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:	Arthur Burritt Reactor Projects Branch 3
To:	Joyce T 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).

Affhur L. Burritt, Chief Division of Reactor Projects Docket Nos: 50-272;50-311 License Nos: DPR-70; DPR-75

Enclosure:

I nspection Report 0500027 2120 1 1 003 and 0500031 1 I 201 1 003 WAttachment: Supplemental I nfontation

REGION I Docket Nos: 50-272,50-311 License Nos: DPR-70, DPR-75 Report No: 050A02721201 1 003 dnd 0500031 1 t201 1003 Licensee: PSEG Nuclear LLC (PSEG)

Facility: Salem Nuclear GenQrating Station, Unit Nos. 1 and 2 Location: P.O. Box 236 Hancocks Bridge, NJ 08038 Dates: April 1 ,2011through June 30, 2011 Inspectors: 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 Approved By: 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 rw probability risk assessment (PRA)

condition. PSEG investigation revealed tha the vendor, who was conducting maintenance on the 3T60 disconnect, the motor control fuse holder that was not part of the tagout for the maintenance. G determined that the cause of the 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 in the Updated Final Safety Analysis (UFSAR). Specifically, PSEG stored a rod drive motor generator (MG) set in a com ble control zone (CCZ) without an engineering evaluation that assessed risk a established compensatory measures.

This finding was determined to be of very safety significance. This issue was 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."

,r vr9, Referencing IMC Appendix F, Attachment 2,

"Degradation Rating Guidance Specific to Various Fire Protection Program Elements,"

the inspectors assigned a low degradation ng to the issues involving the failure to comply with PSEG's transient combustible m. The inspectors' conclusions were based on the fact that none of the items in the combustible free zone could be considered transient combustibles of sig , 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 Cornerstones: Initiating Events, Mitigating Si6tems, Barrier Integrity, and Emergency Preparedness 1R01 Adverse Weather Protection (71111.01 - z 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 the offsite AC Power (OSP) system prior to a during adverse weather conditions.

Specifically, the inspectors verified that the addressed:

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 voltage; 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.

b. Findinos No findings were identified.

.2 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 external flood protection. The inspectors verified that degraded conditions the potential to impact safety-related components and systems were reported in CAP. Corrective action notifications written for degraded conditions were revi to ensure that operability of components in the auxiliary building and EDG enclosures not impacted, Documents reviewed are listed in the Attachment.

b. Findinqs No findings were identified.

1R04 Eouioment Aliqnment (71111.04 - 3 samples 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 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 r

t Unit 2, Turbine building, 100'elevation o

I 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

. Fire/Fresh water pump house b. Findinqs 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

elevation, was established to limit to physical separation afforded by steel ffoor hatches located above CCZ-2. On Ma 9, 2011, inspectors identified a rod drive 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 of this apparent deficiency, and a notification was written.

Replacement of the Unit 2 rod drive MG set s performed under WO 30141286, and contained a step to obtain a TCP for the 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 and adversely affected the cornerstone objective to ensure the availa y of systems that respond to initiating events to prevent undesirable Specifically, the identified transient combustibles were located in a CCZ that required to limit challenges to physical separation afforded by steelfloor hatches the CCZ. Using IMC 0609, Appendix F,

"Fire Protection Significance Determination " the inspectors determined that this issue involved the finding category, "Fire and Administrative Controls."

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). this item was assigned a "low degradation" rating, this issue was of very 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 to minimize fire risk and comply with the plant operating license. (H.3(b))

Enclosure

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)

1R06 Flood Protection Measures (71111.06 - 2 sfmples)

.1 lnternal Floodinq a. 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.

b. Findinos No findings were identified.

.2 a. 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 n the Attachment.

Findinos No findings were identified.

Enclosure

1R07 Heat Sink Performance (71111.07A - 1 sample)

Inspection Scope The inspectors completed one annual heat $ink performance inspection sample. The inspectors reviewed performance data and ifterviewed the NRC Generic Letter (GL) 89-13 program manager to verify that potenlial heat exchanger (HX) or heat sink deficiencies were identified and PSEG adeqirately resolved heat sink performance problems. Specifically, the inspectors revievVed 21 CCHX data collected during a high heat load condition. The inspectors evaluat$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 reviewed are listed in the Attachment.

b. Findinos No findings were identified.

1R08 Inservice Inspection (lSl) (71111.08 - 1 sample)

Inspection Scooe Activities inspected during the Salem Unit 2 ling outage 18 (2R18) included observations of ultrasonic testing (UT) and data review of component testing 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 pressure vesselflange threaded stud holes r procedure 54-lsl-108-006 were reviewed with the UT technician who performed the Additionally, the technique for UT examination of the pressurizer nozzle to ell inner radius was inspected, the implementation of the technique as by EPRI modeling was discussed with the UT technician, and the completed n data package was reviewed. The data package for the UT examination of the 'izer girth shell to upper head weld was also reviewed. The task work orders and data for several ultrasonic and visual examinations were reviewed and confirmed be evaluated by PSEG as part of the lSl process.

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)

Enclosure

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 reviewed. The inspectors reviewed welding parameters and observed FW pipe welds for comparison to the ASME Code fabrication requirements.

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 CRDM to head welds were performed in the 2R18 outage. The inspectors visually observed the lower circumference of the head to confirm the absence of evidence of boric acid leakage from the CRDMs or upper head.

In the area of other boric acid corrosion con (BACC) activities, the inspectors confirmed the extent of plant boric acid during the plant shutdown process and noted that identified problem areas documented in Condition Report Notifications for resolution. The inspectors up on boric acid evaluations and observed corrective actions in the plant, 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 Unit 2 AFW and air lines rerouting to above in the Fuel Transfer Tube Area and the connection points outside the Unit 2 con nment were examined. Records of the post-modification AFW pressure testing reviewed. ln addition, the inspectors reviewed the extent of examination of other pipe systems including the 21 Nuclear SW header and the intake structure turbine building 30" diameter piping.

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

Examination for Tubing," and other listed in the Attachment were confirmed to be in use by interviews with of ECT inspection team and review 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 confirm the extent of independent oversight the ECT process.

Findinqs No findings were identified.

1R11 Licensed Operator Requalification Proqram 71111.11Q - 1 sample)

,1 a. 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 appropriate. Documents reviewed are in the Attachment.

b. Findinqs No findings were identified.

1R12 Maintenance Effectiveness (71111J2Q - 2 $amples)

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 maintenance rule program requirements. inspectors confirmed that the functional failure determinations and unavailability for these systems were documented in 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

l

o Unit 1 reactor vessel level instrumentatidn system (RVLIS)

r Unit 2 RVLIS b. Findinqs No findings were identified, 1R13 Risk (71111.13 - 5 samples)

a. 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 on 3T60 disconnect on April 1 o Unit 2, Defuelto Mode 6 with 21 chilled ter pump and the 21 control area chiller planned maintenance and 22 control chillers unplanned maintenance on April25 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 o Unit 1, control area ventilation dampers and CAA-12 planned maintenance on June 21 b. 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 a yellow PRA condition. PSEG investigatio revealed that the vendor. who was 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 ically independent alternating current circuits between the offsite transmission 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 current circuit and entered a72-hour LCO a a yellow PRA condition in support of 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.

The operations department walked down switchyard in response to the event and found the 3T60 motor controlfuse holder removed from the fuse block. PSEG restored the fuse holder and performed a walkdown of the 3T60 disconnect area. Operations successfully closed the 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 work were the apparent cause of the 3T60 configuration error. The vendor who maintenance on the 3T60 disconnect removed the motor controlfuse 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.

The PSEG ACE also documented that, due maintenance delays encountered earlier in the day, there was no PSEG oversight of vendor work even though PSEG's procedure required that a PSEG supervisor all portions of the vendor performed work. The maintenance delays caused the to continue into the night shift where there was no yard electrical supervisor to oversee the maintenance in the switchyard. Additionally, PSEG that personnel performed an inadequate worksite walkdown after the vendor work performed. This walkdown was another 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 Oversight of Supplemental Workforce," was performance deficiency. The inspectors determined that the performance deficiency more than minor because it was associated with the human performance of the Initiating Events cornerstone, and it adversely affected the cornerstone ive to limit the likelihood of events that upset plant stability and challenge critical functions. Specifically, not following the PSEG procedure for the management and ht of supplemental personnel caused a four hour extension in an elevated risk during which Salem Units 1 and 2 had 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 the increased chance of a loss of offsite power given only one power source the loss of redundancy in power supplies Enclosure

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 indicated that the finding could be more than very low safety significance.

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 human action failures and specify the expos period and uses the plant specific SPAR model to calculate the increase in core frequency. During the pilot period the 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 frequency in the low E-9 per year range for unit, assuming:

. 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 supervision, and did not conduct an post-maintenance restoration walkdown of 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)

1R15 Ooerabilitv Evaluations (71111.15 - 5 sam a. Inspection Scooe The inspectors completed five operability tion inspection samples. The inspectors reviewed the operability determinations for raded or non-conforming conditions associated with:

. Unit 2, charging pump cold leg injection valves 22 and 23 SJ 17 back leakage r Unit 2, safety injection pump cold leg inj check valve 22 SJ 144 back leakage r Unit 1,12A CCHX discharge valve 12Sr -383 failure to fully open during surveillance testing o Unit 2, power relief valve 2PR1 did not in manual at reduced reactor system coolant pressure Enclosure

. 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 's operability determinations.

Additionally, the inspectors reviewed other G identified safety-related equipment deficiencies during this report period and the adequacy of their operability screenings. Documents reviewed are listed the Attachment.

b. Findinos No findings were identified.

1R18 Plant Modifications (71111.18 - 1 sample)

Permanent Modification a. Inspection Scope The inspectors completed one plant tion inspection sample. The inspectors reviewed the permanent modification used to increase the thrust output capability of 2CC30, the 21 CCHX to component cooling header stop valve.

The inspectors' review verified that the des bases, licensing bases, and performance capability of the affected systems were not by the modifications. The inspectors verified the new configuration wa accurately reflected in the design documentation and that the post-modificati testing was adequate to ensure the 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 this permanent plant modification was also The documents reviewed are listed in the Attachment.

b. Findinos No findings were identified.

1R19 Post-Maintenance Testins (71111.19 - 6 ples)

a. lnspection Scope The inspectors completed six post-mai testing (PMT) inspection samples. The inspectors observed portions of and/or the PMT results for the maintenance activities listed below. The inspectors 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 and accuracy for the application; tests were , as written, with applicable Enclosure

prerequisites satisfied; and equipment was to an operational status and ready to perform its safety function. Documents are listed in the Attachment.

. WO 30186101, 2C EDG engine 1 overhaul o WO 50137318, 13 AR/V pump complex snootrng r WO 30186100, 28 EDG planned maintr during refueling outage

. WO 30131825,11 AFW pump breaker r ntenance

. WO 60096650, 2 main generator high p sealoil back-up pump motor maintenance

. WO 60096626, 1428 Vdc battery cell 1 replacement b. Findinos No findings were identified.

1R20 Refuelins and Other Outaqe Activities (71 1 1 sample)

a. Inspection Scope 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.

The inspectors reviewed the schedule and assessment documents associated with S2R18 to confirm that PSEG appropriately 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. to S2R18, the inspectors reviewed PSEG's outage risk assessment to identify sk significant equipment configurations and determine whether planned risk actions were adequate. During S2R18, the inspectors verified that PSEG managed outage risk in accordance with the outage plan.

The inspectors observed portions of the and cooldown processes and monitored PSEG controls over the outage The inspectors also verified that cool down rates were within Technical (TS) limitations. The inspectors entered containment at the start of the outage to check for evidence of previously unidentified reactor coolant leakage. S2R18, the inspectors made additional containment entries to inspect for ind of unidentified leakage, damaged equipment, foreign material control, radia worker work practices and fire prevention.

The inspectors observed portions of activities from the refueling bridge in containment and the spent fuel pool (SFP) to verify refueling gates and seals were properly installed and verify that foreign I exclusion boundaries were established around the reactor cavity. Core offload and reload activities were periodically observed from the control room and refuel bridge to verify operators adequately controlled fuel movements in accordance approved procedures.

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 periodically observed to determine whether riqn material exclusion boundaries were adequate.

During control room tours, the inspectors that operators maintained adequate reactor coolant system (RCS) level and re and that indications were within the expected range for the operating mode.

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 plant design parameters and consistent PSEG's risk assessment for the RFO.

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 as well as the SFP during increased heat load conditions.

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 workers such that minimum days off for individuals working on outage activities 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 reviewed by the inspectors during fuel offload and reload activities to verify that TS procedure requirements were met for containment. Specifically, the inspectors that during fuel movement activities, personnel, materials, and equipment were to close containment penetrations as specified in the licensing basis.

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 containment sump pumps were removed.

The condition of equipment used for fire n, prevention, and suppression were inspected for operability and functionality. of mode changes and reactor startup were observed and reviewed for compliance applicable procedures and TS.

Enclosure

b. Findinqs No findings were identified.

1R22 Surveillance Testinq (71111.22- 8 samples a. Insoection 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 Test, 21CS2, 21CS10, and 21CS48 r S2.OP-ST.AF-0006, Inservice Testing A Feed Water Valves b. Findinos No findings were identified.

lEPO Drill Evaluation (71114.06 - 1 sample)

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

b. Findinss No findings were identified.

Enclosure

2. RADIATION SAFEW Cornerstone: Radiation Safety - Public and 2RS1 (71124.01)

a. 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 for the outage: radiation protection support activities; primary steam generator current activities; scaffold activities in the containment; and pressurizer activities. inspectors verified that pre-work 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 following hazards were properly identified:

. ldentification of hot particles;

. The presence of alpha emitters; The potential for airborne radioactive including the potential presence of transuranics and/or other hard-to-detect adioactive materials; The hazards associated with work activi that could suddenly and severely increase radiological conditions; and Severe radiation field dose gradients tha can result in non-uniform exposures of the 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 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 ( ) alarm set points were in conformance with survey indications and plant policy.

The inspectors selected occurrences where worker's EPD noticeably malfunctioned or alarmed. The inspectors verified that responded appropriately to the off-normal condition. The inspectors verified that the i was included in the CAP and dose evaluations were performed as appropriate.

Enclosure

and Radia The inspectors observed the controls and ures for high-risk HRAs and VHMs.

The inspectors verified that any changes to G procedures did not substantially 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 in access to the VHRA.

Radiation Worker Performance 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 radiation protection work req uirements.

The inspectors determined that technicians aware of the radiological conditions and the RWP controls/limits in their and that their performance was consistent with their training and qualifications with to the radiological hazards and work activities.

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 b. Findinss No findings were identified.

2RS2 ALARA

{71124.02)

a. Inspection Scope Rad iation Worker Performance Enclosure

The inspectors observed radiation worker a radiation protection technician performance during work activities being in radiation areas, airborne radioactivity areas, and HRAs associated 2R18 activities. The inspectors concentrated on work activities that the greatest radiological risk to workers.

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.

b. Findinos No findings were identified.

2RS3 (71124.03)

a. Inspection Scope 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 on systems as part of its engineering controls, in lieu of respiratory protection , to controlairborne radioactivity. The inspectors reviewed procedural guidance use of installed (permanent) plant systems, and verified that the systems were used, to extent practicable, during high-risk activities. The inspectors selected installed 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 airborne radioactivity in work areas below concentrations of an airborne area to the extent practicable.

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

Airborne Monitorinq Protocols The inspectors selected installed systems t monitor and warn of changing airborne concentrations in the plant. The inspectors erified that alarms and setpoints were sufficient to prompt PSEG/worker action to nsure that doses were maintained within the limits of 10 CFR Part2} and ALAM. The i 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.

4. OTHER ACTIVITIES 4OA1 Performance Indicator (Pl) Verification (711 1 - 6 samples)

a. Inspection Scope The inspectors reviewed PSEG submittals the Unit 1 and Unit 2 initiating events cornerstone Pls discussed below. To the accuracy of the Pl data reported during this period the data was compared to the Pl definition and guidance contained in NEI 99-02, "Regulatory Assessment Performance I Guideline," Revision 6.

Cornerstone: lnitiatinq Events

. Unit 1 and Unit 2 unplanned scrams; r Unit 1 and Unit 2 unplanned scrams wi complications; and o Unit 1 and Unit 2 unplanned power cha 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.

b. Findinos No findings were identified.

4c.A2 ldentification and Resolution of Problems 152 - l annual sample; 1 trend sample)

,1 As specified by lnspection Procedure 711 "ldentification and Resolution of Problems,"

and in order to help identify repetitive ent failures or specific human performance issues for follow-up, the inspectors a daily screening of all items entered into Enclosure

PSEG's CAP. This was accomplished by the description of each new notification and attending daily ma revtew commiftee meetings. Documents reviewed are listed in the Attachment.

,2 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. The EDGs provide power to the safety-related 4kV electrical busses in the event of loss of offsite power. This notification was initiated to evaluate the 1A EDG continuing 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 failure to stop when the local control switch was placed in the stop position.

The inspectors assessed PSEG's problem tification threshold, cause evaluations, extent of condition evaluations, operability tions, and prioritization of corrective actions to determine whether PSEG was identifying, characterizing, and correcting problems associated with issues and whether the planned and completed corrective actions were app to prevent recurrence. The inspectors also interviewed plant personnel regarding identified issues, completed corrective actions, and planned corrective actions. inspectors reviewed design standards issued by the lnstitute of Electrical and nic Engineers and General Design Criteria issued by the NRC to determine requiremen for preventing interactions between safety-related and non safety-related equi t. Documents reviewed are listed in the Attachment.

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 potential for recurrence. The inspectors that corrective actions included 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 PSEG appropriately identified that the function of the EDGs to provide power to Enclosure

the emergency 4kV busses during loss of power was not compromised by the failure of the EDGs to trip on demand.

.3 Semi-Annual Review to ldentifv Trends a. Inspection Scope 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 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 with a design that has a proven track record of reliability at other nuclear plant 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 ity of these radiation monitors were not effective.

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 was reading a lower than actual discharge . The quick disconnect fitting that 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 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

4OA3 Event Follow-up (71153 - 5 samples)

.1 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 affected more than just the radiation moni closure of the GB4 valves. The jumper was 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 the ability of the GB4 valves to close on a containment isolation signal.

The cause of bypassing the AFW pump tic closure of the steam generator 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 revisions. PSEG analyzed this condition times that it existed during the 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 nalyzed condition during this surveillance test. This LER is closed.

.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.

.3 (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

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 discovery of a condition prohibited by TS LCp 3.6.1, "Containment lntegrity." The 0500027212011002 and 0500031112011002. Section 4042.2. This LER is closed.

.4 (Closed) LER 05000311/2011-002-0. Fail to Comply with Technical Specification 3.4.5 and 3.4.10.3 On April 11,2011, at 11:51 AM, control 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 key switch was turned to the test position, channel 1 test light illuminated, but the valve did not respond as expected. 2PR1 s restored to its pretest position; however, 2PR1 remained inoperable and off. satisfactorily testing of 2PR2, control room personnelattempted to open 2PR1 normalcontrolroom bezel, but 2PR1 failed to open again. At this point it was 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.

.5 (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 suspended in accordance with TS 3.9.12 'a'when the FHV is inoperable. The measure flow rate was approximately 26 above the TS flow rate of 19,490 cfm.

Enclosure

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 2 FHB is attributed to the air supply balancing damper being out of position; the 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 aspects of this violation are discussed in 4OA7. This LER is closed.

40A5 Other Activities

.1 The inspectors assessed the activities and taken by PSEG to assess its readiness to respond to an event similar to Fukushima Daiichi nuclear plant fuel damage event. This included (1) an assess nt of PSEG's capability to mitigate conditions that may result from beyond desi basis events, with a particular emphasis on strategies related to the spent fuel pool, specified by NRC Security Order Section 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 assessment of the thoroughness of the wal and inspections of important equipment needed to mitigate fire and flood , which were performed by PSEG to identify any potential loss of function of this uipment during seismic events possible for the site.

f nspection Report 0500027212011008 and 11t2011008 (ML111300464)

documented detailed results of this activity.

.2 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

a memorandum to the Chief, Reactor Branch, Division of lnspection and Regional Support, dated May 27,2011 (ML 1 1470361 ).

.3 During the week of August 2, 2010, ins performed the inspection in accordance with Temporary Instruction 25151177. The RC staff developed Temporary Instruction 25151177 to support the NRC's confi review of PSEG's responses to NRC 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 design information) was consistent with the that PSEG submitted to the NRC in response to GL 2008-01. The resu of the inspection were documented in NRC lntegrated Inspection Report 050002 10004 and 0500031112010004 (ADAMS Accession No. ML102980181). At that time the inspectors determined the inspection requirements for Temporary Instruction 251 177 were complete, but since the Office of Nuclear Reactor Regulation (NRR) was still 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, be documented in separate correspondence from NRR.

ln a letter to PSEG, dated June 2,2011 Accession No. ML111380068), the NRC documented the results of the staff's of PSEG's response to the RAl. As 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 using the temporary instruction was The letter also stated that, based on a review of the information provided in PSEG letters, dated April 10, 2008, October 13, zw6, Februarv 'l10.2009, 2008, rgoruary 2008. February February 8,2010, 2009, rgl)rualy u, zuuv, 10, 8, 1v ot I v, atltu 2010, and rvrclrutt I t, .v tvr the March 11,2Q10, Uts rrr\v staff NRC ercul concluded thai PSEG's response to GL 2008-01 was acceptable and considered closed.

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

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 rate to be attributed to the air supply balancing damper being out of position, air pressure regulator on the FHB roll up door was incorrectly set and did not the door sealto inflate, and the FHB fan inlet guide vanes operating in a condition.

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 boundary, and low population zone be well below regulatory limits. PSEG has entered this violation in their CAP as 20506179.

TS 3.4. 1 0.3, "Overpressure Protection s," states, in part, that in mode 5 or 6, two pressurizer overprotection system valves with a lift setting of less than or equalto 375 psig, be operable. With pressurizer overprotection system relief valve inoperable, action is required to 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 PSEG entered this violation in their CAP as notification 20504682.

ATTACHMENT: SUPPLEMENTAL INFORMATI Enclosure

A-1 SUPPLEMENTAL IN FORMATION KEY POINTS OF CONTACT 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 Ooen/Closed 450002721201 1003-01 NCV lrrnproper Control of Transient Combustible t!4aterial (Section 1 R05)

05000272, 31112011003-02 FIN l4adequate Control of Switchyard lt{aintenance (Section 1 R1 3)

Closed 0500027212011-002-0 LER Qlpass of Steam Generator Blowdown lalve lsolation During Testing (Section 4pA3.1)

0540027212011-003-0 LER Manual Reactor Trip Due to Degraded Cbndenser Heat Removal (Section 4OA3.2)

0500031 1t2011-001-0 LER 21SW 122 lsolation Function lnoperable Gfeater Than Allowed by Technical Specification (Section 4OA3.3)

Attachment

0500031 112011-002-0 Failure to Comply with Technical Specification 3.4.5 and 3.4.10.3 (Section 4043.4)

0500031 112011-003-0 Technical Specification Maximum Airflow jin the Fuel Handling Building Exceeded (Section 4OA3.5)

05000333i2515t183 Followup to the Fukushima Daiichi lNuclear Station Fuel Damage Event (Section 4OA5.1)

05000333/2515t184 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 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 Notifications 24462017 20465146 20470724 20476551 20476949 20482843 20485591 20493209 2A496453 204964V1 20501034 2050301 1 20543U2 20503202 20503203 20503266 2050331 1 20503545 20503547 20503549 20505293 20505838 20509672 Orders 30193621 30193732 80102s50 600818q6 70120777 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 Unit Component Cooling 205242, No. 1 Unit Service Water Nuclear Area 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 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 Attachment

Notifications I 20507835 20507836 20507838 20507S39 24512377 20il2676 20514893 20515427 Orders 30191674 60097463 70067380 70102996 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 20505720 20504377 20504305 20504342 20504204 20504205 20503129 20503130 20501319 PSEG Document OU-SA-335-1010, Steam 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 of Containment Liner Plate Monitor Channels, dated 121 17 11990 Letter, PSEG to NRC, Containment Monitor , dated 112611990 Welding Procedure, WPS Number NWP-27, P1 to Material MPWHT, Revision 1 1 PSEG Audit Template, Engineering Programs and Blackout Inspection, E1X-13 for Steam Generators, Revision 1, dated 7 PSEG Audit Template, Control of Special ision 1 Engineering Programs and Station Blackout Audit NOSA-SLM-1 0-06, August 201 0 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 20487926 204691 Orders 70104220 70098606 70117583 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 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 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 Attachment

Drawinqs 205242 205334 205350-StMP-4 Notifications 20512406 20512868 20509141 205089e4 20509053 20508879 Orders 301 30700 60097018 70125112 600e61ie3 70123576 70123632 701 15963 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 60085319 80097745 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 20511p76 Orders 30186101 30186100 30186638 501 38q96 50139536 60090554 60090955 60090986 60089492 600e6f26 60096650 50138618 60096598 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 20510661 20510735 20508356 20508275 20505238 20504511 Orders 50127770 50127803 50138541 60086697 70115963 80104145 60095963 Other Documents Salem 2 Narrative Log, AFW, dated 51212011 PG-PL Governor Manual 36694 Section 1 EP6: Drill Evaluation Procedures 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 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 Scrams per 7000 Critical Hrs Salem 1 and 2,1Q12011 Performance lndicators, Unplanned Power Changes per 7000 Critical Hrs Salem and 2,1Q12011 Performance Indicators, Unpllanned Scrams with Complications

Attachment

A-10 Section 4OM: ldentification and Resolution of Froblems Notifications 20480587 20480691 20480709 20457965 20250998 20153697 20456318 20463767 20471949 20474841 20506016 20506179 20488992 20489517 20490004 20490756 20492498 20492781 20492857 20496252 20498393 20498212 20498776 20499185 20499618 20500324 20500583 20500402 20501554 20501675 20502408 205A2823 20502828 20502776 20502778 20503361 20504511 20504889 20505409 20505927 20505928 20505929 20507932 20508595 20508686 20510374 20510870 20489896 20493650 20487386 20499374 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 4OA3: Event Follow-up Notifications 20506830 20506682 20506599 20506757 20506761 20506758 20506921 Other Documents CIPA-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 2008-01, "Managing Gas Accumulailpn Generic Letter 2006-01, in Emergency uore Accumulatipn In Cooling, Decay Hea Core L;oolrng, Heat Removal, and Containment Spray Systems" (TAC Nos. MD7874 and MD7875), dated 61212011 Attachment

A-11 LIST OF ACRONYMS ACE Apparent Cause Evaluation ADAMS Agency-wide Documents Acdess and Management System AFW Auxiliary Feedwater ALARA As Low As Reasonably AchiQvable ASME American Society of Mechanilcal Engineers BACC Boric Acid Corrosion Control CAP Corrective Action Program CCHX Component Cooling Heat ExQhanger ccz Combustible Control Zone CFM Cubic Feet per Minute CFR Code of Federal Regulation CRDM Control Rod Drive Mechanisnir CRS Control Room Supervisor CW Circulating Water DMW Dissimilar MetalWeld i ECT Eddy Current Testing EDG Emergency Diesel Generator EPD Electronic Personal Dosimetelr EPRI Electrlc Power Research Institute ESOC Electrical System Operations Center FHB Fuel Handling Building FHV Fuel Handling Building Ventildtion System FSAR Final Safety Analysis Report FW Feedwater GL Generic Letter HRA High Radiation Area HX Heat Exchanger rMc Inspection Manual Chapter lsl Inservice lnspection LCO Limiting Condition for Op eratiQn LER Licensee Event Report MG Motor Generator MSR Moisture Separator Reheater NCV Non-cited Violation NEl Nuclear Energy lnstitute i NRC Nuclear Regulatory Commission NRR Office of Nuclear Reactor RegUlation oos Out-of-Service o9P Offsite Power PARS Publicly Available Records PI Performance Indicator PMT Post-Maintenance Test PRA Probability Risk Assessment PSEG Public Service Enterprise Group Nuclear LLC RAI Request for Additional Informaltion RCS Reactor Coolant System RFO Refueling Outage RHR Residual Heat Removal RPV Reactor Pressure Vessel Attachment

A-12 RT Radiographic Testing I RVLIS Reactor Vessel Level lnstrurtrentation System RWP Radiation Work Permit I SAMG Severe Accident Managemerfrt Guideline SBO Station Blackout l SDP Significance Determination Pfocess SFP Spent Fuel Pool SG Steam Generator SPAR Standardized Plant Analysis fteview SRA Senior Reactor Analyst I SW Service Water TCP Transient Combustible Permit TS Technical Specification I TSAS Technical Specification Actiorf Statement UT Ultrasonic Testing VHRA Very High Radiation Area i WO Work Order Attachment