battery and Battery Charger Sizing Calculation, Rev. 5ES-3.004, 28Volt DC Component Study and Voltage Drop Calculation, Rev. 3ES-8.007, Transformer Tap Changer Setting Calculation, Rev. 3ES-13.006, Breaker and Relay Coordination Calculation Safety Related AC System, Rev. 3ES-13.008, 250V, 125V,28V DC System and 1 1 5VAC ASDS Overcurrent Coordination, Rev. 3ES-15.004, Load Flow and Motor Starting, Rev. 4ES-15.005Q, 230V Vital Bus Voltage Drop Calculation for Control Circuits SNGS Unit 1, Rev. 3ES-15.008, Units 1 & 2 Degraded Grid Study, Rev. 5ES-15.009, Essential Controls lnverter Load Study for PSEG SNGS Units 1 & 2, Rev. 10ES-15.014, Motor Running During LOCA Block Start, Rev. 3S-1-ABV-MDC-2050, Salem Unit 1 Auxiliary Building Temperature Calculation - Normal and

Emergency Modes, Rev. 2S-1-AUX-MDC-1714, Pipe Break Pressures in TDAFWP Enclosure and Adjacent Areas, Rev. 0S-1-CAV-MDC-1361, Unit 1 SPAV Return/Exhaust Fan Pressure Drop Calculation, Rev. 0S-1-CAV-MDC-1834, Salem Unit 1, Switchgear and Penetration Area Ventilation System

(SPAVS) - Gothic Model, Rev. 0S-1-DGV-MDC-0661, Diesel Generator Area Ventilation System Equipment Assessment

Capability, Rev.3S-1-DGV-MDC-1227, D/G Area Heat Gain and Loss / Equip Capability Calc., Rev. 1S-2-AUX-MDC-1627 , Pipe Break Pressures in Aux. Bldg. Rooms, Rev' 0S-2-CAV-MDC-0687, Unit 2 - EACS Duct Negative Pressure Calculation, Rev. 1S-2-CC-MDC-0898, 22CC16 MIDAS Calculation, Rev. 0S-C-4KV-JDC-959, Degraded Vital Bus Undervoltage Setpoint, Rev. 5S-C-AF-MDC-0432, Auxiliary Feedwater Pump NPSH, Rev. 1S-C-AF-MDC-0445, Auxiliary Feedwater System Hydraulic Analysis, Rev' 3S-C-AF-MDC-1421, Pressure in TDAFW Pump Enclosure Due to Pipe Break, Rev. 2S-C-AF-MDC-1789, Salem Auxiliary Feedwater Thermal Hydraulic Flow Model, Rev. 1S-C-AF-MEE-0262, Auxiliary Feedwater Pump Turbine Speed Control, dated 4118189S-C-AUX-MDC-0737, Loss of Ventilation During Station Blackout, Rev' 3S-C-DF-MDC-0852, Fuel Oil System - Design Calculation of System Parameters, Rev. 0S-C-DGO12-01, Salem Units 1 & 2 Diesel Generator Starting Air Pressure, Rev. 3S-C-DG-MEE-1111, Thermal Operating Modes - Diesel Starting Air, Booster Air and Jacket

Water Systems, Rev. 0S-C-DG-MEE-1136, Jacket Water Heat Exchanger Freezing Resolution, Rev.1S-C-F400-MSE-083, Use of Sea Water or Brackish Water for Emergency Cooling of Steam

Generator, Salem Generating Station Units No. 1 & 2, Rev. 1

Attachment

A-3

S-C-SJ-MDC-0892(015), MOV Capability Assessment for 12SJ45-MTRY, Rev. 1S-C-SW-MDC-1068, Service Water Design Basis Temperature, Rev. 4S-C-SW-MDC-1317, Service Water System Hydraulic Model, Rev. 7S-C-SW-MDC-1350, Service Water System Mode Ops Analysis, Rev. 8S-C-SW-MDC-1351, Service Water Pump NPSH Calculation, Rev. 2S-C-SW-MDC-1422, Service Water Pump Surveillance Test Error Analysis, Rev. 0S-C-SW-MDC-1967, Service Water System Thermal Hydraulic Model, Rev. 5S-C-SW-MEE-1449, Evaluation of Increased CFCU Service Water Flow Setpoints, Rev. 1S-C-SWV-MDC-1356, SWIS Ventilation Calculation, Rev. 1S-C-SWV-MDC-1512, Salem Nuclear Generating Station - Heating Load for Service Water

Intake Structure, Rev. 0S-C-VAR-EEE-1057, Tabulation of Molded-Case Circuit Breakers and Parameters, Rev. 2S-C-ZZ-SDC-1419, Salem Generating Station Environmental Design Criteria, Rev. 3SR-101, Crane Valves Seismic Weak Link Analysis Report, Rev. 1

Corrective Action Notifications (NOTFs)20168479 20394813 20460490 20491019 20495392. 20496353. 2049706Q*20169662 20397611 20464648 20491741 20495396. 2Q496357. 20497061.20264954 20400099 20464734 20493883. 20495443* 20496386. 20497062.2A282385 20403116 20466242 20493983 20495521 20496387. 2049711520284428 20408830 20466837 20494000. 20495538 20496388. 20497137.20330961 20408831 20469186 20494082 20495595. 20496427. 20497138.20332386 20408862 20469187 20494176. 20495611* 20496442. 20497182.20337290 20416141 20469339 20494178 20495623 20496443. 20497183-20337561 20416513 20470034 20494249* 20495812. 20496447. 20497218-20339257 20422047 20472585 20494394* 20495854 20496543. 20497231-20341869 20424568 20473208 20494396. 20495862" 20496548. 20497232.20345322 2A429349 20474064 2049440Q* 20495863. 20496549. 2Q497275*20351872 20429400 20476554 20494419* 20495864* 20496550. 20497341.20352959 20431538 20477228 20494436 20495871* 20496551* 20497352.20353591 20432597 20478230 20494513. 20496019. 20496622. 20497353.20354465 20440000 20479564 20494554 20496020. 20496736. 20497355-20356789 20444609 20479601 20494664 20496035 20496754. 20497371*20358763 20445377 20479919 20494761* 20496041* 20496798* 20497396.20363981 20445661 20485362 20494800. 20496062 20496800. 20497424*20379126 20446268 20486530. 20494839. 20496070* 20496839. 20497934*20381679 20446384 20489914 20494841. 20496082. 20496872. 20497938*20381920 20446524 20489453 20494962. 20496119. 20496883. 20497940*20381958 20447784 20489462 20495066. 20496123* 20496887. 20497941*20382478 20450241 20489645 20495075. 20496234 20496906. 20497969-20382938 20453137 20490588 20495105. 20496285* 20496937 20498002*20385267 20456681 20490589 20495179" 20496331* 20496967*20386793 20458263 2Q490768 20495181 20496332. 2049696820391738 20458711 20490862 20495313 20496340. 20496996-20392497 20460413 20491018 20495355. 20496347 20497052

* NOTF written as a result of this inspection

Attachment

Corrective Action Evaluations

700404357005674070069050700722477007258670074317700752477007810470078541

70079173700792627007969170082753700832327008740170088076700880817008881 1

700902667009336070091842700941 387009849170100726701 01 8037010272970102769

70102904701054187010612770106627701 07090701 0881 4701 08961701 0928070110141

7Q110427701105247011362570118474701 1 9080

Desiqn & Licensinq BasesLetter from PSEG "Response to NRC Bulletin 88-04," dated 8111188NLR-N94007, Request for License Amendment, dated 3128194NRC Letter L.N. Olshan to L.R. Eliason PSEG, License Amendments 162 and 148, dated

12t12194Safety Evaluation Report by the Directorate of Licensing US Atomic Energy Commission in the

Matter of PSE&G, PECO, Delmarva Power and Light, and Atlantic City ElectricCompany Salem Nuclear Generating Station Units 1 and2, dated October 11,1974

Drawinqs2OSOOO-S-8789-53, No. 1 and No. 2 Units Generators & Main Transformers One-Line Control

Diagram, Rev.53203002-A-8789-34, No. 1 Unit 4160V Vital Buses One Line, Rev. 34203003-A-8789-45, No. 1 Unit 460V and 230V Vital & Non Vital Bus One-Line Control Diagram,

Rev.45203318-8-9781, No. 1 & 2 Units Aux Feedwater System No. 13 & 23 Aux. Feed Pump &

Turbine, Rev. 11203319-8-9781, No. 1 Unit Aux Feedwater System No. 13 Aux. Feed Pump & Turbine, Rev. 23203414-ABL-596, No. 1 & 2 Units Aux Feedwater System Inlet Valve Controls, Rev. 2205203-A-8760-77 Sh. 1, No. 1 Unit Main, Reheat & Turbine Bypass Steam, Rev' 77205234-A-8761-47 , Unit 1 Safety Injection, Rev. 47205236-A-8761, No. 1 Unit Auxiliary Feedwater, Rev. 56205241-A-8761 Sh. 3, No. 1 & 2 Units Diesel Engine Auxiliaries, Rev. 43205242-A-8761-93 Sh. 2, Unit 1 Service Water Nuclear Area, Rev' 85205248-A-8761 Sh. 2, No. 1 Unit Aux. Bldg. Control Area AC & Ventilation, Rev. 48205248-A-8761-35, No. 1 Aux Bldg ControlArea Air Conditioning & Ventilation, Rev. 35205321-A-8762-22 Sh. 1, No. 1 Unit Auxiliary Building Diesel Generator & Fuel Handling Area

Ventilation, Rev.22205321-A-8762-22 Sh. 3, No. 1 Unit Auxiliary Building Diesel Generator & Fuel Handling Area

Ventilation, Rev.22

Attachment

A-5

205331-4-8763 Sh. 1, No. 2 Unit Component Cooling, Rev. 52205331-4-8763 Sh. 2, No. 2 Unit Component Cooling, Rev. 38205331-4-8763 Sh. 3, No. 2 Unit Component Cooling, Rev. 35205348-A-8763, No. 2 Unit Aux. Bldg. Control Area Air Conditioning & Ventilation, Rev. 37205702-A-8939, No. 1 Unit - Auxiliary Building ACS No. 12 Component Cooling Heat

Exchanger Arrangement Panel 204-123 Controls, Rev. 24207909-4-1777-23, No. 1 Unit Auxiliary Building 1C Diesel 230V Vital Control Ctr. One Line

Diagram, Rev.23211348 B 9483, No. 1 and No.2 Units 1B and 28 28VDC Buses, Rev. 1621 1350-8-951 1 , No. 1 Unit - Control Area l BDE 28VDC Distribution Cabinet, Rev. 1 1211357-8-9511, Sh, 1, No. 2 Unit 28 Volt DC One Line, Rev. 14211357-8-951 1, Sh. 2, No. 2 Unit 28 Volt DC One Line, Rev. 12211358-8-951 1, No. 1 Unit - Control Area l DDE 28VDC Distribution Cabinet, Rev. 6211370-A-8859-42, No. 1 Unit 115V Control System, Rev. 422115A18583-15 Sh. 2, No. 1 Unit Residual Heat Removal Sys. No. 21 Residual Heat Removal

Pump - D.C. Schematic, Rev. 15211753-A-8862-12, Service Water lntake Structure Plan, Rev. 12222480-A-1778, No. 2 Unit - Auxiliary Building 2A Diesel 230V Vital Control Ctr. One-Line

Diagram, Rev.25223689-B-979Q-22, No. 1C and 2C Diesel Generators Console Control Sheet 3, Rev. 22223690-A-9790-30, No. 1C Diesel Generators Engine-Engine Control, Rev. 30223825-9-9789, No. 1 and 2 Units - No. 1,A and 2A Diesel Generator 230V Vital Control

Center, Rev. 18223832-8-9789-14, No. 1C Diesel Generator 230V Vital Control Center, Rev. 14223833-8-9789-23, No. 1C Diesel Generator 230V Vital Control Center, Rev. 23233661-8-3012 Sh. 2, No. 1 & 2 Units ControlArea A.C. No. 11 & 21 Emergency Supply Fan

Schematic, Rev. 7238083-8-9635-6, No. 1 Unit Auxiliary Building Diesel Generator Area Ventilation, Rev. 6252002-8-9946, No. 1 Unit - Aux. Bldg. Service Water System No. 12A & 128 Component

Cooling Heat Exchanger Inlet & Outlet Control Valves, Rev. 5601233-8-9528-22, No. 1 Unit Auxiliary Bldg. Control Area 1C - 460V Vital B