IR 05000272/2011009
| ML112450416 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 09/02/2011 |
| From: | Burritt A L Reactor Projects Branch 3 |
| To: | Joyce T P Public Service Enterprise Group |
| Burritt A L RGN-I/DRP/PB3/610-337-5069 | |
| References | |
| IR-11-009 | |
| Download: ML112450416 (20) | |
Text
September 2, TOLLMr. Thomas P. JoYcePresident and Chief Nuclear OfficerPSEG Nuclear LLC - N09P.O. Box 236Hancock's Bridge, NJ 08038suBJECT: SALEM NUCLEAR GENERATING STATION, UNIT NOS] ]-4\D 2 -NRc pROBLEM tDENlFtCnrtON AND RESOLUTION INSPECTION REPORTo5ooo272t2o1 1 oO9 AND 0500031 1 /201 1 009
Dear Mr. Joyce:
on July 21,2011, the U. S. Nuclear Regulatory commis.sion (NRC) completed an inspection atyour Salem ttuctearbenerating StatiollUnit Nos. 1 and 2. The enclosed report documents theinspection results disiussed *itn ur. carl Fricker and other members of your staff during an exit*"Liing on July 21 and with Mr. Fricker during a telephone call on September 2'This inspection examined activities conducted under your license as they relate to identificationand resolution of proui"r" and compliance with the iommission's rules and regulations andconditions of your license. within these areas, the inspection involved examination of selectedprocedures and representative records, observations of activities, and interviews withpersonnel.Based on the samples selected for review, the inspectors concluded that PSEG was generallyeffective in identifying, evaruating, and resorving probrems. psEG personnel identified problemsand entered them into the corrective action prolrar at a low threshold' PSEG prioritized andevaluated issues commensurate with the safet/significance of the problems and correctiveactions were generally implemented in a timely manner'However, the inspection identified one self-revealing finding for not completing timely correctiveactions to repair "*."..iu" grooves discovered on tlre body wear surface.for the 11 servicewater strainer. This issue resulted in an 11 service water strainer trip that rendered the 11service water pumt rop"raur" and unavailable and was determined to potentially have.greaterthan very low safe[y sijnificance. The safety significance determination process analysis forthis issue was not 6or-pr"t"o at time of inspecti6n report issuance. Although the finding haspotential safety significance, it did not represent an immediate safety concern because it did notrepresent a complete loss of service walLisystem operability on Unit 1. At the time, five out ofthe six Unit 1 service water pumps remained operable and available'
T. JoyceIn accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, itsenclosure, and your response (if any) will be available electronically for public inspection in theNRC Public Document Room or from the Publicly Available Records (PARS) component of theNRC's document system (ADAMS). ADAMS is accessible from the NRC website athttp://www.nrc.qov/readinq-rm/adams.html (the Public Electronic Reading Room).
Sincerely,n -//-- ) {J, {1-I i.,L//t{t fU 1/'lArthur L. Burritt, ChiefProjects Branch 3Division of Reactor ProjectsDocket Nos: 50-272;50-311License Nos: DPR-70; DPR-75
Enclosure:
Inspection Report 0500027212011009 and 05000311/2011009
w/Attachment:
Supplemental I nformationcc w/encl: Distribution via ListServ
SUMMARY OF FINDINGS
lR 0500027212011009, 0500031 112011009i 0612712011 - 0711512011; Salem NuclearGenerating Station, Unit Nos. 1 and 2; Biennial Baseline Inspection of Problem ldentificationand Resolution. The inspectors identified one finding in the area of implementation of correctiveactions.This NRC team inspection was performed by three regional inspectors and one residentinspector. The inspectors identified one finding of very low safety significance (Green) duringthis inspection and classified the finding as an NCV. The significance of most findings isindicated by their color (Green, White, Yellow, Red) using NRC Inspection Manual Chapter(lMC) 0609, "Significance Determination Process" (SDP). Findings for which the SDP does notapply may be Green or assigned a severity level after NRC management review. Cross-cuttingaspects associated with findings are determined using IMC 0310, "Components Within theCross-Cutting Areas." The NRC's program for overseeing the safe operation of commercialnuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 4,dated December 2006.Problem ldentification and ResolutionThe inspectors concluded that PSEG was generally effective in identifying, evaluating, andresolving problems. PSEG personnel identified problems, entered them into the correctiveaction program at a low threshold, and prioritized issues commensurate with their safetysignificance. ln most cases, PSEG appropriately screened issues for operability andreportability, and performed causal analyses that appropriately considered extent of conditionand cause, generic issues, and previous occurrences. The inspectors also determined thatPSEG typically implemented corrective actions to address identified problems in a timelymanner. However, for one issue reviewed by the inspectors, the corrective actions completedby PSEG were not timely and the inspectors determined that this was a violation of NRCrequirements, in the area of corrective action implementation.The inspectors concluded that, in general, PSEG adequately identified, reviewed, and appliedrelevant industry operating experience to Salem operations and identified appropriate correctiveactions. ln addition, based on those items selected for review, the inspectors determined thatPSEG self-assessments and audits were thorough and appropriately used the corrective actionprogram to initiate corrective actions for identified issues.With respect to safety conscious work environment, based on interviews and reviews of thecorrective action program and the employees concerns program (ECP) the inspectors did notidentify conditions that negatively impacted the site's safety conscious work environment anddetermined that site personnel were willing to raise safety issues through multiple means.
3become trapped between the rotating strainer drum and the body wear surface, whicheventually bound and tripped the strainer overloads. As corrective action, before the next springgrassing season, PSEG will temporarily fill in the grooves on the 11 service water strainer bodywear surface and then trend the body wear ring condition for future replacement with a monelwear ring. PSEG entered this issue into the corrective action program as 20523166.This performance deficiency was more than minor because it was associated with theequipment performance attribute of the initiating events and mitigating systems cornerstones.The finding affected the cornerstones' objectives to limit the likelihood of those events that couldupset plant stability and challenge critical safety functions during power operations and toensure the availability and reliability of systems that respond to initiating events to preventundesirable consequences. Specifically, not promptly correcting the excessive groovingidentified on that strainer's body wear ring degraded the availability and reliability of the 11service water train. The significance of this finding is designated as To Be Determined (TBD)untit a regional senior reactor analyst completes a Phase 3 analysis, in accordance with IMC0609, Appendix A, "Determining the Significance of Reactor Inspection Findings for At-PowerSituations" (lMC 06094). Phase 1 screened the finding to Phase 2 because the inspectorsconcluded that the finding contributed to both the likelihood of a reactor trip and the likelihoodthat mitigating systems would not have been available. This conclusion was based upon theincreased chance of a loss of service water given one train being removed for strainer repairsand the loss of redundancy in the service water system to cool mitigating equipment over theassumed 53 hour6.134259e-4 days <br />0.0147 hours <br />8.763227e-5 weeks <br />2.01665e-5 months <br /> exposure period. The Phase 3 analysis was required because the SalemPre-solved Risk-lnformed Inspection Notebook does not address the loss of one train of servicewater. This finding has a cross-cutting aspect in the area of problem identification andresolution, corrective action program, because PSEG did not take appropriate corrective actionsto address a safety issue in a timely manner, commensurate with the safety-significance andcomplexity tP.1(d)1. Specifically, PSEG did not implement timely actions to repair excessivegrooves identified in the 11 service water strainer body wear ring in January 2011 because workcontroldocuments were not correctly coded in July 2010. (4OA2.1c(3))
4
REPORT DETAILS
4. OTHER ACTTVITIES (OA)4OA2 Problem ldentification and Resolution (711528)This inspection constitutes one biennial sample of problem identification and resolutionas defined by Inspection Procedure 71152. All documents reviewed during thisinspection are listed in the Attachment to this report..1 Assessment of Corrective Action Proqram Effectivenessa. Inspection ScopeThe inspectors reviewed the procedures that described PSEG's corrective actionprogram at Salem. To assess the effectiveness of the corrective action program, theinspectors reviewed performance in three primary areas: problem identification,prioritization and evaluation of issues, and corrective action implementation. Theinspectors compared performance in these areas to the requirements and standardscontained in 10 CFR 50, Appendix B, Criterion XVl, "Corrective Action," and PSEGprocedure LS-AA-125, "Corrective Action Program Procedure." For each of these areas,the inspectors considered risk insights from the station's risk analysis and reviewednotifications selected across the seven cornerstones of safety in the NRC's ReactorOversight Process. Included in this sample were notifications that documented PSEGsevaluation and corrective actions for a selective sample of NRC-identified non-citedviolations and findings that had been identified since the last biennial problemidentification and resolution inspection completed in June 2009. Additionally, theinspectors attended plan-ofthe-day, station ownership committee, and managementreview committee meetings. The inspectors selected items from the following functionalareas for review: engineering, operations, maintenance, emergency preparedness,radiation protection, chemistry and physical security.(1) Effectiveness of Problem ldentificationIn addition to the items described above, the inspectors reviewed system health reports,a sample of completed corrective and preventative maintenance work orders, completedsurveillance test procedures, operator logs, and periodic trend reports. The inspectorsalso completed field walkdowns of various systems on site, such as the service water,emergency diesel generator, safety injection and auxiliary feedwater systems.Additionally, the inspectors reviewed a sample of notifications written to documentissues identified through internal self-assessments, audits, emergency preparednessdrills, and the operating experience program. The inspectors completed this review toverify that PSEG entered conditions adverse to quality into their corrective actionprogram as apProPriate.(2) Effectiveness of Prioritization and Evaluation of lssuesThe inspectors reviewed the evaluation and prioritization of a sample of notificationsissued since the last NRC biennial Problem ldentification and Resolution inspectioncompleted in June 20A9. The inspectors also reviewed notifications that were assignedlower levels of significance that did not include formal cause evaluations to ensure thatEnclosure 5they were properly classified. The inspectors' review included the appropriateness ofthe assigned significance, the scope and depth of the causal analysis, and the timelinessof resolution. The inspectors assessed whether the evaluations identified likely causesfor the issues and developed appropriate corrective actions to address the identifiedcauses. The inspectors also verified that, when necessary, issue evaluations addressedequipment operability, NRC reporting requirements, and other areas potentially affectedby the identified performance deficiencies.(3) Effectiveness of Corrective ActionsThe inspectors reviewed PSEG's completed corrective actions through documentationreview and, in some cases, field walkdowns to determine whether the actions addressedthe identified causes of the problems. The inspectors also reviewed notifications foradverse trends and repetitive problems to determine whether corrective actions wereeffective in addressing the broader issues. The inspectors reviewed PSEG's timelinessin implementing corrective actions and effectiveness in precluding recurrence forsignificant conditions adverse to quality. The inspectors also reviewed a sample ofnotifications associated with selected non-cited violations and findings to verify thatPSEG personnel properly evaluatbd and resolved these issues. ln addition, theinspectors expanded the corrective action review to five years to evaluate PSEG actionsrelated to service water and circulating water grassing, control air system moisture,control room chillers, safety injection pump bearings, and residual heat removal systemoil leaks.b. Assessment(1) Effectiveness of Problem ldentificationPSEG staff at Salem initiated approximately 11,800 notifications between June 2009 andMay 2011. For this inspection, as part of the scope described above, the inspectorsreviewed the documentation associated with approximately 150 of these notifications.Based on the samples selected for review, the inspectors determined that PSEGidentified problems and entered them into the corrective action program at a lowthreshold.The inspectors observed supervisors at the plan-of-the-day, station ownershipcommittee, and management review committee meetings appropriately questioning andchallenging notifications to ensure clarification of the issues that allowed for appropriateassignments for follow-up actions. The inspectors also concluded that PSEG trendedequipment and programmatic issues at a low level, and appropriately documentedproblems identified through trending in the site's corrective action program.The inspectors determined that, when appropriate, in response to inspector observationsduring this inspection, PSEG personnel promptly initiated notifications and tookimmediate action to address the issues of concern. In addition, based on the scope ofissues reviewed by the inspectors, the inspectors did not identify concerns that were notappropriately entered into the corrective action program for evaluation and resolution.(2) Effectiveness of Pdoritization and Evaluation of lssuesThe inspectors determined that, in general, PSEG appropriately prioritized andevaluated issues commensurate with the safety significance of the identified problem.Enclosure 6PSEG screened notifications for operability and reportability, categorized thenotifications by significance, and assigned actions to the appropriate department forevaluation and resolution. The notification screening process considered humanperformance issues, radiological safety concerns, repetitiveness, adverse trends, andpotential impact on the safety conscious work environment.Items reviewed by the inspectors during the inspection were categorized for evaluationand resolution commensurate with the significance of the issues. Guidance provided byPSEG procedure LS-AA-120, "lssue ldentification and Screening Process," forcategorization appeared sufficient to ensure consistent implementation based on thesample of notifications reviewed by the inspectors. ln general, issues were appropriatelyscreened and prioritized commensurate with their safety significance.The inspectors reviewed 15 root cause analyses,26 apparent cause analyses,6common cause evaluations and approximately 20 work group evaluations. For theevaluations reviewed, the inspectors noted that PSEG's evaluations were generallythorough. Operability and reportability determinations were generally documented whenconditions warranted and in most cases, the evaluations supported the conclusion.Causal analyses appropriately considered the extent of condition or problem, genericissues, and previous occurrences of the issue.(3) Effectiveness of Corrective ActionsThe inspectors reviewed notification disposition documentation and verification ofcorrective action implementation through reviews of implementing orders anddiscussions with personnel involved for over 150 PSEG notifications. The inspectorsconcluded, based on the samples reviewed, that corrective actions for identifieddeficiencies were typically timely and adequately implemented and that for significantconditions adverse to quality, PSEG identified actions to prevent recurrence andperformed in-depth effectiveness reviews to verify that implemented corrective actionswere effective. However, in one case, as a result of a review of PSEG's correctiveactions for repetitive trips of service water strainers during periods of high river watergrass since 2006, the inspectors identified one example of more than minor significancewhere PSEG did not implement timely corrective actions. This finding is documentedbelow.c. Findinqs(1) Untimelv Completion of Corrective Actions Results in No. 11 Service Water Strainer TripDue To Grassinqlntroduction. The inspectors identified a self-revealing apparent violation of 10 CFR 50,Appendix B, Criterion XVl, "Corrective Action," because the 11 service water straineroverloads tripped on February 9, 2Q11, due to binding of the strainer rotating drum,which rendered the 11 service water pump inoperable and unavailable. The bindingoccurred because PSEG did not complete timely corrective actions for a conditionadverse to quality identified following an April 4,2010, 11 service water strainer trip.Specifically, PSEG did not repair excessive grooves on the strainer body wear surfaceby taking the actions specified in the corrective action program in January 2011. Thegrooves caused river grass to become trapped between the rotating strainer drum andbody wear surface, which eventually bound and tripped the strainer overloads.Enclosure 7Description. The Salem service water system is designed to supply cooling water tosafety-related equipment under all credible environmental and weather-relatedconditions. The system consists of six pumps divided into two redundant trains, threepumps each. The pumps take suction from the Delaware River through trash racks andtraveling screens designed to protect the pumps from river debris, while each pumpdischarges through an automatic self-cleaning strainer designed to protect the system'sheat exchangers from tube blockage.On February 9,2011, the 1 1 service water strainer thermal overloads tripped due tobinding caused by river grass that wedged between the strainer drum and body.Tripping of a service water strainer due to binding makes the associated service waterpump inoperable. PSEG determined that the cause of the binding was not installing apreviously approved strainer design change intended to improve the service waterstrainers resistance to grass binding.Each service water strainer assembly consists of a vertical mounted conical shapeddrum with 1104 strainer media elements. The strainer drum rotates inside the strainerbody with 0.015 to 0.063 inches of clearance between the drum and body to ensure thedrum rotates freely. This clearance also allows a small amount of flow to bypass thestrainer elements. Because this bypass flow results in river debris reaching andpotentially fouling system safety- related heat exchangers, it is important to minimize itby maintaining the clearance between the drum and body small. In 2000, due torepetitive heat exchanger fouling and strainer binding issues caused by this bypass flow,PSEG modified the design of the bottom of the service water strainer drum with a wearring that included an embedded rubber o-ring that decreased the clearance between thedrum and the body.After this design change, PSEG determined that, due to the silt entrained in the riverwater, even the small amount of bypass flow around the newly installed o-ring causedwear on the stralner drum and body. This wear over time increased the size of the gapbetween the drum and body and caused grooves on the body wear surface around theo-ring. The increasing gap, if not monitored and managed, caused higher bypass flowthat both allowed grass and debris to bypass the strainer elements and drew grass anddebris into the gap where it accumulated due to the tight clearances and o-ring weargrooves on the strainer body wear surface. The accumulation of grass in this area wasnot cleared during strainer backwash cycles and when it built up, caused increasedfriction between the drum and body. This increased the amount of current needed torotate the strainer drum and eventually caused the thermal overload to trip due to thehigher current. This was what caused the 1 1 strainer to trip on February 9, 2011.PSEG determined that maintaining the strainer bodies was critical to preventingexcessive bypass flow that could lead to grass accumulation and accelerated strainerwear. PSEG controls the gap between the strainer drum and body to within the vendorrecommendations by performing preventative maintenance to inspect and adjust theservice water strainer clearances every six months. Adjustments to the strainer duringperformance of this preventative maintenance were completed based upon the systemengineer's reviews of the gap measurements and wear grooves. In addition, to furthercontrol the gap, PSEG performed the industry standard, every six year, service waterstrainer internal inspections every three years due to the harsh river water conditions atSalem. In the early 2000s, due to excessive wear grooves that were developing on thestrainer body wear surfaces from the o-ring, PSEG issued a design change to modify thestrainer bodies to include a monel wear ring. The intent of the design change was thatEnclosure 8the new wear ring material would increase the hardness of the wear surface increasingthe wear surfaces durability and wear resistance and reducing the frequency of wearring repairs. This modification was not installed on the 11 strainer at the time of theFebruary 9,2011, trip.PSEG identified, during its cause evaluation for the February 2011 trip, that a similar tripof the 11 service water strainer had occurred one year earlier on April 4,2010. Theapparent cause evaluation for that trip determined the cause of the trip was untimelyreplacement of the 11 service water strainer body wear ring. The 11 service waterstrainer body configuration at the time of the April 2010 and February 201 1 trips was theconfiguration provided by the 1993 strainer replacement project. Because the monelwear ring was not installed, without interim corrective action, over time, due to the o-ringan excessive groove developed on the strainer body, which increased the susceptibilityof the strainer to grass clogging. The groove on the 11 strainer body wear surface was acondition adverse to quality that PSEG identified in April 2010. At the time of the April2010 trip, the groove was approximately 180 mils deep and 375 mils wide and byFebruary 2011, due to no corrective actions being completed, the groove widthincreased to 500 mils with no increase in depth. After the April 2010 11 service watertrip, PSEG determined that, in addition to the 11 strainer, five other strainers did nothave the monel wear ring design change (14, 16,23,24, and 26) installed.As documented in order 70109406, PSEG's corrective action for the April 2010 1 1service water strainer trip was to develop and schedule the replacement plan for the sixstrainers that did not have the monel wear ring installed. This corrective action wasdocumented as completed based on scheduling the work orders for the bodyreplacement for all six strainers. The 1 1 strainer work was scheduled to be completed inJanuary 2011. However, due to limited resources, the work was re-scheduled toJanuary 2012. PSEG determined that the rescheduling was allowed to occur becausethe work was not properly coded as a plant health committee significant issue or as agrassing readiness priority in accordance with WC-AA-101-1002, "On-line WorkSchedule Process." As a result, the identified condition adverse to quality was notpromptly corrected and the 1 1 service water strainer tripped on February 9, 2011, due tograss binding, making the 11 service water pump inoperable and unavailable for 53hours.To address the performance deficiency, PSEG scheduled an interim design change forthe 11 service water strainer to plasma spray the body wear ring before the next springgrassing season in January 2012. The plasma spray process will temporarily re-fill thegroove in the strainer body wear ring. PSEG will then trend the 11 strainer body wearring condition for future replacement with the monel wear ring. The monel wear ringdesign change on the 11 service water strainer is currently scheduled to be completed inApril 2013.PSEGs cause evaluation for the February 2011 strainer trip also identified four otherstrainers (14, 16,23, and 26) that still did not have the monel wear ring design changeinstalled. Before the next spring grassing season, PSEG will either install the monelwear ring design change or complete temporary repairs if excessive grooving (greaterthan 0.125 inches deep) exists on the body wear surfaces for these strainers. PSEG willthen monitor the strainers condition until the permanent repairs can be completed. Inaddition to the strainer repairs, PSEG revised service water system abnormal operatingprocedures to require operators to place the intake traveling screens in manual and theEnclosure Istrainers in continuous blowdown operation during heavy grassing periods. Thisresulted in no strainer trips caused by grassing during the April 2011 grass peak.Analvsis. The inspectors concluded that not completing timely repairs for excessivegrooves identified on the 11 service water strainer body wear surface after the April 4,2010, strainer trip was a performance deficiency. The untimely corrective actionsresulted in the February 9,2011, 11 service water strainer trip. This performancedeficiency was more than minor because it was associated with the equipmentperformance attribute of the initiating events and mitigating systems cornerstones. Thefinding affected the cornerstones' objectives to limit the likelihood of those events thatcould upset plant stability and challenge critical safety functions during power operationsand to ensure the availability and reliability of systems that respond to initiating events toprevent undesirable consequences. Specifically, not completing timely correctiveactions for excessive grooving identified on 11 strainer's body wear ring in January 2011degraded the availability and reliability of the 1 1 service water pump.The significance of this finding is designated as To Be Determined (TBD) until a regionalsenior reactor analyst completes a Phase 3 analysis, in accordance with IMC 0609,Appendix A, "Determining the Significance of Reactor Inspection Findings for At-PowerSituations." Phase 1 screened the finding to Phase 2 because the inspectors concludedthat the finding contributed to both the likelihood of a reactor trip and the likelihood thatmitigating systems would not have been available. This conclusion was based upon theincreased chance of a loss of service water given one train being removed for strainerrepairs and the loss of redundancy in the service water system to cool mitigatingequipment over the assumed 53 hour6.134259e-4 days <br />0.0147 hours <br />8.763227e-5 weeks <br />2.01665e-5 months <br /> exposure period. The Phase 3 analysis wasrequired because the Salem Pre-solved Risk-lnformed Inspection Notebook does notaddress the loss of one train of service water. The Phase 3 analysis was not completedat the time of inspection report issuance. The analysis will be completed followingdetermination of the proper assumptions for the increase in the loss of service waterevent frequency and the increase in the common cause failure probability, given theperformance deficiency.This finding has a cross-cutting aspect in the area of problem identification andresolution, corrective action program, because PSEG did not take appropriate correctiveactions to address a safety issue in a timely manner, commensurate with the safety-significance and complexity tP.1(d)1. Specifically, PSEG did not implement timelyactions to repair excessive grooves identified in the 11 service water strainer body wearring in January 2011 because work control documents were not correctly coded in July2010.Enforcement. 10 CFR 50, Appendix B, Criterion XVl, "Corrective Action," requires, inpart, that measures shall be established to assure that conditions adverse to quality,such as failures, malfunctions, deficiencies, deviations, defective material andequipment, and non-conformances are promptly identified and corrected. Contrary tothe above, in July 2010, PSEG did not establish adequate measures to assure that acondition adverse to quality identified on the 11 service water strainer was promptlycorrected. Specifically, because work control documents were not correctly coded inJuly 2010, PSEG did not repair excessive grooves identified on the 1 1 service waterstrainer body wear ring in January 2011. As a result, on February 9,2011, the 1 1service water strainer overloads tripped due to binding of the strainer rotating drum.PSEG entered the issue into the corrective action program as NOTF 20523166.Pending completion of the safety significance determination process analysis for thisEnclosure
.210 issue, the finding was identified as an apparent violation. (AV 0500027213112011009-01, Untimely Completion of Corrective Actions Results in No. 11 Service WaterStrainer Trip Due To Grassing)Assessment of the Use of Operatinq Experiencelnspection ScopeThe inspectors reviewed a sample of notifications associated with review of industryoperating experience to verify that PSEG appropriately evaluated the operatingexperience information for applicability to Salem and had taken appropriate actions,when warranted. The inspectors also reviewed evaluations of operating experiencedocuments associated with a sample of NRC generic communications to ensure thatSalem adequately considered the underlying problems associated with the issues forresolution via their corrective action program.AssessmentThe inspectors determined that PSEG appropriately considered industry operatingexperience information for applicability, and used the information for corrective andpreventive actions to identify and prevent similar issues when appropriate. Theinspectors determined that operating experience was appropriately applied and lessonslearned were communicated and incorporated into plant operations and procedureswhen applicable. The inspectors also observed that industry operating experience wasroutinely discussed and considered during the conduct of Plan-of-the-Day meetings andpre-job briefs.FindinqsNo findings were identified.Assessment of Self-Assessments and AuditsInspection ScopeThe inspectors reviewed a sample of audits, including the most recent audit of thecorrective action program, departmental self-assessments, and assessments performedby independent organizations. Inspectors performed these reviews to determine ifPSEG entered problems identified through these assessments into the corrective actionprogram, when appropriate, and whether PSEG initiated corrective actions to addressidentified deficiencies. The inspectors evaluated the effectiveness of the audits andassessments by comparing audit and assessment results against self-revealing andNRC-identified observations made during the inspection.AssessmentThe inspectors concluded that self-assessments, audits, and other internal PSEGassessments were generally critical, thorough, and effective in identifying issues. Theinspectors observed that PSEG personnel knowledgeable in the subject completedthese audits and self-assessments in a methodical manner. PSEG completed theseaudits and self-assessments to a sufficient depth to identify issues which were thenentered into the corrective action program for evaluation. In general, the stationa.c..3b.Enclosure
11implemented corrective actions associated with the identified issues commensurate withtheir safety significance.c. FindinqsNo findings were identified..4 Assessment of Safetv Conscious Work Environment (SCWE)a. Inspection ScopeDuring interviews with station personnel, the inspectors assessed the safety consciouswork environment at Salem. Specifically, the inspectors interviewed personnel todetermine whether they were hesitant to raise safety concerns to their managementand/or the NRC. The inspectors reviewed implementation of the site employee concernsprogram (ECP). Specifically, the inspectors reviewed the site procedure for conductingECP investigations and reviewed a sample of ECP files to assess the program'seffectiveness at addressing potential safety issues and to verify that PSEG enteredissues into the corrective action program when appropriate. The inspectors alsoreviewed the results of the contractor-performed January 201 1 Nuclear Safety CultureAssessment and PSEG's December 2009 Nuclear Safety Culture Principles Self-Assessment. The review included a discussion of the corrective actions identified byPSEG to address issues uncovered during the assessments.b. AssessmentBased on interviews and reviews of the corrective action program and the ECP, theinspectors determined that site personnel were willing to identify and raise safety issues.All persons interviewed demonstrated an adequate knowledge of the avenues availablefor raising safety concerns including the corrective action program and ECP. Theinspectors also determined that the results of the nuclear safety culture surveysconducted in December 2009 and January 2011 provided PSEG insights into the safetyculture of the site workforce.c. FindinqsNo findings were identified.4OAO Meetinqs. Includinq ExitOn July 21,2011, the inspectors presented the inspection results to Mr. C. Fricker,Salem Site Vice President, and other members of the Salem staff. The inspectorsverified that no proprietary information was retained by the inspectors or documented inthis report.On September 2, 2011, during a telephone call with Mr. C. Fricker, the inspectorsdiscussed the status of the phase 3 significance determination process analysis for thefinding related to untimely completion of corrective actions for 11 SW strainer. At thattime the inspectors informed Mr. Fricker that the report would document the significanceEnclosure 12of the finding as TBD pending determination of the proper assumptions for the increasein the loss of service water event frequency and the increase in the common causefailure probability relative to the performance deficiency.ATTACHMENT: SU PPLEMENTAL I N FORMATI ONEnclosure A-1
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTAGT
Licensee Personnel
- C. Fricker, Site Vice President
- L. Wagner, Plant Manager
- M. Bruecks, Director Security
- R. DeSanctis, Director Maintenance
- J. Garecht, Director Operations
- L. Rajkowski, Director Engineering
- M. Headrick, Manager Employee Concerns
- J. Kandasamy, Manager Regulatory Assurance
- J. Stavely, Manager Nuclear Oversight
- S. Taylor, Manager Radiation Protection
- M. Wagner, Performance lmprovement Manage r
- J. Arena, Performance lmprovement Support
- H. Berrick, Regulatory Compliance
- T. Cachaza, Performance lmprovement Support
- E. Villar, Regulatory Compliance
- J. Arena, Performance lmprovement SupportLIST OF ITEMS OPENED, CLOSED, DISCUSSED, AND UPDATEDOpened and Closed0500027 2, 31 1 I 201 1 009-0 1Untimely Completion of Corrective ActionsResults in No. 11 Service Water Strainer TripDue To GrassingLIST OF DOCUMENTS REVIEWEDSection 4OA2: Problem ldentification and ResolutionAudits and Self-Assessments70095327, Boric Acid Corrosion Control Functional Area Self-Assessment (FASA), 0411610970096371, Contamination Control Self-Assessment, 09/03/0970098506, 2009 Maintenance Resource Management FASA, 07i13/0970106832, Salem Emergency Preparedness and its lmplementing Procedure Self-Assessment,04t3012010801 01 252, Emergency Preparedness Audit, 04114120108A102024, Engineering Programs and Station Blackout Audit, 0811111080103001, Security Plan, FFD, Access Authorization, and PADS Audit, 0210211170118428,2011 Problem ldentification and Resolution FASA, 0310411170098602. Nuclear Safety Culture Principles Self Assessment. 1211110980103804, Corrective Action Program Audit Report, 05/18/201 170109034, Component Design Bases lnspection FASA, 091151107 0092328, Adverse Co ndition Mon itori ng Effectiveness, 09/1 8/09Attachment
Condition Reports204172802041762620425928204350062044318820457965204625602048357020491 69620494419205053782051271220367060203240612041966120267714203883472039771320413128204194232049843320505452205054532045191220358322203549202036706020324061Cause Evaluations70051392700775267009229570122711701246487012456570111159701155877012162670122719701230457Q1074687007993170078030700489187007469470112680701 19080202677142038834720397713204131282041942320498433205054522050545320451912201871332026227020277684202847832029470520330790203309612033277620339102203473022035690820361 05520361 91 62036642020379814203824272038293820383151203868257012041470122605701122397010343070100173700451 3370094482700709647007199570087882700941 38700963327009675970098506701020307010432170110664701 10650A-22040674920407953204099492041807120428645204301 6920433213204392782043981520440514204512112045270120452998204541162446475020465141204671202046951520470602204725332047289720457056204768092047681320476814204768152047681620476817701 1 085170112123701122417011263070114571701150677011520070115231701164467A116452741179317011902870119029701190427011915070119153701191557011972320479582204834082048216120483619204877502048784224490787204941782049526020495818204959222049996720504540205045442Q50491120505092204491952042267320501675205069842050849420510374200979812020510020227288202640Q9202544142045194070120053701204207012053470120414701208827012161370121619701216217012200470122594701227397012371070122874701 051 1 I701 0560470110652701158427011522820446414204456472051 00372051 00352051003420509262205091 8420508042205079682051025520448538204485402040528920506132205058362050572020502800203016862050103720499642205061372045122920434554204656722041966120401134204788872043704770116493701 06673701 03591701122417011223970111625701115377010982770106627701062937009088770118218701209687010940670066657Attachment
A-3Drawinos205200, Unit 1 Control Air - Turbine Building, Sh.1, Revislon 51205243, Unit 1 Control Air - Auxiliary Building, Sh. 1, Revision 47205247, Unit 1 Control Air - Reactor Control & Penetration Area, Sh. 1, Revision 49205332, Unit 2 Residual Heat Removal Pl&D, Sh. 1, Revision 36604495, Units 1&2 Control Air Yard Area - Station Blackout, Revision 2Operatinq Experience70109152, Post Tritium Report70109718, 1'1A Circ Water Pump Casing Cracked70109788, NRC lnformation Notice 2010-0470119956, NRC lnformation Notice 2010-2070078424,Intake Cooling Water Blockage Corrective Action Effectiveness Review7 01 23625, I nconsistent I m plementation of Operating Experience Proced u re70118713, Operating Experience Review From CDBI Self Assessment70123261, Service Water Piping lssues70109106, Auxiliary Feed Pump ActuationNCVs and Findinqs0500027212009003-02, Inadequate maintenance of the 13 AFW pump governor0500031 1/2009003-01, lmproper MR scoping of the service water intake structure sump systemO5OOO272l3112AO9O07-01, Failure to establish goals and monitor for (a)(1) service watersystem0500031 1/2009005-01, Unit 2 Degradation of Shutdown Cooling Caused by Failure ot 22RH180500031112009005-02, Inadequate Maintenance of the 22 CCHX Service Water Outlet ButterflyValve05000272131 1 12010002-01, Chillers Inoperability Exceeds TS AOT050A0272131 1 /201 0003-02, 21 SGFP Trip05000272131112010005-01, 13 TDAFW pump trip mechanism05A00272131112011007-01 , Inadequate Calculations for Degraded Voltage Relay Set Point05000272131112011007-02, Failure to Perform a TS Required Battery Performance Test05000272131112009403-01, Failure to Detect Penetration or Attempted Penetration at theProtected Area Boundary0500027 21 31 1 l 2009403-02, I nadeq uate Protected Area E ntry Sea rch05000272131112011007-03, Failure to ldentify and Correct A Condition Adverse to QuatityAffecting CREACS Expansion JointsLERSOISOOOZZZ\2Ol0-001-0, Automatic Start of the 1C Emergency Diesel Generator (EDG)O5OOO272\2O1O-002-\ Missed Containment Spray Valve Surveillance Per TechnicalSpecification 4.0.5O5OOO27 2120 1 0-004-0, Tech n ical Specif ication 3. 0. 4. b Non-Com pliance0500027212008-002-0, Automatic Reactor Trip Due to Main Power Transformer Bushing FailureProceduresLS-AA-115, Operating Experience Program, Revision 12LS-AA-1 15-1001, Manual for Processing OE1 Documents, Revision 1LS-AA-115-1002, Manualfor Processing OE2 Documents, Revision 0LS-AA-115-1003, Manualfor Processing OE3 Documents, Revision 0LS-AA-1 15-1004, Manual for Processing OE4 Documents, Revision 0ER-AA-3130-1005, Maintenance Rule Dispositioning between (a)(1) and (aX2), Revision 7Attachment
A-4ER-AA-310, lmplementation of the Maintenance Rule, Revision 8LS-AA-120, lssue ldentification and Screening Process, Revision 10LS-AA-125, Corrective Action Program (CAP) Procedure, Revision 13LS-AA-1 25-1002, Common Cause Analysis Manual, Revision 7LS-AA-125-1003, Apparent Cause Evaluation Manual, Revision 11LS-AA-125-1004, Effectiveness Review Manual, Revision 4LS-AA-1 26, Self-Assessment Program, Revision 9LS-AA-126-1 001, Focused Area Self-Assessments, Revision 5LS-AA-1 26-1 005, Check-ln Self-Assessments, Revision 4S
- C. lC-Tl.CA-000't, Control Air Dryers Preventative Maintenance, Revision 3SC.MD-PM.AF-0007, 13 and 23 Auxiliary Feedwater Terry Turbine Linkage Inspection andLubrication, Revision 2WC-AA-106, Work Screening and Processing, Revision 11LS-AA-125-1001, Root Cause Evaluation Manual, Revision 8LS-AA-125-1005, Coding and Analysis Manual, Revision 6LS-AA-125-1006, Department and Station Roll-up Meetings (DRUM SRUM), Revision 2LS-AA-125-F1, Salem/Hope Creek MRC Evaluation and Effectiveness Checklist and GradingSheet. Revision 2LS-AA-125-F2, Salem/Hope Creek Long Term Corrective Action Request (LTCA)LS-AA-125-F4, Work Group Evaluation (WGE)LS-AA-1 26-1002, Management Observation of Activities, Revision 2Maintenance Work Orders600604696008096560083302600844416008661 5600803883016437730076957301749433011761730184482301891275012772750127830501 38541501 39495501 39801501 40351501412824002654630188428301 9205830192351301 931 95301 9321 0301 8632160091 71 6600876726008767360087602301 8682960086708301 76991301907773007959560078098600935606008375660085587600891 50301826086008975760083368Completed SurveillancesS1.OP-ST.DG-002, 1B Diesel Generator Surveillance Test, Completed 06113111S1 .OP-ST.DG-0014, 1C Diesel Generator Endurance Run, Completed 03/16/1 152.OP-ST.DG-004, 21 Fuel Oil Transfer System Operability Test, Completed 06/13i11S2.OP-ST.DG-0019,2A Diesel Generator Hot Restart Test, Completed 021Q411152.OP-ST.DG-004, 21 Fuel Oil Transfer System Operability Test, Completed 07111111S1.OP-ST.AF-0003, Inservice Testing - 13 Auxiliary Feedwater Pump, 06130111S1.OP-ST.AF-0004, Inservice Testing - Auxiliary Feedwater Valves, 06113111S1.OP-ST.AF-0008, Auxiliary Feedwater Valve Verification Modes 1-3,0612011152.OP-ST.AF-0003, Inservice Testing - 23 Auxiliary Feedwater Pump, 0510611152.OP-ST.AF-0006, lnservice Testing - Auxiliary Feedwater Valves, 0512411152.OP-ST.AF-0009, Plant Systems - Auxiliary Feedwater, 0510411 1Attachment
A-5MiscellaneousStation Air System Health Report- 2no Quarter 2011Unit 1 Auxiliary Feedwater System Health Report- 2no Quarler 2011Unit 2 Auxiliary Feedwater System Health Report - 2no Quarter 2Q11Unit 1 Residual Heat Removal System Health Report - 2no Quarter 2011Unit 2 Residual Heat Removal System Health Report - 2no Quarter 2Q11Salem ControlAir Quality Test Results, September, 2009 to June 2011Emergency Preparedness Training Drill Critique Report (S11-02), 0512512011Order 80102809, Provide Range for Oil Levels in RHR Pump Motor Oil Reservoirs, 1111912010CMP-1SW-7 "#13 Containment Fan Coil Unit Service Water Outlet Check Valves to the ServiceWater Discharge Header CM Plan (Unit 1)ADAMSCFRECPtMcNCVNRCPARSPSEGSCWESDPSPARLIST OF AGRONYMSAgency-wide Documents Access and Management SystemCode of Federal RegulationsEmployee Concerns ProgramInspection Manual ChapterNon-Cited ViolationNuclear Regulatory CommissionPublicly Available Records SystemPSEG Nuclear LLCSafety Conscious Work EnvironmentSignificance Determination ProcessStandardized Plant Analysis RiskAttachment