IR 05000272/2011007

Lr 05000272-11-007 and 05000311-11-007: 01/24/2011 - 02/18/2011; Salem Unit Nos. 1 and 2; Component Design Bases Inspection

ML110940193
Person / Time
Site:	Salem
Issue date:	04/04/2011
From:	Doerflein L Engineering Region 1 Branch 2
To:	Joyce T Public Service Enterprise Group
References
IR-11-007
Download: ML110940193 (42)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION

REGION I

475 ALLENDALE ROAD KlNG OF PRUSSlA. PA 19406-1415 April 4, 20lI Mr. Thomas Joyce President and Chief Nuclear Otficer PSEG Nuclear LLC - N09 P.O. Box 236 Hancock's Bridge, NJ 08038 SUBJECT: SALEM NUCLEAR GENERATING STATION, UNIT NOS. 1 AND 2 .

NRC COMPONENT DESIGN BASES INSPECTION REPORT 0500027 2t20 1 1 007 AN D 0s00 03 1 I l 20 1 1 007

Dear Mr. Joyce:

On February 18, 2011, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at the Salem Nuclear Generating Station, Unit Nos. 1 and 2. The enclosed inspection report documents the inspection results, which were discussed on February 18, 2011, with Mr. Edward Eilola, Plant Manager, 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.

In conducting the inspection, the team examined the adequacy of selected components and operator actions to mitigate postulated transients, initiating events, and design basis accidents.

The inspection involved field walkdowns, examination of selected procedurei, calculations and records, and interviews with station personnel.

This report documents three NRC-identified findings that were of very low safety significance (Green). These findings were determined to involve violations of NRC requirementi. However, because of the very low safety significance of the violations and because they were entered into your corrective action program, the NRC is treating these findings as non-cited violations (NCV)

consistent with Section 2.3.2 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, D.C. 20555-0001, with copies to the Regional Administrator, Region l; the Director, Otfice of Enforcement, U.S. Nuclear Regulatory Commission, Washington, D.C. 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 oJ tne date of lhis inspeciion report, with the basis of your disagreement, to the Regional Administrator, Region l, and ihe NRC Resident Inspector at Salem Nuclear Generating Station. ln 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 the public inspection in the NRC Public Docket Room or from the Publicly Available Records component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.qov/readinq-rm/adams.html (the Public Electronic Reading Room).

Sincerely, v

O/o,-**--

Lawrence T. Doerflein, Chief Engineering Branch 2 Division of Reactor Safety Docket Nos: 50-272;50-311 License Nos: DPR-70; DPR-75 Enclosure: Inspection Report 0500027212011007 and 0500031112011007 w/Attachment: Supplemental Information cc Mencl: Distribution via ListServ

SUMMARY OF FINDINGS

lR 0500027212011007 and 0500031 112011007:0112412011 - 0211812011; Salem Unit Nos' 1 and 2; Component Design Bases Inspection.

The report covers the Component Design Bases Inspection conducted by a team of four NRC inspectors and two NRC contractors. Three findings of very low risk significance (Green) were identified, all of which were considered to be non-cited violations. 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). Cross-cutting aspects associated with findings are determined using 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.

Gornerstone: Mitigating Systems

. Green: The team identified a finding of very low safety significance involving a non-cited violation of 10 CFR 50, Appendix B, Criterion lll, "Design Control," because PSEG had not verified the adequacy of the design for the DVR voltage setpoint. Specifically,

PSEG had not performed calculations for motor starting and running conditions, and for operation of other safety-related equipment based on voltages afforded by the degraded voltage relays. PSEG entered this issue into their corrective action program and performed preliminary calculations to demonstrate reasonable assurance of operability.

The finding is more than minor because it is associated with the design control attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The team evaluated the finding in accordance with IMC 0609, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, Table 4afor the Mitigating Systems Cornerstone. The team determined that the finding was of very low safety significance because it was a design deficiency confirmed not to result in loss of operability.

The team determined that this finding has a cross-cutting aspect in the area of Problem ldentification and Resolution, Operating Experience Component, because PSEG did not ensure that relevant internal and external operating experience was collected, evaluated, and communicated to affected internal stakeholders in a timely manner.

Specifically, PSEG did not adequately evaluate a similar finding documented in a Hope Creek Generating Station NRC component design bases inspection report in November 2009 (NCV 050035412009007-03) and missed an opportunity in their internal response to NRC Information Notice 2Q08-02, "Findings ldentified During Component Design Bases Inspections," issued in March 2008. (lMC 0310' Aspect P.2(a))

(Section 1R21.2.1.1)

.

Green.

The team identified a finding of very low safety significance (Green) involving a non-cited violation of Salem Unit 1 Technical Specification (TS) Surveillance Requirement (SR) 4.8.2.5.2.n Specifically, the team identified that PSEG did not perform a battery capacity test of the 1B 28VDC battery within 12 months of the previous performance test that showed signs of degradation (battery capacity as measured on October 28,2008, dropped more than 10 percent compared to the April 26, 2004, performance test). PSEG promptly entered TS 4.0.3 and completed all TS 4.0.3 requirements for a surveillance not performed within its specified frequency.

Additionally PSEG entered the issue into their corrective action program to evaluate the casual factors for long{erm corrective action and scheduled the 1B 28VDC battery performance test during the next scheduled Salem Unit 1 shutdown.

The finding is more than minor because it is associated with the human performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the availability of the 1B 28VDC battery was not ensured by performing additional surveillance testing to monitor for battery degradation. The team evaluated the finding in accordance with IMC 0609, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, Table 4afor the Mitigating Systems Cornerstone. The team determined that the finding was of very low safety significance because it was a qualification deficiency confirmed not to result in loss of operability.

The team determined that this finding has a cross-cutting aspect in the area of Human Performance, Work Practices Component, because PSEG personnel did not follow procedure requirements during the 1B 28VDC battery performance discharge surveillance test. Specifically, personnel did not follow step 5.12.21 of SC.MD-FT.28D-0003 which required technicians to mark the surveillance data sheet "Yes" for "Battery Degraded," notify supervision, and initiate a corrective action notification if the calculated battery performance capacity drop was greater than 10 percent. (lMC 0310, Aspect H.4(b)) (Section 1R21.2.1.2)

Cornerstone: Barrier lntegrity

o

Green.

The team identified a finding of very low safety significance (Green) involving a non-cited violation of 10 CFR 50, Appendix B, Criterion XVl, "Corrective Action," because PSEG did not identify and correct a condition adverse to quality. Specifically,

PSEG did not identify and correct the degraded condition of the Unit 1 and Unit 2 control room emergency air conditioning system (CREACS) common suction expansion joints because they did not implement appropriate preventive maintenance (PM) per their performance-centered maintenance (PCM) template. PSEG placed the finding and the associated issues in its corrective action program. In response to the identified control room envelope (CRE) breach, operators promptly entered TS 3.7.6 and initiated mitigation actions. PSEG affected prompt repairs, performed an appropriate post maintenance test, declared the CRE fully operable, and exited the TS limiting condition for operation action statement.

The finding is more than minor because it is associated with the barrier performance attribute of the Barrier Integrity Cornerstone and adversely affected the cornerstone objective of providing reasonable assurance that physical design barriers protect the control room operators from radionuclide releases caused by accidents or events. The finding was evaluated in accordance with IMC 0609, Attachment 4, Table 4a for the containment barrier. Since the finding had the potential to impact more than the radiological barrier function, a Region 1 Senior Reactor Analyst (SRA) performed a Phase 3 analysis. The SRA determined that the dominant sequence involved a sufficient degradation of the CREACS barrier that would allow sufficient in-leakage to force an evacuation of the control room during a fire or toxic gas event. The areas with the degradation were in room 15615 and 25615 for Units 1 and 2, respectively. The SRA evaluated these areas and determined that the potential impact due to in-leakage through the degraded barrier from fire and toxic gas would be negligible. The SRA also reviewed the results of recent CRE in-leakage testing conducted in September 2010.

The condition of the expansion joint tearing and wear could reasonably be assumed to have existed during the September testing. This testing also confirmed that the total in-leakage in these areas was small. Based on the above factors, the SRA determined the finding was of very low safety significance (Green).

The team determined that this finding has a cross-cutting aspect in the area of Human Performance, Work Control Component, because PSEG did not plan work activities to support long-term equipment reliability by ensuring that maintenance scheduling was more preventive than reactive. Specifically, PSEG did not implement appropriate PMs on the CREACS filter expansion joints necessitating several reactive corrective maintenance activities. (lMC 0310, Aspect H.3(b)) (Section 1R21 .2.1 .3)

Other Findinqs None IV

REPORT DETAILS

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R21 Component Desiqn Bases Inspection (lP 71111.21)

.1 Inspection Sample Selection Process

The team selected risk significant components and operator actions for review using information contained in the Salem Probabilistic Risk Assessment (PRA) and the U. S. Nuclear Regulatory Commission's (NRC) Standardized Plant Analysis Risk (SPAR) modelfor the Salem Generating Station. Additionally, the team referenced the Risk-lnformed Inspection Notebook for the Salem Generating Station (Revision 2.1a) in the selection of potential components and operator actions for review. In general, the selection process focused on components and operator actions that had a Risk Achievement Worth (RAW) factor greater than 1.3 or a Risk Reduction Worth (RRW)factor greater than 1.005. The components and actions selected were associated with both safety-related and non-safety related systems, and included a variety of components such as pumps, breakers, ventilation fans, diesel engines, batteries, and valves.

The team initially compiled a list of components and operator actions based on the risk factors previously mentioned. Additionally, the team reviewed the previous component design bases inspection (CDBI) reports (05000272 & 311120008007 and 05000272 &

31112006006) and excluded the majority of those components previously inspected.

The team then performed a margin assessment to narrow the focus of the inspection to 17 components and 5 operating experience (OE) items. The team selected a main steam isolation valve (MSIV) for large early release fraction (LERF) implications. The team's evaluation of possible low design margin included consideration of original design issues, margin reductions due to modifications, or margin reductions identified as a result of material condition/equipment reliability issues. The assessment also included items such as failed performance test results, corrective action history, repeated maintenance, Maintenance Rule (aXl ) status, operability reviews for degraded conditions, NRC resident inspector insights, system health reports, and industry OE.

Finally, consideration was also given to the uniqueness and complexity of the design and the available defense-in-depth margins.

The inspection performed by the team was conducted as outlined in NRC Inspection Procedure (lP) 71 111.21. This inspection effort included walkdowns of selected components; interviews with operators, system engineers, and design engineers; and reviews of associated design documents and calculations to assess the adequacy of the components to meet design basis, licensing basis, and risk-informed beyond design basis requirements.

Summaries of the reviews performed for each component and OE sample, and the specific inspection findings identified are discussed in the subsequent sections of this report. Documents reviewed for this inspection are listed in the Attachment.

.2.1.1 1C - 460V Vital Bus (1SWGR1CX)

a. Inspection Scope

The team reviewed bus loading calculations to determine whether the 460V system had sufficient capacity to support its required loads under worst case accident loading and grid voltage conditions. The team reviewed the design of the degraded voltage protection scheme to determine whether it afforded adequate voltage to safety-related devices at all voltage distribution levels, including the 460V vital buses. This included review of degraded voltage relay (DVR) setpoint calculations, motor starting and running voltage calculations, and motor control center (MCC) control circuit voltage drop calculations. The team reviewed procedures and completed surveillances for calibration of the DVRs to determine whether acceptance criteria were consistent with design calculations, and to determine whether the relays were performing satisfactorily. The team reviewed calculations for overcurrent protection devices to determine whether equipment was adequately protected, whether loads were subject to spurious tripping, and whether protective devices featured selective tripping coordination. The team reviewed operating procedures to determine whether the limits and protocols for maintaining offsite voltage were consistent with design calculations. The team reviewed vendor manuals, maintenance schedules, maintenance procedures, and completed work orders to determine whether PSEG adequately maintained the 1C 460V vital bus and its associated circuit breakers. The team reviewed corrective action documents and maintenance records to determine whether there were any adverse operating trends. In addition, the team performed a visual inspection of the 1C 460V vital bus to assess the material condition and the presence of hazards.

b.

Findinqs lntroduction: The team identified a finding of very low safety significance (Green)irwolving a non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion lll, Design Control, because PSEG had not adequately verified the adequacy of the design for the DVR voltage setpoint. Specifically, PSEG had not performed calculations for motor starting and running conditions, and for operation of other safety-related equipment based on voltages afforded by the DVRs.

Description:

NRC Letter dated June 2, 1977, required installation of the DVRs. The letter required the DVR voltage to be determined from an analysis of the voltage requirements of Class 1E loads at all onsite system distribution levels, and required inciusion of the setpoints in Technical Specifications (TSs). Technical Specification Table 3.3-4 item 7.b. specified an allowable value of > 94 percent for the DVRs. This allowable value corresponded to an analytical limit (actual minimum bus voltage that could occur without transfer to the emergency diesel generators) of 93.2 percent, as documented in a PSEG license amendment request dated March 28,1994. The team determined that PSEG had not adequately determined the DVR setpoints by analyzing the voltage it afforded safety-related equipment. In some cases, PSEG's voltage calculations used bus voltage based on the minimum voltage afforded by the non-safety related load tap changers installed on the station power transformers. In other cases, PSEG used voltage based on the TS specified DVR allowable value, rather than the design analytical limit. Finally, PSEG omitted some types of safety-related equipment from the voltage analyses.

Specifically, the team determined that PSEG based motor starting calculations on minimum bus voltage afforded by the non-safety related load tap changer rather than minimum bus voltage afforded by the DVR setpoints specified in TSs. Calculation ES-15.008 analyzed motor starting voltage during loss-of-coolant accident (LOCA) block loading. Similarly, calculation ES-15.014 performed an analysis of motor starting voltage both during LOCA block loading, and also for starting individual motors during steady state conditions. These calculations also determined the effect of the transient voltage dips that occur on the safety buses during motor starting to determine whether there were any deleterious effects of transient low voltage on other equipment already connected to the safety-related buses. Both of these calculations used a bus voltage of 4210V (approximately 101

.2 percent of nominal bus voltage of 4160V), rather than

voltage based on the analytical limit of 93.2 percent supported by TSs. As a result, the existing calculations of record for motor starting were non-conservative by approximately I percent. The team was concerned that during block loading, motors and other equipment would not have adequate voltage to start, and adverse effects including delayed operation of equipment, and overcurrent device tripping could occur. In response, PSEG performed preliminary calculations to assess the effect of degraded voltage during block loading and determined that motors would start in sufficient time to satisfy the assumptions of the accident analysis, and that tripping of overcurrent protective devices would not occur. PSEG documented this concern in their corrective action program (CAP) as notification (NOTF) 20494513.

The team also determined that calculations for motor running voltage were non-conseryative and that justifications for motors when voltages were outside their ratings were not consistent with the Updated Final Safety Analysis Report (UFSAR)commitments. PSEG determined the running motor voltage at degraded voltage in calculation ES-15.008. Although the calculation methodology for analyzing running motors was not explicitly described in the calculation, the "Results" section reported that motor starting was analyzed with a 4kY safety bus voltage of 94 percent. This value was non conservative relative to the minimum voltage that could occur on the safety bus represented by the analytical limit of 93.2 percent. Also, calculation ES-15.008, Section 2.3.1 stated that the minimum steady state voltage criteria for running motors was 90 percent, and that motors not meeting this criteria were evaluated in Engineering Evaluation S-C-EE-230-E4C-0-0753. The engineering evaluation concluded that running voltages slightly below 90 percent were acceptable based on available thermal life. The team noted that this approach was not consistent with UFSAR Section 8.3, which stated that the onsite distribution system has been shown by analysis and test to possess sufficient capacity and capability to automatically start and subsequently operate all safety loads within their voltage ratings for anticipated transients and accidents. ln addition, UFSAR Section 8.3.1.2 stated that the minimum allowable trip value and trip setpoint of the DVRs were derived using the 90 percent minimum motor terminal voltage requirement. The team noted that the setpoints specified in surveillance procedure 31.MD-FT.4kV-0002 were adequate to ensure a minimum bus voltage of 94 percent, consistent with the analytical approach, and that the justification in Engineering Evaluation S-C-EE-230-E4C-0-0753 appeared to provide reasonable assur-ance of operability for the affected loads without 90 percent rated voltage. PSEG documented this concern in their CAP via corrective action NOTF 20497060.

The team also noted that calculations ES-15,008 and ES-15.004 did not include minimum voltage acceptance criteria or evaluate steady state and transient voltage for non-motor loads such as vital inverters and battery chargers. In response, PSEG performed preliminary calculations and determined that these components would have their minimum required voltage except for brief periods during block loading conditions.

These were deemed acceptable because of the ability of the affected equipment and buses to automatically transfer to backup power supplies. PSEG documented this concern in their CAP via corrective action NOTF 20497062.

The team noted that PSEG personnel missed several opportunities to identify this design control performance deficiency and engage their CAP that may have precluded NRC identification in February 2011. Specifically, these opportunities involved internal and external OE associated with degraded voltage calculations and included

(1) a similar finding documented in a Hope Creek Generating Station (HCGS) NRC component design bases inspection (CDBI) report in November 2009 (NCV 05000354/2009007-03, Inadequate Design Control for 4 kV Bus Degraded Voltage Relay Bases), and

(2) NRC lnformation Notice (lN) 2008-02, "Findings ldentified During Component Design Bases Inspections," issued in March 2008.

Analvsis: The team determined that the failure to properly verify the adequacy of the volta& setpoint for the DVRs was a performance deficiency that was reasonably within PSEG's ability to foresee and prevent. The finding was determined to be more than minor because it was similar to example 3.j. of NRC IMC 0612, Appendix E, Examples of Minor lssues, in that based on PSEG's existing non-conservative calculations, the team had a reasonable doubt of operability of the safety-related motors until PSEG performed additional analYses.

Additionally, the finding was associated with the design control attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems (safety-related loads powered from vital busses) that respond to initiating events to prevent undesirable consequences. The team evaluated the finding in accordance with IMC 0609, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, Table 4afor the Mitigating Systems Cornerstone. The team determined the finding was of very low safety significance because it was a design deficiency confirmed not to result in loss of operability.

The team determined that this finding had a cross-cutting aspect in the area of Problem ldentification and Resolution, Operating Experience Component, because PSEG did not ensure that relevant internal and external OE was collected, evaluated, and communicated to affected internal stakeholders in a timely manner. Specifically, PSEG did not adequately evaluate a similar finding documented in a HCGS NRC CDBI report in November 2009 (NCV 050035412009007-03) and missed an opportunity in their internal response to NRC lN 2008-02, "Findings ldentified During Component Design Bases Inspections," issued in March 2008. (lMC 0310, Aspect P.2(a))

Enforcement:

10 CFR 50, Appendix B, Criterion lll, "Design Control," requires, in part, that measures be provided for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculational methods, or by the performance of a suitable testing program, and to ensure that the design is correctly translated into specifications, drawings, procedures, and instructions.

Contrary to the above, as of February 1,2011, PSEG's design control measures did not verify the adequacy of the design for the DVR voltage setpoint. Specifically, PSEG had not performed calculations for motor starting and running conditions, and for operation of other safety-related equipment based on voltages afforded by the DVRs. Because this violation is of very low safety significance and has been entered into PSEG's CAP (NOTFs 2Q494513,20497060, and2Q497062), it is being treated as a NCV consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000272; 0500031 112011007-01, Inadequate Calculations for Degraded Voltage Relay Voltage Setpoint)

.2.1.2 1B 28 Volt Direct Current Batterv

a. Inspection Scope

The team inspected the 1B 28 volt direct current (VDC) battery to verify that it was capable of meeting its design basis requirements for a LOCA concurrent with a loss-of-offsite power (LOOP) or a station blackout (SBO) event. The team reviewed maintenance activity and TS surveillance results to verify that the capacity and condition of the 1B 28VDC battery was adequately maintained. The team reviewed calculations and vendor information to verify that the 181 and 1B.2 battery chargers were of sufficient capacity to restore the charge on the 1B 28VDC battery after a design bases LOOP event occurred. The team reviewed the TS surveillance test results that demonstrated the full load capabilities of the 181 and 182 battery chargers against TS surveillance requirements (SRs) and design basis calculations to verify that the surveillance test results were satisfactory. The team reviewed 2BVDC battery sizing calculations to determine whether adequate voltage and charge was available to support the associated loads.

The team verified that modifications to the 28VDC system were appropriately evaluated for impact to the 1B 28VDC battery. The team also reviewed corrective action documents and system health reports and interviewed the system engineer to determine whether there were any adverse operating trends or existing issues affecting 28VDC battery reliability. Finally, the team performed a visual examination of the 1B 28VDC battery, as well as the 1A,2A, and 28 28VDC batteries to assess the material condition and the presence of potential hazards to the 28VDC batteries.

b. Findinqs lntroduction: The team identified a finding of very low safety significance (Green)involving a non-cited violation of Salem Unit 1 TS SR 4.8.2.5.2.h. Specifically, the team identified that PSEG did not perform a battery capacity test of the 1B 28VDC battery within 12 months of the previous performance test that showed signs of degradation.

Description:

The team reviewed the results of surveillance test SC.MD-FT.28D-0003, 28 Volt Station Batteries Performance Discharge Test Using BCT-2000 with Windows Software and Associated Surveillance Testing, performed on October 28, 2008. The purpose of the surveillance test was to fulfill requirements of TS SR 4.8.2.5.2.h. and demonstrate battery capacity was at least 80 percent of the manufacturer's rating.

Additionally, the surveillance instructions require a comparison to the previous battery performance discharge test to determine signs of battery degradation. Technical Specification SR 4.8.2.5.2.h. states that degradation is indicated when the battery capacity drops more than 10 percent of rated capacity from its capacity on the previous performance test. Step 5.12.21 of SC.MD-FT.28D-0003, Revision 2, required the technicians to mark the surveillance data sheet "Yes" for "Battery Degraded," notify supervision, and initiate a corrective action notification if the calculated value was greater than 10 percent. Technicians had calculated the 1B 28VDC battery capacity as 1 19 percent during the previous battery capacity test performed on April 26, 2004. The calculated capacity on October 28,20Q8, was 102.2 percent. The technicians calculated a 16.8 percent drop, but contrary to procedure instructions, did not mark the surveillance data sheet as "Yes" to "Battery Degraded" and did not initiate a corrective action notification.

On February 7,2011, the team notified PSEG that they had not performed the TS required surveillance testing of the 18 28VDC battery. PSEG promptly entered TS 4.0.3 for a surveillance not performed within its specified frequency. Consistent with TS 4.0.3 requirements, PSEG performed a risk evaluation and determined that the battery performance test could be delayed until the Fall2011 Salem Unit 1 refuel outage.

PSEG also performed a review of all previous 1B 28VDC battery performance test results and weekly and quarterly battery surveillance results and determined that the 1B 28VDC battery remained operable even though the October 28,2008, performance test had a capacity drop of greater than 10 percent. The team reviewed PSEG's associated risk and operability evaluations and determined that they were reasonable.

PSEG entered this issue into their CAP as NOTF 20495611. PSEG corrective actions included scheduling the 1B 28VDC battery performance test during the next scheduled Salem Unit 1 shutdown and evaluating causal factors to support the development of long-term corrective actions.

Analvsis: The team determined that the failure to perform TS SR 4.8.2.5.2.h was a performance deficiency that was reasonably within PSEG's ability to foresee and prevent. Specifically, prior to October 2009, PSEG personnel had opportunities to identify that they needed to perform a battery performance test at least once per 12 months when the 1B 28VDC battery showed signs of degradation on October 28, 2008, because battery capacity dropped more than 10 percent of rated capacity from its previous performance test on April 26,2004. The team noted that the finding was not sufficiently similar to any of the examples in NRC IMC 0612, Appendix E, Examples of Minor lssues. The finding was more than minor because it was associated with the human performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

Specifically, the availability of the 1B 28VDC battery was not ensured by performing additional surveillance testing to monitor for battery degradation. The team evaluated the finding in accordance with IMC 0609, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, Table 4afor the Mitigating Systems Cornerstone. The team determined the finding was of very low safety significance because it was a qualification deficiency confirmed not to result in loss of operability.

The team determined that this finding had a cross-cutting aspect in the area of Human Performance, Work Practices Component, because PSEG personnel did not follow procedure requirements during the 1B 28VDC battery performance discharge surveillance test. Specifically, personnel did not follow step 5.12.21 of SC.MD-FT.28D-0003 which required technicians to mark the surveillance data sheet "Yes" for "Battery Degraded," notify supervision, and initiate a corrective action notification if the calculated battery performance capacity drop was greater than 10 percent. (lMC 0310, Aspect H.4(b))

Enforcement:

Salem Unit 1 TS SR 4.8.2.5.2.h requires that PSEG verify, at least once po lZ months, during shutdown, if the battery shows signs of degradation. On October 28,2Q08, the 1B 28VDC battery showed signs of degradation because its battery capacity dropped more than 10 percent of rated capacity from its capacity on the previous performance test. Contrary to SR 4.8.2.5.2.h, on October 28, 2009, PSEG failed to meet SR 4.8.2.2.h and had not performed a subsequent battery performance test of the 1B 28VDC battery. On February 8,2011, PSEG completed SR 4.0.3 actions for the missed surveillance, which included justification for continued operability until the Unit 1 Fall2011 refuel outage to test the battery. Because this violation was of very low safety significance and was entered into PSEG's CAP (NOTF 20495611), it is being treated as a NCV consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV OSOOO272I2O11OO7-02, Failure to Perform a TS Required Battery Performance Test)

.2.1.3 No. 21 Control Room Emerqencv Air Conditioninq Svstem Supplv

Fan

a. Inspection Scope

The team inspected the No. 21 control room emergency air conditioning system (CREACS) supply fan to verify its capability to meet design basis requirements. The CREACS is initiated following receipt of a safety injection (Sl) or high radiation actuation signal for areas inside the control room envelope (CRE). lt must provide a protected environment from which operators can control the reactor unit during airborne challenges from radioactivity, hazardous chemicals, and fire byproducts such as fire suppression agents and smoke during both normal and accident conditions. The No. 21 supply fan, as well as each of the other fans, must be individually capable of providing 100 percent of the required CRE pressurization air to 1/8 inches of water gauge pressure. The team also reviewed the CREACS fan support systems to ensure that they would function as designed under transient and accident conditions. The support systems included the associated system high efficiency particulate air (HEPA) filter, cooling coils, isolation dampers, ducting, component expansion joints, and mechanical supports.

The team reviewed the UFSAR, TSs, design basis documents, drawings, supporting calculations and procedures to identify the design basis requirements of the fan and system. The team reviewed recently completed system walkdown reports and surveillance tests to ensure the capability of the system had been maintained. The team discussed the design, operation, and maintenance of the CREACS with the engineering staff to gain an understanding of the performance history, maintenance and overall health of the fan and other system components. The team reviewed corrective action documents to determine if there were any adverse trends associated with the fan and to assess PSEG's capability to evaluate and correct problems. The team performed field walkdowns of the system and observed leak-check smoke tests to independently assess the material condition and to verify that the system configuration was consistent with the design basis assumptions, system operating procedures, and plant drawings.

The team also evaluated the manual operator actions to realign the control area ventilation (CAV) system given a failure of the control room air conditioning system.

Specifically, the team inspected operator critical tasks including recognizing loss of air conditioning to the control room and performing steps to align control room ventilation dampers and fans in order to provide sufficient air flow through the CRE to ensure equipment temperature limits are not exceeded. The team interviewed licensed operators, observed a walkthrough of the procedure and reviewed associated alarm response procedures to assess the likelihood of cognitive or execution errors. The team evaluated the available time margins to perform the actions to verify the reasonableness of PSEG's procedures and risk assumptions. The team also reviewed room heat-up calculations and a test performed to determine heat-up rates in various portions of the CRE used to evaluate the adequacy of the ventilation alignment following implementation of the procedure.

I b. Findinqs lntroduction: The team identified a finding of very low safety significance (Green)involving a non-cited violation of 10 CFR 50, Appendix B, Criterion XVl, "Corrective Action," because PSEG did not identify and correct a condition adverse to quality.

Specifically, PSEG did not identify and correct the degraded condition of the Unit 1 and Unit 2 CREACS common suction expansion joints because they did not implement appropriate PMs per their performance-centered maintenance (PCM) template.

Description:

During a walkdown of the Unit 2 CREACS fans on February 10,2011, the team identified a small tear (approximately 1.5 inches in length) in the expansion joint between the CREACS filter housing and the cooling coil. The small opening represented a CRE breach and was of particular concern as it was downstream of the HEPA filter and immediately upstream of the common suction to both Unit 2 CREACS fans. This deficiency potentially impacted both Salem operating units as the redundant Unit 1 and Unit 2 CREACS trains supply filtered air under accident conditions to a common control room. In response, PSEG personnel initiated corrective action NOTF 20496285. Operators promptly entered TS 3.7.6 for this CRE breach and initiated mitigation actions. On February 10, maintenance installed a patch on the filter housing expansion joint covering the tear and two other wear spots. On the morning of February 11, operations reviewed and accepted the repair and engineering performed a satisfactory smoke test to validate the repairs while CAV was aligned for accident pressurized mode of operation in accordance with 52.OP-ST.SSPS-0010. Operators exited TS 3.7.6 and declared the CRE operable.

During a post-repair and extent-of-condition walkdown of the Unit 1 and Unit 2 CREACS trains on the afternoon of February 11,2011, the team identified several wear spots and three additional small breaches on the Unit 1 and Unit 2 filter housing expansion joints.

In response, PSEG personnel initiated NOTFs 20496388 and 20496387 for the Unit 1 and Unit 2 expansion joint issues, respectively. PSEG determined that the additional wear spots and small openings were enveloped by their existing technical evaluation performed in response to the identified unplanned breach on February 10 and the results of their CRE tracer gas testing performed in September 2010. The team found PSEG's evaluation reasonable. Notwithstanding, PSEG prioritized the repair of these additional degraded locations and maintenance patched both Unit 1 and Unit 2 CREACS filter housing expansion joints by February 15,2011. Following this repair effort, the team performed additionalwalkdowns on the Unit 1 and Unit 2 CREACS trains and did not identify any additional deficiencies.

PSEG determined that the individual inlet and outlet expansion joints for each respective Unit 1 and Unit 2 CREACS fan all had existing 2-year PM recurring tasks to perform inspection and repairs, as necessary. However, PSEG had not created similar PM tasks for the larger common filter housing expansion joints (one for each unit) contrary to the guidance in their expansion joint PCM template (NOTF 20496357). In addition, the expansion joint PCM template noted that a review of industry OE showed that the mean time to failure for rubber expansion joints is 12 to 15 years. Based on the team's questions, PSEG concluded that the filter housing expansion joints were most likely manufactured in 1975 and installed during initial construction. The team concluded that had PSEG created the expansion joint PM in January 2007 in accordance with their PCM template guidance, they would have likely identified the condition during inspections and/or replaced the dated expansion joints. The team noted that PSEG had several opportunities to identify the missing PMs since January 2007 including

(1) in June 2008, a PSEG self-assessment identified that there were no active PMs to inspect the expansion joints at the inleUoutlet of the CREACS fans and created a 2-year PM;

(2) in July 2009, PSEG inspected the No. 21 and No. 22 CREACS fan expansion joints (PMs 30170606 and 30170607) which are located in close proximity to the degraded Unit 2 expansion joint; and

(3) in June 2010, PSEG performed PM template reviews on critical heating, ventilation and air conditioning (HVAC) expansion joints. Upon identification of the issue in February 2011, engineering promptly initiated a PM change request (PMCR). The PSEG PM Oversight Committee Chair reviewed and approved the associated PMCR. The PMCR prescribed an initial expansion joint replacement, followed by recurring periodic inspections, and an 18-year scheduled replacement (70119543). PSEG targeted the first-call replacements for the next available maintenance windows. PSEG also initiated corrective action NOTFs to perform extent-of-condition inspections from the inside of the expansion joint plenums (20496442 and 20496443).

The team noted that PSEG personnel missed several opportunities to identify the degraded condition of the Unit 1 and Unit 2 expansion joints and engage their CAP that may have precluded NRC identification in February 2011. Specifically, these opportunities included

(1) an Unit 2 filter unit inspection on July 26, 2010 (WO 50121539),

(2) walkdowns associated with tracer gas testing in September 2010,

(3) system engineering walkdowns of the Unit 1 and Unit 2 CREACS rooms on December 29,2010, and

(4) engineering extent-of-condition walkdowns on February 10,2011. Based on the time dependent nature of the expansion joint wear (long-term aging and cyclic fatigue of the expansion boot), the team concluded that the degraded condition most likely existed since July 26,2010.

Analvsis: The team determined that the failure to identify and correct the degraded condition of the CREACS expansion joints was a performance deficiency that was reasonably within PSEG's ability to foresee and prevent. Specifically, PSEG had not implemented appropriate PMs for the CREACS common suction expansion joints per their expansion joint performance-centered maintenance (PCM) template. The team noted that the finding was not similar to any of the examples in NRC IMC 0612, Appendix E, Examples of Minor lssues. The finding was more than minor because it was associated with the barrier (door, dampers, seals) performance attribute of the Barrier Integrity Cornerstone and adversely affected the cornerstone objective of providing reasonable assurance that physicaldesign barriers (the CRE in this case)protect the control room operators from radionuclide releases caused by accidents or events. The finding was evaluated in accordance with IMC 0609, Attachment 4, Table 4a for a containment barrier. Since the finding had the potential to impact more than the radiological barrier function, a Region I Senior Reactor Analyst (SRA)performed a Phase 3 analysis. The SRA determined that the dominant sequence involved a sufficient degradation of the CREACS barrier that would allow sufficient in-leakage to force an evacuation of the control room during a fire or toxic gas event. The areas with the degradation were in room 15615 and 25615 for Units 1 and 2, respectively. The SRA evaluated these areas and determined that the potential impact due to in-leakage through the degraded barrier from fire and toxic gas would be negligible. The SRA also reviewed the results of recent CRE in-leakage testing conducted in September 2010. The condition of the expansion joint tearing and wear could reasonably be assumed to have existed during the September testing. This testing also confirmed that the total in-leakage in these areas was small. Based on the above factors, the SRA determined the finding was of very low safety significance (Green).

This finding had a cross-cutting aspect in the area of Human Performance, Work Control Component, because PSEG did not plan work activities to support long{erm equipment reliability by ensuring that maintenance scheduling was more preventive than reactive. Specifically, PSEG did not implement appropriate PMs on the CREACS filter expansion joints necessitating several reactive corrective maintenance (CM) activities.

(lMC 0310, Aspect H.3(b))

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, PSEG did not promptly identify and correct the degraded condition of the Unit 1 and Unit 2 expansion joints that existed from approximately July 26, 2010, to February 11,2011. Because this violation was of very low safety significance (Green)and has been entered into PSEG's CAP (NOTFs 20496357,20496387,20496388), it is being treated as an NCV consistent with Section 2.3.2 of the NRC Enforcement Policy.

(NCV 05000272;0500031112011007-03, Failure to ldentify and Correct a Condition Adverse to Quality Affecting the CREACS Expansion Joints)

.2.1.4 21 Service Water Pump (2SWE1)

a. Inspection Scope

The team inspected 21 service water (SW) pump to verify its ability to meet the design basis requirements in response to transient and accident events, including supply of cooling water to the reactor safeguard and auxiliary equipment under all credible seismic, flood, drought and storm conditions. The team reviewed the SW system hydraulic model and the design basis hydraulic analyses/calculations to verify that PSEG properly considered the required total dynamic head (TDH), required net positive suction head (NPSH), and the potential for vortex formation under all design basis accidenVevent conditions. The team reviewed the SW pump in-service test (lST)procedures, recent test results, and trends in test data to verify that pump performance remained consistent with design basis requirements. The team also reviewed the IST reference values for flow rate and TDH to verify appropriate correlation to accident analyses conditions, taking into account setpoint tolerances and instrument inaccuracies.

The team reviewed the SW pump motor bearing oil cooler inspection and performance monitoring procedures, including tesUinspection results, to verify compliance with licensing commitments under the Generic Letter (GL) 89-13, "Service Water System Problems Affecting Safety-Related Equipment," program plan. The team reviewed the maintenance and functional history of the 21 SW pump by sampling corrective action reports, system health reports, and PM/CM records. The team reviewed the effectiveness of traveling screen/strainer design features and adverse condition operating procedures for limiting potential adverse effects of ice and river grass on the SW pumps/system. The team also conducted several detailed walkdowns to visually inspect the physical/material condition of the SW pump and its support systems, including control room instrumentation and indication, and to ensure adequate config u ration control.

b. Findings

No findings were identified.

.2.1.5 Unit 1 Turbine Driven Auxiliarv Feedwater Pump

a. Inspection Scope

The team inspected the Unit 1 turbine driven auxiliary feed water (TDAFW) pump to verify that it was capable of meeting its design basis requirements. The team reviewed applicable portions of the UFSAR and design basis documents to identify the design basis requirements for the pump and associated steam turbine. The team reviewed calculations and surveillance test procedures to determine if the turbine and pump were capable of achieving design basis head/flow requirements during design basis conditions and that test acceptance criteria were consistent with these requirements.

The team reviewed the hydraulic calculations associated with system flow rate and pressure as well as the NPSH calculation for the pump to ensure that the required performance could be achieved. The team also reviewed design calculations for the TDAFW pump enclosure to determine if it was capable of mitigating the effects of a high energy line break (HELB) event. Additionally, the team reviewed calculations for room healup to assess if the assumptions in the calculation were acceptable and to ensure that equipment in the room did not exceed design temperature limits. Finally, the team determined if operator actions credited during SBO events for the TDAFW pump could be performed within the time constraints assumed in the design calculation and Salem PRA.

The team interviewed design and system engineers in order to review the design and system functional requirements, as well as obtain historical test performance results. ln addition, the team reviewed corrective action documents to assess failures or nonconforming issues, and to determine if PSEG appropriately identified, evaluated, and corrected deficiencies. The team performed severalwalkdowns of the TDAFW pump and support systems to assess the material condition of the equipment and determine if the equipment configuration was in accordance with drawings and design assumptions.

Finally, the team performed a review of the emergency operating procedures (EOPs)associated with post-accident pump operation to ensure the pump would be operated in accordance with its design requirements.

b.

Findinos No findings were identified.

.2.1.6 1C Emergencv Diesel Generator

a.

lnspection Scope The team inspected the 1C emergency diesel generator (EDG) and its associated fuel oil, lube oil, starting air, intake, exhaust, and jacket water cooling systems to ensure they could perform their respective design basis function in response to transient and accident events, including a LOOP. The team reviewed the UFSAR, TSs, design basis calculations, vendor documents, and procedures to identify the design basis, maintenance, and operational requirements for the engine and its support systems. The team reviewed fuel oil consumption calculations to ensure TS requirements were met under design basis loading conditions. The team reviewed the design specification for the starting air system, as well as air start test results, the normal operating pressure band, air compressor actuation setpoint and the TS limit for operability to verify that the starting air system was properly sized and could meet its design function for successive starts. The team reviewed EDG surveillance test results, operating procedures and maintenance work packages to determine the overall health of the EDG engine and its mechanical support systems.

The team performed several field walkdowns of all six EDGs (three EDGs per unit) to independently assess the material condition and the operating environment of the EDGs and associated electrical equipment. During the walkdowns, the team compared local and remote EDG control switch positions, breaker position indicating lights, and system alignments to design and licensing basis assumptions to verify the adequacy of PSEG's configuration control. The team interviewed system engineers and operators to evaluate past performance and operation of the EDGs. The team reviewed system health reports and corrective action documents to determine if there was any adverse equipment operating trends and to ensure problems were properly identified and corrected. Additionally, the team observed portions of the 28 and 2C EDG tests in February 2011 during their respective 24-hour endurance runs and hot-restart surveillance tests, and conducted pre and post-operation walkdowns to ensure proper operation and assess material condition.

b.

Findinos No findings were identified.

.2.1.7 1B 28VDC Bus

a.

lnspection Scope The team inspected the 1B 28VDC bus and associated distribution panels to verify that they were capable of meeting their design basis requirements. The team reviewed controlled drawings and several calculations to determine if the associated loads would reliably operate under worst case conditions. Calculations reviewed included voltage drop, short circuit, breaker coordination, and component study calculations. The team reviewed PM activities associated with the 1B 28VDC bus and associated distribution panels to ensure that PSEG properly maintained the equipment and identified any adverse trends or deficient conditions. The team also reviewed a test and replacement program for aging molded case circuit breakers (MCCBs) against industry standards to veriiy that PSEG adequately maintained the reliability of the 28VDC MCCBS, as well as a large population of MCCBs used in other Salem electrical distribution systems, The team also reviewed corrective action documents and system health reports, and interviewed the system engineer to determine whether there were any adverse operating trends or existing issues affecting the 28VDC bus and distribution system reliability. Finally, the team performed a visual examination of the 1B 28VDC bus and distribution panels, as well as the 1A,2A, and 28 28VDC buses and associated distribution panels, to assess the material condition and the presence of potential hazards to the 28VDC distribution systems.

b.

Findinqs No findings were identified.

2.1.8 Residual Heat Removal/Safetv Iniection Cross-tie Valve (12SJ45)

a. Inspection Scope

The team inspected motor operated valve (MOV) 12SJ45 to verify its ability to meet its design basis requirements, including isolation of the cross-tie between the residual heat removal (RHR) and Sl pumps until needed during long-term recirculation in response to transient and accident conditions. The team reviewed calculations for required thrust, maximum differential pressure, and valve weak link analysis. The team reviewed diagnostic testing and IST surveillance results, including stroke time and available thrust, to verify that acceptance criteria were met and performance degradation could be identified. The team reviewed documentation to verify that valve motor design was consistent with the environmental qualification (EQ) basis for limiting conditions. The team reviewed the maintenance and functional history of the cross-tie valve by sampling corrective action reports, the system health report, and PM/CM records. The team also conducted several detailed walkdowns to visually inspect the physical/material condition of the valve and its support systems, including control room indication, and to ensure adequate configuration control.

b.

Findinqs No findings were identified.

.2.1.9 1D 1 15V Vital Instrument Bus (1DlS181

1YA)a.

Inspection Scooe The team reviewed calculations for 1 15V vital bus loading to determine whether the vital inverters were being applied within their load ratings. The team reviewed calculations for 115V system voltage drop contained in design change documents, and preliminary voltage calculations for circuits estimated to be the most limiting, to determine whether 1 15V vital system loads were being applied within their required voltage ratings. The team reviewed system health documents and corrective action histories to determine whether there had been any adverse operating trends, including obsolescence issues.

The team reviewed maintenance schedules and completed work packages to determine whether equipment, including the vital inverter supplying the bus, was being properly maintained. ln addition, the team performed a visual inspection of the 1D 1 15V vital bus to assess material condition and the presence of hazards' b.

Findinos No findings were identified.

.2.1.1 0 21 Diesel Fuel Oil Transfer Pump Motor

a. Inspection Scope

The team inspected the No. 21 diesel fuel oil transfer pump (DFOTP) motor to verify it was capable of meeting its design basis requirements to supply fuel to the 2A, 28, and 2C EDG day tanks. The team reviewed controlled electrical drawings, motor nameplate data, vendor electrical contactor and overload data, and a mechanical calculation to determine that the motor would reliably operate under worst case conditions and support the 21DFOTP. The team reviewed PM activities associated with the 21 DFOTP motor and breaker to ensure that PSEG properly maintained the equipment and identified any adverse trends or deficient conditions. The team also reviewed corrective action documents and system health reports and interviewed the system engineer to determine whether there were any adverse operating trends or existing issues affecting the 21 DFOTP motor reliability. Finally, the team performed a visual examination of the 21 DFOTP motor and associated MCC, as well as the 22,11, and 12 DFOTP motors and associated MCCs to assess the material condition and the presence of potential hazards to the Unit 1 and Unit 2 DFOTPS and motors.

b.

Findinqs No findings were identified.

.2.1.1 1Residual Heat Removal Heat Exchanqer Component Coolinq Water Outlet lsolation

Motor Operated Valve No. 22CC16

a. Inspection Scope

The team inspected the Unit 2No.22 RHR heat exchanger (HX) component cooling water (CCW) outlet isolation MOV (22CC16) to verify its capability to perform its required design basis functions. The 22CC16 valve is a normally closed valve which opens on an auto-open signal tied to a safety injection or refueling water storage tank (RWST) low levelsignal. The team reviewed the UFSAR, TSs, design basis documents, drawings, and procedures to identify the design basis requirements of the valve. The team reviewed periodic MOV diagnostic test results and stroke-timing test data to verify acceptance criteria were met. The team verified that the MOV safety functions, performance capability, torque switch configuration and design margins were adequately monitored and maintained in accordance with GL 89-10 guidance. The team reviewed MOV weak link calculations to ensure the ability of the valve to remain structurally functional while stroking under design basis conditions. The team verified that the valve analysis used the maximum differential pressure expected across the valve during worst case operating conditions. Additionally, the team reviewed motor data, degraded voltage conditions, and voltage drop calculation results to confirm that the MOV would have sufficient voltage and power available to perform its safety function at degraded voltage conditions.

The team discussed the design, operation, and maintenance of the MOV with the engineering staff to gain an understanding of the performance history, maintenance and overall component health of the valve. On February 8,2011, the team directly observed technicians modify the 22CC16 valve stem and install a state-of-the-art Quick Stem System (OSS) strain gage, and observed the post-maintenance stroke time and torque surveillance testing. The team reviewed the test data and discussed it with the engineering staff to confirm that the valve's design basis functions and operating margin were adequately maintained. The team also conducted walkdowns of both units' RHR HX CCW outlet valves to assess the material condition of the MOVs, and to verify the installed configurations were consistent with the plant drawings, design and licensing basis. Finally, the team reviewed corrective action NOTFs and system health reports to verify that PSEG appropriately identified and resolved deficiencies and maintained the MOVs properly.

b.

Findinqs No findings were identified.

.2.1.1 2 Main Steam lsolation Valve (22MS167)

a. Inspection Scope

The team inspected steam piston-operated valve 22M5167 to verify its ability to meet its design basis requirements, including containment isolation of the main steam piping in response to transient and accident events. The team reviewed IST procedures and results for valve stroke time to verify that the acceptance criteria were met and performance degradation could be identified. The team reviewed the maintenance and functional history of the vatve by sampling corrective action reports, the system health report, and PM/CM records. The team reviewed a recently completed modification package to the piston operator for the valve to confirm that design basis for the valve was m-aintained. The team also conducted severalwalkdowns to visually inspect the physical/material condition of the valve and its support systems, including control room instrumentation and indication, and to ensure adequate configuration control.

b.

Findinqs No findings were identified.

.2.1.1 321 Residual Heat Removal Pump 4KV Breaker (S24KV-2AD1AX7D)

a. Inspection Scope

The team reviewed bus load flow calculations to determine whether the 21 RHR pump 4KV breaker was applied within its specified capacity ratings under worst case accident loading and grid voltage conditions. The team reviewed schematic diagrams and calculations for the breaker to determine whether equipment operation was consistent with the design bases. The team reviewed calculations for protective device settings to determine whether the pump motor was adequately protected, whether it was subject to spurious tripping, and whether the breaker was selectively coordinated with upstream devices. The team reviewed maintenance schedules, vendor data, and procedures for breaker routine maintenance and overhauls to determine whether scheduled maintenance activities were consistent with vendor recommendations. The team reviewed recent corrective action documents and completed maintenance and testing records to determine whether there were any adverse operating trends. In addition, the team performed a visual inspection of the 2A 4160V vital bus to confirm overcurrent trip device settings for the 21 RHR pump 4KV breaker, and to assess the material condition and the presence of hazards.

b.

Findinqs No findings were identified.

.2.1.1 412A Component Coolinq Water Heat Exchanoer Service Water lnlet Valve (12SW376)

lnstrument Air Controller a.

lnspection Scope The No. 12ACCW HX SW inlet valve (12SW376) is an air operated valve (AOV), with no manual operation capability, and has a risk-important function to open for RHR cooling and a risk-important function to close during a LOCA concurrent with a LOOP.

The te-am inspected the 12SW376 instrument air (lA) controls to verify that it was capable of meeting its design basis requirements to supply cooling water to the RHR HXs and to isolate, when required, to maximize cooling water to the EDGs and containment fan cooling units (CFCUs). The team reviewed lA drawings, vendor manuals for all associated pneumatic controllers, and AOV diagnostic testing results to verify that 12SW376 would operate reliably and to verify that the AOV was performing with acceptable pneumatic margin. The team reviewed PM activities associated with 12SW376 to ensure that PSEG properly maintained the valve and identified any adverse trends or deficient conditions. The team also reviewed corrective action documents and system health reports; and interviewed the AOV engineer, instrument and controls technicians, and system engineers to determine whether there were any adverse operating trends or existing issues affecting 12SW376 reliability. Finally, the team performed a visual examination of 12SW376 and the associated lA controls to assess the material condition and the presence of potential hazards.

b.

Findinqs No findings were identified.

2.1.15 Batterv Charqer Portable Diesel Generator a.

lnspection Scope The team evaluated the manual operator actions to align the dedicated portable diesel generator to the 125 volt and 28 volt battery chargers during a SBO. The team determined if this action could be appropriately credited by reviewing the critical operator tasks including diesel starting requirements, breaker realignment requirements, and temporary cable installation. The team interviewed licensed and non-licensed operators, reviewed associated operating procedures and observed operators perform a walk though of the procedure to assess PSEG's ability to perform the required actions and to determine the likelihood of cognitive or execution errors. The team evaluated the available time margins to perform the actions to verify the reasonableness of PSEG's operating procedures and risk assumptions. The team also walked down the associated battery rooms, battery chargers, switching panels, diesel generator and standby cables to assess PSEG's configuration control and the material condition of the associated structures, systems and components (SSCs). Finally, the team reviewed the modification package developed to install and test the equipment required for this action to determine if design basis requirements for the installed SSCs were maintained, and testing of the equipment installed by the modification was adequate to conclude that the lineup would perform as intended.

b.

Findinqs No findings were identified.

.2.1.1 61C Emerqencv Diesel Generator Room Area Ventilation Fan (1VH27)

a. Inspection Scope

The team reviewed calculations for sizing the fan and motor to determine whether the ventilation scheme was adequate to maintain the EDG room within its required temperature limits. The team reviewed calculations for overcurrent protective device settings to determine whether the fan motor was adequately protected, whether it was subject to spurious tripping, and whether its breaker was selectively coordinated with upstream devices. The team reviewed electrical schematic diagrams to determine whether the control scheme for the fan and its associated dampers was consistent with the design bases. The team reviewed vendor data, maintenance schedules, and task descriptions to determine whether PSEG properly maintained the equipment. In addition, the team performed a visual inspection of the 1C EDG room area ventilation fan and its environs to assess the material condition and the presence of hazards.

b.

Findinqs No findings were identified.

2.1.17 Switchqear and Penetration Area Ventilation Supplv Fan (1VHE1012)a.

lnspection Scope The team inspected the No. 12 switchgear and penetration area ventilation (SPAV)supply fan to verify its ability to meet design basis requirements, including supply of re-circulated and/or outside air to maintain acceptable levels of temperature for the switchgear and penetration areas, in response to transient and accident conditions. The team reviewed the maintenance and functional history of the fan by sampling corrective action reports, the system health report, and PM/CM records. The team reviewed inputs and assumptions used in Gothic modeling of the SPAV system to verify that they were consistent with physical conditions in the plant. The team also conducted several detailed walkdowns to visually inspect the physical/material condition of the fan and its support systems, including control room instrumentation and indication, and to ensure adequate configuration control.

b.

Findinqs No findings were identified.

.2.2 Review of IndustrV Operating Experience and Generic lssues (5 samples)

The team reviewed selected OE issues for applicability at Salem Unit 1 and 2. The team performed a detailed review of the OE issues listed below to verify that PSEG had appropriately assessed potential applicability to site equipment and initiated corrective actions when necessary.

.2.3.1 Operatino Experience Smart Sample FY 2008-01 - Neoative Trend and

Recurrinq Events Involvinq Emerqencv Diesel Generators a.

Inspection ScoPe NRC Operating Experience Smart Sample (OpESS) FY 2008-01 is directly related to NRC lN 2OO7-27, "Recurring Events lnvolving Emergency Diesel Generator Operability."

The team reviewed PSEG's evaluation of lN 2007-27 and their associated corrective actions. The team reviewed PSEG's EDG system health reports, EDG NOTFs and work orders, leakage database, and surveillance test results to verify that PSEG appropriately dispolitioned EDG concerns. Additionally, the team independently walked down ihe Uriit t and Unit 2 EDGs on several occasions to inspect for indications of vibration-induced degradation on EDG piping and tubing and for any type of leakage (air, fuel oil, lube oil, andlorjacket water). The team also directly observed the 2B and 2C EDG monthly surveillance runs in February 2011, and performed pre and post-run walkdowns on the EDGs, as well as the 1B and 1C EDGs, to ensure PSEG maintained appropriate configuration control and identified deficiencies at a low threshold.

b.

Findinqs No findings were identified.

.2.3.2 RC lnforma

Breakers a.

lnspection Scope The team evaluated PSEG's applicability review and disposition of NRC lN 2007-34.

The NRC issued this lN to inform licensees about OE regarding low, medium, and high voltage circuit breakers, including problems with:

o Deficient fit-up with cubicles o Inadequate or excessive tolerances and gaps r Worn or misadjusted operating linkages o lnadequate or inappropriate maintenance practices o Configuration control errors r Deficiencies from original design and refurbishment

.

Design changes The team reviewed maintenance schedules, vendor data, and procedures for medium and low voltage breaker routine maintenance and overhauls to determine whether scheduled maintenance activities were consistent with vendor recommendations' The team reviewed recent corrective action documents and completed maintenance and testing records to determine whether there were any adverse operating trends. ln addition, the team conducted interviews with engineering personnel to assess knowledge of industry trends and OE.

b.

Findinqs No findings were identified.

.2.3.3 NRC lnformation Notice 2008-09: Turbine-Driven Auxiliary Feedwater Pump Bearinq

lssues a.

lnspection Scope The team evaluated PSEG's applicability review and disposition of NRC lN 2008-09.

The NRC issued the lN to alert licensees of issues with TDAFW pumps, as they relate to the importance of having accurate maintenance instructions and effective post-maintenance testing. The team reviewed PSEG's evaluation of their TDAFW pump maintenance procedures. The team also reviewed bearing temperature operating profiles, corrective action documents, and maintenance procedures related to the TDAFW pumps to determine if Salem was susceptible to the issues stated in the lN.

The team also performed severalwalkdowns of the Unit 1 and Unit 2 TDAFW pumps to assess the material condition of the equipment, including independently observing the governor and bearing oil levels and condition for indications of excessive leakage and/or overheating. On January 27,2011, the team performed a posf lST walkdown of the No. 13 TDAFW pump to assess the material condition of the pump and oil systems.

b.

Findinqs No findings were identified.

.2.3.4 Spurious Safetv Iniection Actuation and Reactor Tdp

a. Inspection Scope

The team evaluated PSEG's applicability review and disposition of NRC lN 2009-03.

The lN was issued to inform licensees about OE regarding unique solid state protection system (SSPS) failures that cause spurious Sl actuations and cannot be overridden with control room panel override switches. The team reviewed PSEG's evaluation of the operation and maintenance issues associated with the SSPS OE. Specifically, the team reviewed corrective action documents and abnormaloperating procedure (AOP)

S1.OP-AB.SSP-0001, Local Reset of ESF Actuation, and interviewed the system engineer to validate that PSEG

(1) established a PM program for SSPS electronic cards,

(2) developed an AOP to reset spurious Sl signals locally if the control room switches were ineffective, and

(3) maintained a life-cycle for SSPS electronic cards.

b.

Findinqs No findings were identified.

.2.3.5 Stem Lubricant

a. Inspection Scope

The team evaluated PSEG's applicability review and disposition of NRC lN 2010-03.

The NRC issued the lN to inform licensees of recent failures and corrective actions for MOVs because of degraded lubricant on the valve stem and actuator stem nut threaded area. The team reviewed corrective action documents and maintenance procedures to ensure that PSEG adequately maintained applicable MOVs to preclude the degraded conditions described in the lN. The team conducted several risk-informed walkdowns of accessible MOVs to independently assess the material condition of MOV valve stem and actuator stem nut threaded areas and reviewed the PM history for a sample of valves.

b. Findinqs No findings were

OTHER ACTIVITIES

4c42 ldentification and Resolution of Problems (lP 71152)

The team reviewed a sample of problems that PSEG had previously identified and entered into the CAP. The team reviewed these issues to verify an appropriate threshold for identifying issues and to evaluate the effectiveness of corrective actions.

In addition, the team reviewed corrective action NOTFs written on issues identified during the inspection to verify adequate problem identification and incorporation of the problem into the CAP. The specific corrective action documents that were sampled and reviewed by the team are listed in the attachment.

b. Findinqs No findings were identified.

40A6 Meetinqs. Includinq Exit On February 18, 2011, the team presented the inspection results to Mr. Edward Eilola, Plant Manager, and other members of PSEG management. The team reviewed proprietary information and returned the associated documents to PSEG at the end of ihe inspection. The team verified that no proprietary information is documented in the report.

ATTACHMENT SUPPLEM ENTAL INFORMATION KEY POINTS OF CONTACT PSEG Personnel M. CraMord, Acting Mechanical Design Manager E. Eilola, Plant Manager D. Johnson, MOV Program Owner K. King, Senior Engineer, Mechanical Design W. Kittle, IST Program Owner D. Kolasinski, System Manager G. Luh, Principal Engineer, Mechanical Design G. Pahwa, GL 89-13 Program Owner F. Priestly, Senior Reactor Operator L. Rajkowski, Engineering Director T. Ram, System Engineer B. Thomas, Senior Compliance Engineer M. Winkelspecht, System Manager NRC Personnel D. Schroeder Senior Resident Inspector C. Cahill Senior Reactor Analyst LIST OF ITEMS OPENED, CLOSED AND DISCUSSED Open and Closjd Q5AQO27 2; 050003 1 1I 20 11 007 -0 1 NCV Inadequate Calculations for Degraded Voltage Relay Voltage Setpoint (Section 1R21

.2.1 .1)

0500027212011007-02 NCV Failure to Perform a TS Required Battery Performance Test (Section

1R21 .2.1.2)

050Q027 2: 050003 1 1 l 201 1 007 -03 NCV Failure to ldentify and Correct a Condition Adverse to Quality Affecting the CREACS Expansion Joints (Section 1R21.2.1.3)

LIST OF

DOCUMENTS REVIEWED

Audits and Self-Assessments

70109034-60, Salem NRC Component Design Basis Inspection Focused Area Self

Assessment, dated 11 19110

80102344-40, Motor Operated Valve Setup Margin NOS Performance Assessment, dated

9t7t10

Calculations

A-5-500-E4C-0-1930, 500 kV and 4.16kV Systems Voltage Drop due to Unit Trip, Rev. 2

ES-3.001, 28VDC Short Circuit and System Voltage Drop Calculation, Rev. 6

ES-3.002, 28 Volt DC Battery and Battery Charger Sizing Calculation, Rev. 5

ES-3.004, 28Volt DC Component Study and Voltage Drop Calculation, Rev. 3

ES-8.007, Transformer Tap Changer Setting Calculation, Rev. 3

ES-13.006, Breaker and Relay Coordination Calculation Safety Related AC System, Rev. 3

ES-13.008, 250V, 125V,28V DC System and 1 1 5VAC ASDS Overcurrent Coordination, Rev. 3

ES-15.004, Load Flow and Motor Starting, Rev. 4

ES-15.005Q, 230V Vital Bus Voltage Drop Calculation for Control Circuits SNGS Unit 1, Rev. 3

ES-15.008, Units 1 & 2 Degraded Grid Study, Rev. 5

ES-15.009, Essential Controls lnverter Load Study for PSEG SNGS Units 1 & 2, Rev. 10

ES-15.014, Motor Running During LOCA Block Start, Rev. 3

S-1-ABV-MDC-2050, Salem Unit 1 Auxiliary Building Temperature Calculation - Normal and

Emergency Modes, Rev. 2

S-1-AUX-MDC-1714, Pipe Break Pressures in TDAFWP Enclosure and Adjacent Areas, Rev. 0

S-1-CAV-MDC-1361, Unit 1 SPAV Return/Exhaust Fan Pressure Drop Calculation, Rev. 0

S-1-CAV-MDC-1834, Salem Unit 1, Switchgear and Penetration Area Ventilation System

(SPAVS) - Gothic Model, Rev. 0

S-1-DGV-MDC-0661, Diesel Generator Area Ventilation System Equipment Assessment

Capability, Rev.3

S-1-DGV-MDC-1227, D/G Area Heat Gain and Loss / Equip Capability Calc., Rev. 1

S-2-AUX-MDC-1627 , Pipe Break Pressures in Aux. Bldg. Rooms, Rev' 0

S-2-CAV-MDC-0687, Unit 2 - EACS Duct Negative Pressure Calculation, Rev. 1

S-2-CC-MDC-0898, 22CC16 MIDAS Calculation, Rev. 0

S-C-4KV-JDC-959, Degraded Vital Bus Undervoltage Setpoint, Rev. 5

S-C-AF-MDC-0432, Auxiliary Feedwater Pump NPSH, Rev. 1

S-C-AF-MDC-0445, Auxiliary Feedwater System Hydraulic Analysis, Rev' 3

S-C-AF-MDC-1421, Pressure in TDAFW Pump Enclosure Due to Pipe Break, Rev. 2

S-C-AF-MDC-1789, Salem Auxiliary Feedwater Thermal Hydraulic Flow Model, Rev. 1

S-C-AF-MEE-0262, Auxiliary Feedwater Pump Turbine Speed Control, dated 4118189

S-C-AUX-MDC-0737, Loss of Ventilation During Station Blackout, Rev' 3

S-C-DF-MDC-0852, Fuel Oil System - Design Calculation of System Parameters, Rev. 0

S-C-DGO12-01, Salem Units 1 & 2 Diesel Generator Starting Air Pressure, Rev. 3

S-C-DG-MEE-1111, Thermal Operating Modes - Diesel Starting Air, Booster Air and Jacket

Water Systems, Rev. 0

S-C-DG-MEE-1136, Jacket Water Heat Exchanger Freezing Resolution, Rev.1

S-C-F400-MSE-083, Use of Sea Water or Brackish Water for Emergency Cooling of Steam

Generator, Salem Generating Station Units No. 1 & 2, Rev. 1

S-C-SJ-MDC-0892(015), MOV Capability Assessment for 12SJ45-MTRY, Rev. 1

S-C-SW-MDC-1068, Service Water Design Basis Temperature, Rev. 4

S-C-SW-MDC-1317, Service Water System Hydraulic Model, Rev. 7

S-C-SW-MDC-1350, Service Water System Mode Ops Analysis, Rev. 8

S-C-SW-MDC-1351, Service Water Pump NPSH Calculation, Rev. 2

S-C-SW-MDC-1422, Service Water Pump Surveillance Test Error Analysis, Rev. 0

S-C-SW-MDC-1967, Service Water System Thermal Hydraulic Model, Rev. 5

S-C-SW-MEE-1449, Evaluation of Increased CFCU Service Water Flow Setpoints, Rev. 1

S-C-SWV-MDC-1356, SWIS Ventilation Calculation, Rev. 1

S-C-SWV-MDC-1512, Salem Nuclear Generating Station - Heating Load for Service Water

Intake Structure, Rev. 0

S-C-VAR-EEE-1057, Tabulation of Molded-Case Circuit Breakers and Parameters, Rev. 2

S-C-ZZ-SDC-1419, Salem Generating Station Environmental Design Criteria, Rev. 3

SR-101, Crane Valves Seismic Weak Link Analysis Report, Rev. 1

Corrective Action Notifications (NOTFs)

20168479 20394813 20460490 20491019 20495392. 20496353. 2049706Q*

20169662 20397611 20464648 20491741 20495396. 2Q496357. 20497061.

264954 20400099 20464734 20493883. 20495443* 20496386. 20497062.

2A282385 20403116 20466242 20493983 20495521 20496387. 20497115

284428 20408830 20466837 20494000. 20495538 20496388. 20497137.

20330961 20408831 20469186 20494082 20495595. 20496427. 20497138.

20332386 20408862 20469187 20494176. 20495611* 20496442. 20497182.

20337290 20416141 20469339 20494178 20495623 20496443. 20497183-

20337561 20416513 20470034 20494249* 20495812. 20496447. 20497218-

20339257 20422047 20472585 20494394* 20495854 20496543. 20497231-

20341869 20424568 20473208 20494396. 20495862" 20496548. 20497232.

20345322 2A429349 20474064 2049440Q* 20495863. 20496549. 2Q497275*

20351872 20429400 20476554 20494419* 20495864* 20496550. 20497341.

20352959 20431538 20477228 20494436 20495871* 20496551* 20497352.

20353591 20432597 20478230 20494513. 20496019. 20496622. 20497353.

20354465 20440000 20479564 20494554 20496020. 20496736. 20497355-

20356789 20444609 20479601 20494664 20496035 20496754. 20497371*

20358763 20445377 20479919 20494761* 20496041* 20496798* 20497396.

20363981 20445661 20485362 20494800. 20496062 20496800. 20497424*

20379126 20446268 20486530. 20494839. 20496070* 20496839. 20497934*

20381679 20446384 20489914 20494841. 20496082. 20496872. 20497938*

20381920 20446524 20489453 20494962. 20496119. 20496883. 20497940*

20381958 20447784 20489462 20495066. 20496123* 20496887. 20497941*

20382478 20450241 20489645 20495075. 20496234 20496906. 20497969-

20382938 20453137 20490588 20495105. 20496285* 20496937 20498002*

20385267 20456681 20490589 20495179" 20496331* 20496967*

20386793 20458263 2Q490768 20495181 20496332. 20496968

20391738 20458711 20490862 20495313 20496340. 20496996-

20392497 20460413 20491018 20495355. 20496347 20497052

• NOTF written as a result of this inspection

Corrective Action Evaluations

70040435 70079173 70090266 70102904 7Q110427

70056740 70079262 70093360 70105418 70110524

70069050 70079691 70091842 70106127 70113625

70072247 70082753 700941 38 70106627 70118474

70072586 70083232 70098491 701 07090 701 1 9080

70074317 70087401 70100726 701 0881 4

70075247 70088076 701 01 803 701 08961

70078104 70088081 70102729 701 09280

70078541 7008881 1 70102769 70110141

Desiqn & Licensinq Bases

Letter from PSEG "Response to NRC Bulletin 88-04," dated 8111188

NLR-N94007, Request for License Amendment, dated 3128194

NRC Letter

L.N. Olshan to L.R. Eliason PSEG, License Amendments 162 and 148, dated

2t12194

Safety Evaluation Report by the Directorate of Licensing US Atomic Energy Commission in the

Matter of PSE&G, PECO, Delmarva Power and Light, and Atlantic City Electric

Company Salem Nuclear Generating Station Units 1 and2, dated October 11,1974

Drawinqs

2OSOOO-S-8789-53, No. 1 and No. 2 Units Generators & Main Transformers One-Line Control

Diagram, Rev.53

203002-A-8789-34, No. 1 Unit 4160V Vital Buses One Line, Rev. 34

203003-A-8789-45, No. 1 Unit 460V and 230V Vital & Non Vital Bus One-Line Control Diagram,

Rev.45

203318-8-9781, No. 1 & 2 Units Aux Feedwater System No. 13 & 23 Aux. Feed Pump &

Turbine, Rev. 11

203319-8-9781, No. 1 Unit Aux Feedwater System No. 13 Aux. Feed Pump & Turbine, Rev. 23

203414-ABL-596, No. 1 & 2 Units Aux Feedwater System Inlet Valve Controls, Rev. 2

205203-A-8760-77 Sh. 1, No. 1 Unit Main, Reheat & Turbine Bypass Steam, Rev' 77

205234-A-8761-47 , Unit 1 Safety Injection, Rev. 47

205236-A-8761, No. 1 Unit Auxiliary Feedwater, Rev. 56

205241-A-8761 Sh. 3, No. 1 & 2 Units Diesel Engine Auxiliaries, Rev. 43

205242-A-8761-93 Sh. 2, Unit 1 Service Water Nuclear Area, Rev' 85

205248-A-8761 Sh. 2, No. 1 Unit Aux. Bldg. Control Area AC & Ventilation, Rev. 48

205248-A-8761-35, No. 1 Aux Bldg ControlArea Air Conditioning & Ventilation, Rev. 35

205321-A-8762-22 Sh. 1, No. 1 Unit Auxiliary Building Diesel Generator & Fuel Handling Area

Ventilation, Rev.22

205321-A-8762-22 Sh. 3, No. 1 Unit Auxiliary Building Diesel Generator & Fuel Handling Area

Ventilation, Rev.22

205331-4-8763 Sh. 1, No. 2 Unit Component Cooling, Rev. 52

205331-4-8763 Sh. 2, No. 2 Unit Component Cooling, Rev. 38

205331-4-8763 Sh. 3, No. 2 Unit Component Cooling, Rev. 35

205348-A-8763, No. 2 Unit Aux. Bldg. Control Area Air Conditioning & Ventilation, Rev. 37

205702-A-8939, No. 1 Unit - Auxiliary Building ACS No. 12 Component Cooling Heat

Exchanger Arrangement Panel 204-123 Controls, Rev. 24

207909-4-1777-23, No. 1 Unit Auxiliary Building 1C Diesel 230V Vital Control Ctr. One Line

Diagram, Rev.23

211348 B 9483, No. 1 and No.2 Units 1B and 28 28VDC Buses, Rev. 16

1350-8-951 1 , No. 1 Unit - Control Area l BDE 28VDC Distribution Cabinet, Rev. 1 1

211357-8-9511, Sh, 1, No. 2 Unit 28 Volt DC One Line, Rev. 14

211357-8-951 1, Sh. 2, No. 2 Unit 28 Volt DC One Line, Rev. 12

211358-8-951 1, No. 1 Unit - Control Area l DDE 28VDC Distribution Cabinet, Rev. 6

211370-A-8859-42, No. 1 Unit 115V Control System, Rev. 42

2115A18583-15 Sh. 2, No. 1 Unit Residual Heat Removal Sys. No. 21 Residual Heat Removal

Pump -

D.C. Schematic, Rev. 15

211753-A-8862-12, Service Water lntake Structure Plan, Rev. 12

2480-A-1778, No. 2 Unit - Auxiliary Building 2A Diesel 230V Vital Control Ctr. One-Line

Diagram, Rev.25

23689-B-979Q-22, No. 1C and 2C Diesel Generators Console Control Sheet 3, Rev. 22

23690-A-9790-30, No. 1C Diesel Generators Engine-Engine Control, Rev. 30

23825-9-9789, No. 1 and 2 Units - No. 1,A and 2A Diesel Generator 230V Vital Control

Center, Rev. 18

23832-8-9789-14, No. 1C Diesel Generator 230V Vital Control Center, Rev. 14

23833-8-9789-23, No. 1C Diesel Generator 230V Vital Control Center, Rev. 23

233661-8-3012 Sh. 2, No. 1 & 2 Units ControlArea A.C. No. 11 & 21 Emergency Supply Fan

Schematic, Rev. 7

238083-8-9635-6, No. 1 Unit Auxiliary Building Diesel Generator Area Ventilation, Rev. 6

2002-8-9946, No. 1 Unit - Aux. Bldg. Service Water System No. 12A & 128 Component

Cooling Heat Exchanger Inlet & Outlet Control Valves, Rev. 5

601233-8-9528-22, No. 1 Unit Auxiliary Bldg. Control Area 1C - 460V Vital Bus One-Line

Diagram, Rev.22

601243-8-9528-21, No. 1 Unit Auxiliary Bldg. Control Area 1C - 230V Vital Bus One-Line

Diagram, Rev.22

DW

G. 123934, Min Flow Orifice, Rev. B

DW

G. 147153,13 &23 Min-Flow Orifice Capacity Curve, Rev. 0

DWG 237088-D-4262, No. 1 Unit Aux Bldg. Main Steam to Aux. Feedwater Pump

Encapsulation Details, Rev. 7

WD 135830, Main Steam Parallel Slide Stop Valve, Rev. E

Enqineerinq Evaluations

70029296, Lack of Winter Readiness at Salem Root Cause Evaluation, dated 1127103

70055065, 15 SW Pump Trip due to Loss of Cooling Water Apparent Cause Evaluation, dated

7t21t06

70083232,25 Service Water Pump Strainer (S2SW -2SWE1 1) Tripped due to Binding Caused

by Foreign MaterialApparent Cause Evaluation, dated 3l25lOB

70106627, CW Screen lcing - Plant Trip Root Cause Evaluation, dated 3117110

A-}-ZZ-SEE-1160, Establishment of Requirements for Monitoring the Condition of Structures,

Rev. 1

DCP 80097745, Online MOV Upgrades for 22CC16, Rev. 0

Design Change 80102246, Update Trip Analysis A-5-500-E4C-0-1930, Rev. 0

NC.PM-AP .ZZ-0724 Form 1 02-2525, Hydraulic Operator for MSIV Valve Commercial Grade

Item Dedication Evaluation, Rev. 0

ND.DE.TS.ZZ-2021, Engineering & Plant Betterment Technical Standard - AC Power Cable

Selection and Sizing, Rev. 0

Op Eval No.10-023, Units 1 & 2 ControlArea Ventilation (CAV) Operability Evaluation, Rev. 0

S-2-SJ-MEE-0693, Evaluation for Determination of Torque Switch Settings and Thrust/Torque

Limits for Salem Motor Operator 21SJ45, Rev. 0.

S-C-230-E4C-0-0753, Evaluation of 230V Motor Operation During Degraded Grid Conditions,

dated 5/18/93

S-C-4KV-E4C-0-1792, Assessment of Salem Bus Transfer Capability (as a result of 7129103

failure), Rev.0

S-C-4KV-E4C-0-1795, Establishment of New Lower Voltage Limit for Vital Buses at Salem

Stations, Rev. 1

SO 10-012, Control Room Habitability Common Unit Standing Order, dated 10118110

Functional. Surveillaqce and Modification Acceptance Testinq

Locked Vafve Surveillance (Lineup 700 & 728), performed 1123111

NCS Corporation Control Room Envelope ln-Leakage Testing at Salem Nuclear Generating

Station 2010, dated 10110110

S1-OP-ST.AF-0007, Inservice Testing Auxiliary Feedwater Valves-Mode 3, performed 413110

S1.OP-ST.DG-0001, 1A Diesel Generator Surveillance Test, performed 9127110,10127110 and

10125110

S1.OP-ST.DG-0002, 1B Diesel Generator Surveillance Test, performed 1113110

51.OP-ST.DG-0003, 1C Diesel Generator Surveillance Test, performed 1119110 and 1/18111

S1.OP-ST.DG-001 4, 1C Diesel Generator Endurance Run, performed 5112110

S1.OP-ST.RP1-0003, lST, Remote Position Verification, Cold Shutdown, performed 4l23l1O

S1.OP-ST-SJ-0005, Inservice Testing, Safety Injection Valves, Modes 5-6, performed 4117l10

S1.RA-ST.CAV-0001, Control Room Emergency Ventilation System Surveillance Testing,

performed 9/1 6/09 and 7 130110

S2.OP-ST.CC-0004, Inservice Testing Component Cooling Valves, performed 9117110 and

2t22t10

2.OP-ST.DG-0001, 2A Diesel Generator Surveillance Test, performed 10128110 and 1 1/3/10

S2.OP-ST.DG-0002, 28 Diesel Generator Surveillance Test, performed 1117110 and 2110111

S2.OP-ST.DG-0003, 2C Diesel Generator Surveillance Test, performed 11117110 and 2117111

2.OP-ST.MS-0003, Steam Line lsolation & Response Time Testing, performed 11111109

2.OP-ST.RPl-0001, IST - Remote Position Verification - Aux Bldg, performed 10/30/09

S2.OP-ST.SW-0001, Inservice Testing 21 Service Water Pump, performed 7129110 & 10129110

S2.RA-ST.CAV-0003, Unit 2 Control Room Emergency Air Conditioning System (EACS)

Surveillance Testing, performed 7 1261 1 0

SC.MD-FT.28D-0002, 28 Volt Station Batteries Performance Discharge Test Using BCT-2000,

performed 4126104

SC.MD-FT.28D-0003, 28 Volt Station Batteries Performance Discharge Test Using BCT-2000

with Windows Software and Associated Surveillance Testing, performed 10128108

SC.MD-PM.DG-0032, Periodic Diesel lnspection - 1C Diesel Generator Compression and Firing

Pressures and Temperatures, performed 417110

SC.OP-ST.CAV-0001, Plant Systems Control Room Ventilation, performed 11113110

SC.OP-ST.CAV-0002, Control Room Emergency Air Conditioning System, performed 12119110

SC.OP-ST.CAV-0003, Control Room Emergency Air Conditioning System Manual Actuation,

performed 11113110

Miscellaneous

70114268, AFW MR 41 Action Plan, dated 115111

80099009, EAC PRA/MSPI Upgrade Project, Rev. 3

ACIT 70069315-010, PCM Template Review for Low Voltage Circuit Breakers, undated

ET232 (AnchorlDarling), Max Thrust & Seismic Analysis, Rev. 0

Handbook of Hydraulic Resistance, Second Edition

MA-AA-716-210-1001 Expansion Joint PCM Template, dated 1122107

NEMA Standard AB-4-2003, Guidelines for Inspection and Preventive Maintenance of Molded

Case Circuit Breakers Used in Commercial and IndustrialApplications, Revised 2003

OP-SH-111-101-1001, Salem 1 and Salem 2 Narrative Log, dated 112110 - 114110 and 1l22l1o -

24110

P2-0437927, 18 28VDC Battery Purchase Order, dated 213199

PSBP 313969, Design & Seismic Report E-1522 - MSIV Seismic Analysis, Rev. 3

SC.OP-DL .ZZ-0008 Attachment 1, Circulating/Service Water Log, dated 12128109 - 1l10l1O and

1t17111 - 1130111

SO-08-021, Component Cooling Heat Exchanger Operation Temporary Standing Order, dated

10/30/08

T-33452-1, Byron Jackson 13 Auxiliary Feedwater Certified Pump Test, dated 211173

Normal and Special (Abnormal) Operations Procedures

S1.OP-AB.CA-001, Loss of ControlAir, Rev. 18

S1.OP-AB.GRID-0001, Abnormal Grid, Rev. 19

51.OP-AB.SSP-0001, Local Reset of ESF Actuation, Rev. 0

51.OP-DL.ZZ-0005-F1, Unit 1 Secondary Plant Log, Rev. 3

51.OP-DL.ZZ-0006-F1, Unit 1 Primary Plant Log, Rev. 1

51.OP-SO.4KV-0001 ,1A4KV Vital Bus Operation, Rev.26

51.OP-SO.4KV-0002, 1B 4KV Vital Bus Operation, Rev. 33

S1.OP-SO.4KV-0003, 1C 4KV Vital Bus Operation, Rev. 29

51.OP-SO.4KV-0004, lE 4KV Bus Operation, Rev. 11

S1.OP-SO.4KV-0005 , 1F 4KV Bus Operation, Rev. 18

51.OP-SO.4KV-0006, 1G 4KV Bus Operation, Rev. 1 1

51.OP-SO.4KV-0007, 1H 4KV Bus Operation, Rev. 16

51.OP-SO.4KV-0008, 4KV Group Buses Power Supply Transfer, Rev. 10

S1.OP-SO.4KV-0009, 1CW 4KV Bus Operation, Rev. 15

Sl .OP-SO.4KV-001 0, Miscellaneous Transformer Operation, Rev. 2

S1.OP-SO.AF-OOO1, Auxiliary Feedwater System Operation, Rev. 28

S1.OP-SO.PC-0001, Switchgear and Penetration Area Ventilation Operation, Rev. 17

51.OP-ST.4KV-0001, Electrical Power Systems 4KV Vital Bus Transfer, Rev. 13

S1.OP-ST.4KV-0002, Electrical Power Systems AC Distribution, Rev. 22

51.OP-ST.AF-0003, Inservice Testing - 13 Auxiliary Feedwater Pump, Rev. 40

S1-OP-ST.AF-0007, Inservice Testing Auxiliary Feedwater Valves-Mode 3, Rev. 20

S1.OP-ST.AF-0008, Auxiliary Feedwater Valve Verification Mode 1-3, Rev. 3

S2.OP-AB.CAV-001, Loss of Unit 2 Control Area HVAC, Rev' 3

2.OP-AB.LOOP-0001, Blackout Coping Actions, Rev. 23

S2.OP-AB.SW-0001, Loss of Service Water Header Pressure, Rev' 16

S2.OP-AR .ZZ-0002, 21 -23 SW SCRNWSH TRBL, Rev. 35

S2.OP-AR.ZZ-0007, Overhead Annunciators Window G, Rev' 46

2.OP-SO .500-0125, SBO Diesel-Vital Battery Chargers, Rev. 0

2.OP-SO.SW-0001, Service Water Pump Operation, Rev. 24

S2.OP-SO.SW-005, Service Water System Operation, Rev. 40

S2.OP-ST.SSP-0002, SEC Mode OPS Testing 24 Vital Bus, Rev' 32

SC.OP-AB .ZZ-0001, Adverse Environmental Conditions, Rev. 1 3

SC.OP-PT.500-0125, SBO Diesel- Vital Battery Chargers, Rev' 0

SC.OP-PT.ZZ-002, Station Preparation for Seasonal Conditions, Rev. 11

SC.OP-SO.CAV-0001, Control Room Envelope Breach, Rev. 1

SC.OP-ST.CAV-0002, Control Room Emergency Air Conditioning System, Rev. 3

SC.OP-ST.CAV-0003, Control Room Emergency Air Conditioning System Manual Actuation,

Rev.2

Operatinq Experience

70106895, PSEG Response to NRC lN 2010-03, dated 5110110

MEC-91-565, GL 89-13 Action ltem 11, dated 5112191

NRC Generic Letter No. 2003-01: Control Room Habitability, dated 6112lO3

NRC Generic Letter No. 83-28: Required Actions Based on Generic lmplications of Salem

ATWS Events, dated 718183

NRC lnformation Notice 86-76: Problems Noted in Control Room Emergency Ventilation

Systems, dated 8128186

NRC lnformation Notice 96-36: Degradation of Cooling Water Systems Due to lcing, dated

6112196

NRC lnformation Notice 2008-02: Findings ldentified During Component Design Bases

Inspections, dated 31 19108

PSEG GL 89-13 Response White Paper, 2005

Westinghouse TB-04-13, Replacement Solutions for Obsolete Classic Molded Case Circuit

-Breakers,

UL Testing lssues, Breaker Design Life and Trip Band Adjustment, dated

28104

Operator Traininq

NOS05460VAC-06, 460/230VAC Electrical, Rev. 6

NOS0SCAVENT, ControlArea Ventilation System Lesson Plan, Rev. 8

NOS05CCW000, Component Cooling Water Lesson Plan, Rev. 6

NOSO5DCELEC-06, DC Electrical Systems, dated 118110

NOS05ECCS00-04, Lesson Plan, Emergency Core Cooling System, dated 5l22l13

NOS05EDG000, Emergency Diesel Generators Lesson Plan, Rev. I

NOSOSMSTEAM-O7, Lesson Plan, Main Steam, dated 3l23log

NOS05SPAV00-05, Lesson Plan, Switchgear and Penetration Area Ventilation (SPAV) System,

dated 3123107

NOSg5SWBAYS-14, Lesson Plan, Service Water System - Intake Bays, dated 9/18/09

Preventive Maintenance and Inspections

A-1-ZZ-SEE-1160, Condition Monitoring of Structure (Unit 1 & Unit 2 Auxiliary Building),

performed 6121196

Predict OilAnalysis, 1DAE38 #1C EDG, sampled on 12117110

Predict OilAnalysis, 1DAE4 #1AEDG, sampled on9127l1O

S2SW-2SWE1-MTRD, Service Water Pump, Motor Upper Bearing OilAnalysis, dated 7127110

S-lR-6S0-0023, Falcon Power Inc. Groundwater Intrusion lnspection Report Salem Generating

Station Units 1 & 2, dated 1128109

SC.MD-PM.DG-0032, Periodic Diesel Engine Inspection Maintenance, performed 10124108

SC.MD-PM.ZZ-0118, Valve Stem Lubrication for Motor Operated Rising Stem Valves,

performed 1111103

Procedures

CC-AA-204, Control of Vendor Technical Documents, Rev. 10

CC-M-204-1001, PSEG Nuclear Vendor Technical Document Recontact Process, Rev. 2

ER-AA-310-1009, Condition Monitoring of Structures, Rev' 1

ER-AA-390-1001 Attachment 2, CRE Boundary Control and Maintenance, Rev. 1

MA-AA-716-230-1001, Oil Analysis Interpretation Guideline, Rev. 7

MA-AA-723-300, Diagnostic Testing & lnspection of Motor Operated Valves, Rev. 5

MA-AA-723-301, Periodic Inspection of Limitorque Model SMB/SB/SBD-000 through 5 Motor

Operated Valves, Rev. 7

MA-AA-723-300-1004, Quiklook Diagnostic Test EquipmenVSensor Guideline, Rev. 4

MA-AA-723-302, lnstallation and Checkout of Quick Stem Sensor (QSS) on Valve Stems,

Rev.4

OP-AA-1 08-107 -1001, Electric System Emergency Operations and Electric Systems Operator

Interface, Rev. 3

S1 . RA-ST.AF-0003, Inservice Testing 12 Auxiliary Feedwater Pump Acceptance Criteria,

Rev. 19

S1.RA-ST.DG-0003, 1C Diesel Generator Surveillance Test Acceptance Criteria, Rev. 6

S1.RA-ST.SJ-0005, Inservice Testing, Safety Injection Valves Modes 5-6, Acceptance Criteria,

Rev.7

S2.M-ST.SW-0001, lnservice Testing - 21 Service Water Pump Acceptance Criteria, Rev. 10

SC.MD-FT.28D-0003, 28 Volt Station Batteries Performance Discharge Test Using BCT-2000

with Windows Software and Associated Surveillance Testing, Rev. 3

S1.MD-F

T. 4KV-0002, ESFAS lnstrumentation Monthly Functional Test 1B 4KV Vital Bus

Undervoltage, Rev.26

SC.MD-;S.4KV-0001, 4KV and 13KV Magne-Blast Circuit Breakers Inspection and Test,

Rev.24

SC.MD-PM.115-0001 ,10112 KVA Vital Instrument Bus lnverter Preventive Maintenance,

Rev. 12

SC.MD-pM.230-0003, 230 and 460 Volt ABB K-Line Circuit Breaker Preventive Maintenance,

Rev.5

SC.MD-PM .ZZ-0005, Molded Case Circuit Breaker Maintenance, Rev' 4

SC.MD-ST.230-0001, 230 and 460 Volt ITE K-Series Circuit Breaker Overload Test, Rev. 22

SC.MD-ST.230-0002, 230 and 460 Volt ITE K-series Circuit Breaker Solid State Overload Trip

Device Test, Rev. 11

SC.MD-ST.230-0003, 230 and 460 Volt ABB K-Line Circuit Breaker Refurbishment, Rev. 24

SC.MD-ST.28D-0001, Preventive Maintenance and 18 Month Surveillance of 28 Volt Station

Battery Chargers, Rev. 16

SC.MD-ST.28D-0003, Quarterly Inspection and Preventive Maintenance of 28 Volt Vital

Batteries, Rev. 13

SC.MD-ST.28D-0005, Annual Inspection and Surveillance of Unit 1 and 2 28 Volt Vital

Batteries, Rev. 2

SC.MD-ST.28D-0006, 28 Volt Station Batteries 18 Month Service Test Using BCT-2000 with

Windows Software and Associated Surveillance Testing, Rev. 2

SC.MD-ST.CAV-0002, ControlArea Ventilation Tracer Gas Test, Rev' 0

SC.MD-ST .ZZ-QOO3,Inspection and Preventive Maintenance of Unit 1, 2, and 3 Batteries,

Rev.30

SH.IC-GP.ZZ-OOO2, Disassembly, Inspection, Reassembly and Testing of Masoneilan Model

37138 Air Operated Actuators, Rev. 10

Risk and Marqin Manaqement

Post+ittator Calcuiation 41, Operator Fails to open TDAFW pump Room Door for SBO, dated

28102

Post-lnitiator Calculation A51, Operator Fails to lncrease Outdoor Intake Upon Loss of Chiller,

dated 10/5/09

Risk-lnformed Inspection Notebook for Salem Generating Station, Revision 2.1a

Salem Low Margin lssues Database, dated 11116110

SA-SURV-oO3, Risk Assessment of Missed Surveillance - 1B 28VDC Battery, Rev. 0

SCG-PRA-OOS.03, Safety lnjection System Notebook, Rev.0

SCG-PRA-O0S.07, Containment lsolation System Notebook, Rev.0

SCG-PRA-O0S.13, SW System Notebook, Rev. 0

SCG-PRA-00S.16, ControlArea Ventilation System Notebook, Rev. 0

Svstem Health. Svstem Walkdowns, and Trendinq

ALx Feedwate- eump Quarterly IST Results, completed 5112104 through 12112110

Volt DC System Health Report, 4'".QTR 2010

115 Volt AC System Health Report, 4'" QTR 2010

DG/DF/DGV - 5112, Units 1 and 2 EDG System Walkdown Record, performed 618110 and

2115110

ER-AA-2030 Attachment 4, System Walkdown Unit 1 11112 RHR, performed 3/6/08 &717108

ER-M-2030 Attachment 4, System Walkdown Unit 221122 RHR, performed 6/9/08

S2.OP-SJ-0003 Valve Test Trend Report for 2SJ1, dated 10124109 - 12113110

Unit 1 and Unit 2 Main Steam System Health Report, 4tn QTR 2010

Unit 1 and Unit 2 Safety lnjectioh System Health Repott, *tn QTR 2010

Unit 1 and Unit 2 Service Water System Health Report,4"'QTR 2010

Unit 1 ControlArea Ventilation System Health Report, 4'n QTR 2010

Vendor Technical Manuals

WO PlAO1, AC & DC Low Voltage Swgr & Components, Rev' 36

tlTD 123810, Instruction Manual for 28V 150A ARR24HK150F3 Battery Charger, dated 1/70

WD 127877, 4kV GRP and Vital Bus Switchgear, Rev. 25

VTD 140319, Hopkinson LTD, Main Steam lsolation Valve, Rev' 17

VTD 142905, Buffalo Forge, Ventilation Fans, Rev. 8

\f[D 174547 , Terry Turbine Manual, Rev. 21

y1D 301103, ALCO Power Inc., Manual - Installation, Operation, Maintenance for Diesel

Generator Package Model #18-251, May 1972

y1D 309448, C&D Technologies, Inc. Standby Battery Vented Cell Installation and Operating

Instructions, dated 7 125191

WD 31 1353, Vital UPS 1A 1B 1C 1D Essential UPS 1 1 & 12, Rev. 2

WD 313629, Anchor/Darling, 8" Valves, Rev. 3

\ftD 314442, ASCO Automatic Switch, dated 9113191

VTD 315837, Ventilation Fans, Rev. 2

VTD 320408, Johnston Pump, Service Water Pumps, Rev. 9

WD 322428, JOY Technologies Inc., MIVANE Fan Operators Handbook, Rev. 0

Work Orders

30002655 301 31 860 30154517 30202321 501 1 8055 60078308 60094002

30002895 301 32485 301 5451 8 40004291 501 1 8302 60080030 60094003

30003743 301 33097 301 5451 9 40023245 50121289 60081 1 53 60095055

30004291 301 381 57 301 55659 40023934 501 21 539 60083077 60095056

30043865 301 4601 4 30155672 50001404 501 34367 60084432 80099125

30068464 301 50255 30163930 50003785 501 35836 60086705 801 01 386

30083816 301 50256 301 67996 50003793 501 37303 60086891 801 02898

30085402 30151297 30168812 50003802 50137722 60088093 801 02965

30089041 30153294 30174495 50003807 50137770 60091475 80102966

30102967 301 54030 30174496 500091 36 60052430 60093670 93071 31 59

301 09871 301 54031 30174497 50Q75712 60063439 60093958 961007218

301 26589 301 54032 301 86623 501 08975 60074863 60093975 990122200

301 30954 30154516 302001 68 50112662 60074984 60093976

LIST OF ACRONYMS

AC Alternating Current

ADAMS Agency-Wide Documents Access and Management System

AFW Auxiliary Feedwater

AOP Abnormal Operating Procedure

AOV Air Operated Valve

CAP Corrective Action Program

CAV Control Area Ventilation

CCW Component Cooling Water

CDBI Component Design Bases Inspection

CFCU Containment Fan Cooling Unit

CFR Code of Federal Regulations

CM Corrective Maintenance

CRE Control Room Envelope

CREACS Control Room Emergency Air Conditioning System

DC Direct Current

DFOTP Diesel Fuel OilTransfer PumP

DRS Division of Reactor Safety

DVR Degraded Voltage Relay

EDG Emergency Diesel Generator

EOP Emergency Operating Procedure

EQ Environmental Qualification

GL Generic Letter

HCGS Hope Creek Generating Station

HELB High Energy Line Break

HEPA High Efficiency Particulate Air

HVAC Heating Ventilation and Air Conditioning

HX Heat Exchanger

IA lnstrument Air

rMc Inspection Manual Chapter

IN lnformation Notice

IP Inspection Procedure

IST ln-Service Test

LERF Large Early Release Fraction

LOCA Loss-of-Coolant Accident

LOOP Loss-of-Offsite Power

MCC Motor Control Center

MCCB Molded Case Circuit Breaker

MOV Motor Operated Valve

MR Maintenance Rule

MSIV Main Steam lsolation Valve

NCV Non-Cited Violation

NOS Nuclear Oversight

NOTF Notification

NPSH Net Positive Suction Head

NRC Nuclear Regulatory Commission

OE Operating Experience

OpESS Operating Experience Smart Sample

PARS Publicly Available Records

PCM Performance Centered Maintenance

PM Preventive Maintenance

PMCR Preventive Maintenance Change Request

PRA Probabilistic Risk Assessment

PSEG Public Service Enterprise Group Nuclear LLC

QSS Quick Stem System

RAW Risk Achievement Worth

RHR Residual Heat Removal

RRW Risk Reduction Worth

RWST Refueling Water Storage Tank

SBO Station Blackout

SDP Significance Determination Process

SI Safety lnjection

SPAR Standardized Plant Analysis Risk

SPAV Switchgear and Penetration Area Ventilation

SR Surveillance Requirement

SRA Senior Reactor Analyst

SSC Structure, System, and Component

SSPS Solid State Protection System

SW Service Water

TDAFW Turbine Driven Auxiliary Feedwater

TDH Total Dynamic Head

TS Technical Specification

UFSAR Updated Final Safety Analysis Report

Volt

Attachment