IR 05000272/2011003

IR 05000272-11-003 & 05000311-11-003, on 04-01-11 - 06-30-11, Salem Nuclear Generating Station, Units 1 and 2, NRC Integrated Inspection Report

ML112210277
Person / Time
Site:	Salem
Issue date:	08/09/2011
From:	Burritt A L Reactor Projects Branch 3
To:	Joyce T P Public Service Enterprise Group
BURRITT, AL
References
IR-11-003
Download: ML112210277 (45)

Text

UNITED STATES NUCLEAR REGU LATORY COMMISSION REGION I 475 ALLENDALE ROAD KING OF PRUSSIA. PENNSYLVANIA 19406-1415 August 9, 20L7 Mr. Thomas President and Chief Nuclear Officer PSEG Nuclear LLC - N09 P.O. Box 236 Hancock's Bridge, NJ 08038

SUBJECT: SALEM NUCLEAR GENERATING STATION, UNIT NOS. 1 AND 2 -NRC INTEGRATED INSPECTION REPORT O5OOO272I2O11OO3 and 0500031 1t2011003

Dear Mr. Joyce:

On June 30, 2011, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at the Salem Nuclear Generating Station, Unit Nos. 1 and 2. The enclosed integrated inspection report documents the inspection results discussed on July 14,2011, with Mr. Wagner and other members of your staff.The inspection examined activities conducted under your license as they relate to safety and compliance with the Commission's rules and regulations and with the conditions of your license.The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

The report documents one NRC identified and one self-revealing finding of very low safety significance (Green). One of the findings was determined to involve a violation of NRC requirements.

Additionally, two licensee-identified violations of very low safety significance are listed in this report. However, because of their very low safety significance and because they are entered into your corrective action program (CAP), the NRC is treating these findings as non-cited violations (NCVs) consistent with Section 2.3.2.a of the NRC Enforcement Policy. lf you contest any NCV in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the RegionalAdministrator, Region l; the Director, Office of Enforcement, U. S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Salem Nuclear Generating Station. ln addition, if you disagree with the cross-cutting aspect assigned to any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis of your disagreement, to the Regional Administrator, Region 1, and the NRC Resident Inspector at Salem Nuclear Generating Station. In accordance with 10 CFR 2.390 of the NRC's "Rgles of Practice," a copy of this letter, its enclosure, and your response (if any) will be avail{ble electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS). ADAMS is aocessible from the NRC Web site at http://www.nrc.sov/readinq-rm/adams.html (the PUblic Electronic Reading Room).Division of Reactor Projects Docket Nos: License Nos:

Enclosure:

50-272;50-311 DPR-70; DPR-75 I nspection Report 0500027 2120 1 1 003 and 0500031 1 I 201 1 003 W

Attachment:

Supplemental I nfontation cc Wencl: Distribution via ListServ Affhur L. Burritt, Chief 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 availdble electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS). ADAMS is acicessible from the NRC Web site at http://www.nrc.qovlreadino-rm/adams.html (the PUblic Electronic Reading Room).Sincefely,/RA/Arthur L. Burritt, Chief Projeqts Branch 3 Divisi0n of Reactor Projects Docket Nos: 50-272:50-311 License Nos: DPR-70; DPR-75

Enclosure:

Inspection Report 05000272120110p3 and 0500031112011003

w/Attachment:

Supplemental Inforrhation cc Mencl: Distribution via ListServ Distribution dencl.W. Dean, RA D. Lew, DRA D. Roberts, DRP J. Clifford, DRP C. Miller, DRS P. Wilson, DRS A. Burritt, DRP L. Cline, DRP (RIORAMAIL Resource)(RIORAMAIL Resource)(RIDRPMAlL Resource)(RlDRPMail Resource)(RlDRSMail Resource)(Rl DRSMail Resource)A. Turilin, DRP C. Douglas, DRP D. Schroeder, DRP, SRI P. McKenna, DRP, Rl K. McKenzie, DRP, OA J. McHale, RIOEDO RidsNrrPMSalem Resource RidsN rrDorl Lpl 1 -2Resource ROPreportsResource MLl12210277 SUNSI Review Complete:

LC (Reviewer's Initials)DoCUMENT NAME: G\DRP\BRANCH3\INSPECTION\REP0RTS\ISSUED\2011 (ROP 12)\SAL1103.D0CX After declaring this document "An Official Agency Recotd" it yg!!! be released to the Public.To receive a coov of this doqirFnt, indicate in the box; 'c"=copy wiftout with attadlmenuenclosure CFFICE mmt RI/DRP RI/DRP RI/DRP NAME DSchroeder/

LC for LCline/ LC ABurritU ALB)ATE 08t05t11 08t05111 08109 t11 OFFICIAL COPY U.S. NUCLEAR REGULA'TORY COMMISSION REGION I Docket Nos: License Nos: Report No: Licensee: Facility: Location: Dates: Inspectors:

Approved By: 50-272,50-311 DPR-70, DPR-75 050A02721201 1 003 dnd 0500031 1 t201 1003 PSEG Nuclear LLC (PSEG)Salem Nuclear GenQrating Station, Unit Nos. 1 and 2 P.O. Box 236 Hancocks Bridge, NJ 08038 April 1 ,2011through June 30, 2011 Resident Inspector P. McKenna, Resideht Inspector J. Furia, Senior Physicist E. H. Gray, Senior Inspector R. Fuhrmeister, Reactor Inspector M. Balazik, Reactor fnsPector C. Douglas, Project I Arthur L. Burritt, Chief Projects Branch 3 Division of Reactor Frojects Enclosure SUMMARY OF FINDINGS lR 0500027212011003, 0500031112011003; 0410112011 - 061301201 1 ; Salem Nuclear Generating Station Unit Nos. 1 and 2; Fire Protection, Maintenance Risk Assessment and Emergent Work Control.The report covered a three-month period of inspectfon by resident inspectors, and announced inspections by a regional radiation specialist and rehctor engineers.

One Green finding and one Green NCV were identified.

The significance of most findings is indicated by their color (Green, White, Yellow, or Red) and determined using lnspeption Manual Chapter (lMC) 0609,"Significance Determination Process" (SDP). The dross cutting aspect of a finding is determined using the guidance in IMC 0310, "Com$onents Within the Cross-Cutting Areas." Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in [UREG-1649, "Reactor Oversight Process", Revision 4, dated December 2006.Cornerstone:

Initiating Events. Green. A self-revealing finding of very low significance was identified on April 1, 2011, because 500 KV load break 3T60 failed to operate upon the restoration of switchyard maintenance.

caused a four hour delay in the restoration from a single source of offsite power, the from a 72hour Limiting Condition for Operation (LCO), and the extension of a yel condition.

PSEG investigation revealed tha rw probability risk assessment (PRA)the vendor, who was conducting maintenance on the 3T60 disconnect, the motor control fuse holder that was G determined that the cause of the not part of the tagout for the maintenance.

disconnect not closing was that PSEG did adequately brief and control the maintenance evolution.

PSEG entered this into the corrective action program as notification 20503254.The performance deficiency was more than minor because it was associated with the human performance attribute of the Initiating Events cornerstone, and it adversely affected the cornerstone objective to limit thb likelihood of events that upset plant stability and challenge critical safety functiorirs.

Specifically, not following the PSEG procedure for the management and oversigtrt of supplemental personnel caused a four hour extension into aT2hour LCO in which Salem Units 1 and2 had only one source of offsite electrical power. The finding was ev{luated under IMC 0609, Attachment 4, Phase 1 screening, and was determined to fequire additional evaluation.

The finding was subsequently evaluated in Phase 3 utiliping a pilot implementation of NRC's SAPHIRE 8 risk analysis SDP interface tool using the Salem specific standardized plant analysis review (SPAR) model, and confirmpd to be of very low safety significance (Green).This performance deficiency has a cross-cufting aspect in the area of human performance, because PSEG did not ensur$ supervisory and management oversight of the vendor work activity.

Specifically, PSEQ personnel did not conduct an adequate pre-job brief with the vendor, did not assign a srjpervisor to provide in-field supervision, and Enclosure did not conduct an adequate post-maintenairce restoration walkdown of the 3T60 switchyard maintenance. (H.4(c)) (Section ilR13)Cornerstone:

Mitigating Systems r Green. The inspectors identified a NCV of Operating License condition 2.C.5, that requires PSEG implement all of the Fire Protection Program as described (UFSAR). Specifically, PSEG stored a rod in the Updated Final Safety Analysis drive motor generator (MG) set in a com ble control zone (CCZ) without an engineering evaluation that assessed risk a established compensatory measures.safety significance.

This issue was This finding was determined to be of very entered into PSEG's CAP as notification 19. PSEGs immediate corrective actions were to issue a valid transient tible permit (TCP)and remove the transient combustibles from the CCZ within next three days.The inspectors determined that storing combustibles in a CCZ without a permit was a performance deficiency because PS$G prooedure FP-M-011 stated that transient combustible material was prohibitdd in a QQZ when not constantly attended or approved by a TCP. This finding was more minor because it was associated with the external factors attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to the availability of systems that respond to initiating events to prevent undesirable uences. Specifically, the identified transient combustibles were located in a that was required to limit challenges to physical separation afforded by steelfloor above the CCZ. Using IMC 0609, Appendix F, "Fire Protection Significance tion Process," the inspectors determined that this issue involved the category, "Fire Prevention and Administrative Controls." Referencing IMC Appendix F, Attachment 2, ,r vr9,"Degradation Rating Guidance Specific to Various Fire Protection Program Elements," the inspectors assigned a low degradation comply with PSEG's transient combustible ng to the issues involving the failure to m. The inspectors'

conclusions were based on the fact that none of the items considered transient combustibles of sig in the combustible free zone could be , as described in IMC 0609, Appendix F, Attachment 2. This attachment defined combustibles of significance as low flash point liquids (below 200"F) and combustibles (oily rags). Because this minimize fire risk and comply with the plant operating license. (H.3(b)) (Section 1R05)Enclosure REPORT DETAILS Summarv of Plant Status Salem Nuclear Generating Station Unit 1 (Unit 1) bdgan the period at 100 percent power. On April 19, 2011, plant operators reduced power to 96 percent due to heavy river detritus.

Unit 1 was returned to full power on April 20. On April21, plant operators manually tripped Unit 1 due to a loss of four circulators caused by heavy river d$tritus.

Unit 1 was synchronized to the grid on April 23, and power was raised to 60 percent whpn the power ascension was placed on hold due to heavy river detritus.

On April24, the main tulrbine was removed from service after power was reduced due to heavy river detritus.

Reactor pQwer was maintained at 8 percent until April 28, when Unit 1 was synchronized to the grid. Powpr ascension was placed on hold at 96 percent power on April 29 due to heavy river detrituf.

Power was reduced to 8 percent and the 1. REACTOR SAFETY Si6tems, Barrier Integrity, and Emergency sSmples).1 Evaluate Summer Readiness of Offsite and Alternate AC Power Syslems a. lnspection Scope The inspectors completed one adverse inspection sample to evaluate the readiness of offsite power to the Salem units to the summer season when electrical grid stability can be most challenged.

The i verified that PSEG provided procedure requirements or guidance to and maintain availability and reliability of during adverse weather conditions.

the offsite AC Power (OSP) system prior to a Specifically, the inspectors verified that the addressed:

Cornerstones:

Initiating Events, Mitigating Preparedness 1R01 Adverse Weather Protection (71111.01 - z voltage;The actions to be taken when notified by the electrical system operations center (ESOC) of the PJM interconnection that tfie post-trip voltage of the OSP system at Salem will not be acceptable to assure thp continued operation of the safety-related loads without transferring to the EDGs;The compensatory actions to be performQd if ESOC cannot predict the post-trip Enclosure

. The re-assessment of plant risk for mairitenance activities that could affect grid reliability or OSP system availability to the Salem units; and Communication requirements between $alem and the ESOC regarding plant changes that could impact the transmission system, or the capacity of the season specific to the main power transformers and the OSP system. The inspectors interviewed engineering and work control personnel and reviewed work orders and completed portions of WC-AA-107, "Seasonpl Readiness," to verify that PSEG took measures to ensure the reliability of the main transformers and the OSP system during the summer season. Documents reviewed dre listed in the Attachment.

.2 b.Findinos No findings were identified.

a. Inspection Scope The inspectors completed one adverse protection sample (in conjunction with Temporary Instruction 25151183)

to readiness for external flooding.

The inspectors reviewed PSEG's preparations compensatory measures for severe weather conditions that posed a risk of. The inspectors interviewed operations and engineering personnel regarding the they would take to prepare for severe weather and walked down risk significant s to independently assess the adequacy of PSEG's preparations.

the inspectors reviewed the condition of the Unit 2 auxiliary building and Unit 2 EDG inspectors verified that degraded conditions external flood protection.

The the potential to impact safety-related components and systems were reported in CAP. Corrective action notifications to ensure that operability of components written for degraded conditions were revi in the auxiliary building and EDG enclosures are listed in the Attachment.

b. Findinqs No findings were identified.

1R04 Eouioment Aliqnment (71111.04 - 3 samples not impacted, Documents reviewed PartialWalkdown a. Inspection Scope The inspectors completed three partial systerp walkdown inspection samples. The inspectors walked down the systems listed bglow to verify the system's operability when redundant or diverse trains and components lvere inoperable, The inspectors focused their review on potential discrepancies that cQuld impact the function of the system and increase plant risk. The inspectors reviewed Npplicable operating procedures, walked Enclosure down control system components, and verifiBd that selected breakers, valves, and support equipment were in the correct positipn to support system operation.

The inspectors also verified that PSEG properly gtilized its CAP to identify and resolve equipment alignment problems.

Documentq reviewed are listed in the Attachment.

r Unit 2, 4 service water (SW) bay with 2 $W bay out of service (OOS) on April 15. Unit 1, 3 SW bay with 1 SW bay OOS ori May 25 o Unit 1, 11 and 128 component cooling hpat exchanger (CCHX) with 12A CCHX OOS on June 1 b. Findinos No findings were identified.

1R05 Fire Protection (71111.05Q - 6 samples).1 Fire Protection - Tours a. Inspection Scope. Fire/Fresh water pump house b. Findinqs The inspectors completed six fire protection duarterly inspection samples. The inspectors walked down the systems listed bblow to assess the material condition and operational status of fire protection features.

The inspectors verified that combustibles and ignition sources were controlled in accorflance with PSEG's administrative procedures; fire detection and suppression e0uipment was available for use; that passive fire barriers were maintained in good material condition; and that compensatory measures for OOS, degraded, or inoperable fire protection equipment were implemented in accordance with PSEG's fire plan. Documbnts reviewed are listed in the Attachment.

o Unit 2, Turbine building, 88' elevation t r Unit 2, Turbine building, 100'elevation I o Unit 2, Turbine building, 120'elevation o Unit 1, 4160V Switchgear room and batteiy room, 64'elevation. Unit 2, Reactor Containment, 78', 100', alnd 130'elevations Introduction:

The inspectors identified a NCV of Salem Operating License condition 2.C.5, that requires PSEG implement all provisions of the Fire Protection Program as described in the UFSAR. Specifically, PSEG lstored a rod drive MG set in a CCZ without an engineering evaluation that assessed risk fnd established compensatory measures.This finding was determined to be of very low safety significance (Green).Descriotion:

PSEG procedure FP-AA-O11, "Control of Transient Combustible Material," governs the handling and limits the use of ordinary combustible materials and combustible and flammable liquids and gasesf An important part of this control program was the designation of transient CCZs. A CCY. was defined as an area in the plant in which transient combustible material is prohibited when not constantly attended or approved by a TCP. CCZ-Z,located in the Uriit 1 4160 volt switchgear room, on the 64'Enclosure 8 elevation, was established to limit ffoor hatches located above CCZ-2. On Ma to physical separation afforded by steel 9, 2011, inspectors identified a rod drive Specifically, the identified transient required to limit challenges to physical MG set removed during the spring Unit 2 outage (RFO) in CCZ-2. Further inspection revealed that an engineering to determine the risk and appropriate compensatory measures did not exist for transient combustibles located in this CCZ.The inspectors notified the control room notification was written.of this apparent deficiency, and a contained a step to obtain a TCP for the Replacement of the Unit 2 rod drive MG set s performed under WO 30141286, and A TCP was issued on March 29,2A11, to move the replacement rod drive MG set h CCZ-? and stage the machine for replacement during the RFO. The permit a fire loading of 800,000 BTUs, and the permit duration was three days. Followirfg replacement of the 22 rod drive MG set, the replaced rod drive MG set was set in.2 in preparation for rigging and removal from the auxiliary building for repair. lt was in CQZ-Z without a permit for approximately two weeks, because work due to high detritus levels in the river shifted resources that were originally to lift the MG set out of the CCZ. This is"Control of Transient Combustible Material," specified a TCP for transient combustibles staged in a CCZ. The inspectors determined that this was a performance deficiency because PSEG procedure FP-AA-O11 stated that transient combustible material was prohibited in a CQZ when not constantly attended or approved by a TCP. PSEG's immediate corrective actions were to issue a valid TCP and remove the transient combustibles from the CCZ within the next t$ree days.Analvsis:

This finding was more than minor se it was associated with the external factors attribute of the Mitigating Systems cornerstone objective to ensure the availa and adversely affected the y of systems that respond to initiating events to prevent undesirable combustibles were located in a CCZ that separation afforded by steelfloor hatches the CCZ. Using IMC 0609, Appendix F,"Fire Protection Significance Determination" the inspectors determined that this and Administrative Controls." issue involved the finding category, "Fire Referencing IMC 0609, Appendix F, 2, "Degradation Rating Guidance Specific to Various Fire Protection Program ts," the inspectors assigned a low degradation rating to the issues involving failure to comply with PSEG's transient combustible program. The inspectors'

were based on the fact that none of the items found in the combustible free zone could be considered transient combustibles of significance, as described in IMC 0609, x F, Attachment 2. This attachment defined transient combustibles of signi as low flash point liquids (below 200"F)and self-igniting combustibles (oily rags).degradation" rating, this issue was of very this item was assigned a "low safety significance (Green) in accordance with IMC 0609, Appendix F, Task 1.3.1.finding had a cross-cutting aspect in human performance in the area of work co because PSEG personneldid not coordinate work activities consistent with safety. Specifically, work groups did not communicate, coordinate, and with each other during the replacement and removalof the 22rod drive MG set in plant operating license. (H.3(b))to minimize fire risk and comply with the Enclosure 1R06.1 a..2 a.b.Enforcement:

License condition 2.C.5 requifes that PSEG implement and_maintain in effect all provisions of the Fire Protection Prfgram as described in the UFSAR. Section 9.S.1.1.2 of the UFSAR, "Use of Combustiblp Materials," states that "Administrative controls are established to minimize the quantity of combustibles in areas designated as combustible control zones." PSEG proceduie FP-AA-O11 defined a transient CCZ as an area in the plant in which transient combustiple materialwas prohibited when not constantly attended, or permitted by an app{oved TCP. Contrary to the above, on May g, ZOl1, the NRC identified that transieht combustible materials.were stored in a CCZ unattended and without an approved TCP. Specifically, a rod drive MG set with an estimated heat content of 800,000 BTU vivas located in CCZ-2. PSEG's immediate corrective actions for this issue were to issub a valid TCP and remove the transient combustibles from the CCZ within the next tfrree days. Because this issue was of very low safety significance and has been enterelJ into PSEG's CAP as notification 20509410, this violation is being treated as 0 NCV, consistent with Section 2.3.2a of the NRC Enforcement Policy. (NCV 05000272lpOttOOe-01, lmproper Control of Transient Combustible Material)Flood Protection Measures (71111.06 - 2 sfmples)lnternal Floodinq lnspection Scope The inspectors completed one internalflood protection inspection sample. The inspectors evaluated flood protection measrires for the Unit 2 inner mechanical penetration room.. The inspectors interviewfd engineering personneland.

walked down the areas to asseis the operational readinefs of the various features in place that were designed to protect the redundant safety-relpted components located in these rooms.TheJe features included plant drains, water{ight doors, sump pumps, and wall penetration seals. The inspectors also revi$wed the penetration seal inspection results, operator logs, and corrective action notificalions associated with flood protection measures.

The documents reviewed are lidted in the Attachment.

Findinos No findings were identified.

Insoection Scooe The inspectors completed one undergroun{

cable inspection sample. The inspectors evaluated the condiiion of safety-related cafles located in underground bunkers and manholes.

The inspectors interviewed engineering personneland inspected the conditions in manhole vaufts MH-23, MH-24, MH-28 and MH-GBT'24.

The inspectors verified that safety,related cables were not fubmerged in water, the integrity of the cables, the condition of cable support struclures, and the ability to dewater these structures.

Documents reviewed are listed Findinos No findings were identified.

n the Attachment.

Enclosure 10 1R07 Heat Sink Performance (71111.07A - 1 sample)Inspection Scope The inspectors completed one annual heat $ink performance inspection sample. The inspectors reviewed performance data and ifterviewed the NRC Generic Letter (GL)89-13 program manager to verify that potenlial heat exchanger (HX) or heat sink deficiencies were identified and PSEG adeqirately resolved heat sink performance reviewed are listed in the Attachment.

problems.

Specifically, the inspectors revievVed 21 CCHX data collected during a high heat load condition.

The inspectors evaluat$d trending data and verified that equipment would perform satisfactorily under design basis conditions.

The method of performance monitoring was compared to the guidance ptovided in NRC GL 89-13, "Service Water System Problems Affecting Safety-Related Squipment," and Electric Power Research Institute (EPRI) NP 7552, "HX Performance

[t/onitoring Guidelines." Documents b. Findinos No findings were identified.

A sample of visual inspection techniques indluded the areas of the containment inner boundary at the containment liner to containinent floor intersection.

The inspectors observed the visual examination scope of thF containment liner boundary and the examinations done of the area of the contairfment liner to floor intersection to the American Society of Mechanical Engineers (ASME) Code Section Xl lWE, per procedure OU-M-335-OB-R3.

This included inspection of the process for remote visual and ultrasonic examination of the Ya" thicK contaihment liner under the floor concrete surface.ln addition, the inspectors observed the con{itions and the ASME Section Xl visual examination scope in the 25J44 valve room and the containment sump areas.For component replacement work, the inspeptors observed the installation and reviewed the work orders for the replacement of checfi valve 21-BF-22in the feedwater (FW)1R08 Inservice Inspection (lSl) (71111.08 - 1 sample)Inspection Scooe Activities inspected during the Salem Unit 2 ling outage 18 (2R18) included and data review of component testing observations of ultrasonic testing (UT)in-progress using manual UT techniques.

is included UT of the 14" diameter residual heat removal (RHR) piping welds 1211-4,1 11-7, and 1211-13, done per procedure 54-151-836.

The UT technique and the of examining the area around the reactor r procedure 54-lsl-108-006 were reviewed pressure vesselflange threaded stud holes with the UT technician who performed the Additionally, the technique for UT examination of the pressurizer nozzle to ell inner radius was inspected, the by EPRI modeling was discussed with the implementation of the technique as UT technician, and the completed n data package was reviewed.

The data also reviewed.

The task work orders and package for the UT examination of the'izer girth shell to upper head weld was data for several ultrasonic and visual examinations were reviewed and confirmed be evaluated by PSEG as part of the lSl process.Enclosure 11 system. The work instruction package, i the requirements for welding and related quality verifications, was reviewed.itionally, the preparations for radiographic testing (RT), the RT procedure and radiographs of the two 14" diameter, 1.094" thick circumferential FW pipe welds welding parameters and observed FW pipe ASME Code fabrication requirements.

reviewed.

The inspectors reviewed welds for comparison to the As the Salem Unit 2 upper reactor pressure (RPV) head with control rod drive mechanism (CRDM) penetrations was cerltly replaced, no detailed examination of the the 2R18 outage. The inspectors visually head to confirm the absence of evidence upper head.In the area of other boric acid corrosion con (BACC) activities, the inspectors confirmed the extent of plant boric acid and noted that identified problem areas during the plant shutdown process documented in Condition Report Notifications for resolution.

The inspectors observed corrective actions in the plant, up on boric acid evaluations and The Salem Unit 2 auxiliary feedwater (AFW)piping, control air, and service air lines that were excavated to determine the condition the pipe coating and pipe integrity was observed.

The results of guided wave ultrasonic thickness measurements and the recoating of this piping were examined.inspectors verified that these pipes had been adequately protected while buried.inspectors confirmed that the Unit 2 AFW piping was pressure tested during the plant process to meet the ASME Code Section Xl pressure test requirement a to buried piping. Documentation of the CRDM to head welds were performed in observed the lower circumference of the of boric acid leakage from the CRDMs or Unit 2 AFW and air lines rerouting to above the connection points outside the Unit 2 con reviewed the extent of examination of other Nuclear SW header and the intake structure in the Fuel Transfer Tube Area and nment were examined.

Records of the pipe systems including the 21 turbine building 30" diameter piping.post-modification AFW pressure testing reviewed.

ln addition, the inspectors In the area of piping dissimilar metalwelds (PMW), the inspectors verified that for the Unit 2 cold leg piping welds previously found to be acceptable by UT during 2R17, but not mechanically stress improved as planned, would be re-examined by UT in the 2014 refueling outage in accordance with the MRF-139 DMW program.There were no ASME Section Xl non-destruQtive examination (NDE) indications from previous outages that required follow-up insflection during 2R18.For Steam Generator tube eddy current testiirg (ECT), the inspectors reviewed the Steam Generator Degradation Assessment (pocument 51-9152234-000)

for 2R18, noting that inspection was planned for all the tubes in each steam generator including the tube u-bend areas.The PSEG Document OU-SA-335-1010, ReVision 2, "Steam Generator Data Analysis," Procedure ER-AP-420-0051, Revision 14, "Conduct of Steam Generator Management Activities," Document 51-91 18973-001, "Quaf ified Eddy Current Examination Techniques for Salem Unit 2," Procedure 54-lsl-400-019J "Multi-Frequency Eddy Current Enclosure 12 1R11 ,1 a.Examination for Tubing," and other listed in the Attachment were of ECT inspection team and review confirmed to be in use by interviews with of computer based records. The inspectors that eddy current analysts were qualified and confirmed to be prepared for site specific conditions of the Unit 2 steam generators by applicable testing. The of data and the data analysis process were observed.

The independent quality analyst work scope was reviewed to the ECT process.confirm the extent of independent oversight Findinqs No findings were identified.

Licensed Operator Requalification Proqram 71111.11Q - 1 sample)Insoection Scope The inspectors completed one quarterly lice operator req ualification program inspection sample. Specifically, the i observed an unannounced simulator scenario on May 25,2011. The scenario i a small break loss of coolant accident which was complicated by a damaged AFW tank and a ruptured containment spray pipe which caused a loss of Fuel element damage during the scenario led to a general emergency action The inspectors reviewed operator actions to implement the abnormal and ncy operating procedures.

The inspectors examined the operators'

ability perform actions associated with high risk activities, the Emergency Plan, previous learned items, and the correct use and implementation of procedures.

The i also observed and verified that the deficiencies were adequately identified, rssed, and entered into the CAP, as in the Attachment.

appropriate.

Documents reviewed are$amples)b. Findinqs No findings were identified.

1R12 Maintenance Effectiveness (71111J2Q - 2 a. Insoection Scooe The inspectors completed two quarterly effectiveness inspection samples.The inspectors reviewed performance moni ng and maintenance effectiveness issues for the systems listed below. The reviewed PSEG's process for monitoring equipment performance and assessing tive maintenance effectiveness.

The inspectors verified that systems and nts were monitored in accordance with the inspectors confirmed that the functional for these systems were documented in maintenance rule program requirements.

failure determinations and unavailability accordance with the maintenance rule and PSEG established performance goals for these systems were met. The inspectors reviewed applicable work orders (WOs), corrective action notifications, and maintenance tasks for these systems. The documents reviewed during the inspection listed in the Attachment.

Enclosure o Unit 1 r Unit 2 l 13 reactor vessel level instrumentatidn RVLIS system (RVLIS)b.Findinqs No findings were identified, (71111.13 - 5 samples)lnspection Scope meetings, control room tours, and plant The inspectors used PSEG's on-line risk monitor (Equipment OOS) to gain insights into the risk associated with these plant configurations.

The inspectQrs also reviewed corrective action notifications written to document problems iated with risk assessments and emergent work evaluations.

Documents are listed in the Attachment.

o Units 1 and Unit 2, switchyard planned o Unit 2, Defuelto Mode 6 with 21 chilled ter pump and the 21 control area chiller on 3T60 disconnect on April 1 planned maintenance and 22 control April25 chillers unplanned maintenance on o Unit 1,28V emergent battery cell on May 19 o Unit 2, 23 control area ventilation supply , 23 control area chiller, and 25 containment fan coil unit planned mai on May 19 and CAA-12 planned maintenance on o Unit 1, control area ventilation dampers June 21 Findinss Introduction:

A self-revealing finding of very safety significance was identified on April 1 ,2411, because 500 KV load break 3T60 failed to operate upon the restoration of switchyard maintenance.

This used a four hour delay in the restoration from a single source of offsite power, the from a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> LCO, and the extension of revealed that the vendor. who was a yellow PRA condition.

PSEG investigatio conducting maintenance on the 3T60 removed the motor controlfuse holder that was not part of the tagout for the main. PSEG determined that the cause of the disconnect not closing was that PSEG di not adequately brief and control the maintenance evolution.

Description:

Salem Units 1 and 2 have two circuits between the offsite transmission 1R13 a.Risk b.ically independent alternating current and the onsite Class lE (Vital)distribution system. On March 30,2011, al Salem Units 1 and 2 were operating at 100% power when the station aligned offsite to one independent alternating a yellow PRA condition in support of current circuit and entered a72-hour LCO a Enclosure 14t switchyard maintenance.

The planned maihtenance was completed and the 3T60 circuit switch was operated on April 1 ,2011, at 04p0 to restore the normal offsite power lineup, but did not operate as expected.switchyard in response to the event and removed from the fuse block. PSEG walkdown of the 3T60 disconnect circuit switch at0749, three hours and 49 minutes after the original attempt to the 3T60 disconnect.

PSEG entered this event into the CAP as notification PSEG performed an apparent cause (ACE) and determined that not using the pre-job brief procedure checklists and use of the standards, policies, and administrative controls required to perform 3T60 configuration error. The vendor who disconnect removed the motor controlfuse work were the apparent cause of the to the circuit switcher to prevent inadvertent actuation of the disconnect.

fuse removalwas not documented in accordance with PSEG administrative and was not communicated to station personnel.

The removal of the fuses was specified by any procedure for the task the vendor was performing and the fuse lwas inside the tagging boundary.

Because there was no documentation of the removal the fuse holder. there was no documentation requiring the reinstallation the fuse holder.maintenance delays encountered earlier The operations department walked down found the 3T60 motor controlfuse holder restored the fuse holder and performed a area. Operations successfully closed the The PSEG ACE also documented that, due in the day, there was no PSEG oversight of procedure required that a PSEG supervisor work. The maintenance delays caused the there was no yard electrical supervisor switchyard.

Additionally, PSEG worksite walkdown after the vendor work Oversight of Supplemental Workforce," was determined that the performance deficiency and it adversely affected the cornerstone upset plant stability and challenge critical PSEG procedure for the management and a four hour extension in an elevated risk maintenance on the 3T60 vendor work even though PSEG's all portions of the vendor performed to continue into the night shift where to oversee the maintenance in the that personnel performed an inadequate performed.

This walkdown was another ive to limit the likelihood of events that functions.

Specifically, not following the ht of supplemental personnel caused during which Salem Units 1 and 2 had barrier that should have discovered that the fuse holder was removed.Analysis:

The inspectors determined that failure of PSEG to assign a supplemental workforce supervisor or task manager to continuous in-field supervision of the 3T60 disconnect maintenance in accord with AD-M-2001, "Management and performance deficiency.

The inspectors more than minor because it was associated with the human performance of the Initiating Events cornerstone, only one source of offsite electrical power.The finding was determined to be of very safety significance (Green) in accordance with IMC 0609, Appendix A, "Determining Significance of Reactor lnspection Findings for At-Power Situations," using Phases 1,2and 3. Phase 1 screenedthe finding to Phase 2 because the inspectors that the finding contributed to both the likelihood of a reactor trip and the that mitigating systems would not have been available.

This conclusion was based offsite power given only one power source the increased chance of a loss of the loss of redundancy in power supplies Enclosure model to calculate the increase in core 1R15 Ooerabilitv Evaluations (71111.15 - 5 sam a. Inspection Scooe 15 to mitigating equipment.

A Region I Senior Analyst (SRA)performed a Phase 3 analysis because the Phase 2 analysis by the inspectors using the Salem Pre-solved Risk-lnformed Inspection than very low safety significance.

indicated that the finding could be more Salem Units 1 and 2 were selected for the lot implementation of the NRC's SAPHIRE 8 risk analysis SDP interface tool using the specific SPAR modelfor the conduct of Phase 2 SDP evaluations.

This tool allows inspector to enter specific equipment and period and uses the plant specific SPAR frequency.

During the pilot period the human action failures and specify the expos SDP process currently document in IMC including use of the Salem Pre-solved Risk-lnformed Inspection Notebook and an additional SRA performed Phase 3 evaluations represent the official result. For is type of situation the pilot guidance directs the SRA to conduct a Phase 3 a The SRA performed a Phase 3 evaluation ting an increase in core damage unit, assuming: frequency in the low E-9 per year range for. An increase in the initiating event of a plant centered loss of offsite power.To estimate this value the analyst took square root of the frequency used with two offsite sources available (a a factor of twenty increase);

and o Both Salem Units were operating with a of their safety busses aligned to one of the two offsite power sources for a period of hours.The inspectors determined that this finding a cross-cutting aspect in the area of human performance, because PSEG did ensure supervisory and management oversight of the vendor work activity.

S , PSEG personnel did not conduct an adequate pre-job brief with the vendor, did assign a supervisor to provide in-field post-maintenance restoration walkdown of supervision, and did not conduct an the 3T60 switchyard maintenance. (H.a(c))Enforcement:

This finding does not involve action because no regulatory requirement violation was identified.

this finding does not involve a violation and has very low safety significance, it is tified as a finding. (FlN 05000272, 0500031 1/201 1003-02, Inadequate C of Switchyard Maintenance)

The inspectors completed five operability tion inspection samples.raded or non-conforming The inspectors conditions reviewed the operability determinations for associated with:. Unit 2, charging pump cold leg injection r Unit 2, safety injection pump cold leg inj r Unit 1,12A CCHX discharge valve 12Sr testing o Unit 2, power relief valve 2PR1 did not coolant pressure valves 22 and 23 SJ 17 back leakage check valve 22 SJ 144 back leakage-383 failure to fully open during surveillance in manual at reduced reactor system Enclosure b.. Unit 2, boron injection tank slow urization The inspectors reviewed the technical of the operability determinations to ensure the conclusions were justified.

The i also walked down accessible equipment to corroborate the 6dequacy of Additionally, the inspectors reviewed other's operability determinations.

G identified safety-related equipment deficiencies during this report period and the adequacy of their operability screenings.

Documents reviewed are listed the Attachment.

Findinos No findings were identified.

Plant Modifications (71111.18 - 1 sample)1R18 Permanent Modification a. Inspection Scope this permanent plant modification was also listed in the Attachment.

b. Findinos No findings were identified.

1R19 Post-Maintenance Testins (71111.19 - 6 a. lnspection Scope The inspectors completed six post-mai inspectors observed portions of and/or activities listed below. The inspectors The inspectors completed one plant tion inspection sample. The inspectors reviewed the permanent modification capability of 2CC30, the 21 CCHX to The inspectors'

review verified that the des capability of the affected systems were not by the modifications.

The inspectors verified the new configuration wa accurately reflected in the design testing was adequate to ensure the documentation and that the post-modificati structures, systems, and components a would continue to function properly.

The inspectors also interviewed plant staff and issues that were entered into the CAP to assess whether PSEG was effective t identifying and resolving problems associated with the modification process.10 CFR 50.59 screening associated with used to increase the thrust output component cooling header stop valve.bases, licensing bases, and performance The documents reviewed are ples)testing (PMT) inspection samples. The the PMT results for the maintenance that the effect of testing on the plant was adequately addressed by control room and ineering personnel; testing was adequate for the maintenance performed; acceptance were clear, demonstrated operational readiness, and were consistent design and licensing basis documentation; test instrumentation was current and the appropriate range , as written, with applicable and accuracy for the application; tests were Enclosure 17 maintenance. WO 60096626, 1428 Vdc battery cell 1 b. Findinos No findings were identified.

1R20 Refuelins and Other Outaqe Activities (71 1 a. Inspection Scope The inspectors reviewed the schedule and S2R18 to confirm that PSEG appropriately cool down rates were within Technical entered containment at the start of the Unit 2 RFO(S2R18).

The inspectors complQted one RFO activity inspection sample.The inspectors observed or reviewed the following RFO activities to verify that operability requirements were met and that fisk, industry experience, the fatigue rule, and previous site specific problems were coi"rsidered.

Documents reviewed are listed in the Attachment.

replacement 1 sample)assessment documents associated with idered risk, operating experience, and site specific problems in developing and i ng a plan that ensured maintenance of defense-in-depth systems and barriers.PSEG's outage risk assessment to identify to S2R18, the inspectors reviewed sk significant equipment configurations and determine whether planned risk actions were adequate.

During S2R18, the inspectors verified that PSEG managed outage plan.outage risk in accordance with the The inspectors observed portions of the and cooldown processes and monitored PSEG controls over the outage The inspectors also verified that (TS) limitations.

The inspectors outage to check for evidence of previously unidentified reactor coolant leakage.containment entries to inspect for ind S2R18, the inspectors made additional of unidentified leakage, damaged equipment, foreign material control, radia worker work practices and fire prevention.

activities from the refueling bridge in The inspectors observed portions of containment and the spent fuel pool (SFP)to verify refueling gates and seals were I exclusion boundaries were established properly installed and verify that foreign around the reactor cavity. Core offload and reload activities were periodically observed from the control room and refuel prerequisites satisfied; and equipment was to perform its safety function.

Documents. WO 30186101, 2C EDG engine 1 overhaul o WO 50137318, 13 AR/V pump complex r WO 30186100, 28 EDG planned maintr. WO 30131825,11 AFW pump breaker r. WO 60096650, 2 main generator high p snootrng during refueling outage ntenance sealoil back-up pump motor bridge to verify operators adequately approved procedures.

to an operational status and ready are listed in the Attachment.

controlled fuel movements in accordance Enclosure The inspectors verified that tagged equ t was properly controlled and equipment configured to safely support maintenance. Specifically, inspectors observed the control of work activities in the auxiliary ing during reduced inventory to verify that risk of unplanned equipment unavailability minimized.

Equipment work areas were riqn material exclusion boundaries were periodically observed to determine whether adequate.During control room tours, the inspectors that operators maintained adequate reactor coolant system (RCS) level and expected range for the operating mode.re and that indications were within the The inspectors verified that offsite and o electrical power sources were maintained in accordance with TS requirements and with the outage risk assessment.

Periodic walk downs of portions of the electrical buses and the EDGs were performed during risk significant electrical The inspectors verified through routine status activities that the decay heat removal safety function was maintained with the redundancy as required by TS and consistent with PSEG's outage risk. During core offload, the inspectors periodically verified that the fuel pool system was performing in accordance with PSEG's risk assessment for the RFO.plant design parameters and consistent The inspectors observed the Unit 2 RCS ning to a reduced inventory condition on May 1 ,2011. RCS inventory controls and plans were reviewed by inspectors to verify that they met TS and provided for adequate inventory control. The inspectors reviewed proced and observed portions of activities in the control room when the unit was in reduced ntory modes of operation.

The inspectors verified that level and core measurement instrumentation were installed and operational.

Calculations that time to boil information were also reviewed for RCS reduced inventory heat load conditions.

as well as the SFP during increased Inspectors verified that PSEG managed ue of outage workers by reviewing a sample of waiver requests, self declarations, and assessments that were available near the end of the RFO. PSEG scheduled individuals working on outage activities workers such that minimum days off for in compliance with the fatigue rule. In addition, control room staff for Unit 1 rema on operating unit work hour controls.Containment status and procedural controls offload and reload activities to verify that TS reviewed by the inspectors during fuel containment.

Specifically, the inspectors procedure requirements were met for that during fuel movement activities, personnel, materials, and equipment were specified in the licensing basis.to close containment penetrations as The inspectors performed a thorough walk of containment prior to reactor startup.Areas of containment where work was were inspected for evidence of leakage and to ensure debris that could The condition of equipment used for fire containment sump pumps were removed.n, prevention, and suppression were inspected for operability and functionality.

of mode changes and reactor startup applicable procedures and TS.were observed and reviewed for compliance Enclosure b. Findinqs No findings were identified.

1R22 Surveillance Testinq (71111.22-

8 samples a. Insoection Scope b. Findinos No findings were identified.

lEPO Drill Evaluation (71114.06 - 1 sample)a. Inspection Scope The inspectors completed eight surveillance testing inspection samples. The inspectors observed portions of and/or reviewed result$ for the surveillance tests listed below to verify, as appropriate, whether the applicablb system requirements for operability were adequately incorporated into the procedure!

and that test acceptance criteria were consistent with procedure requirements, the TS requirements, the Updated Final Safety Analysis Report, and ASME Section Xlfor pilmp and valve testing. Documents reviewed are listed in the Attachment.

o S2.OP-ST.AF-0007, 23 AFW Pump Full llow Test o S2.OP-LR.AF-0001, AFW Piping Pressufe Drop Test o S2.OP-ST.SSP-0004, SEC Mode Ops Tpsting 2C Vital Bus. S2.OP-LR.FP-0001, Type C (ClV) Leak ftate Test, 2FP1 47 and 2FP148 r S2.OP-ST.CS-0005, 22 CS Pump Full Fllow Test. 52.OP-ST.SJ-0O15, lntermediate Head ltlot Leg Throttling Valve Flow Balance Verification o S2.OP-LR.CS-0001, Type C (ClV) Leak r S2.OP-ST.AF-0006, Inservice Testing A Feed Water Valves Test, 21CS2, 21CS10, and 21CS48 b.The inspectors completed one drill inspection sample. On May 25,2011, the inspectors observed emergency plan respon actions at the simulated control room and the Emergency Operation Facility d an emergency preparedness drill. The inspectors evaluated operator performance and notifications.

The inspectors reviewed to developing event classifications inspectors referenced Nuclear Energy Salem Event Classification Guides. The (NEl) 99-02, "Regulatory Assessment Performance Indicator (Pl) Guideline," Revi 6, and verified that PSEG correctly counted the evaluated scenario's contri performance.

to the NRC Pl for drill and exercise Findinss No findings were identified.

Enclosure 2.20 RADIATION SAFEW Cornerstone:

Radiation Safety - Public and (71124.01)

Inspection Scooe Radiolooical Hazard Assessment The inspectors selected radiologically risk work activities associated with the Unit 2 RFO (2R18) that involved exposure radiation.

These activities included the four highest collective exposure activities sched support activities; primary steam generator the containment; and pressurizer activities.

for the outage: radiation protection surveys were performed, which were to identify and quantify the radiological hazard and to establish adequate protective res. The inspectors evaluated the radiological survey program to determine if identified:

following hazards were properly. ldentification of hot particles;. The presence of alpha emitters;including the potential presence of adioactive materials; that could suddenly and severely can result in non-uniform exposures of the The inspectors reviewed radiation work its (RWPs) used to access high radiation areas (HRAs) and identify what work control ions or control barriers had been specified.

The inspectors verified that a stay times or permissible dose for radiologically significant work under each was clearly identified.

The inspectors verified that electronic personal dosimeter (with survey indications and plant policy.) alarm set points were in conformance The inspectors selected occurrences where worker's EPD noticeably malfunctioned or responded appropriately to the off-normal alarmed. The inspectors verified that condition.

The inspectors verified that the i was included in the CAP and dose 2RS1 a.current activities; scaffold activities in inspectors verified that pre-work The potential for airborne radioactive transuranics and/or other hard-to-detect The hazards associated with work activi increase radiological conditions; and Severe radiation field dose gradients tha body.The inspectors selected air sample survey rQcords and verified that samples were collected and counted in accordance with PEEG procedures.

The inspectors observed work in potential airborne areas and verified fhat air samples were representative of the breathing air zone. The inspectors verified tltpat PSEG has a program for monitoring levels of loose surface contamination in areas of the plant with the potential for the contamination to become airborne.Instructions to Workers evaluations were performed as appropriate.

Enclosure b.and 21 Radia The inspectors observed the controls and ures for high-risk HRAs and VHMs.not substantially The inspectors verified that any changes to G procedures did reduce the effectiveness and level of protection.

The inspectors reviewed the controls in for special areas that have the potential to become VHRAs during certain plant The inspectors verified that PSEG controls for all VHRAS, and areas with the to become a VHRA, ensured that unauthorized individuals were not able to Radiation Worker Performance in access to the VHRA.During job performdnce observations, the observed radiation worker performance with respect to stated ra protection work requirements.

The inspectors determined that workers were of the significant radiological conditions in their workplace, RWP controls/limits in place, and that their performance reflected the level of radiological hazards The inspectors reviewed radiological reports since the last inspection that found the cause of the event to be human ce errors. The inspectors determined that there was no observable pattern tracea to a similar cause. The inspectors determined that this perspective matched corrective action approach taken by PSEG to resolve the reported problems.

The discussed with the Radiation Protection Manager any problems with the corrective planned or taken.During job performance observations, the observed the performance of the radiation protection technician with respect The inspectors determined that technicians radiation protection work req uirements.

aware of the radiological conditions and the RWP controls/limits in their and that their performance was consistent with their training and qualifications with activities.

to the radiological hazards and work The inspectors reviewed radiological reports since the last inspection where the cause of the event was found to be protection technician error. The inspectors determined that there was no observable traceable to a similar cause. The inspectors determined that this perspective the corrective action approach taken by PSEG to resolve the reported Findinss No findings were identified.

{71124.02)

Inspection Scope Rad iation Worker Performance 2RS2 a.ALARA Enclosure 22 The inspectors observed radiation worker a radiation protection technician performance during work activities being radioactivity areas, and HRAs associated in radiation areas, airborne b.The inspectors determined that workers the ALARA philosophy in practice and that there were no procedure complia issues. Also, the inspectors observed radiation worker performance to determine the training and skill level was sufficient with respect to the radiological and the work involved.Findinos No findings were identified.

(71124.03)

a.Inspection Scope concentrated on work activities that airborne radioactivity in work areas below extent practicable.

2R18 activities.

The inspectors the greatest radiological risk to workers.concentrations of an airborne area to the 2RS3 lnspection Planninq The inspectors reviewed the plant final safetf analysis report (FSAR)to identify areas of the plant designed as potential airborne radiption areas and any associated ventilation systems or airborne monitoring instrumentation.

The inspectors reviewed the FSAR for an overview of the respiratory protection m and a description of the types of devices used. The inspectors reviewed the SAR, TSs, and emergency planning documents to identify the location and of respiratory protection devices stored for emergency use. The inspectors PSEG's procedures for maintenance, inspection, and use of respiratory protection ipment, including self-contained breathing apparatus.

Additionally, the i reviewed procedures for air quality maintenance.

The inspectors reviewed the performance indicators to identify any related to unintended dose resulting frorfl intakes of radioactive materials.

Enqineerinq Controls Permanent and Temoorarv Ventilation The inspectors verified that PSEG used controls, in lieu of respiratory protection on systems as part of its engineering , to controlairborne radioactivity.

The inspectors reviewed procedural guidance use of installed (permanent)

plant systems, and verified that the systems were used, to activities.

The inspectors selected installed extent practicable, during high-risk systems used to mitigate the potential for airborne radioactivity, and that ventilation airflow capacity, flow path, and filter/charcoal unit efficiencies were with maintaining concentrations of The inspectors selected temporary ventila system setups high-efficiency particulate air used to support work in contaminated. The inspectors verified that the use of these systems was consistent with PSEG ralguidance and ALARA.Enclosure 23 Airborne Monitorinq Protocols The inspectors selected installed systems t monitor and warn of changing airborne concentrations in the plant. The inspectors sufficient to prompt PSEG/worker action to limits of 10 CFR Part2} and ALAM. The i erified that alarms and setpoints were 4. OTHER ACTIVITIES 4OA1 Performance Indicator (Pl) Verification (711 a. Inspection Scope nsure that doses were maintained within the the accuracy of the Pl data reported during definition and guidance contained in NEI 99-complications; and spectors verified that PSEG had established trigger points for evaluating levdls of airborne beta-emitting and alpha-emitting radionuclides.

Problem ldentification and Resolution The inspectors verified that problems associated with the control and mitigation of in-plant airborne radioactivity were being identified by PSEG at an appropriate threshold and were properly addressed for resolution in their CAP.Findinos No findings were identified.

1 - 6 samples)The inspectors reviewed PSEG submittals the Unit 1 and Unit 2 initiating events cornerstone Pls discussed below. To this period the data was compared to the Pl 02, "Regulatory Assessment Performance I Guideline," Revision 6.Cornerstone:

lnitiatinq Events. Unit 1 r Unit 1 o Unit 1 and Unit 2 unplanned scrams;and Unit 2 unplanned scrams wi and Unit 2 unplanned power cha b.The inspectors verified the accuracy of the ata by comparing it to CAP records, control room operators'logs, the site operating database, and key Pl summary records.Findinos No findings were identified.

ldentification and Resolution of Problems 152 - l annual sample; 1 trend sample)As specified by lnspection Procedure 711"ldentification and Resolution of Problems," ent failures or specific human performance and in order to help identify repetitive a daily screening of all items entered into 4c.A2 ,1 issues for follow-up, the inspectors Enclosure

,2 24 PSEG's CAP. This was accomplished by the description of each new commiftee meetings.

Documents notification and attending daily ma revtew reviewed are listed in the Attachment.

lnspection Scope The inspectors selected an issue with E not shutting down after receiving a stop signalas documented in notification 701111 as a problem and identification resolution sample for a detailed follow-up review. No cation 70111159 documented that the 1A EDG failed to shut down by normal at the completion of testing in accordance with surveillance test S1.OP-ST.SSP-0002.

related 4kV electrical busses in the event of initiated to evaluate the 1A EDG continuing The EDGs provide power to the safety-loss of offsite power. This notification was run after the local control switch was placed in the stop position, and referenced milar conditions had previously occurred with the 1B and 2A EDGs. PSEG de that the failure to trip was the result of induced voltages across the coils of the shu relays caused by failures of filtering capacitors on the inputs of the power of the EDG annunciator panels. PSEG determined that the safety function of the to supply AC power to the 4kV emergency busses was not impacted by the was placed in the stop position.failure to stop when the local control switch The inspectors assessed PSEG's problem extent of condition evaluations, operability tification threshold, cause evaluations, tions, and prioritization of corrective actions to determine whether PSEG was identifying, characterizing, and correcting problems associated with issues and whether the planned and to prevent recurrence.

The inspectors identified issues, completed corrective completed corrective actions were app also interviewed plant personnel regarding actions, and planned corrective actions.inspectors reviewed design standards issued by the lnstitute of Electrical and issued by the NRC to determine requiremen nic Engineers and General Design Criteria for preventing interactions between safety-related and non safety-related equi Attachment.

t. Documents reviewed are listed in the Findinos and Observations No findings were identified.

The inspectors identified that PSEG implernented their CAP regarding the issue which was reviewed.

The notification were complete and included cause evaluations, operability evaluations, extent condition reviews, operating experience information (both internaland external), and listings of completed and planned corrective actions. The corrective actions to be appropriate to minimize the that corrective actions included potential for recurrence.

The inspectors periodic replacements of the annunciator supplies, changes to the power supply purchase orders, changes to the preventive nce of spare power supplies in storage, and changes to testing of power in service. For this issue, PSEG performed adequate operability evaluations, adeq uate corrective actions, and initiated appropriate procedure The inspectors also determined that function of the EDGs to provide power to PSEG appropriately identified that the Enclosure

.3 a.25 the emergency 4kV busses during loss of failure of the EDGs to trip on demand.power was not compromised by the Semi-Annual Review to ldentifv Trends Inspection Scope No findings were identified.

During this review the inspectors noted a tive trend continue in the containment fan cooling unit SW effluent radiation monitor (R 3) reliability.

PSEG has taken action to authorize replacement of these radiation record of reliability at other nuclear plant with a design that has a proven track Compensatory measures are in place for the R13 radiation monitors that are not to ensure that their safety function is maintained.

Previous actions to improve the not effective.

ity of these radiation monitors were Additionally, there were two instances of i inservice tests on AFW pumps that required complex troubleshooting and PSEG resources to resolve. The 13 AFW pump failed its inservice test and was inoperable during the Unit 2 RFO.The complex troubleshooting specified two additional pump runs to determine that the discharge pressure test instrumentation was blocked, and the test gauge. The quick disconnect fitting that was reading a lower than actual discharge was causing the problem was removed, and tfie pump test results returned to the acceptable band. A degrading trend of test were seen for the 11 AFW pump, and preparations were made to perform ivelmaintenance as a contingent action to a failed test result. Troubleshooting was during the test of the 11 AFW pump, and a similar quick disconnect fitting was fourid on the discharge pump pressure connection.

During this troubleshooting, the reading obtained was higher than As specified by lnspection Procedure 71 152f "ldentification and Resolution of Problems," the inspectors performed a review of PSEG'$ CAP and associated documents to identify trends that could indicate the existence of a fnore significant safety issue. The inspectors'

review was focused on repetitiveimaintenance and corrective maintenance issues, but also considered the results of thQ daily inspector CAP screening discussed in Section 4OA2.1. The review included issue$ documented in system health reports, corrective maintenance WOs, maintenance rlule assessments, and plant health committee meeting reports. The inspectors'fieview nominally considered the six month period of December 1, 2010 through May 31 ) 2011, although some examples expanded beyond those dates when the scope of the trbnd warranted.

Corrective actions associated with a sample of the issues identified in PSEG's trend report were reviewed for adequacy.

Documents reviewed are listep in the Attachment.

Assessments and Observations trend that had been identified was due to inacpurate test results in previous tests, and the most recent pump test results were wellwithin the acceptable range for the test.PSEG corrective actions include a revision to fhe test procedure to look for degraded quick connect test fittings as part of initial troupleshooting for unexpected IST results.Enclosure 26.1 4OA3 Event Follow-up (71153 - 5 samples)Event Bypass of Steam Generator Blowdown Valve lsolation during On February 24, 2011, the Control Room (CRS)questioned the testing being performed for the replacement of the steam high radiation relay (HR1) in the steam generator blowdown radiation moni (1R198) test circuit. Jumpers were to be installed in accordance with section 5.1.5 of 51.IC-FT.RM-0129 to prevent the closure of the 11 to 14 GB4 steam ge blowdown isolation valves during functional testing of the 1R198 radiation monitor. The 3RS questioned whether the jumpers closure of the GB4 valves. The jumper was affected more than just the radiation moni determined to not only prevent closure of GB4 valves from a radiation monitoring signal but would also prevent closure of the on the automatic start of the AFW pumps. The jumper installation did not im containment isolation signal.the ability of the GB4 valves to close on a tic closure of the steam generator The cause of bypassing the AFW pump blowdown isolation valves during steam blowdown radiation monitor functional testing was due to knowledge errors during preparation and review of procedure 51.IC-FT.RM-O129.

Corrective actions in personnel accountability and procedure times that it existed during the revisions.

PSEG analyzed this condition surveillance tests, and determined that the safety function was not lost during these time periods. The NRC determined this was a minor violation of regulatory requirements, due to the existence of an test. This LER is closed.nalyzed condition during this surveillance

.2 (Closed) LER 05000272/2011-003-0.

Manu{l Reactor Trip Due to Degraded Condenser Heat Removal On April 21, 2011, at approximately 4:00 Pfvt, a manual reactor trip was initiated with reactor power level at approximately 89 per(ent. The manual reactor trip was initiated in response to a degraded circulating water (CyV) system and in accordance with abnormal operating procedures.

The CW system degrfadation was due to heavy detritus loading that affected the ability of CW traveling watei screens to operate, and the resultant loss of circulating water pumps.The unit was returned to service on April 23, 2011 , at 5:19 AM, after the debris was cleared from the screens, condenser water $oxes were cleaned, and the established management criteria developed in the Oper4tional and Technical Decision Making Process were met. The inspectors complet$d a review of this LER and did not identify a violation of regulatory requirements.

This L$R is closed.(Closed) LER 05000311/2011-001-0.

21SW122lsolation Function Inoperable Greater Than Allowed By Technical Specification On May 17,2010 at 1:16 AM, while performing a high flowflush of the No.21 CCHX, the specified SW flow range of 9000 - 10000 gallons per minute could not be achieved.Technical Specification Action Statement (TFAS) 3.7.3 was entered. A PSEG team established to investigate the CCHX low SV\if flow issue determined that the 215W122 valve was not controlling flow. The valve w{s declared inoperable on May 17 at 10:05 Enclosure.3 27.4 (Closed) LER 05000311/2011-002-0.

Fail 3.4.5 and 3.4.10.3 room personnelattempted to open 2PR1 failed to open again. At this point it was AM and Containment Integrity TSAS 3.6.1.1 was entered. The No. 21 CCHX was isolated on May 17 at 10:53 AM and TSAS q.6.1.1 was exited. Troubleshooting activities identified that the shaft of the No. Al CCHX inlet air operated valve 21SW122 had corroded to the point of complete severiflg at the stem to body interface.

The valve stem was replaced and the valve returned tQ operable status on May 18, 2010. A past operability evaluation was completed ofp May 28,2010, This evaluation concluded that the valve was inoperable for the closed (Containment Integrity)

direction.

On February 16,2011, during an NRC inspectiofr of the 215W122 repair and extent of condition reviews, it was discovered that the 215W122 being inoperable greater than the TS allowed action time had not been repprted in accordance with 10 CFR Actions taken included replacement of all inspectors'

review of this issue resulted in a Severity Level lV NCV, specifically that PSEG personnel did not provide a written report to the NRC within 60 days after.5 discovery of a condition prohibited by TS LCp 3.6.1, "Containment lntegrity." The 0500027212011002 and 0500031112011002.

Section 4042.2. This LER is closed.On April 11,2011, at 11:51 AM, control to Comply with Technical Specification personnel entered TS 3.4.10.3 Act b to support testing of the Pressurizer Protection System channel 1 (2PR1) in accordance with procedure 52.OP-ST,PZR , "lnservice Testing Pressurizer and Reactor Head Vent Valves." When the valve was demanded to open as the test channel 1 test light illuminated, but the key switch was turned to the test position, valve did not respond as expected.

2PR1 s restored to its pretest position; however, 2PR1 remained inoperable and off.satisfactorily testing of 2PR2, control normalcontrolroom bezel, but 2PR1 ined that 2PR1 had been inoperable since the entry into Mode 5 on April 10 at2: 1 AM, and that Salem Unit 2 had operated in a condition prohibited by TSs. The tro ng and the as-found condition of the valve plug OD and cage lD confirmed that n materialwas the most likely cause of the failure of the valve to open upon initial. A new trim set was installed into the valve, and the valve was tested satisfactorily The inspectors'

review of this issue noted a licensee identified violation of regulatory ts. The enforcement aspects of this violation are discussed in Section 4OA7.This LER is closed.(Closed) LER 0500031 11201 1 -003-0, T Specification Maximum Airflow in the Fuel Handling Building Exceeded At approximately 1:00 AM on April 8, 2011, test of the Unit 2 Fuel Handling Building Ventilation System (FHV) was performed ing the replacement of the high efficiency particulate air filter on the 21 FHV filtration. The fuel handling building (FHB)exhaust flow was measured at24,627 cubic per minute (cfm) with the 21 FHV filtration train in service. TS 4.9.12.c requi a system flow rate of 19,490 cfm, +/- 10 percent during system operation.

irradiated fuel in the FHB is to be'a'when the FHV is inoperable.

The suspended in accordance with TS 3.9.12 measure flow rate was approximately 26 above the TS flow rate of 19,490 cfm.Enclosure 40A5.1 PSEG determined on April 5, 2011, fuelwas moved in the Unit 2 FHB with the air flow rate exceeding the requirements of 3.9.12.The cause of the high air flow rate in the Un balancing damper being out of position; the 2 FHB is attributed to the air supply pressure regulator on the FHB roll up door was incorrectly set not allowing the seal to inflate; and the FHB exhaust fan inlet guide vanes operating in a degraded. Corrective actions consisted of setting the supply damper in the correct , restoring the FHB roll up door air regulator to the proper setting, repairing the HB exhaust fans, and revising the procedure for control of fuel movement in FHB. The inspectors'

review of this issue noted a licensee identified violation of requirements.

The enforcement 4OA7. This LER is closed.aspects of this violation are discussed in Other Activities taken by PSEG to assess its Fukushima Daiichi nuclear plant fuel nt of PSEG's capability to mitigate The inspectors assessed the activities and readiness to respond to an event similar to.2 damage event. This included (1) an assess conditions that may result from beyond desi basis events, with a particular emphasis specified by NRC Security Order Section on strategies related to the spent fuel pool, 8.5.b issued February 25,2Q02, as to in severe accident management guidelines, and as specified by 10 CFR 50.); (2) an assessment of PSEG's capability to mitigate station blackout (SBO)itions, as specified by 10 CFR 50.63 and station design bases; (3) an of PSEG's capability to mitigate internal and externalflooding events, as required design bases; and (4) an and inspections of important assessment of the thoroughness of the wal equipment needed to mitigate fire and flood identify any potential loss of function of this the site., which were performed by PSEG to uipment during seismic events possible for f nspection Report 0500027212011008 and 11t2011008 (ML 1 1 1300464)documented detailed results of this activity.On May 20, 2011, the inspectors completed a review of PSEG's severe accident management guidelines (SAMGs), implemefrted as a voluntary industry initiative in the 1990's, to determine (1) whether the SAMG$ were available and updated, (2) whether PSEG had procedures and processes in plape to control and update its SAMGS, (3) the nature and extent of PSEG's training of perdonnel on the use of SAMGs, and (4) PSEG personnel's familiarity with SAMG implemenltation.

The results of this review was provided to thb NRC task force chartered by the Executive Director for Operations to conduct a near-tef'm evaluation of the need for agency actions following the Fukushima Daiichifuel damagg event in Japan. Plant-specific results for Salem Nuclear Generating Station, Unit Nol. 1 and 2, were provided in an Attachment to Enclosure

.3 a memorandum to the Chief, Reactor Branch, Division of lnspection and Regional Support, dated May 27,2011 (ML 1 1470361 ).During the week of August 2, 2010, ins performed the inspection in accordance with Temporary Instruction 25151177.

The RC staff developed Temporary Instruction review of PSEG's responses to NRC 25151177 to support the NRC's confi L 2008-01, "Managing Gas Accumulation in Core Cooling, Decay Heat Removal and Containment Spray Systems.As part of the inspection, the inspectors verified that the plant-specific information (uding licensing basis documents and that PSEG submitted to the of the inspection were documented in NRC lntegrated Inspection Report 050002 10004 and 0500031112010004 (ADAMS Accession No. ML102980181).

At that time requirements for Temporary Instruction 251 Nuclear Reactor Regulation (NRR) was still the inspectors determined the inspection 177 were complete, but since the Office of ng some technical aspects associated with PSEG's response to a for additional information (RAl), the temporary instruction was left open to e further inspection was not required.

ln addition, the inspectors noted that the final of GL 2008-01 for Salem Nuclear Generating Station, Unit Nos. 1 and 2, correspondence from NRR.be documented in separate ln a letter to PSEG, dated June 2,2011 Accession No. ML111380068), the of PSEG's response to the RAl. As NRC documented the results of the staff's noted in the letter, the NRC staff determine( that the information provided by PSEG, in a letter dated March 11, 2010, was to the GL, and that no further inspection The letter also stated that, based on a using the temporary instruction was review of the information provided in PSEG letters, dated April 10, 2008, October 13, 2008. Februarv 10.2009, February 8,2010, and March 11,2Q10, the NRC staff 2008, February 10, 2009, February 8, 2010, zw6, rgoruary 'l u, zuuv, rgl)rualy ot 1v I v, atltu rvrclrutt I t, .v tvr Uts rrr\v ercul concluded thai PSEG's response to GL 2008-01 was acceptable and considered closed.design information)

was consistent with the NRC in response to GL 2008-01. The resu Based on the above, Temporary Instruction 25151177 is considered closed.4OAO Meetinss.

Includinq Exit The inspectors presented the inspection reslults to Mr. L. Wagner and other members of PSEG management at the conclusion of thQ inspection on July 14, 2011. The inspectors asked PSEQwhether any materials examinBd during the inspection were proprietary.

No proprietary information was identified.

4C.A7 Licensee-l4entified Violations The following violations of NRC requiremenfs were identified by PSEG. They were determined to have very low safety significqnce (Green) and meet the criteria of Section 2.3 of the NRC Enforcement Policy, NUREQ-1600, for being dispositioned as NCVs: r TS 4.9.12.crequires a system flow rate pe verified at 19,490 cfm, +/- 10 percent during system operation.

This requirempnt applies during the movement of irradiateb fuel in the FHB. Contrary to tfie above, PSEG measured the ventilation Enclosure 30 flow rate to be approximately 26 percent than the TS flow rate of 19,490 cfm, and determined that this condition during the movement of irradiated fuel.PSEG determined the cause of the high balancing damper being out of position, rate to be attributed to the air supply air pressure regulator on the FHB roll up door was incorrectly set and did not the door sealto inflate, and the FHB fan condition.

inlet guide vanes operating in a This violation was determined to be of low safety significance (Green) because negative pressure was maintained in fudl handling building during fuel movement, the amount of radioactivity from a postulated fuel handling accident was unchanged, and any to the control room, exclusion area be well below regulatory limits. PSEG has boundary, and low population zone entered this violation in their CAP as 20506179.TS 3.4. 1 0.3, "Overpressure Protection two pressurizer overprotection system s," states, in part, that in mode 5 or 6, valves with a lift setting of less than or equalto 375 psig, be operable.

With valve inoperable, action is required to pressurizer overprotection system relief the valve to operable status in 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or complete depressurization and t of the RCS. Contrary to the above, on April 1 1, 2011, PSEG determined that 2PR1, one of the pressurizer overprotection system relief valves, had inoperable for more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.Upon discovery, PSEG completed and venting of the RCS.This violation was determined to be of low safety significance (Green) because it did not increase the likelihood of a of RCS inventory, it did not degrade PSEG's ability to remove decay heat the RHR or AFW systems, and did not affect PSEG's ability to terminate a leak CAP as notification 20504682.ATTACHMENT:

SUPPLEMENTAL INFORMATI PSEG entered this violation in their Enclosure Ooen/Closed 450002721201 1003-01 SUPPLEMENTAL IN FORMATION KEY POINTS OF CONTACT A-1 PSEG personnel:

C. Fricker, Site Vice President L. Wagner, Plant Manager R. DeSanctis, Maintenance Director L. Rajkowski, Engineering Director L. Curran, Engineering Manager R. Moore, Electrical Design Engineering Manager J. Garecht, Operations Director J. Stead, Electrical Design Engineer S. Taylor, Radiation Protection Manager H. Berrick, Senior Licensing Engineer E. Villar, Senior Licensing Engineer B. Thomas, Licensing Engineer D. Kolasinski, EDG System Engineer T. Giles, lSl Program Manager T. Oliveri, NDE Project Manager W. Kittle, IST Engineer LIST OF ITEMS OPENED, CLO$ED, AND DISCUSSED 05000272, 31112011003-02 FIN Closed 0500027212011-002-0 LER 0540027212011-003-0 LER lrrnproper Control of Transient Combustible t!4aterial (Section 1 R05)l4adequate Control of Switchyard lt{aintenance (Section 1 R1 3)Qlpass of Steam Generator Blowdown lalve lsolation During Testing (Section 4pA3.1)Manual Reactor Trip Due to Degraded Cbndenser Heat Removal (Section 4OA3.2)21SW 122 lsolation Function lnoperable Gfeater Than Allowed by Technical Specification (Section 4OA3.3)NCV 0500031 1t2011-001-0 LER Attachment 0500031 112011-002-0 0500031 112011-003-0 05000333i2515t183 05000333/2515t184 31.OP-AB.GRID-0001, Abnormal Grid, Rev. 19 51.OP-AB.GRID-0001, Abnormal Grid, Rev. 17 WC-M-107, Seasonal Readiness, Revision 10 Failure to Comply with Technical Specification 3.4.5 and 3.4.10.3 (Section 4043.4)Technical Specification Maximum Airflow jin the Fuel Handling Building Exceeded (Section 4OA3.5)Followup to the Fukushima Daiichi lNuclear Station Fuel Damage Event (Section 4OA5.1)l,Availability and Readiness Inspection of Bevere Accident Management Guidelines (Section 4OA5.2)LIST OF DOCUMEN'I]S REVIEWED In addition to the documents identified in the body of this report, the inspectors reviewed the following documents and records: Section 1R01: Adverse Weather Protection Procedures NC.OP-DG.ZZ-0002, Severe Weather Guide, Revisibn 7 OP-M-108-107-1001, Electric System Emergency Qperations and Electric Systems Operator Interface, Revision 3 SC.FP-SV.FBR-0026, Flood and Fire Barrier Penetrqtion Seal lnspection, Revision 4 SC.MD-PM.ZZ-0036, Watertight Door Inspection an{ Repair, Revision 5 SC.OP-AB .ZZ-0001 (Q), Adverse Environmental Coriditions, Revision 1 3 SC.OP-PT.ZZ-0002(q, Station Preparations for Sedsonal Conditions, Revision 11 Notifications 24462017 20465146 20470724 20485591 20493209 2A496453 20543U2 20503202 20503203 20503547 20503549 20505293 20476551 204964V1 20503266 20505838 20476949 20501034 2050331 1 20509672 70120777 20482843 2050301 1 20503545 Orders 30193621 30193732 80102s50 600818q6 Other Documents 201 1 Salem Seasonal Readiness Affirmation, 041291?011 Attachment Section 1R04: Equipment Aliqnment Procedures 51.OP-SO.CC-0002, 11 and 12 Component Coolin$ Heat Exchanger Operation, Revision 26 Drawinqs 205231, No. 1 205242, No. 1 Notifications 20512406 Orders 30130700 60097018 Section 1R05: Fire Protection Procedures FRS-ll-21 1, Salem Unit 1 (Unit 2) Pre-Fire Plan, Turpine Generator Area Elevation:

88', Revision 5 FRS-Il-221, Salem Unit 1 (Unit 2) Pre-Fire Plan, Turpine Generator Area Elevation:

100', Revision 4 FRS-ll-231, Salem Unit 1 (Unit 2) Pre-Fire Plan, Turpine Generator Area Elevation:

120', Revision 4 FRS-ll-61 1, Salem Unit 1 (Unit 2) Pre-Fire Plan, Reqctor Containment Elevations:

78', 100', &130', Revision 5 FRS-ll-815, Salem Unit 1 (Unit 2) Pre-Fire Plan, FirQiFresh Water Pump House, Revision 1 FRS-ll-421, Salem Unit 1 (Unit 2) Pre-Fire Plan, 416p V Switchgear Rooms & Battery Rooms Elevation:

64', Revision 6 FP-M-01 1, Control of Transient Combustible Material, Revision 2 Notifications 2050941 9 Other Documents FP-M-002-F5, Form 5, Transient Combustible in Sqfety Related Areas lmpairment Log, Revision 0 FP-M-011-F1, Form 1, Transient Combustible Perniit, Revision 0 Procedures ER-M-3003, Cable Condition Monitoring and Aging Management Program, Revision 0 Unit Component Cooling Unit Service Water Nuclear Area Attachment S2.OP-AB.7J-0002, Flooding, Revision 3 SC.FP-SV.FBR-0026, Flood and Fire Barrier Penetr{tion Seal lnspection, Revision 4 SC.DE-TS.ZZ-2034, Technical Requirements for Cohstruction of Electrical Installation, Salem Generating Station, Revision 5 SC.MD-PM.22-0036, Watertight Door lnspection and Repair, Revision 5 Drawinqs 602798 602799 604709 604710 604726 Notifications 20507835 20514893 Orders 30191674 20507836 20515427 60097463 20507838 70067380 I 20507S39 70102996 24512377 20il2676 Other Documents S-C-4KV-EEE-1751, Safety Related Medium VottagB Cable lssues routed below grade in duct bank or potentially submerged condition for Salem Unit 1 and 2, Revision 0 Section 1R07: Heat Sink Performance Orders 30122382 30126783 Other Documents Work Scope for Service Water 89-13 Project During 2R18 (Spring 2011)SW HX Biofouling Monitoring, 21 Comp Cooling HX (2CCE5), dated 412212011 21 CCHX Thermal Performance Test, dated 411A12011 Eddy Current Inspection Results Field Report, Mapl$wood Testing Services, dated 4llWZAf Section 1R08: Inservice Inspection (lSl)Procedures OU-AA-335-005, Radiographic Examination, Revision 0 OU-AA-335-018, VT1 and W3 Visual Examination of ASME Class MC and CC Containment Surfaces and Components, Revision 3 i ER-M-330-007, Visual Examination of Section Xl Class MC and Class CC, Revision 8 ER-AP-331, Boric Acid Corrosion Control (BACC) Prbgram, Revision 5 ER-AP-331-1001, Boric Acid Corrosion Control lnspdction Locations, lmplementation and lnspection Guidelines, Revision 6 i ER-AP-331-1002, Boric Acid Corrosion Control Progfam ldentification, Screening, and Evaluation, Revision 6 ER-AP-331-1003, RC Leakage Monitoring and Actiorl Plan, Revision 4 ER-AP-420-0051, Conduct of Steam Generator Mandgement Program Activities, Revision 14 54-lSl-130, Shell to Head UT Procedure, Revision 4V 54-lsl-130-047, UT of Ferritic VesselWelds Greater than 2.0" in Thickness, Revision 47 54-lSl-132, Pressurizer Surge Line Nozzle UT Proce$ure, Revision 11 54-lSl-108-006, UT of Stud Hole Ligaments in Reactqr Vessel Flange 54-lSl-836-013, UT of Austenitic Piping Welds Drawinqs 201448, Salem Unit 2, Reactor Containment Bottom Liner 201275, Salem Unit 2, Liner under the Containment

$ump 201499, Salem Unit 2, Containment Sump I 204808, Salem Unit 2, IWE Boundary 201182, Salem Containment Building, Sump Valve Rpom Liners 90461668, ASME ECT Calibration Standard, AREVAi Revision 0 Attachment t A-5 Notifications 20204686 20206512 20207794 20504342 20504204 20504205 20505720 20503129 20504377 20504305 20503130 20501319 PSEG Document OU-SA-335-1010, Steam 2 Data Analysis for Salem Unit 2, Revision AREVA Document 51-9152234-000, Salem 2R18 Generator Degradation Assessment AREVA Document 51-9118973-001, Qualified Edd Current Examination Techniques for Salem Unit 2 AREVA Document 51-9044781-001, Technical Sunlmary of Salem Unit 2 Replacement Steam Generator Eddy Current Pre-service Inspection January/February 2007 AREVA Document 51-9153947-000, Salem 2R18 Epdy Current lnspection Plan AREVA Document 51-9128572-001, Salem Unit 2 61/19T SG Condition Monitoring for 2R17 and Final Operational Assessment for Cycle 18 AREVA Document 03-9154042, Secondary Side Vi$ual lnspection Plan for 2R18 AREVA Document 51-9137471-000, Salem 2R17 Sfeam Generator Deposit Characterization AREVA Examination Technique Specification Sheet (ETSS), 1 bobbin MlZ80, Salem Unit 2, Outage 2R18 AREVA ETSS, 2 RPC 3-coil MlZ80, Salem Unit 2, Qutage 2R18 AREVA ETSS, 3 RPC 1-coil MlZ80, Salem Unit 2, Qutage 2R18 AREVA ETSS, 4 RPC 2-coil MlZ80, Salem Unit 2, Qutage 2R18 AREVA ETSS, 5 RPC Sizing, Salem Unit 2, Outage 2R18 EPRI Steam Generator Management Program, Pregsurized Water Reactor Steam Generator Examination Guidelines (Document 101370Q), Revision 7 EPRI Steam Generator Management Program, Steqm Generator lntegrity Assessment Guidelines (Document 1019038), Revision 3 NDE Data Sheets/Reports AFW Pipe Wall Thickness UT Measurements, Ordef 60084161, dated 411512011 Pressurizer Shell D to Head, UT Report No. UT-1 1-Q41, dated 412012011 Pressurizer Surge Line Nozzle, 14-PSN-1231-lRS, tpT Report No. UT-11-039, dated 412012011 RHR Pipe to Elbow UT of Weld 14-RH-121 1-7, Repbrt UT-11-031 RHR Pipe to Elbow UT of Weld 14-RH-1211-4, Repprt UT-11-030 RHR Pipe to Elbow UT of Weld 14-RH-1211-13, Report UT-11-020 Other Documents Letter, NRC to PSEG, Safety Evaluation on Channels, dated 121 17 11990 Letter, PSEG to NRC, Containment Monitor of Containment Liner Plate Monitor Welding Procedure, WPS Number NWP-27, P1 to PSEG Audit Template, Engineering Programs and , dated 112611990 Material MPWHT, Revision 1 1 Steam Generators, Revision 1, dated 7 Blackout Inspection, E1X-13 for ision 1 NOSA-SLM-1 0-06, August 201 0 PSEG Audit Template, Control of Special Engineering Programs and Station Blackout Audit Salem Unit 1 and Unit 2, Alloy 600 Management Plafr, Order 70106866, Revision 3 Unit 2 AFW Pressure Drop Test Record, dated 411112011 Design Change Package 80102598, Rerouting Unit p AFW Piping Inside the FTTA Post Modification Pressure Test Report for Unit 2 AFW Piping, dated 41261201" Attachment A-6 Section 1R11: Licensed Operator Requalificatioh Proqram Procedures 2-EOP-TRIP-1, Reactor Trip or Safety lnjection, Reirision 27 2-EOP-LOCA-1, Loss of Reactor Coolant, Revision 28 2-EOP-LOCA-2, Post LOCA Cooldown and Depresburization, Revision 25 2-EOP-LOCA-3, Transfer to Cold Leg Recirculationj Revision 29 S2.OP-AB.RC-001, Reactor Coolant System Leak, ftevision 10 SC.OP-AB.ZZ-0001, Adverse Environmental Conditions, Revision 1 3 Notifications 205121A4 Section 1 Rl2: Maintenance Effectiveness Notifications 20460803 20491258 Orders 70104220 70098606 20487926 70117583 204691 701 189 701 10005 Other Documents System Function Level Maintenance Rule Scoping, freactor Vessel Level Indication, dated 5l2U2Ar Salem 1 and 2, RVLIS Reliability (Cumulative)

Chartl 512008 - 512011 Salem 1 and 2, Narrative Log, RVLIS, dated 5120120111 WC-M-101 , On-Line Work Management Process, Rbvision 19 Other Documents SGS Unit 1 PSA Risk Assessment for Work Week 1215 (6119 to 6/25), Revision 0 OU-AA-103, Shutdown Safety Management Program, Revision 15 OU-AA-103, Attachment 1, Safety Shutdown Approv{I, dated 4/2212011 and 412612011 Safem 2 Narrative Log, dated 412612011 l Salem 1 Narrative Log, dated 511912011 i Salem 1 and 2, Operator's Risk Report, dated 511912V1 9ection 1 R15: Operabilitv Evaluations Procedures S1.OP-SO.CC-0002, 11 and 12 Component Cooling Heat Exchanger Operation, Revision 26 31.OP-PT.SW-0017 , 12 Qomponent Cooling Heat Exphanger Heat Transfer Performance Data Collection, Revision 16 I S2.OP-SO.SJ-0001, Preparation for SJ System Oper{tion, Revision 18 Procedures OP-M-101-112-1002, On-Line Risk Management, flevision 5 OP-AA-108-116, Protected Equipment Program, ReVision 3 S1.OP-SO.CAV-0001, Control Area Ventilation Operqtion, Revision 36 Attachment Drawinqs 205242 205334 Notifications 20512406 20512868 Orders 301 30700 701 15963 205350-StMP-4 20509141 60097018 70125112 205089e4 600e61ie3 60085319 80097745 20509053 20508879 70123576 70123632 Other Documents ECCS Check Valve Mechanical Agitation Letters Section 1R18: Plant Modifications Procedures S2. RA-ST. CC-0004, Inservice Testing Component Qooling Valves Acceptance Criteria, Revision 12 ER-AA-302-1005, Motor Operated Valves Design D{tabase Control and Design Data Sheet Activities, Revision 5 MA-AA-723-300, Diagnostic Testing and lnspection pf Motor Operated Valves, Revision 6 MA-M-723-300-1004, Quicklook Diagnostic Test E(uipmenUSensor Guideline, Revision 4 MA-M-723-301, Periodic Inspection of Limitorque Model SMB/SB/SBD-000 Through 5 Motor Operated Valves, Revision 7 SH.MD-CM.ZZ-0028, Disassembly and Reassembly of Type SMB-O through 4 and 4T Limitorque Actuators, Revision 5 I Drawinqs 250886 252293 601685 Notifications 20425010 Orders 30139768 30139772 Other Documents MIDAS As-Left Test of Record for 2CC30, dated 04121111 Section 1 R19: Post-Maintenance TestinE Procedures S1.OP-ST.28-0001, Electrical Power Systems 28VDQ Distribution, Revision 4 S2.OP-ST.DG-0003, 2C Diesel Generator Surveillande Test, Revision 48 S2.OP-ST.TRB-0002, Turbine Protection System Fulf FunctionalTest, Revision 24 SC.MD-PM.DG-0032, Periodic Diesel Engine Inspection Maintenance, Revision 17 S2.OP-ST,DG-0002, 2B Diesel Generator Surveillande Test, Revision 45 S2.RA-ST.DG-0002, 28 Diesel Generator Surveillande Test Acceptance Criteria, Revision 2 S1.OP-ST.AF-0001, Inseryice Testing - 11 AFW Pump, Revision 16 Attachment A-8 20508611 20509044 Orders 30186101 30186100 30186638 60090955 60090986 60089492 60096598 20511p76 501 38q96 600e6f26 50139536 60090554 60096650 50138618 Other Documents Revision 10, dated 311512011 1R20: Refuelins and Other Outase Activities Procedures OU-SA-105, Shutdown Safety Management Program - Salem Annex, Revision 0 OP-AA-108-110, Evaluation of Special Tests or Evdlutions, Revision 2 OU-SA-103, Shutdown Safety Management Prograln, Revision 15 Notifications 20511800 20505230 Other Documents Westinghouse Technical Bulletin NSD-TB-94-06-Rq, Model 93A RCP Turning Vane Bolt IGSCC lssue, dated 811111994 Nuclear Fuels Lost Parts Evaluation for Missing Malerial Reactor Coolant Pump Turning Vane (NUCR 70123042, Operation 30)CC-AA-309-101, Attachment 1, Foreign Material FoUnd on Lower Core Plate During FOSAR lnspections, Revision 10 NRC Information Notice 95-43, Failure of the Bolt-Locking Device on the Reactor Coolant Pump Turning Vane, dated 912811995 OU-AA-103, Attachment 1 , Shutdown Safety Approrfal, Revision 1 5, dated 31712011 ORAM Contingency Plan (2R18 Refueling Outage), RCS at mid-loop post-refueling 2 R18 Major Work Scope Spreadsheet Section 1 R22: Surveillance Testinq Procedures 51.OP-ST.AF-0003, lnservice Testing - 13 AFW Pu/np, Revision 40 52.OP-ST.AF-0007, Inservice Testing AFW Valves, jMode 3, Revision 21 52.OP-LR.AF-0001, AFW Piping Pressure Drop Teqt, Revision 0 S2.OP-ST.SSP-0004, SEC Mode Ops Testing 2C Vital Bus, Revision 35 S2,OP-LR.FP-0001, Type C Leak Rate Test, 2FP14V and 2FP148, Revision 1 S2.OP-ST.CS-0005, 22 CS Pump Full Flow Test, R$vision 24 52.OP-ST.SJ-0014, Intermediate Head Cold Leg Thf'ottling Valve Flow Balance Verification, Revision 25 S2.OP-ST.SJ-0015, lntermediate Head Hot Leg Thr$ttling Valve Flow Balance Verification, Revision 23 S2.OP-LR.CS-0001, Type C Leak Rate Test, 21C52,21CS10, and 21CS48, Revision 1 52.OP-ST.AF-0006, Inservice Testing Aux Feed Water Valves, Revision 12 32.RA-ST.AF-0006, Inservice Testing Aux Feed Wafer Valves Acceptance Criteria, Revision 11 Attachment A-9 Drawinqs 205335 205336 Notifications 20504471 20508436 20505238 20504511 20510661 20510735 20508356 20508275 Orders 50127770 60095963 50127803 50138541 60086697 70115963 80104145 Other Documents Salem 2 Narrative Log, AFW, dated 51212011 PG-PL Governor Manual 36694 Section 1 EP6: Drill Evaluation Procedures Notifications 20512104 Other Documents Salem Event Classification Guides PSEG Nuclear Salem - Training Drill (S11-02), Scenarip Synopsis, 05125111 Section 2RS1: Radioloqical Hazard Assessment bnd Exposure Controls Radiation Work Permits 1t2213015 ALAM Plans 2011-20 2011-61 2011-10 2011-23 Section 4OA1: Performance Indicator Verification I Other Documents Salem 1 and 2,1Q12011 Performance Indicators, Unplanned Salem 1 and 2,1Q12011 Performance lndicators, Unplanned Hrs Salem 1 and 2,1Q12011 Performance Indicators, Unpllanned Scrams per 7000 Critical Hrs Power Changes per 7000 Critical Scrams with Complications 2-EOP-TRIP-1, Reactor Trip or Safety Injection, Rer/ision 27 2-EOP-LOCA-1, Loss of Reactor Coolant, Revision 28 2-EOP-LOCA-2, Post LOCA Cooldown and Depressjurization, Revision 25 2-EOP-LOCA-3, Transfer to Cold Leg Recirculation, jRevision 29 S2.OP-AB.RC-001, Reactor Coolant System Leak, Revision 10 SC.OP-AB.ZZ-0001, Adverse Environmental Conditibns.

Revision 13 Attachment A-10 20457965 20250998 20153697 20474841 20506016 20506179 20490756 20492498 20492781 20498212 20498776 20499185 20500402 20501554 20501675 20502776 20502778 20503361 20505927 20505928 20505929 20510374 20510870 20489896 20499373 20501631 Orders 70111159 70059902 80098188 70108963 60089556 3A2U224 Other Documents IEEE 603-2009, Standard Criteria for Safety Syster4s for Nuclear Power Generating Stations IEEE 387-1984, Standard Criteria for Diesel-Genergtor Units Applied as Standby Power Supplies for Nuclear Power Generating Stations IEEE 384-1992, Standard Criteria for Independenc4 of Class 1E Equipment and Circuits IEEE 308-1980, Standard Criteria for Class 1E Porller Systems for Nuclear Power Generating Stations Salem Top 10 Equipment fssues Report, dated 61212011 Salem Equipment Exception Report Summary, datQd 511812011 Plant Health Committee Meeting Agenda, dated 41412011 and 512312011 Section 4OM: ldentification and Resolution of Froblems Notifications 20480587 20480691 20480709 20456318 20463767 20471949 20488992 20489517 20490004 20492857 20496252 20498393 20499618 20500324 20500583 20502408 205A2823 20502828 20504511 20504889 20505409 20507932 20508595 20508686 20493650 20487386 20499374 Section 4OA3: Event Follow-up Notifications 20506830 20506682 20506599 20506921 Other Documents 20506757 20506761 20506758 CIP*A-108-1 14-1001, Post-Trip Data Collection GUidelines - Salem, Revision 1 Salem 1 Narrative Log, dated 412112A11 l CC-AA-5001, Attachment 1, SSCs lnspected and DBgraded Conditions ldentified During Post Transient Walkdown, Revision 4, dated 412U2011 Sequence of Events Review Spreadsheet, dated 4l?112011 Section 4OA5: Other Activities Other Documents NRC Letter to PSEG, Salem Nuclear Generating St{tion, Unit Nos. 1 and 2 - Closeout of Generic Letter 2008-01, "Managing Gas Accumulatipn in Emergency Core Cooling, Decay Heat Generic Letter 2006-01, "Managing Gas Accumulailpn In Emergency uore L;oolrng, Decay Hea Removal, and Containment Spray Systems" (TAC Nos. MD7874 and MD7875), dated 61212011 Attachment ACE ADAMS AFW ALARA ASME BACC CAP CCHX ccz CFM CFR CRDM CRS CW DMW ECT EDG EPD EPRI ESOC FHB FHV FSAR FW GL HRA HX rMc lsl LCO LER MG MSR NCV NEl NRC NRR oos o9P PARS PI PMT PRA PSEG RAI RCS RFO RHR RPV A-11 LIST OF ACRONYMS Apparent Cause Evaluation Agency-wide Documents Acdess and Management System Auxiliary Feedwater As Low As Reasonably AchiQvable American Society of Mechanilcal Engineers Boric Acid Corrosion Control Corrective Action Program Component Cooling Heat ExQhanger Combustible Control Zone Cubic Feet per Minute Code of Federal Regulation Control Rod Drive Mechanisnir Control Room Supervisor Circulating Water Dissimilar MetalWeld i Eddy Current Testing Emergency Diesel Generator Electronic Personal Dosimetelr Electrlc Power Research Institute Electrical System Operations Center Fuel Handling Building Fuel Handling Building Ventildtion System Final Safety Analysis Report Feedwater Generic Letter High Radiation Area Heat Exchanger Inspection Manual Chapter Inservice lnspection Limiting Condition for Op Licensee Event Report Motor Generator Moisture Separator Reheater Non-cited Violation eratiQn Nuclear Energy lnstitute i Nuclear Regulatory Commission Office of Nuclear Reactor RegUlation Out-of-Service Offsite Power Publicly Available Records Performance Indicator Post-Maintenance Test Probability Risk Assessment Public Service Enterprise Group Nuclear LLC Request for Additional Informaltion Reactor Coolant System Refueling Outage Residual Heat Removal Reactor Pressure Vessel Attachment A-12 RT RVLIS RWP SAMG SBO SDP SFP SG SPAR SRA SW TCP TS TSAS UT VHRA WO Radiographic Testing I Reactor Vessel Level lnstrurtrentation System Radiation Work Permit I Severe Accident Managemerfrt Guideline Station Blackout l Significance Determination Pfocess Spent Fuel Pool Steam Generator Standardized Plant Analysis fteview Senior Reactor Analyst I Service Water Transient Combustible Permit Technical Specification I Technical Specification Actiorf Statement Ultrasonic Testing Very High Radiation Area i Work Order Attachment