IR 05000272/2011009

IR 05000272-11-009 & 05000311-11-009, on 06/27/2011-07/15/2011, Salem Nuclear Generating Station, Units 1 and 2, Biennial Baseline Inspection of Problem Identification and Resolution

ML112450416
Person / Time
Site:	Salem
Issue date:	09/02/2011
From:	Arthur Burritt Reactor Projects Branch 3
To:	Joyce T Public Service Enterprise Group
Burritt A RGN-I/DRP/PB3/610-337-5069
References
IR-11-009
Download: ML112450416 (20)

Text

UNITED STATES NUCLEAR REGU LATORY COMMISSION

REGION I

475 ALLENDALE ROAD KING OF PRUSSIA, PENNSYLVANIA 19406-1415 September 2, TOLL Mr. Thomas P. JoYce 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] ]-4\D 2 -

INSPECTION REPORT NRc pROBLEM tDENlFtCnrtON AND RESOLUTION o5ooo272t2o1 1 oO9 AND 0500031 1 /201 1 009

Dear Mr. Joyce:

an inspection at on July 21,2011, the U. S. Nuclear Regulatory commis.sion (NRC) completed documents the your Salem ttuctearbenerating StatiollUnit Nos. 1 and 2. The enclosed report of your staff during an exit inspection results disiussed *itn ur. carl Fricker and other members 2'

• "Liing on July 21 and with Mr. Fricker during a telephone call on September they relate to identification This inspection examined activities conducted under your license as rules and regulations and and resolution of proui"r" and compliance with the iommission's involved examination of selected conditions of your license. within these areas, the inspection interviews with procedures and representative records, observations of activities, and personnel.

that PSEG was generally Based on the samples selected for review, the inspectors concluded psEG personnel identified problems effective in identifying, evaruating, and resorving probrems. prioritized and and entered them into the corrective action prolrar at a low threshold' PSEG the problems and corrective evaluated issues commensurate with the safet/significance of actions were generally implemented in a timely manner'

not completing timely corrective However, the inspection identified one self-revealing finding for grooves discovered on tlre body wear surface.for the 11 service actions to repair

"*."..iu" the 11 water strainer. This issue resulted in an 11 service water strainer trip that rendered to potentially have.greater service water pumt rop"raur" and unavailable and was determined The safety significance determination process analysis for than very low safe[y sijnificance.

Although the finding has this issue was not 6or-pr"t"o at time of inspecti6n report issuance.

because it did not potential safety significance, it did not represent an immediate safety concern on Unit 1. At the time, five out of represent a complete loss of service walLisystem operability the six Unit 1 service water pumps remained operable and available' In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of the NRC's document system (ADAMS). ADAMS is accessible from the NRC website at http://www.nrc.qov/readinq-rm/adams.html (the Public Electronic Reading Room).

Sincerely, ni.,L//t{t

-//-- )

fU 1/'l{J, {1-I Arthur L. Burritt, Chief Projects Branch 3 Division of Reactor Projects Docket Nos: 50-272;50-311 License Nos: DPR-70; DPR-75 Enclosure: Inspection Report 0500027212011009 and 05000311/2011009 w/Attachment: Supplemental I nformation cc w/encl: Distribution via ListServ

SUMMARY OF FINDINGS

lR 0500027212011009, 0500031 112011009i 0612712011 - 0711512011; Salem Nuclear

Generating Station, Unit Nos. 1 and 2; Biennial Baseline Inspection of Problem ldentification and Resolution. The inspectors identified one finding in the area of implementation of corrective actions.

This NRC team inspection was performed by three regional inspectors and one resident inspector. The inspectors identified one finding of very low safety significance (Green) during this inspection and classified the finding as an NCV. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using NRC Inspection Manual Chapter (lMC) 0609, "Significance Determination Process" (SDP). Findings for which the SDP does not apply may be Green or assigned a severity level after NRC management review. Cross-cutting aspects associated with findings are determined using IMC 0310, "Components Within the Cross-Cutting Areas." The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 4, dated December 2006.

Problem ldentification and Resolution The inspectors concluded that PSEG was generally effective in identifying, evaluating, and resolving problems. PSEG personnel identified problems, entered them into the corrective action program at a low threshold, and prioritized issues commensurate with their safety significance. ln most cases, PSEG appropriately screened issues for operability and reportability, and performed causal analyses that appropriately considered extent of condition and cause, generic issues, and previous occurrences. The inspectors also determined that PSEG typically implemented corrective actions to address identified problems in a timely manner. However, for one issue reviewed by the inspectors, the corrective actions completed by PSEG were not timely and the inspectors determined that this was a violation of NRC requirements, in the area of corrective action implementation.

The inspectors concluded that, in general, PSEG adequately identified, reviewed, and applied relevant industry operating experience to Salem operations and identified appropriate corrective actions. ln addition, based on those items selected for review, the inspectors determined that PSEG self-assessments and audits were thorough and appropriately used the corrective action program to initiate corrective actions for identified issues.

With respect to safety conscious work environment, based on interviews and reviews of the corrective action program and the employees concerns program (ECP) the inspectors did not identify conditions that negatively impacted the site's safety conscious work environment and determined that site personnel were willing to raise safety issues through multiple means.

Cornerstone: Initiating Events

TBD. The inspectors identified a self-revealing apparent violation of 10 CFR 50, Appendix B,

Criterion XVl, "Corrective Action," because the 11 service water strainer overloads tripped on February 9,2011, due to binding of the strainer rotating drum, which rendered the 't 1 service water strainer pump inoperable and unavailable. The binding occurred because PSEG did not complete timely corrective actions for a condition adverse to quality identified following an April 4,2010,11 service water strainer trip. Specifically, PSEG did not repair excessive grooves identified on the 11 service water strainer body wear surface by taking the actions specified in their corrective action program in January 2011. As a result, the grooves caused river grass to become trapped between the rotating strainer drum and the body wear surface, which eventually bound and tripped the strainer overloads. As corrective action, before the next spring grassing season, PSEG will temporarily fill in the grooves on the 11 service water strainer body wear surface and then trend the body wear ring condition for future replacement with a monel wear ring. PSEG entered this issue into the corrective action program as 20523166.

This performance deficiency was more than minor because it was associated with the equipment performance attribute of the initiating events and mitigating systems cornerstones.

The finding affected the cornerstones' objectives to limit the likelihood of those events that could upset plant stability and challenge critical safety functions during power operations and to ensure the availability and reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, not promptly correcting the excessive grooving identified on that strainer's body wear ring degraded the availability and reliability of the 11 service 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 IMC 0609, Appendix A, "Determining the Significance of Reactor Inspection Findings for At-Power Situations" (lMC 06094). Phase 1 screened the finding to Phase 2 because the inspectors concluded that the finding contributed to both the likelihood of a reactor trip and the likelihood that mitigating systems would not have been available. This conclusion was based upon the increased chance of a loss of service water given one train being removed for strainer repairs and the loss of redundancy in the service water system to cool mitigating equipment 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 was required because the Salem Pre-solved Risk-lnformed Inspection Notebook does not address the loss of one train of service water. This finding has a cross-cutting aspect in the area of problem identification and resolution, corrective action program, because PSEG did not take appropriate corrective actions 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 timely actions to repair excessive grooves identified in the 11 service water strainer body wear ring in January 2011 because work controldocuments were not correctly coded in July 2010. (4OA2.1c(3))

REPORT DETAILS

4OA2 Problem ldentification and Resolution (711528)

This inspection constitutes one biennial sample of problem identification and resolution as defined by Inspection Procedure 71152. All documents reviewed during this inspection are listed in the Attachment to this report.

.1 Assessment of Corrective Action Proqram Effectiveness

a. Inspection Scope

The inspectors reviewed the procedures that described PSEG's corrective action program at Salem. To assess the effectiveness of the corrective action program, the inspectors reviewed performance in three primary areas: problem identification, prioritization and evaluation of issues, and corrective action implementation. The inspectors compared performance in these areas to the requirements and standards contained in 10 CFR 50, Appendix B, Criterion XVl, "Corrective Action," and PSEG procedure LS-AA-125, "Corrective Action Program Procedure." For each of these areas, the inspectors considered risk insights from the station's risk analysis and reviewed notifications selected across the seven cornerstones of safety in the NRC's Reactor Oversight Process. Included in this sample were notifications that documented PSEGs evaluation and corrective actions for a selective sample of NRC-identified non-cited violations and findings that had been identified since the last biennial problem identification and resolution inspection completed in June 2009. Additionally, the inspectors attended plan-ofthe-day, station ownership committee, and management review committee meetings. The inspectors selected items from the following functional areas for review: engineering, operations, maintenance, emergency preparedness, radiation protection, chemistry and physical security.

(1) Effectiveness of Problem ldentification In addition to the items described above, the inspectors reviewed system health reports, a sample of completed corrective and preventative maintenance work orders, completed surveillance test procedures, operator logs, and periodic trend reports. The inspectors also 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 document issues identified through internal self-assessments, audits, emergency preparedness drills, and the operating experience program. The inspectors completed this review to verify that PSEG entered conditions adverse to quality into their corrective action program as apProPriate.

(2) Effectiveness of Prioritization and Evaluation of lssues The inspectors reviewed the evaluation and prioritization of a sample of notifications issued since the last NRC biennial Problem ldentification and Resolution inspection completed in June 20A9. The inspectors also reviewed notifications that were assigned lower levels of significance that did not include formal cause evaluations to ensure that they were properly classified. The inspectors' review included the appropriateness of the assigned significance, the scope and depth of the causal analysis, and the timeliness of resolution. The inspectors assessed whether the evaluations identified likely causes for the issues and developed appropriate corrective actions to address the identified causes. The inspectors also verified that, when necessary, issue evaluations addressed equipment operability, NRC reporting requirements, and other areas potentially affected by the identified performance deficiencies.

(3) Effectiveness of Corrective Actions The inspectors reviewed PSEG's completed corrective actions through documentation review and, in some cases, field walkdowns to determine whether the actions addressed the identified causes of the problems. The inspectors also reviewed notifications for adverse trends and repetitive problems to determine whether corrective actions were effective in addressing the broader issues. The inspectors reviewed PSEG's timeliness in implementing corrective actions and effectiveness in precluding recurrence for significant conditions adverse to quality. The inspectors also reviewed a sample of notifications associated with selected non-cited violations and findings to verify that PSEG personnel properly evaluatbd and resolved these issues. ln addition, the inspectors expanded the corrective action review to five years to evaluate PSEG actions related to service water and circulating water grassing, control air system moisture, control room chillers, safety injection pump bearings, and residual heat removal system oil leaks.

b.

Assessment

(1) Effectiveness of Problem ldentification PSEG staff at Salem initiated approximately 11,800 notifications between June 2009 and May 2011. For this inspection, as part of the scope described above, the inspectors reviewed the documentation associated with approximately 150 of these notifications.

Based on the samples selected for review, the inspectors determined that PSEG identified problems and entered them into the corrective action program at a low threshold.

The inspectors observed supervisors at the plan-of-the-day, station ownership committee, and management review committee meetings appropriately questioning and challenging notifications to ensure clarification of the issues that allowed for appropriate assignments for follow-up actions. The inspectors also concluded that PSEG trended equipment and programmatic issues at a low level, and appropriately documented problems identified through trending in the site's corrective action program.

The inspectors determined that, when appropriate, in response to inspector observations during this inspection, PSEG personnel promptly initiated notifications and took immediate action to address the issues of concern. In addition, based on the scope of issues reviewed by the inspectors, the inspectors did not identify concerns that were not appropriately entered into the corrective action program for evaluation and resolution.

(2) Effectiveness of Pdoritization and Evaluation of lssues The inspectors determined that, in general, PSEG appropriately prioritized and evaluated issues commensurate with the safety significance of the identified problem.

PSEG screened notifications for operability and reportability, categorized the notifications by significance, and assigned actions to the appropriate department for evaluation and resolution. The notification screening process considered human performance issues, radiological safety concerns, repetitiveness, adverse trends, and potential impact on the safety conscious work environment.

Items reviewed by the inspectors during the inspection were categorized for evaluation and resolution commensurate with the significance of the issues. Guidance provided by PSEG procedure LS-AA-120, "lssue ldentification and Screening Process," for categorization appeared sufficient to ensure consistent implementation based on the sample of notifications reviewed by the inspectors. ln general, issues were appropriately screened and prioritized commensurate with their safety significance.

The inspectors reviewed 15 root cause analyses,26 apparent cause analyses,6 common cause evaluations and approximately 20 work group evaluations. For the evaluations reviewed, the inspectors noted that PSEG's evaluations were generally thorough. Operability and reportability determinations were generally documented when conditions warranted and in most cases, the evaluations supported the conclusion.

Causal analyses appropriately considered the extent of condition or problem, generic issues, and previous occurrences of the issue.

(3) Effectiveness of Corrective Actions The inspectors reviewed notification disposition documentation and verification of corrective action implementation through reviews of implementing orders and discussions with personnel involved for over 150 PSEG notifications. The inspectors concluded, based on the samples reviewed, that corrective actions for identified deficiencies were typically timely and adequately implemented and that for significant conditions adverse to quality, PSEG identified actions to prevent recurrence and performed in-depth effectiveness reviews to verify that implemented corrective actions were effective. However, in one case, as a result of a review of PSEG's corrective actions for repetitive trips of service water strainers during periods of high river water grass since 2006, the inspectors identified one example of more than minor significance where PSEG did not implement timely corrective actions. This finding is documented below.

c.

Findinqs

(1) Untimelv Completion of Corrective Actions Results in No. 11 Service Water Strainer Trip Due To Grassinq lntroduction. The inspectors identified a self-revealing apparent violation of 10 CFR 50, Appendix B, Criterion XVl, "Corrective Action," because the 11 service water strainer overloads tripped on February 9, 2Q11, due to binding of the strainer rotating drum, which rendered the 11 service water pump inoperable and unavailable. The binding occurred because PSEG did not complete timely corrective actions for a condition adverse 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 surface by taking the actions specified in the corrective action program in January 2011. The grooves caused river grass to become trapped between the rotating strainer drum and body wear surface, which eventually bound and tripped the strainer overloads.

Description.

The Salem service water system is designed to supply cooling water to safety-related equipment under all credible environmental and weather-related conditions. The system consists of six pumps divided into two redundant trains, three pumps each. The pumps take suction from the Delaware River through trash racks and traveling screens designed to protect the pumps from river debris, while each pump discharges through an automatic self-cleaning strainer designed to protect the system's heat exchangers from tube blockage.

On February 9,2011, the 1 1 service water strainer thermal overloads tripped due to binding 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 water pump inoperable. PSEG determined that the cause of the binding was not installing a previously approved strainer design change intended to improve the service water strainers resistance to grass binding.

Each service water strainer assembly consists of a vertical mounted conical shaped drum with 1104 strainer media elements. The strainer drum rotates inside the strainer body with 0.015 to 0.063 inches of clearance between the drum and body to ensure the drum rotates freely. This clearance also allows a small amount of flow to bypass the strainer elements. Because this bypass flow results in river debris reaching and potentially fouling system safety- related heat exchangers, it is important to minimize it by maintaining the clearance between the drum and body small. In 2000, due to repetitive 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 wear ring that included an embedded rubber o-ring that decreased the clearance between the drum and the body.

After this design change, PSEG determined that, due to the silt entrained in the river water, even the small amount of bypass flow around the newly installed o-ring caused wear on the stralner drum and body. This wear over time increased the size of the gap between the drum and body and caused grooves on the body wear surface around the o-ring. The increasing gap, if not monitored and managed, caused higher bypass flow that both allowed grass and debris to bypass the strainer elements and drew grass and debris into the gap where it accumulated due to the tight clearances and o-ring wear grooves on the strainer body wear surface. The accumulation of grass in this area was not cleared during strainer backwash cycles and when it built up, caused increased friction between the drum and body. This increased the amount of current needed to rotate the strainer drum and eventually caused the thermal overload to trip due to the higher 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 preventing excessive bypass flow that could lead to grass accumulation and accelerated strainer wear. PSEG controls the gap between the strainer drum and body to within the vendor recommendations by performing preventative maintenance to inspect and adjust the service water strainer clearances every six months. Adjustments to the strainer during performance of this preventative maintenance were completed based upon the system engineer's reviews of the gap measurements and wear grooves. In addition, to further control the gap, PSEG performed the industry standard, every six year, service water strainer internal inspections every three years due to the harsh river water conditions at Salem. In the early 2000s, due to excessive wear grooves that were developing on the strainer body wear surfaces from the o-ring, PSEG issued a design change to modify the strainer bodies to include a monel wear ring. The intent of the design change was that the new wear ring material would increase the hardness of the wear surface increasing the wear surfaces durability and wear resistance and reducing the frequency of wear ring repairs. This modification was not installed on the 11 strainer at the time of the February 9,2011, trip.

PSEG identified, during its cause evaluation for the February 2011 trip, that a similar trip of the 11 service water strainer had occurred one year earlier on April 4,2010. The apparent cause evaluation for that trip determined the cause of the trip was untimely replacement of the 11 service water strainer body wear ring. The 11 service water strainer body configuration at the time of the April 2010 and February 201 1 trips was the configuration provided by the 1993 strainer replacement project. Because the monel wear ring was not installed, without interim corrective action, over time, due to the o-ring an excessive groove developed on the strainer body, which increased the susceptibility of the strainer to grass clogging. The groove on the 11 strainer body wear surface was a condition adverse to quality that PSEG identified in April 2010. At the time of the April 2010 trip, the groove was approximately 180 mils deep and 375 mils wide and by February 2011, due to no corrective actions being completed, the groove width increased to 500 mils with no increase in depth. After the April 2010 11 service water trip, PSEG determined that, in addition to the 11 strainer, five other strainers did not have 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 1 service water strainer trip was to develop and schedule the replacement plan for the six strainers that did not have the monel wear ring installed. This corrective action was documented as completed based on scheduling the work orders for the body replacement for all six strainers. The 1 1 strainer work was scheduled to be completed in January 2011. However, due to limited resources, the work was re-scheduled to January 2012. PSEG determined that the rescheduling was allowed to occur because the work was not properly coded as a plant health committee significant issue or as a grassing readiness priority in accordance with WC-AA-101-1002, "On-line Work Schedule Process." As a result, the identified condition adverse to quality was not promptly corrected and the 1 1 service water strainer tripped on February 9, 2011, due to grass binding, making the 11 service water pump inoperable and unavailable for 53 hours6.134259e-4 days <br />0.0147 hours <br />8.763227e-5 weeks <br />2.01665e-5 months <br />.

To address the performance deficiency, PSEG scheduled an interim design change for the 11 service water strainer to plasma spray the body wear ring before the next spring grassing season in January 2012. The plasma spray process will temporarily re-fill the groove in the strainer body wear ring. PSEG will then trend the 11 strainer body wear ring condition for future replacement with the monel wear ring. The monel wear ring design change on the 11 service water strainer is currently scheduled to be completed in April 2013.

PSEGs cause evaluation for the February 2011 strainer trip also identified four other strainers (14, 16,23, and 26) that still did not have the monel wear ring design change installed. Before the next spring grassing season, PSEG will either install the monel wear ring design change or complete temporary repairs if excessive grooving (greater than 0.125 inches deep) exists on the body wear surfaces for these strainers. PSEG will then monitor the strainers condition until the permanent repairs can be completed. In addition to the strainer repairs, PSEG revised service water system abnormal operating procedures to require operators to place the intake traveling screens in manual and the I

strainers in continuous blowdown operation during heavy grassing periods. This resulted in no strainer trips caused by grassing during the April 2011 grass peak.

Analvsis. The inspectors concluded that not completing timely repairs for excessive grooves identified on the 11 service water strainer body wear surface after the April 4, 2010, strainer trip was a performance deficiency. The untimely corrective actions resulted in the February 9,2011, 11 service water strainer trip. This performance deficiency was more than minor because it was associated with the equipment performance attribute of the initiating events and mitigating systems cornerstones. The finding affected the cornerstones' objectives to limit the likelihood of those events that could upset plant stability and challenge critical safety functions during power operations and to ensure the availability and reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, not completing timely corrective actions for excessive grooving identified on 11 strainer's body wear ring in January 2011 degraded 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 regional senior reactor analyst completes a Phase 3 analysis, in accordance with IMC 0609, Appendix A, "Determining the Significance of Reactor Inspection Findings for At-Power Situations." Phase 1 screened the finding to Phase 2 because the inspectors concluded that the finding contributed to both the likelihood of a reactor trip and the likelihood that mitigating systems would not have been available. This conclusion was based upon the increased chance of a loss of service water given one train being removed for strainer repairs and the loss of redundancy in the service water system to cool mitigating equipment 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 was required because the Salem Pre-solved Risk-lnformed Inspection Notebook does not address the loss of one train of service water. The Phase 3 analysis was not completed at the time of inspection report issuance. The analysis will be completed following determination of the proper assumptions for the increase in the loss of service water event frequency and the increase in the common cause failure probability, given the performance deficiency.

This finding has a cross-cutting aspect in the area of problem identification and resolution, corrective action program, because PSEG did not take appropriate corrective actions 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 timely actions to repair excessive grooves identified in the 11 service water strainer body wear ring in January 2011 because work control documents were not correctly coded in July 2010.

Enforcement.

10 CFR 50, Appendix B, Criterion XVl, "Corrective Action," requires, in part, that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and non-conformances are promptly identified and corrected. Contrary to the above, in July 2010, PSEG did not establish adequate measures to assure that a condition adverse to quality identified on the 11 service water strainer was promptly corrected. Specifically, because work control documents were not correctly coded in July 2010, PSEG did not repair excessive grooves identified on the 1 1 service water strainer body wear ring in January 2011. As a result, on February 9,2011, the 1 1 service 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 this issue, the finding was identified as an apparent violation. (AV 0500027213112011009-01, Untimely Completion of Corrective Actions Results in No. 11 Service Water Strainer Trip Due To Grassing)

.2 Assessment of the Use of Operatinq Experience

a. lnspection Scope The inspectors reviewed a sample of notifications associated with review of industry operating experience to verify that PSEG appropriately evaluated the operating experience information for applicability to Salem and had taken appropriate actions, when warranted. The inspectors also reviewed evaluations of operating experience documents associated with a sample of NRC generic communications to ensure that Salem adequately considered the underlying problems associated with the issues for resolution via their corrective action program.

Assessment The inspectors determined that PSEG appropriately considered industry operating experience information for applicability, and used the information for corrective and preventive actions to identify and prevent similar issues when appropriate. The inspectors determined that operating experience was appropriately applied and lessons learned were communicated and incorporated into plant operations and procedures when applicable. The inspectors also observed that industry operating experience was routinely discussed and considered during the conduct of Plan-of-the-Day meetings and pre-job briefs.

c. Findinqs No findings were identified.

.3 Assessment of Self-Assessments and Audits

Inspection Scope The inspectors reviewed a sample of audits, including the most recent audit of the corrective action program, departmental self-assessments, and assessments performed by independent organizations. Inspectors performed these reviews to determine if PSEG entered problems identified through these assessments into the corrective action program, when appropriate, and whether PSEG initiated corrective actions to address identified deficiencies. The inspectors evaluated the effectiveness of the audits and assessments by comparing audit and assessment results against self-revealing and NRC-identified observations made during the inspection.

b. Assessment The inspectors concluded that self-assessments, audits, and other internal PSEG assessments were generally critical, thorough, and effective in identifying issues. The inspectors observed that PSEG personnel knowledgeable in the subject completed these audits and self-assessments in a methodical manner. PSEG completed these audits and self-assessments to a sufficient depth to identify issues which were then entered into the corrective action program for evaluation. In general, the station implemented corrective actions associated with the identified issues commensurate with their safety significance.

c.

Findinqs No findings were identified.

.4 Assessment of Safetv Conscious Work Environment (SCWE)

a. Inspection Scope

During interviews with station personnel, the inspectors assessed the safety conscious work environment at Salem. Specifically, the inspectors interviewed personnel to determine whether they were hesitant to raise safety concerns to their management and/or the NRC. The inspectors reviewed implementation of the site employee concerns program (ECP). Specifically, the inspectors reviewed the site procedure for conducting ECP investigations and reviewed a sample of ECP files to assess the program's effectiveness at addressing potential safety issues and to verify that PSEG entered issues into the corrective action program when appropriate. The inspectors also reviewed the results of the contractor-performed January 201 1 Nuclear Safety Culture Assessment and PSEG's December 2009 Nuclear Safety Culture Principles Self-Assessment. The review included a discussion of the corrective actions identified by PSEG to address issues uncovered during the assessments.

b. Assessment Based on interviews and reviews of the corrective action program and the ECP, the inspectors determined that site personnel were willing to identify and raise safety issues.

All persons interviewed demonstrated an adequate knowledge of the avenues available for raising safety concerns including the corrective action program and ECP. The inspectors also determined that the results of the nuclear safety culture surveys conducted in December 2009 and January 2011 provided PSEG insights into the safety culture of the site workforce.

c. Findinqs No findings were identified.

4OAO Meetinqs. Includinq Exit On 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 inspectors verified that no proprietary information was retained by the inspectors or documented in this report.

On September 2, 2011, during a telephone call with Mr. C. Fricker, the inspectors discussed the status of the phase 3 significance determination process analysis for the finding related to untimely completion of corrective actions for 11 SW strainer. At that time the inspectors informed Mr. Fricker that the report would document the significance of the finding as TBD pending determination of the proper assumptions for the increase in the loss of service water event frequency and the increase in the common cause failure probability relative to the performance deficiency.

ATTACHMENT: SU PPLEMENTAL I N FORMATI ON

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 Support

LIST OF ITEMS OPENED, CLOSED, DISCUSSED, AND UPDATED

Opened and Closed

0500027 2, 31 1I 201 1 009-0 1 Untimely Completion of Corrective Actions

Results in No. 11 Service Water Strainer Trip

Due To Grassing

LIST OF DOCUMENTS REVIEWED

Section 4OA2: Problem ldentification and Resolution

Audits and Self-Assessments

70095327, Boric Acid Corrosion Control Functional Area Self-Assessment (FASA), 04116109

70096371, Contamination Control Self-Assessment, 09/03/09

70098506, 2009 Maintenance Resource Management FASA, 07i13/09

70106832, Salem Emergency Preparedness and its lmplementing Procedure Self-Assessment,

04t3012010

801 01 252, Emergency Preparedness Audit, 0411412010

8A102024, Engineering Programs and Station Blackout Audit, 08111110

80103001, Security Plan, FFD, Access Authorization, and PADS Audit, 02102111

70118428,2011 Problem ldentification and Resolution FASA, 03104111

70098602. Nuclear Safety Culture Principles Self Assessment. 12111109

80103804, Corrective Action Program Audit Report, 05/18/201 1

70109034, Component Design Bases lnspection FASA, 09115110

0092328, Adverse Co ndition Mon itori ng Effectiveness, 09/1 8/09

Condition Reports

20417280 20267714 20406749 20479582 20446414

20417626 20388347 20407953 20483408 20445647

20425928 20397713 20409949 20482161 2051 0037

20435006 20413128 20418071 20483619 2051 0035

20443188 20419423 20428645 20487750 20510034

20457965 20498433 204301 69 20487842 20509262

20462560 20505452 20433213 24490787 205091 84

20483570 20505453 20439278 20494178 20508042

20491 696 20451912 20439815 20495260 20507968

20494419 20187133 20440514 20495818 20510255

20505378 20262270 20451211 20495922 20448538

20512712 20277684 20452701 20499967 20448540

20367060 20284783 20452998 20504540 20405289

20324061 20294705 20454116 20504544 20506132

20419661 20330790 24464750 2Q504911 20505836

267714 20330961 20465141 20505092 20505720

20388347 20332776 20467120 20449195 20502800

20397713 20339102 20469515 20422673 20301686

20413128 20347302 20470602 20501675 20501037

20419423 20356908 20472533 20506984 20499642

20498433 20361 055 20472897 20508494 20506137

20505452 20361 91 6 20457056 20510374 20451229

20505453 20366420 20476809 20097981 20434554

20451912 20379814 20476813 20205100 20465672

20358322 20382427 20476814 20227288 20419661

20354920 20382938 20476815 202640Q9 20401134

20367060 20383151 20476816 20254414 20478887

20324061 20386825 20476817 20451940 20437047

Cause Evaluations

70051392 70120414 701 1 0851 70120053 70116493

70077526 70122605 70112123 70120420 701 06673

70092295 70112239 70112241 70120534 701 03591

70122711 70103430 70112630 70120414 70112241

70124648 70100173 70114571 70120882 70112239

70124565 700451 33 70115067 70121613 70111625

70111159 70094482 70115200 70121619 70111537

70115587 70070964 70115231 70121621 70109827

70121626 70071995 70116446 70122004 70106627

70122719 70087882 7A116452 70122594 70106293

70123045 700941 38 74117931 70122739 70090887

7Q107468 70096332 70119028 70123710 70118218

70079931 70096759 70119029 70122874 70120968

70078030 70098506 70119042 701 051 1 I 70109406

70048918 70102030 70119150 701 05604 70066657

70074694 70104321 70119153 70110652

70112680 70110664 70119155 70115842

701 19080 701 10650 70119723 70115228

Drawinos

205200, Unit 1 Control Air - Turbine Building, Sh.1, Revislon 51

205243, Unit 1 Control Air - Auxiliary Building, Sh. 1, Revision 47

205247, Unit 1 Control Air - Reactor Control & Penetration Area, Sh. 1, Revision 49

205332, Unit 2 Residual Heat Removal Pl&D, Sh. 1, Revision 36

604495, Units 1&2 Control Air Yard Area - Station Blackout, Revision 2

Operatinq Experience

70109152, Post Tritium Report

70109718, 1'1A Circ Water Pump Casing Cracked

70109788, NRC lnformation Notice 2010-04

70119956, NRC lnformation Notice 2010-20

70078424,Intake Cooling Water Blockage Corrective Action Effectiveness Review

01 23625, nconsistent m plementation of Operating Experience Proced u re

I I

70118713, Operating Experience Review From CDBI Self Assessment

70123261, Service Water Piping lssues

70109106, Auxiliary Feed Pump Actuation

NCVs and Findinqs0500027212009003-02, Inadequate maintenance of the 13 AFW pump governor

0500031 1/2009003-01, lmproper MR scoping of the service water intake structure sump system

O5OOO272l3112AO9O07-01, Failure to establish goals and monitor for (a)(1) service water

system

0500031 1/2009005-01, Unit 2 Degradation of Shutdown Cooling Caused by Failure ot 22RH18

0500031112009005-02, Inadequate Maintenance of the 22 CCHX Service Water Outlet Butterfly

Valve

05000272131 1 12010002-01, Chillers Inoperability Exceeds TS AOT

050A0272131 1 /201 0003-02, 21 SGFP Trip

05000272131112010005-01, 13 TDAFW pump trip mechanism

05A00272131112011007-01 , Inadequate Calculations for Degraded Voltage Relay Set Point

05000272131112011007-02, Failure to Perform a TS Required Battery Performance Test

05000272131112009403-01, Failure to Detect Penetration or Attempted Penetration at the

Protected Area Boundary

0500027 21 31 1 l 2009403-02, I nadeq uate Protected Area E ntry Sea rch

05000272131112011007-03, Failure to ldentify and Correct A Condition Adverse to Quatity

Affecting CREACS Expansion Joints

LERS

OISOOOZZZ\2Ol0-001-0, Automatic Start of the 1C Emergency Diesel Generator (EDG)

O5OOO272\2O1O-002-\ Missed Containment Spray Valve Surveillance Per Technical Specification 4.0.5

O5OOO27 2120 1 0-004-0, Tech n ical Specif ication 3. 0. 4. b Non-Com pliance

0500027212008-002-0, Automatic Reactor Trip Due to Main Power Transformer Bushing Failure

Procedures

LS-AA-115, Operating Experience Program, Revision 12

LS-AA-1 15-1001, Manual for Processing OE1 Documents, Revision 1

LS-AA-115-1002, Manualfor Processing OE2 Documents, Revision 0

LS-AA-115-1003, Manualfor Processing OE3 Documents, Revision 0

LS-AA-1 15-1004, Manual for Processing OE4 Documents, Revision 0

ER-AA-3130-1005, Maintenance Rule Dispositioning between (a)(1) and (aX2), Revision 7

ER-AA-310, lmplementation of the Maintenance Rule, Revision 8

LS-AA-120, lssue ldentification and Screening Process, Revision 10

LS-AA-125, Corrective Action Program (CAP) Procedure, Revision 13

LS-AA-1 25-1002, Common Cause Analysis Manual, Revision 7

LS-AA-125-1003, Apparent Cause Evaluation Manual, Revision 11

LS-AA-125-1004, Effectiveness Review Manual, Revision 4

LS-AA-1 26, Self-Assessment Program, Revision 9

LS-AA-126-1 001, Focused Area Self-Assessments, Revision 5

LS-AA-1 26-1 005, Check-ln Self-Assessments, Revision 4

S

C. lC-Tl.CA-000't, Control Air Dryers Preventative Maintenance, Revision 3

SC.MD-PM.AF-0007, 13 and 23 Auxiliary Feedwater Terry Turbine Linkage Inspection and

Lubrication, Revision 2

WC-AA-106, Work Screening and Processing, Revision 11

LS-AA-125-1001, Root Cause Evaluation Manual, Revision 8

LS-AA-125-1005, Coding and Analysis Manual, Revision 6

LS-AA-125-1006, Department and Station Roll-up Meetings (DRUM SRUM), Revision 2

LS-AA-125-F1, Salem/Hope Creek MRC Evaluation and Effectiveness Checklist and Grading

Sheet. Revision 2

LS-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 2

Maintenance Work Orders

60060469 30117617 50141282 60087672 60093560

60080965 30184482 40026546 60087673 60083756

60083302 30189127 30188428 60087602 60085587

60084441 50127727 301 92058 301 86829 600891 50

6008661 5 50127830 30192351 60086708 30182608

60080388 501 38541 301 931 95 301 76991 60089757

30164377 501 39495 301 9321 0 30190777 60083368

30076957 501 39801 301 86321 30079595

30174943 501 40351 60091 71 6 60078098

Completed Surveillances

S1.OP-ST.DG-002, 1B Diesel Generator Surveillance Test, Completed 06113111

S1 .OP-ST.DG-0014, 1C Diesel Generator Endurance Run, Completed 03/16/1 1

2.OP-ST.DG-004, 21 Fuel Oil Transfer System Operability Test, Completed 06/13i11

S2.OP-ST.DG-0019,2A Diesel Generator Hot Restart Test, Completed 021Q4111

2.OP-ST.DG-004, 21 Fuel Oil Transfer System Operability Test, Completed 07111111

S1.OP-ST.AF-0003, Inservice Testing - 13 Auxiliary Feedwater Pump, 06130111

S1.OP-ST.AF-0004, Inservice Testing - Auxiliary Feedwater Valves, 06113111

S1.OP-ST.AF-0008, Auxiliary Feedwater Valve Verification Modes 1-3,06120111

2.OP-ST.AF-0003, Inservice Testing - 23 Auxiliary Feedwater Pump, 05106111

2.OP-ST.AF-0006, lnservice Testing - Auxiliary Feedwater Valves, 05124111

2.OP-ST.AF-0009, Plant Systems - Auxiliary Feedwater, 0510411 1

Miscellaneous

Station Air System Health Report- 2no Quarter 2011

Unit 1 Auxiliary Feedwater System Health Report- 2no Quarler 2011

Unit 2 Auxiliary Feedwater System Health Report - 2no Quarter 2Q11

Unit 1 Residual Heat Removal System Health Report - 2no Quarter 2011

Unit 2 Residual Heat Removal System Health Report - 2no Quarter 2Q11

Salem ControlAir Quality Test Results, September, 2009 to June 2011

Emergency Preparedness Training Drill Critique Report (S11-02), 0512512011

Order 80102809, Provide Range for Oil Levels in RHR Pump Motor Oil Reservoirs, 1111912010

CMP-1SW-7 "#13 Containment Fan Coil Unit Service Water Outlet Check Valves to the Service

Water Discharge Header CM Plan (Unit 1)

LIST OF AGRONYMS

ADAMS Agency-wide Documents Access and Management System

CFR Code of Federal Regulations

ECP Employee Concerns Program

tMc Inspection Manual Chapter

NCV Non-Cited Violation

NRC Nuclear Regulatory Commission

PARS Publicly Available Records System

PSEG PSEG Nuclear LLC

SCWE Safety Conscious Work Environment

SDP Significance Determination Process

SPAR Standardized Plant Analysis Risk

Attachment