IR 05000272/2011004

IR 05000272-11-004 & 05000311-11-004, on 07-01-11 - 09-30-11, Salem Nuclear Generating Station, Unit Nos. 1 and 2 - NRC Integrated Inspection Report

ML113130028
Person / Time
Site:	Salem
Issue date:	11/09/2011
From:	Arthur Burritt Reactor Projects Branch 3
To:	Joyce T Public Service Enterprise Group
BURRITT, AL
References
IR-11-004
Download: ML113130028 (40)

Text

UNITED STATES NUCLEAR REGU LATORY COMMISSION

REGION I

475 ALLENDALE ROAD KING OF PRUSSIA, PENNSYLVANIA 19406.1415 rrf November 9, 2011.

Mr. Thomas President and Chief Nuclear Officer PSEG Nuclear LLC - N09 P.O. Box 236 Hancock's Bridge, NJ 08038 SUBJECT: SALEM NUCLEAR GENERATING STATION, UNIT NOS. 1 AND 2.

NRC INTEGRATED INSPECTION REPORT O5OOO272I2O11OO4 And 0500031 112011004

Dear Mr. Joyce:

On September 30, 2011, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at the Salem Nuclear Generating Station, Unit Nos. 1 and 2. The enclosed integrated inspection report documents the inspection results discussed on October 6,2011, with Mr. Wagner and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commission's rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

The report documents one NRC identified and two self-revealing findings of very low safety significance (Green). Two of these findings were determined to involve violations of NRC requirements. The report also documents completion of the final significance determination for AV 0500027212A11009-01 that also involved a violation of NRC requirements. The Phase 3 significance determination process analysis for this finding was not previously completed because additional evaluation of the assumptions regarding event frequency and common cause failure probability were required. A senior reactor analyst completed the Phase 3 significance determination process analysis for this finding and determined it was of very low safety significance. Because of the very low safety significance of the findings and because they were entered into your CAP, the three findings that involve violations of NRC requirements will be treated as non-cited violations consistent with Section 2.3.2.a of the NRC Enforcement Policy.

lf you contest any NCV in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the RegionalAdministrator, Region l; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Salem Nuclear Generating Station. ln addition, if you disagree with the cross-cutting aspect assigned to any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis of your disagreement, to the Regional Administrator, Region l, and the NRC Resident Inspector at Salem Nuclear Generating Station. ln accordance with 10 Code of Federal Regulations (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 NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

/4 SincerelY'

L--'l {J Y-(//N H4"/U c Arthur L. Burritt, Chief Projects Branch 3 Division of Reactor Projects Docket Nos: 50-272;50-311 License Nos: DPR-70; DPR-75 Enclosure: I nspection Report 0500027 21 201 1 004 a nd 0500031 1 l 20 1 I 004 w/Attachment: Supplemental I nformation cc Mencl: Distribution via ListServ

SUMMARY OF FINDINGS

lR 0500027212011004, 0500031112011004; Q7lO1l2O11 - 0913012011; Salem Nuclear

Generating Station Unit Nos. 1 and 2; Post-Maintenance Testing, Refueling and Other Activities,

Event Follow-up, Other Activities.

The report covered a three-month period of inspection by resident inspectors, and announced inspections by a regional radiation specialist and reactor engineers. One Green finding and two Green NCVs were identified. The report also finalizes the significance determination for TBD AV 0500027212011009-01 as Green (Section 4OA5). The significance of most findings is indicated by their color (Green, White, Yellow, or Red) and determined using Inspection Manual Chapter (lMC) 0609, "Significance Determination Process" (SDP). The cross cutting aspect of a finding is determined using the guidance in IMC 0310, "Components Within the Cross-Cutting Areas." Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 4, dated December 2006.

Cornerstone: Initiating Events

.

Green.

A self-revealing finding of very low safety significance was identified on June 26, 2011, as Salem Unit 2 tripped following a trip of the 23 reactor coolant pump (RCP) due to a ground fault inside the 23 RCP motor junction box. PSEG determined that the cause of the ground fault was RCP motor cable jacket cracking that was first identified in 2005. PSEG entered this event into the CAP as notification 20515977.

The performance deficiency was more than minor because it was associated with the equipment performance attribute of the Initiating Events cornerstone, and it adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during power operations. Specifically, action from notifications in January 2006 for the engineering department to determine various options to address RCP motor lead jacket cracking including an evaluation on whether to replace the cables during the June 2008 refueling outage (RFO) was not completed prior to the June 2008 motor replacement and continued to be an open action up to the point of the June 2011 RCP cable failure and reactor trip. The finding was evaluated under IMC 0609, Attachment 4, "Phase 1 - Initial Screening and Characterization of Findings." The inspectors determined that the finding is of very low safety significance because it did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions would not be available. This finding had a cross-cutting aspect in the area of problem identification and resolution, corrective action program, because PSEG did not take appropriate corrective action to address safety issues and adverse trends in a timely manner, commensurate with their safety significance and complexity. Specifically, PSEG did not ensure that the CAP assignment for the engineering department to evaluate longterm corrective action options for the RCP motor lead cables were completed timely and effectively in accordance with their CAP procedure. (P.1(d)) (Section 1R20)

Cornerstone: Mitigating Systems

.

Green.

The inspectors identified a NCV of Salem Technical Specification (TS) 6.8.4.j,

"ln Service Testing," that implements the in service testing program for ASME Code-omponents Class 1,2, and 3 in accordance with the American Society of Mechanical Engineers (ASME) Operations and Maintenance (OM) code. Specifically, PSEG di9.n9t complete an adequate ASME OM code required evaluation following the test of the Unit 2 Boron lnjection Tank (BlT) relief, 2SJ1O, which lifted outside of its acceptance criteria.

This findin-g was determined to be of very low safety significance. PSEG entered this issue into their CAP as notifications 20523948 and 20518249. Corrective actions at that time included replacing the damaged seat and disk, rebuilding the valve, and performing a post maintenance test of the rebuilt valve.

This finding is more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone, and it impacted the cornerstone objective of ensuring the availability, reliability, and capability of systems to respond to iniiiating events to prevent undesirable consequences. Specifically, leakage of greater than l Ogpm through the 2SJ10 valve degraded the ability of the charging system to deliver design flow rates to the reactor following a safety injection signal that would un-isolate tne glf. The inspectors evaluated this finding using IMC 0609, Attachment 4'

The finding was determined to be of very low safety significance because it was not a design or qualification deficiency, did not represent an actual loss of system safety function, and was not potentially risk significant for external events. This finding had a cross-cutting aspect in the area of problem identification and resolution, corrective action program, beiause PSEG did not thoroughly evaluate problems such that the resolutions addless causes and extent of conditions, as necessary. Specifically, PSEG's evaluation following the 2SJ10 failure in April 2011 did not meet the requirements of PSEG procedure ER-SA-321-1010. The evaluation contained incorrect information regarding valve refurbishment that prevented PSEG from identifying the cause of the 2SJ10 failure. (P.1(c)) (Section 1R19)

Gornerstone: Emergency Preparedness o

Green.

The inspectors identified a NCV of 10 CFR 50.47, "Emergency Plans."

Specifically, staie officials were not notified within 15 minutes of the declaration of an Unusual Event (UE), a risk significant planning standard. PSEG has entered this issue into their CAP as notification 20518004. PSEG's corrective actions for this performance deficiency was to complete licensed operator training regarding classification and notification requirements for short duration emergency events terminated before classifications and notifications can be completed.

The inspectors determined that a performance deficiency was identified associated with timely notification to state and local government agencies during an actual event' PSEG diO nbt notify Delaware and New Jersey state government agencies within the specified 1S minutes after declaring a UE. The finding was greater than minor because it is associated with the Emergency Planning cornerstone attribute of Emergency Response Organization performance during actual event response. The finding affected the cornerstone objective of ensuring that the licensee is capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. The inspectors reviewed this finding using IMC 0609, Appendix B,

"Emergeniy Preparedness Significance Determination Process," Sheet 2, "Actual Event lmplementation Problem." This finding was determined to be of low safety significance because it was a failure to implement a risk significant planning standard during an actual event associated with the declaration of a UE. This finding had a cross-cutting aspect in the area of human performance, work practices, because PSEG personnel did not ensure supervisory and management oversight of work activities, such that nuclear safety is supported. Specifically, the Shift Manager was distracted from his supervisory oversight role and did not direct the communicators to perform state notifications within the required 15 minute time period. (H.4(c)) (Section 4OA3)

REPORT DETAILS

Summarv of Plant Status Salem Nuclear Generating Station Unit 1 (Unit 1) began the period at 100 percent power. On August 30, 201 1, plant operators reduced power to 64 percent due to heavy river detritus following Hurricane lrene. Operators returned Unit 1 to full power on September 7. On September 8, operators reduced power to 95 percent, on September 9, operators reduced power to 85 percent, on September 10, operators reduced power to 60 percent, and on September 12, operators reduced power to 40 percent. Each of these power reductions were performed because of heavy river detritus. As the river detritus levels subsided, operators commenced power ascension on September 14 and returned Unit 1 to 100 percent power on September 27, 2011. Unit 1 remained at 100 percer'rt power for the remainder of the period.

Salem Nuclear Generating Station Unit 2 (Unit 2) began the period shut down for a forced outage. Unit 2 was synchronized to the grid on July 1 ,2011, and returned to full power on July 5, 2011. On July 14, plant operators performed a manual reactor shutdown following a high head injection piping leak caused by a cracked weld. Unit 2 was synchronized to the grid on July 19,2Q11, and reached full power later that day. Unit 2 remained at 100 percent power for the remainder of the period.

1. REACTORSAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier lntegrity, and Emergency Preparedness

1R01 Adverse Weather Protection

.1 Evaluate Readiness for Seasonal Extreme Weather Conditions

a. Inspection Scope

The inspectors completed one adverse weather protection sample to evaluate readiness for seasonal extreme weather conditions, The inspectors reviewed PSEG's preparation and protection of risk significant systems at tJnit 1 and Unit 2 during hot weather conditions between July 5 and July 6,2011. The inspectors evaluated PSEG's implementation of summer readiness procedures and compensatory measures for extreme hot weather that included ultimate heat sink temperatures above 84'F and ambient air temperatures above 100"F. The inspectors walked down risk-significant structures, systems, and components (SSCs)to ensure that weather-related conditions did not adversely impact SSC operability. In addition, the inspectors assessed the condition of balance of plant equipment with the potential to initiate plant-level transients.

The inspectors performed detailed walkdowns of the service water (SW) intake structure, emergency diesel generators (EDGs), vital switchgear rooms, component cooling water (CCW), and the main turbine and generators. The inspectors also reviewed PSEG corrective action notifications to ensure that PSEG appropriately identified and resolved weather related problems. Documents reviewed are listed in the Attachment.

b.

Findinos No findings were identified.

.2 Evaluate Readiness for lmpendinq Adverse Weather Conditions

a.

Insoection Scope The inspectors completed one impending adverse weather protection sample. The inspectors reviewed the actions completed by PSEG to prepare for Hurricane lrene between August 25 and August 27,2011. The inspectors evaluated PSEG's implementation of severe weather and fatigue management procedures and compensatory measures for extreme wind speed and rain that included predicted wind speed above 74 mph and rain accumulation Above 7 inches. The inspectors verified that adequate operating staffing was onsite for the predicted conditions. The inspectors walked down risk-significant SSCs to ensure that weather related conditions did not adversely impact SSC operability. ln addition, the inspectors walked down the entire site to ensure that equipment and temporary structures where firmly secured so as to not create hazards during the predicted high winds. The inspectors performed detailed walkdowns of the SW intake structure, EDGs, the main turbine and generators, and all outside equipment laydown areas. Documents reviewed are listed in the Attachment.

b. Findinqs No findings were identified.

1R04 Equioment Alisnment (71111.04 - 4 samples; 71111.045 - 1 sample)

.1 PartialWalkdown

a. Inspection Scope

The inspectors completed four partial system walkdown inspection samples. The inspectors walked down the systems listed below to verify the system's operability when redundant or diverse trains and components were inoperable. The inspectors focused their review on potential discrepancies that could impact the function of the system and increase plant risk. The inspectors reviewed applicable operating procedures, walked down control system components, and verified that selected breakers, valves, and support equipment were in the correct position to support system operation. The inspectors also verified that PSEG properly utilized its CAP to identify and resolve equipment alignment problems. Documents reviewed are listed in the Attachment.

.

Unit 2, 2A and 28 EDGs with 2C EDG out of service (OOS) on August 18

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Unit 1, 12 and 13 CCW pump with 1 1 CCW pump OOS on August 22 r Unit 1, 11 and 12 chillers with 13 chiller OOS on September 19 o Units 1 and 2, 1A, 1 B, 1C, 2A, 28 and 2C EDGs while on a single source of off-site electrical power on September 26 b. Findinos No findings were identified.

I

.2 Complete Walkdown

a. lnspection Scope The inspectors conducted one complete walkdown inspection sample of the Unit 1 and Unit 2 containment spray systems. The inspectors independently verified the alignment and status of the containment spray pumps and valve electrical power, labeling, hangers and supports, and associated support systems. The walkdown also included verification of valve positions, evaluation of system piping and equipment to verify pipe hangers were in satisfactory condition, oil reservoir levels were normal, pump rooms were adequately ventilated, system parameters were within established ranges, and equipment deficiencies were appropriately identified. The inspectors interviewed engineering personnel and reviewed corrective action evaluations associated with the system to verify that equipment alignment problems were identified and corrected.

Documents reviewed are listed in the Attachment.

b. Findinqs No findings were identified.

1R05 Fire Protection (71111

.1 Fire Protection - Tours

a. lnspection Scope The inspectors completed six fire protection quarterly inspection samples. The inspectors walked down the systems listed below to assess the material condition and operational status of fire protection features. The inspectors verified that combustibles and ignition sources were controlled in accordance with PSEG's administrative procedures; fire detection and suppression equipment was available for use; that passive fire barriers were maintained in good material condition; and that compensatory measures for OOS, degraded, or inoperable fire protection equipment were implemented in accordance with PSEG's fire plan. Documents reviewed are listed in the Attachment.

o Unit 1, Charging Pumps, Spray Additive Tank Area, 84' elevation r Unit 2, Charging Pumps, Spray Additive Tank Area, 84'elevation o Unit 1, Charging and Volume Control (CVC) System Hold-up Tank Area, 64' elevation r Unit 1, Diesel Generator Area, 100' and 122' elevation o Unit 2, Diesel Generator Area, 100' and 122' elevation

.

Unit 1, Outer Penetration Area b. Findinqs No findings were identified.

I

.2 Fire Protection - Drill Observation

a. Inspection Scope

The inspectors completed one fire drill observation sample. The inspectors observed an unannounced fire drill conducted in the Unit 2 chemical lab on August 23,2011. The inspectors observed the drill to evaluate the rteadiness of the plant fire brigade to fight fires. The inspectors verified that PSEG staff identified deficiencies; openly discussed them in a self-critical manner at the drill debrief; and took appropriate corrective actions.

Specific attributes evaluated were: proper wearing of turnout gear and self-contained breathing apparatus; proper use and layout of fire hoses; use of appropriate fire fighting techniques; sufficient firefighting equipment brought to the scene; effectiveness of fire brigade leader communications, command, and control; search for victims and propagation of the fire into other plant areas; smoke removal operations; utilization of pre-planned strategies; and adherence to the pre-planned drill scenario and drill objectives.

b.

Findinqs No findings were identified.

1R1 1 Licensed Ooerator Requalification Proqram (71111

.1 Requalification Activities Review bv Resident Staff

a.

lnspection Scope The inspectors completed one quarterly licensed operator requalification program inspection sample. Specifically, the inspectors observed a simulator scenario on September 15,2011. The scenario included a large break loss of coolant accident with an anticipated transient without scram complicated by a stuck open steam generator safety valve and flooding in the number 4 SW bay. The inspectors reviewed operator implementation of the site's abnormal and emergency operating procedures, and confirmed that lessons learned items from previous training scenarios and events were incorporated into operator response where applicable. The inspectors also verified that deficiencies identified during the scenario were discussed during scenario debriefs. The documents reviewed are listed in the Attachment.

b.

Findinqs No findings were identified.

1R12 Maintenance Effectiveness

a.

lnspection Scope The inspectors completed three quarterly maintenance effectiveness inspection samples. The inspectors reviewed performance monitoring and maintenance effectiveness issues for the systems listed below. The inspectors reviewed PSEG's process for monitoring equipment performance and assessing preventive maintenance effectiveness. The inspectors verified that systems and components were monitored in accordance with the maintenance rule program requirements. The inspectors confirmed that the functional failure determinations and unavailability hours for these systems were documented in accordance with the maintenance rule and that PSEG established performance goals for these systems were met. The inspectors interviewed engineering personnel and reviewed applicable work orders (WOs), corrective action notifications, and preventive maintenance tasks for these systems. The documents reviewed are listed in the Attachment.

.

Unit 1 and Unit 2 circulating water systems r Unit 1 and Unit 2 manipulator cranes

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Unit 1 CCW system b. Findinos No findings were identified.

1R13 Maintenance Risk Assessments and Emerqent Work Control

a. lnspection Scope The inspectors completed four maintenance risk assessment and emergent work control inspection samples. The inspectors reviewed the maintenance activities listed below to verify that the appropriate risk assessments were performed as specified by 10 CFR 50.65(a)( ) prior to removing equipment for work. The inspectors reviewed the applicable risk evaluations, work schedules, and control room logs for these configurations. PSEG's risk management aotions were reviewed during shift turnover meetings, control room tours, and plant walkdowns. The inspectors used PSEG's on-line risk monitor (Equipment OOS workstation) to gain insights into the risk associated with these plant configurations. The inspectors also reviewed corrective action notifications written to document problems associated with risk assessments and emergent work evaluations. Documents reviewed are listed in the Attachment.

.

Unit 1 and Unit 2, control area ventilation damper planned maintenance on August

.

Unit 1, 11 CCW pump OOS for unplanned maintenance on August 22

.

Unit 2,21 component cooling heat exchanger and 23 SW pump OOS for planned maintenance on August 24

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Unit 1 and Unit 2, single source of offsite power during planned switchyard maintenance on September 26 b. Findinss No findings were identified.

1R15 Operabilitv Evaluations

a. Inspection Scope

The inspectors completed four operability evaluation inspection samples. The inspectors reviewed the operability determinations for degraded or non-conforming conditions associated with:

o Unit 1 , 1C EDG, 13SW39 failed stroke time during an in-service test (lST)

.

Unit 2, solid-state protection system time response after trip signal o Unit 2, 2SW163,22 satety injection (Sl) pump lube oil cooler SW valve stroking slowly o Unit 2,22 charging pump oil leak on speed increaser The inspectors reviewed the technical adequacy of the operability determinations to ensure the conclusions were justified. The inspectors also walked down accessible equipment to corroborate the adequacy of PSEG's operability determinations.

Additionally, the inspectors reviewed other PSEG identified safety-related equipment deficiencies during this report period and assessed the adequacy of their operability screenings. The documents reviewed are listed in the Attachment.

b. Findinqs No findings were identified.

1R18 Plant Modifications

.1 Permanent Modifications

a. Inspection Scope

The inspectors completed two plant modification inspection samples by reviewing the key characteristics associated with the two permanent plant modifications listed below.

The inspectors' review verified that the design bases, licensing bases, and performance capability of the affected systems were not degraded by the modifications. The inspectors verified the new configuration was accurately reflected in the design documentation and that the post-modification testing was adequate to ensure the (SSCs) affected would continue to function properly. The inspectors also interviewed plant staff and reviewed issues that were entered into the CAP to assess whether PSEG was effective at identifying and resolving problems associated with the modification process. The 10 CFR 50.59 screening associated with these permanent plant modifications were also reviewed. Documents reviewed are listed in the Attachment.

r Unit 1, installation of a high point vent and associated valves on the residual heat removal (RHR) cross-connect header between RHR pumps after inspecting the system per NRC Generic Letter 2008-001 o Unit 1, replacement of the SW25 manual isolation valves on the SW pump automatic strainer backwash discharge. The 6 inch 316L stainless steel plug valves were replaced with 6 inch BNL molybdenum stainless steel ballvalves.

b. Findinos No findings were identified.

1R19 Post-Maintenance Testino (71111.19 - 6 sarnples)

a. Inspection Scope

The inspectors completed six post-maintenance testing (PMT) inspection samples. The inspectors observed portions of and/or reviewed the PMT results for the maintenance activities listed below. The inspectors verified that the effect of testing on the plant was adequately addressed by control room and engineering personnel; testing was adequate for the maintenance performed; acceptance criteria were clear, demonstrated operational readiness, and were consistent with design and licensing basis documentation; test instrumentation calibration was current and the appropriate range and accuracy for the application; tests were performed, as written, with applicable prerequisites satisfied; and equipment was returned to an operational status and ready to perform its safety function. The documents reviewed are listed in the Attachment.

r WO 40013700, 22 CVC pump after valve replacement on August 17

.

WO 60097458, 22 Sl pump gear oil cooler SW valve (2SW163) repair on August 16

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WO 60085314, 12-13 CCW discharge header cross-over valve (12CC3) and 12-13 CCW suction header cross-over valve (12CC18) motor modifications on August 30 e WO 60097859, 2SJ10 BIT relief valve refurbishment on July 16 o WO 60098632, 13 chiller refrigerant leak and compressor replacement on September 27

.

WO 30212156, 128 CCW heat exchanger open and inspect on September 28 b. Findinqs lntroduction. The inspectors identified a NCV of Salem Technical Specification (TS)6.8.4.j, "ln Service Testing," that implements the in service testing program for ASME Code Class 1,2, and 3 components in accordance with the American Society of Mechanical Engineers (ASME) Operations and Maintenance (OM) code. Specifically, PSEG did not complete an adequate ASME OM code required evaluation following the test of the Unit 2BlT relief, 2SJ10, which lifted outside of its acceptance criteria. This finding was determined to be of very low safety significance (Green).

Description.

The 2SJ10 is a code class 2 relief valve that provides overpressure protection to the BlT. On April 22, 2011 , during the Unit 2 refuel outage, the 2SJ10 was tested in accordance with the ASME OM code. The setpoint for this direct acting valve is 2735 psig, with a tolerance of +i-3 percent. An as found test was conducted and the relief valve did not lift at a test pressure of 2975 psig, or 108 percent of rated pressure.

Technicians did not raise pressure any higher because of test equipment limitations.

PSEG documented the unsatisfactory test result in notification 20506870, adjusted the valve setpoint and then confirmed the valve met its test requirements when it successfully lifted at rated pressure and passed a leak rate test at 90 percent of rated pressure. PSEG then reinstalled the relief valve into the system before plant restart on May 8.

On July 14, while performing a monthly emergency core cooling system (ECCS) fill and vent surveillance test on Unit 2, the 2SJ10 relief valve lifted and a through-wall crack was identified on a capped portion of a vent line within the BIT boundary. Plant operators subsequently declared a UE when reactor coolant system leakage was greater than 10 gpm and shutdown the plant to complete repairs. PSEG determined that most of the leakage, approximately 14 gpm, was actually through the 2SJ 1 0 valve, and only a small portion, less than 1 gpm, was through the cracked weld. This leakage from the ECCS piping degraded the ability of the high head injection pumps to inject water into the reactor coolant system.

OnJulyl6,the2SJl0wasremoved,tested,andfoundtobeleakingat44Qpsig.

PSEG disassembled and inspected the valve, identifying damage to the seating surfaces as the probable cause for the leakage. Corrective actions at that time included replacing the damaged seat and disk, rebuilding the valve, and performing a post maintenance test of the rebuilt valve.

PSEG performed an apparent cause evaluation for the 2SJ10 valve leakage and determined that insufficient margin existed between the relief valve setpoint and the system operating pressure. The inspectors also independently reviewed the circumstances that led up to the UE, including the 2SJ10 test failure on April 22,2010, and identified that PSEG procedure ER-SA-321-1010, "Testing of ASME Code 1 ,2, and 3 Safety/Relief Valves," required that an evaluation to determine the ability of the zSJ10 valve to perform its intended function until the next testing interval be completed after unsatisfactory test results. The inspectors identified that even though the valve was reinstalled into the system before the startup on May 8, PSEG did not complete the technical evaluation required to comply with this requirement until June 13. The evaluation stated that the 2SJ10 was refurbished, retested, and reinstalled into the system following the satisfactory retest. However, based on a review of the documentation for the testing and maintenance for 2SJ10, the inspectors determined that the actual scope of work performed on the valve was limited to an as-found lift test, subsequent pressure setpoint adjustment, and an as-left lift test and leak rate check.

PSEG's documented bases for restoring the 2SJ10 valve to service in the June 13 evaluation that was performed subsequent to the testing failure in April was that the valve was refurbished and retested satisfactory. The inspectors determined that this evaluation did not meet the requirements of PSEG procedure ER-SA-321-1010 because it contained incorrect information regarding valve refurbishment, and PSEG did not determine the cause of the 2SJ10 valve failure to lift within the acceptance criteria before it was returned to service in the safety injection system. The inspectors concluded that not correcting the cause of the 2SJ10 test failure on April 22, 2011 , and simply adjusting the valve lift setpoint, was the probable cause of the July 14 UE.

Analvsis. The inspectors determined that PSEG's failure to adequately evaluate the 2SJ10's ability to perform its intended function untilthe next maintenance intervalwas a performance deficiency. Specifically, the technical evaluation for the 2SJ10 stated that the valve had been refurbished after failing to lift during an as found test, but the valve had only been adjusted and tested prior to being reinstalled in the system. The evaluation did not determine the cause of the failure, and did not evaluate operability until the next surveillance test. The finding is more than minor because it is associated with the equipment performance attribute of the mitigating systems cornerstone, and it impacted the cornerstone objective of ensuring the availability, reliability, and capability of systems to respond to initiating events to prevent undesirable consequences.

Specifically, leakage of greater than 1 0 gpm through the 2SJ 10 valve degraded the ability of the charging system to deliver design flow rates to the reactor following a safety injection signal that would un-isolate the BlT.

The inspectors evaluated this finding using IMC 0609, Attachment 4, "Phase 1 - Initial Screening and Characterization of Findings," worksheet. This finding was determined to be of very low safety significance because it was not a design or qualification deficiency, did not represent an actual loss of system safety function, and was not potentially risk significant for external events. This finding had a cross-cutting aspect in the area of problem identification and resolution, corrective action program, because PSEG did not thoroughly evaluate problems such that the resolutions address causes and extent of conditions, as necessary. Specifically, PSEG's evaluation following the 2SJ10 failure in April 2011 did not meet the requirements of FSEG procedure ER-SA-321-1010. The evaluation contained incorrect information regarding valve refurbishment that prevented PSEG from identifying the cause of the 2SJ10 failure. (P.1(c))

Enforcement.

TS 6.8.4.j provides controls for the in service testing of ASME code class 1, 2, and 3 components. PSEG's IST program implements 10 CFR 50.55(aXfX4) for in service testing requirements set forth in the ASME OM code. Section l 7460 of the OM code covers class 2 and 3 pressure relief valves. Paragraph

(d) of this section states, in part, that valves that do not comply with their respective acceptance criteria shall be evaluated to determine the ability of the valve to perform its intended function until the next testing interval or maintenance opportunity. Contrary to the above, between April 22 and July 14, PSEG did not perform an adequate evaluation to determine the ability of the 2SJ10 valve to perform its intended function until the next testing interval after it did not lift within its acceptance criteria. Specifically, the evaluation completed stated that the valve had been refurbished and adjusted, but the valve had not been refurbished foflowing its failure to lift within the designated pressure band when tested on April22.

Because this issue is of very low safety significance (Green) and PSEG entered this issue into their CAP as notifications 20523948 and 20518249, this violation is being treated as an NCV consistent with the NRC Enforcement Policy. (NCV 0500031112011004-01, Inadequate IST Program Evaluation of a Pressure Relief Valve)

1R20 Refuelinq and Other Activities

a. Inspection Scope

Plant Trip Followinq Loss of 23 RCP. On June 26,2011, Unit 2 tripped following the loss of 23 RCP related to a failure of the RCP motor lead cables. PSEG conducted a forced outage from June 26,2011, through July 1 ,2011, to repair the 23 RCP and perform additional maintenance activities. During the outage, the inspectors monitored or observed the activities listed below to verify PSEG controls over the outage activities.

The documents reviewed are listed in the Attachment.

.

Portions of the shutdown process o Outage risk management

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Decay heat removal operations

.

Configuration management, including maintenance of defense in depth r Status and configuration of electrical systems and switchyard activities to ensure that TSs were met r Personnelfatiguemanagementcontrols b. Findinqs lntroduction. A self-revealing finding of very low safety significance (Green) was identified because Salem Unit 2 tripped on June 26,2011. The unit tripped following a trip of the 23 RCP due to a ground fault inside the 23 RCP motor junction box. PSEG determined that the cause of the ground fault was RCP motor cable jacket cracking that was first identified in 2005. PSEG entered this event into the CAP as notification 20515977.

Description.

On June 26,2011 an automatio reactor trip was initiated due to a trip of 23 RCP above 36 percent power (P-8 setpoint). The RCP trip was a result of phase to ground fault inside the RCP motor junction box. PSEG entered this event into the CAP as notification 2051 5977. During an inspection of the 23 RCP motor lead cables in the April 2011 Unit 2 RFO, the cable jacket was found with extensive cracking, but the insulation that was visible under the cracked cable jacket was evaluated as being intact.

The cracking was evaluated to be caused by heat and radiation exposure. The cable jacket was repaired by installing heat shrink tubing over the existing outer jacket up to the point where the jacket was removed for installation of the original termination kit, slightly overlapping the outer covering of the termination kit. Meggering of the 23 RCP motor leads to verify the integrity of the underlying cable insulation was satisfactory.

During the 2R13 RFO in April 2005, the 23 RCP motor lead cable jackets were found to be badly cracked. Two notifications were written in January 2OOO (20267215 and 20267218) to request engineering to present the options for repair or replacement of the RCP cables with a required due date of May 31, 2006. The recommended action in the notifications was to either replace the cables when the motors were replaced during the 10 year RCP motor replacement interval, or possibly repair the leads. A boroscopic inspection of the cables down inside the flexible conduits was performed in 2R14 RFO (October 2006) in order to determine a course of action. A notification (20301 125) was written for engineering to evaluate the test results and requested a technical evaluation to determine any immediate and long{erm corrective action for the motor lead cable jacket cracking.

This technical evaluation, which was completed in February 2007, evaluated the motor leads as acceptable and also recommended long-term corrective actions be developed to repair or replace the motor lead cables, noting the notifications written in January 2006 (20267215 and 20267218) had action to accomplish this. Although the technical evaluation completed in 20Q7 noted that engineering recommendations for long-term corrective action had not yet been accomplished, no notification was written to document that this action had not been performed.

The incomplete long-term corrective active included evaluating whether the RCP cables needed to be replaced during the next RCP motor replacement, which for the 23 RCP motor, was scheduled to occur in the 2R16 RFO in June 2008. The 23 RCP motor was replaced in the 2R16 RFO in June 2008 with no action taken on the cables including not completing the corrective action to evaluate cable replacement as part of the motor replacement. No other action was taken prior to the failure occurring in June 2011.

PSEG performed a root cause evaluation (RCE) for the June 2011 reactor trip and determined that the root cause for the 23 RCP cable failure was that PMT for medium voltage cables terminating at motors and subject to adverse heat environments does not employ testing methodologies that would identify degrading cable insulation below the termination kit prior to failure. PSEG's RCE also discussed that the engineering department did not address previous recommendations from notifications 202267215 and 20267218 to address cable jacket cracking prior to the June 2011 23 RCP cable failure.

Analvsis. The inspectors determined that the failure of PSEG to complete the corrective actions for the 23 RCP motor cables in accordance with LS-AA-125, "Corrective Action Program," was a performance deficiency. Specifically, PSEG did not ensure that CAP assignments and documentation were completed timely and effectively in accordance with their CAP procedure. The inspectors noted that the RCE performed by PSEG has determined that the PMT performed for medium voltage cables would not have detected the insulation fault in the 23 RCP cable, but have determined that PSEG missed an opportunity to determine a corrective action plan when they did not evaluate options for future replacement or repair as discussed in notifications 202267215 and202267218 written in January 2006 and restated in an engineering technical evaluation completed in February 2007. The inspectors determined that the performance deficiency was more than minor because it was associated with the equipment performance attribute of the Initiating Events cornerstone, and it adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during power operations. Specifically, action from notifications in January 2006 for the engineering department to determine options to address RCP motor lead jacket cracking including an evaluation on whether to replace the cables during the June 2008 RFO was not completed prior to the June 2008 motor replacement and continued to be an open action up to the point of the June 201 1 RCP cable failure and reactor trip.

The finding was evaluated under IMC 0609, Attachment 4, "Phase 1 - lnitial Screening and Characterization of Findings." The inspectors determined that the finding is of very low safety significance (Green) because it does not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions will not be available.

The inspectors determined that this finding has a cross-cutting aspect in the area of problem identification and resolution, because PSEG did not take appropriate corrective action to address safety issues and adverse trends in a timely manner, commensurate with their safety significance and complexity. Specifically, PSEG did not ensure that the CAP assignment for the engineering department to evaluate long-term corrective action options for the RCP motor lead cables were completed timely and effectively in accordance with their CAP procedure. (P.1(d))

Enforcement.

This finding does not involve enforcement action because no regulatory req uirement violation was identified. (FlN 0500031 1 l2O1 1004-02, Failure to Evaluate Corrective Action Options for RCP Motor Gables)

1R22 Surveillance Testinq

a. Inspection Scope

The inspectors completed seven surveillance testing inspection samples. The inspectors observed portions of and/or reviewed results for the surveillance tests listed below to verify, as appropriate, whether the applicable system requirements for operability were adequately incorporated into the procedures and that test acceptance criteria were consistent with procedure requirements, the TS requirements, the Updated Final Safety Analysis Report, and ASME Section Xl for pump and valve testing. The documents reviewed are listed in the Attachment.

.

S2.OP-ST.PZR-0002, Pilot Operated Relief Valve (PORV) block valves o 51.OP-ST.DG-0001, 1A EDG surveiltance test o S2.OP-ST.DG-0001, 2,A EDG surveillance test

.

51.OP-ST.RHR-0002, 12 RHR pump in-service test

.

S1.OP-ST.CC-0001, 1 1 Component Cooling pump in-service test o 51.OP-ST.DG-0012, 1A EDG endurance run

.

S1.OP-ST.RC-0008, Reactor Coolant System Water Inventory Balance b.

Findinos No findings were identified.

1EP6 Drill Evaluation

a. Inspection Scope

The inspectors completed one drill evaluation inspection sample. On September 15, 2011, the inspectors observed emergency plan response actions at the simulated control room during an evaluated licensed operator requalification training scenario. The inspectors evaluated operator performance related to developing event classifications and notifications. The inspectors reviewed the Salem Event Classification Guides. The inspectors referenced Nuclear Energy lnstitute (NEl) 99-02, "Regulatory Assessment Performance lndicator (Pl) Guideline," Revision 6, and verified that PSEG correctly counted the evaluated scenario's contribution to the NRC Pl for drill and exercise performance.

b. Findinqs No findings were identified.

2RS7 Radioloqical Environmental Monitorinq Proqram (REMP)

a. lnspection Scope The inspectors reviewed the Annual Radiological Environmental Operating Report, and the results of any PSEG assessments since the last inspection, to verify that the REMP was implemented as required by TSs and the Offsite Dose Calculation Manual (ODCM).

The inspectors reviewed the report for changes to the ODCM with respect to environmental monitoring, commitments in terms of sampling locations, monitoring and measurement frequencies, land use census, inter-laboratory comparison program, and analysis of data. The inspectors reviewed the ODCM to identify locations of environmental monitoring stations and reviewed the Final Safety Analysis Report (FSAR) for information regarding the environmental monitoring program and meteorological monitoring instrumentation.

The inspectors reviewed the Annual Effluent Release Report and the 10 CFR Part 61, "Licensing Requirements for Land Disposal of Radioactive Waste," report to determine if PSEG was sampling, as appropriate, for the predominant and dose-causing radionuclides likely to be released in effluents.

The inspectors walked down air sampling stations and thermoluminescent dosimeter (TLD) monitoring stations to determine whether they were located as described in the ODCM and to determine the equipment material condition. The inspectors reviewed the calibration and maintenance records of the air samplers and TLDs to verify that they demonstrate adequate operability of these components. Additionally, the inspectors reviewed the calibration and maintenance records of composite water samplers as available. The inspectors verified that PSEG had initiated sampling of other appropriate media upon loss of a required sampling station.

The inspectors observed the collection and preparation of environmental samples from different environmental media (e.g., ground and surface water, milk, vegetation, sediment, and soil) as available. The inspectors verified that environmental sampling was representative of the release pathways as specified in the ODCM and that sampling techniques were in accordance with procedures.

Based on direct observation and review of records, the inspectors verified that the meteorological instruments are operable, calibrated, and maintained in accordance with guidance contained in the FSAR, NRC Regulatory Guide 1.23, "Meteorological Monitoring Programs for Nuclear Power Plants," and PSEG procedures. The inspectors verified that the meteorological data readout and recording instruments in the control room and at the tower were operable.

The inspectors verified that missed and/or anomalous environmental samples were identified and reported in the Annual Environmental Monitoring Report. The inspectors reviewed PSEGts assessment of any positive sample results. The inspectors reviewed the associated radioactive effluent release data that was the source of the released material.

The inspectors selected SSCs that involved or could reasonably involve licensed material for which there is a credible mechanism for licensed material to reach ground water, and verified that PSEG had implemented a sampling and monitoring program sufficient to detect leakage of these SSCs to ground water. The inspectors verified that records, as required by 10 CFR 50.75(9), of leaks, spills, and remediation since the previous inspection were retained in a retrievable manner.

The inspectors reviewed any significant changes made by PSEG to the ODCM as the result of changes to the land census, long-term meteorological conditions (3-year average), or modifications to the sampler stations since the last inspection. The inspectors reviewed technicaljustifications for any changed sampling locations. The inspectors verified that PSEG performed the reviews required to ensure that the changes did not affect its ability to monitor the impacts of radioactive effluent releases on the environment.

The inspectors verified that the appropriate detection sensitivities with respect to TS/ODCM were used for counting samples, The inspectors reviewed quality control charts for maintaining radiation measurement instrument status and actions taken for degrading detector performance, The inspectors reviewed the results of PSEG's inter-laboratory comparison program to verify the adequacy of environmental sample analyses performed by PSEG. The inspectors verified that the inter-laboratory comparison test included the media/nuclide mix appropriate for the facility.

The inspectors verified that problems associated with the REMP are being identified by PSEG at an appropriate threshold and were properly addressed for resolution in their CAP. The inspectors verified the appropriateness of the corrective actions for a selected sample of problems documented by PSEG that involved the REMP.

b. Findinqs No findings were identified.

4OA1 Performance Indicator (Pl) Verification

a. lnspection Scope The inspectors reviewed PSEG submittals for the Unit 1 and Unit 2 mitigating systems cornerstone Pls listed below for the period of July 1,2010 through June 30, 2011. To verify the accuracy of the Pl data reported during this period, the data was compared to the Pl definition and guidance contained in NEI 99-02, "Regulatory Assessment Performance lndicator Guideline," Revision 6.

Cornerstone: Mitiqatinq Svstems

.

Unit 1 and Unit 2 Auxiliary Feedwater (AFW) Systems o Unit 1 and Unit 2 RHR Systems

.

Unit 1 and Unit 2 SW Systems The inspectors verified the accuracy of the data by comparing it to CAP records, control room operators' logs, the site operating history database, and key Pl summary records.

b.

Findinqs No findings were identified.

4OA2 ldentification and Resolution of Problems

.1 Review of ltems Entered into the Corrective Action Proqram

As required by Inspection Procedure71152; "ldentification and Resolution of Problems,"

and in order to help identify repetitive equipment failures or specific human performance issues for follow-up, the inspectors performed a daily screening of all items entered into PSEG's CAP. This was accomplished by reviewing the description of each new notification and attending daily management review committee meetings.

4043 Event Follow-up (71153 - 2 samples)

.1 (Closed) Licensee Event Report (LER) 0500031 1/2011-004-0, Automatic Reactor Trip

Due to Trip of the 23 Reactor Coolant Pump On'June 26,2011, the 23 RCP tripped resulting in an automatic reactor trip on low flow in one reactor coolant loop above the P-8 permissive (36 percent power permissive). As expected, the 21 ,22, and 23 AFW pumps started on low steam generator level following the unit trip. Unit 2 was stabilized in Mode 3 at normal operating temperature and pressure with the 21,22, and 24 RCPs in service.

The low flow condition was the result of the trip of the 23 RCP due to a short in the motor lead junction box. The damaged sections of the RCP motor leads were removed and new terminations were made. The 23 RCP motor re-tested satisfactorily. Megger testing and visual examination of the 21,22, and 24 RCP motor leads was also performed. The inspectors completed a review of this LER, a self-revealing finding that did not involve a violation of regulatory requirements, is documented in Section 1R20.

This LER is closed,

.2 (Closed) LER 05000311/2011-005-0, Completion of a Plant Shutdown in Accordance

With Technical Specification 3.0.3

a. Inspection Scope

At 8:38 PM on July 14, 2011, during the performance of the Salem Unit 2 ECCS filland vent monthly surveillance test, a leakage path was identified from the BIT relief valve 2SJ10 piping. The leakage was identified as

(1) leakage to the environment through a circumferential crack in a socket weld at a tee next to BIT relief valve and

(2) leakage through the 2SJ10 relief valve seat. The leak was isolated by closing the BIT isolation valves. The BIT is part of the flow path of the high head safety injection system.

Without the high head safety injection flow path operable, TS 3.0.3 was entered.

lnitial follow-up inspection was conducted during July 1 I - 20,2011, with a scope that included field observations of existing and replaced piping in the Unit 2 boron injection tank room and the similar areas in Unit 1, a review of the condition documentation, and discussion with those inspecting, evaluating, and resolving the condition.

ftems reviewed included the technical evaluation, document70126040, the extent of condition determination, the replacement work package, including post replacement pressure testing, the notification for the leak, leak related documentation, and the initial leak before break considerations.

The inspectors determined what applicable evaluation and metallurgical laboratory work was planned following the initial pressure boundary repair. The inspectors explored operating experience and industry references on socket weld leaks to establish whether the chosen scope for the extent of condition evaluation was consistent with the socket weld failure mode.

An additional inspection to review and evaluate extended work and analysis by PSEG was conducted during September 7 - 8,2011. The inspectors confirmed that an appropriate adverse condition monitoring plan was implemented for Unit 1 and Unit 2 to verify that no new leaks or cracks initiated untilthe casual analysis and appropriate long term corrective actions were completed. The inspectors reviewed the AREVA metallurgical lab report for the Unit 2 socket weld leak and the calculated strength for the remaining socket weld ligament for input to leak before break applicability and to confirm that the extent of condition evaluation was consistent with the failure analysis. The inspectors also reviewed the Spring 2011 outage testing and setpoint adjustment process for the 2SJ10 relief valve along with effectiveness in meeting the OM code, paragraph l-7460

(d) which calls for an evaluation to determine the ability of a valve to perform its function until its next test.

The affected piping has been replaced with a new straight run of pipe to minimize welded fittings exposed to the stagnant aerated borated water conditions, the relief valve was removed from service, and the valve internals were replaced. The relief valve was tested satisfactory and placed back in service. The inspectors completed a review of this LER and identified two violations of regulatory requirements, one of which is documented below and the other in Section 1R19, This LER is closed.

Findinqs lntroduction. The inspectors identified a NCV of 10 CFR 50.47, "Emergency Plans."

Specifically, state officials were not notified within 15 minutes of the declaration of an UE, a risk significant planning standard. This finding was determined to be of very low safety significance (Green).

Description.

On July 14,2011, at 8:36 PM, during the performance of a routine surveillance test, the BIT inlet valve was opened, pressurizing the BlT. Opening the BIT inlet valve normally diverts a very small amount of flow from the charging header makeup flow to the reactor. Unexpectedly, the pressurizer level was observed to be lowering in response to lower charging rate flow. At 8:38 PM, a plant operator reported a loud noise from the BIT room, in the vicinity of the 2SJ10, the BIT thermal relief valve, and at 8:41 PM, the control room operator closed the BIT inlet valve from the control room, isolating the leak in the ECCS. At 8:53 PM, a UE was declared on Unit 2 because reactor coolant system leakage was greater than 10 gpm. The emergency declaration was performed satisfactorily within the 15 minute assessment time; however, notifications to the states of Delaware and New Jersey did not meet the 15 minute state notification requirement. Notifications to the state agencies were completed at 9:14 PM, 21 minutes after the UE declaration.

PSEG completed an apparent cause evaluation for the late notifications and determined that a discussion between the shift manager and shift technical assistant (STA), which occurred after the event declaration, caused the late state notifications. Twelve minutes before the UE declaration, operators closed the BIT isolation valve, which isolated the leak and stopped the event. This fact is important because it led to a discussion between the STA and shift manager regarding the reporting requirements for an event that has terminated before notifications could be completed. The discussion, after the event declaration was made at 8:53 PM, delayed the Shift Manager's order to the control room communicators to report the event until 9:12 PM. This in turn delayed the primary and secondary communicators' completion of the state notifications until 9:14 PM,21 minutes after the UE declaration.

The inspectors determined that, as described above, the cause for the delay in state notifications was not related to PSEG personnel performing safety-related activities to protect the public health and safety; and therefore, the late notifications constituted a performance deficiency. The topic of the discussion was appropriate for a training critique, but acted as a distraction during an actual event. PSEG's corrective actions for this performance deficiency was to complete licensed operator training regarding classification and notification requirements for short duration emergency events terminated before classifications and notifications can be completed.

Analvsis. The inspectors determined that a performance deficiency was identified associated with timely notification to state and local government agencies during an actual event. PSEG did not notify Delaware and New Jersey state government agencies within the specified 15 minutes after declaring a UE. The finding was greater than minor because it is associated with the Emergency Planning cornerstone attribute of Emergency Response Organization performance during actual event response. The finding affected the cornerstone objective of ensuring that the licensee is capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. The inspectors reviewed this finding using IMC 0609, Appendix B, "Emergency Preparedness Significance Determination Process," Sheet 2, "Actual Event lmplementation Problem." This finding was determined to be of low safety significance (Green) because it was a failure to implement a risk significant planning standard during an actual event associated with the declaration of a UE. This finding had a cross-cutting aspect in the area of hunran performance, work practices, because PSEG personnel did not ensure supervisory and management oversight of work activities, such that nuclear safety is supported. Specifically, the Shift Manager was distracted from his supervisory oversight role and did not direct the communicators to perform state notifications within the required 15 minute time period. (H.4(c))

Enforcement.

In accordance with 10 CFR 50.54(q), a licensee authorized to possess and operate a nuclear power reactor shall follow and maintain in effect emergency plans which meet the standards in 10 CFR 50.47(b). 10 CFR 50.47(bX5) states that procedures shall be established for notification of state and local response organizations. ln addition, 10 CFR 50, Appendix E, lV.D.3, states that a licensee shall notify the state and local government agencies within 15 minutes after declaring an event. Contrary to the above, on July 14,2011, PSEG did not notify the state and local government agencies within 15 minutes after declaring an event. Specifically, PSEG declared a UE at 8:53 PM, and completed the notification to the state and local government agencies at9:14 PM, or 21 minutes after the declaration of the UE. Timely offsite notifications enable state and local agencies to make decisions for taking initial offsite response measures that could affect the general public. Because this issue is of very low safety significance (Green) and PSEG has entered this issue into their CAP as notification 20518004, this finding is being treated as an NCV consistent with the NRC Enforcement Policy. (NCV 0500031112011004-03, Late State Notification of UE)4045 Other Activities

.1 Operation of an Independent Spent Fuel Stgrase Installation (lSFSl) at Operatinq Plants

(60855.1)a. lnspection Scope The inspectors verified by direct observation and independent evaluation that PSEG had performed loading activities at the ISFSI in a safe manner and in compliance with applicable procedu res.

b. Findinqs No findings were identified.

Closed TBD AV 05000272/201 1009-01, Untimely Completion of Corrective Actions Results in No. 11 Service Water Strainer Trip Due To Grassing lnspection Scope A Region I senior reactor analyst completed the Phase 3 SDP analysis for AV 050002722011009-01, "Untimely Completion of Corrective Actions Results in No. 11 Service Water Strainer Trip Due To Grassing," in accordance with !MC 0609, Appendix A, "Determining the Significance of Reactor Inspection Findings for At-Power Situations."

The significance of this finding was documehted as "to be determined' (TBD) in NRC lR 05000272,31112011009. The Phase 3 analysis was not completed at the time of that inspection report's issuance because further: work was required to verify the proper assumptions for the increase in the loss of service water event frequency and the increase in the common cause failure probability associated with the performance deficiency. Based on the results of the Phase 3 analysis, the TBD for AV 0500027213112011009-01 is now closed. The finding description and final risk significance determination for this NCV are documented below' b. Findinqs tntroduction. The inspectors identified a self-revealing Green 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 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 Aprril 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.

Each automatic self-cleaning 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 must be minimized by maintaining the clearance between the drum and body small. ln 2000, due to difficulties in maintaining the clearance and repetitive heat exchanger fouling 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.

PSEG controls the clearance or 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 clearances during performance of this preventative maintenance were completed based upon the system engineer's review of the gap measurements. ln addition, to further control the gap, due to the harsh river water conditions at Salem, PSEG performed the industry standard six year service water strainer internal inspections every three years.

During strainer internal inspections in the early 2000s, PSEG identified excessive wear grooves developing on the strainer body wear surfaces from the o-ring installed by modification. These grooves caused grass and debris to accumulate in the gap between the strainer drum and body and the accumulation of grass in this area was not cleared during strainer backwash cycles. As a result, it caused increased friction between the drum and body, which increased the amount of current needed to rotate the strainer drum and eventually caused the thermal overload to trip due to the higher current' ln response to the excessive grooving identified in the early 2000s, PSEG issued a design change to modify the strainer bodies to include a monelwear ring. The intent of the design change was that the new wear ring material would increase the hardness of the weai surface increasing the wear surface durability and the strainer's resistance to grass accumulation. On February 9,2011, the 11 service water strainer thermal 6verloads tripped making the associated service water pump inoperable. PSEG determined the strainer tripped due to binding caused by river grass that wedged between the strainer drum and body. The river grass build-up was caused by excessive grooves on the strainer body wear surface that were not addressed by installing the ironel wear ring design change. PSEG also identified that the 11 service water strainer had previously iripped on April 4,2A10, and that at that time the cause was also deteimined to be untimely replacement of the 1 1 service water strainer body wear ring.

Because the monelwear ring was not installed and no interim corrective action taken to address excessive grooving ldentified in the 11 strainer body wear surface in April 2010, this increased the susceptibility of the 11 strainer to grass clogging. This resulted in the February g,2011, 1 1 strainer irip and resulted in 53 hours6.134259e-4 days <br />0.0147 hours <br />8.763227e-5 weeks <br />2.01665e-5 months <br /> of unavailability for the 11 SW pump. ihe inspectors determined that the excessive groove on the 11 strainer body weai surface was, therefore, a condition adverse to quality that PSEG identified, but did not correct in a timely manner after the strainer tripped in April 2010.

As documented in order 70109406, PSEG's corrective action for the April 2010 11 service water strainer trip was to develop and schedule the replacement plan for the six strainers (11, 14, 16, 23,24, and 26) that it identified did not have the monel wear ring installed. This corrective action was documented as completed when scheduling for the work orders for the body replacement for all six strainers was completed in July 2010' The 11 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 inappropriate 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'"

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-fillthe 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. PSEG also identified that four other strainers (14, 16, 23, and 26) still did not have the monel wear ring design change installed. Before the 2012 spring grassing season, PSEG will either install the monelwear 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 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, 1 1 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 11 service water pump.

The finding was determined to be of very low safety significance in accordance with IMC 0609, Appendix A, "Determining the Significance of Reactor lnspection Findings for At-Power Situations" (lMC 0609A) using significance determination process (SDP) Phases 1, 2 and 3. 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 (LOSW) given one train being removed for strainer repairs and the loss of redundancy in the service water system (SW) 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 lnspection Notebook does not address the loss of one train of SW. An external event evaluation was also conducted, because the internal event increase in core damage frequency (ACDF) was in the E-7 range.

Salem Units 1 and 2 were selected for the pilot implementation of the NRC's SAPHIRE 8 risk analysis SDP interface tool using the Salem specific standardized plant analysis review (SPAR) model for the conduct of Phase 2 SDP evaluations. This tool allows the inspector to enter specific equipment and human action failures and specify the exposure period and uses the plant specific SPAR modelto calculate the increase in core damage frequency (ACDF). During the pilot period the SDP process currently document in IMC 0609 including use of the Salem Pre-solved Risk-lnformed lnspection Notebook and any additional SRA conducted Phase 3 evaluations represent the official result. For this type of situation the pilot guidance directs the SRA to conduct a Phase 3 analysis.

The SRA conducted Phase 3 evaluation, using the Salem combined internal and external initiating event SPAR model revision 8.16, estimated an internaland external initiating event ACDF in the High-E-7 per year range, given the #11 SW strainer out of service for the 53 hours6.134259e-4 days <br />0.0147 hours <br />8.763227e-5 weeks <br />2.01665e-5 months <br /> exposure period and the following changes and assumptions:

.

The common cause failure (CCF) factors for the SW strainers were updated to the 2009 NRC data set and the basic event for CCF of all strainers was taken to six of six, which reflected the failure criteria of the SW system.

.

Based on initial cutset review a rule for station blackout sequences was changed to not allow credit for offsite power and emergency diesel generator recovery, given a CCF of all SW trains.

o An increase in the initiating event frequency of a loss of SW (LOSW) by a factor of 14, based on the increase in the chance that the service water system would not be able to mitigate an event, given one service water train out of service and on the solution of the SW system fault tree, which was confirmed by PSE&G using their initiating event fault tree method.

The result was dominated by the increased frequency of the LOSW events; the most significant sequence included a loss of reactor coolant pump (RCP) seal cooling leading to sealfailure and leakage. RCP seal injection is lost due to charging pump damage from the failure to isolate reactor coolant system letdown and switch charging pump suction to the refueling water storage tank and RCP seal cooling is lost due to failure to recover SW leading to loss of component cooling water. Core damage subsequently would occur because of an inability to achieve decay heat removal with high pressure recirculation.

The remaining internal and external event results related to the reduced mitigation capability of the SW system were driven by the increased chance of common cause failure of all the remaining strainers, given the #11 strainer failure. Transients and loss of offsite power event contributions were lower, by over an order of magnitude and fire events which would result in transients and loss of offsite power with additional loss of SW redundancy were over two orders of magnitude lower, than the LOSW event contribution.

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 11 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. (NCV 0500027212011009-01, Untimely Completion of Corrective Actions Results in No. 11 Service Water Strainer Trip Due To Grassing)4OAO Meetinos. Including Exit The inspectors presented the inspection results to Mr. L. Wagner and other members of PSEG management at the conclusion of the inspection on October 6, 2011. The inspectors asked PSEG whether any materials examined during the inspection were proprietary. No proprietary information was identified.

The inspectors presented the results of the Phase 3 SDP evaluation for AV 05000272112011009-01 to Mr. H. Berrick and other members of PSEG management via telephone call on October 20, 2011. The inspectors asked whether any materials examined during the inspection were proprietary. No proprietary information was identified.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

C. Fricker, Site Vice President

L. Wagner, Plant Manager

R. DeSanctis, Maintenance Director

L. Rajkowski, Engineering Director

J. Garecht, Operations Director

J. Kandasamy, Regulatory Assurance Manager

H. Berrick, Regulatory Assurance

E. Villar, Regulatory Assurance

T. Giles, lSl Program Manager

J. Shelton, Environmental Affairs, Nuclear

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Open/Closed 0500031 1 12011004-01 NCV lnadequate IST Program Evaluation of a Pressure Relief Valve (Section 1R19)

0500031 1t2011004-02 FIN Failure to Evaluate Corrective Action Options for RCP Motor Cables (Section R20)

0500031 1t2011004-03 NCV Late State Notification of UE (Section 4OA3.2)

05000272t201 1009-01 NCV Untimely Completion of Corrective Actions Results in No. 11 Service Water Strainer Trip Due To Grassing (Section 4OA5.2)

Closed

0500031 1t2011-004-0 LER Automatic Reactor Trip Due to Trip of the 23 Reactor Coolant Pump (Section 4OA3.1)

0500031 1/201 1-005-0 LER Completion of a Plant Shutdown in Accordance with Technical Specification 3.0.3 (Section 4OA3.2)

050a0272t201 1009-01 AV Untimely Completion of Corrective Actions Results in No. 11 Service Water Strainer Trip Due To Grassing (Section 4045.2)