IR 05000272/2014002

IR 05000272-14-002, 05000311-14-002; on 01/01/2014 - 03/31/2014; Salem Nuclear Generating Station Units 1 and 2; Fire Protection, Maintenance Risk Assessments and Emergent Work Control, Post-Maintenance Testing, Problem Identification and R

ML14132A020
Person / Time
Site:	Salem
Issue date:	05/09/2014
From:	Glenn Dentel Reactor Projects Branch 3
To:	Joyce T Public Service Enterprise Group
DENTEL, GT
References
IR-14-002
Download: ML14132A020 (64)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION

REGION I

2100 RENAISSANCE BLVD., SUITE 100 KING OF PRUSSIA, PA 19406-2713 May 9, 2014 Mr. Thomas President and Chief Nuclear Officer PSEG Nuclear LLC - N09 P.O. Box 236 Hancocks Bridge, NJ 08038 SUBJECT: SALEM NUCLEAR GENERATING STATION, UNIT NOS. 1 AND 2 -

NRC INTEGRATED INSPECTION REPORT 05000272/2014002 AND 05000311/2014002

Dear Mr. Joyce:

On March 31, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Salem Nuclear Generating Station, Units 1 and 2. The enclosed inspection report documents the inspection results, which were discussed on April 10, 2014, with Mr. John Perry, Salem Site Vice President, and other members of your staff.

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

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

This report documents four NRC-identified findings and three self-revealing findings of very low safety significance (Green). Five of these findings were determined to involve violations of NRC requirements. Additionally, a licensee-identified violation, which was determined to be of very low safety significance, is listed in this report. However, because of the very low safety significance, and because they are entered into your corrective action program, the NRC is treating these findings as non-cited violations, consistent with Section 2.3.2.a of the NRC Enforcement Policy. If you contest the non-cited violations 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 Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region I; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at Salem Nuclear Generating Station. In addition, if you disagree with the cross-cutting aspect assigned to any finding, or a finding not associated with a regulatory requirement in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region I, and the NRC Resident Inspector at Salem Nuclear Generating Station.

Additionally, as we informed you in the most recent NRC integrated inspection report, cross-cutting aspects identified in the last six months of 2013 using the previous terminology were being converted in accordance with the cross-reference in Inspection Manual Chapter 0310. Section 4OA5 of the enclosed report documents the conversion of these cross-cutting aspects which will be evaluated for cross-cutting themes and potential substantive cross-cutting issues in accordance with Inspection Manual Chapter 0305 starting with the 2014 mid-cycle assessment review. If you disagree with the cross-cutting aspect assigned, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region I, and the NRC Resident Inspector at Salem Nuclear Generating Station.

In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390 of the NRCs Rules of Practice, a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRCs Public Document Room or from the Publicly Available Records component of the NRCs Agencywide Documents Access and Management System (ADAMS). ADAMS is accessible from the NRC website at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Glenn T. Dentel, Chief Reactor Projects Branch 3 Division of Reactor Projects Docket Nos. 50-272, 50-311 License Nos. DPR-70, DPR-75

Enclosure:

Inspection Report 05000272/2014002 and 05000311/2014002 w/Attachment: Supplementary Information

REGION I==

Docket Nos. 50-272, 50-311 License Nos. DPR-70, DPR-75 Report Nos. 05000272/2014002 and 05000311/2014002 Licensee: PSEG Nuclear LLC (PSEG)

Facility: Salem Nuclear Generating Station, Units 1 and 2 Location: P.O. Box 236 Hancocks Bridge, NJ 08038 Dates: January 1, 2014 through March 31, 2014 Inspectors: P. Finney, Senior Resident Inspector A. Ziedonis, Resident Inspector R. Nimitz, Senior Health Physicist J. Schoppy, Senior Reactor Inspector R. Barkley, Senior Project Engineer E. Burket, Emergency Preparedness Inspector Approved By: Glenn T. Dentel, Chief Reactor Projects Branch 3 Division of Reactor Projects Enclosure

SUMMARY

Inspection Report (IR) 05000272/2014002, 05000311/2014002; 01/01/2014 - 03/31/2014;

Salem Nuclear Generating Station Units 1 and 2; Fire Protection, Maintenance Risk Assessments and Emergent Work Control, Post-Maintenance Testing, Problem Identification and Resolution.

This report covered a three-month period of inspection by resident inspectors and announced inspections performed by regional inspectors. Inspectors identified five non-cited violations (NCVs) and two findings (FINs) of very low safety significance (Green). The significance of most findings is indicated by their color (i.e., greater than Green, or Green, White, Yellow, Red)and determined using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP), dated June 2, 2011. Cross-cutting aspects are determined using IMC 0310,

Aspects Within the Cross-Cutting Areas, dated December 19, 2013. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy, dated July 9, 2013. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 5, dated February 2014.

Cornerstone: Initiating Events

Green.

A self-revealing Green FIN was identified against PSEG procedure MA-AA-716-009,

Use of Maintenance Procedures, Revision 5, when PSEG staff did not follow the rules of usage for Maintenance Department procedures as applied to work on a Unit 2 isolated phase bus cooling fan. Specifically, PSEG staff did not perform inspection and testing as required. Subsequently, the 2B fan belts broke causing high temperatures in the bus enclosure, control room alarms, and an unplanned reduction to 51 percent reactor thermal power. As interim corrective actions, PSEG entered this in their corrective action program (CAP), initiated a prompt investigation, installed fan belts and swapped operations to the 2A motor, and established weekly readings to monitor drive belt conditions.

The issue was more than minor since it was associated with the Equipment Performance attribute of the Initiating Events cornerstone and adversely impacted its objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the failure of the drive belts resulted in an unplanned downpower. The finding was evaluated in accordance with IMC 0609,

Attachment 4, and Appendix A where it screened as very low safety significance (Green) as a support system initiator. Specifically, the finding did contribute to the likelihood of, or cause, both an initiating event and affect mitigation equipment. The finding had a cross-cutting aspect in the area of Human Performance, Teamwork, in that individuals and work groups communicate and coordinate their activities within and across organizational boundaries to ensure nuclear safety is maintained. Specifically, PSEG operations, maintenance, and engineering staff did not coordinate to ensure that inspections and testing were completed appropriately or that decisions not to complete steps as required were reviewed by the appropriate departments. [H.4] (Section 4OA2)

Green.

The inspectors identified a Green NCV of Title 10 of the Code of Federal Regulations (10 CFR) 50.65(a)(4) when PSEG inadequately assessed risk during a period of adverse grid conditions. On January 7, 2014, the regional transmission organization declared a Maximum Emergency Generation Action, a condition that PSEG was procedurally required to consider a high risk evolution (HRE) for a loss of offsite power (LOOP). Specifically, PSEG was to elevate online risk to a Yellow condition; however,

PSEG did not assess risk as

Yellow.

PSEG subsequently elevated their risk condition, protected equipment, took other risk management actions (RMAs), and entered the issue in their CAP.

The issue was more than minor since it was associated with the Protection Against External Factors attribute of the Initiating Events cornerstone and adversely affected its objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the extreme cold weather conditions indirectly were affecting grid stability and required risk assessment and management. Additionally, it was similar to IMC 0612, Appendix E, example 7.e, in that an inadequate risk assessment is not minor if the overall plant risk would put the plant into a higher licensee-established risk category. In this case, plant risk was reclassified from Green to Yellow when properly assessed. Specifically, the extreme cold weather conditions indirectly were affecting grid stability. The inspectors evaluated the finding using IMC 0612,

Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process. Since the incremental core damage probability deficit was less than 1 E-6 and the incremental large early release probability deficit was less than 1 E-7, this finding was determined to be of very low safety significance (Green). The finding was determined to have a cross-cutting aspect in the area of Human Performance, Teamwork, in that individuals and work groups communicate and coordinate their activities within and across organizational boundaries to ensure nuclear safety is maintained. Specifically,

PSEG staff in the Electric System Operations Center (ESOC), Salem control room, and Hope Creek control room did not appropriately communicate across organizational boundaries to ensure that risk was appropriately assessed. [H.4] (Section 1R13)

Green.

Inspectors identified a Green NCV of 10 CFR 50.65(a)(4) when PSEG did not properly assess Unit 2 risk and implement RMAs in accordance with station procedures.

PSEG conducted undervoltage (UV) surveillance testing on a 4 kilovolt (kV) vital bus without considering plant conditions to include operations without a redundant offsite power source and work in the vicinity of protected equipment. PSEG entered this in their CAP and completed a crew clock reset.

The issue was more than minor since it was associated with the Equipment Performance attribute of the Initiating Events cornerstone and adversely affected its objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, UV testing of a vital bus when powered by a single offsite power source had the potential to result in a loss of vital bus power or a LOOP. Additionally, the issue was more than minor based on similarity to IMC 0612,

Appendix E, examples 7.e and 7.f. Specifically, the overall elevated plant risk placed the plant into a higher licensee-established risk category and required, under plant procedures,

RMAs that were not implemented. The inspectors evaluated the finding using IMC 0612,

Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process. A senior reactor analyst considered the base condition of an increased probability of a LOOP and the lack of RMAs as two order of magnitude increases.

Since the incremental core damage probability deficit was less than 1 E-6 and the incremental large early release probability deficit was not applicable for this issue, this finding was determined to be of very low safety significance (Green). The finding was determined to have a cross-cutting aspect in the area of Human Performance, Conservative Bias, in that individuals use decision making-practices that emphasize prudent choices over those that are simply allowable. Specifically, PSEG did not implement procedurally driven decision-making that would have emphasized prudent choices regarding UV testing under different plant conditions. [H.14] (Section 1R13)

Cornerstone: Mitigating Systems

Green.

The inspectors determined there was a Green, self-revealing violation of Technical Specification (TS) 6.8.1, Procedures and Programs, as described in Regulatory Guide 1.33, Revision 2, February 1978, when PSEG failed to adequately implement procedure steps associated with fire protection hose flow verification testing on March 6, 2014.

Consequently, a fuel oil day tank was overfilled, resulting in approximately 3000 gallons of fuel oil on the pump house roof, leaks through the roof onto the fire pumps, and Salem fire water suppression system unavailability for approximately two days. PSEG stopped the leak, entered this issue in their CAP, and completed a Prompt Investigation.

The inspectors determined that the performance deficiency was more than minor because it was associated with the Protection Against External Factors attribute of the Mitigating System cornerstone and adversely its cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events (fire) to prevent undesirable consequences. The inspectors determined that the finding was of very low safety significance (Green) because it did not impact the ability of Salem Units 1 or 2 to achieve and maintain safe shutdown. The inspectors determined that this finding had a cross-cutting aspect in the area of Human Performance, Avoid Complacency, because PSEG fire protection operators did not recognize and plan for the possibly of mistakes, latent issues, and inherent risk, even while expecting successful outcomes of procedure steps to refill the fuel oil day tank. Further, they did not implement appropriate error reduction tools. [H.12] (Section 1R05)

Green.

The inspectors identified a Green NCV of 10 CFR 50.65(a)(1) associated with Unit 1. Specifically, PSEG did not establish appropriate performance goals in response to positive displacement pump (PDP) performance issues that resulted in significant emergent unavailability and a repeat maintenance preventable function failure (RMPFF). PSEG entered this issue into their CAP to evaluate PDP performance goals and action plans.

The finding was more than minor because it was associated with the Equipment Performance attribute of the Mitigating System cornerstone and affected its objective to ensure the availability and reliability of systems (safe shutdown charging cross-connect)that respond to initiating events (fire) to prevent undesirable consequences (i.e., core damage). The inspectors evaluated the finding in accordance with IMC 0609, Appendix F,

Fire Protection Significance Determination Process. The inspectors determined that Finding Category 1.4.5 (post-fire, safe shutdown) applied as the finding potentially impacted a system credited for post-fire, safe shutdown. The inspectors determined that the finding was of very low safety significance (Green) because the Unit 2 reactor would have been able to reach and maintain safe shutdown, crediting the Unit 1 operating centrifugal charging pump as necessary (based on a yes response to question 1.3.1.A). This finding has a cross-cutting aspect in the area of Human Performance, Procedure Adherence, in that PSEG personnel did not follow Maintenance Rule (MR) processes and procedures.

Specifically, PSEG personnel did not follow MR program procedure guidance to set appropriate (a)(1) monitoring goals or revise existing (a)(1) monitoring goals to monitor the effectiveness of actions taken to restore PDP performance. [H.8] (Section 4OA2)

Green.

The inspectors identified a Green FIN associated with Unit 1 for PSEGs failure to take adequate corrective actions in accordance with procedure LS-AA-125, Corrective Action Program, Attachment 1 guidance following a PDP failure to couple-on-demand event, and to preclude subsequent failures during other couple-on-demand events and additional unplanned PDP unavailability. PSEG entered this issue into their CAP, implemented a compensatory measure, and initiated actions to correct the condition causing the failure to couple events.

The performance deficiency was more than minor because it was associated with the Equipment Performance attribute of the Mitigating Systems cornerstone and affected its objective to ensure the availability and reliability of systems (safe shutdown charging cross-connect) that respond to initiating events (fire) to prevent undesirable consequences (i.e.,

core damage). The inspectors determined that the finding was very low safety significance as the Unit 2 reactor would have been able to reach and maintain safe shutdown. This finding has a cross-cutting aspect in the area of Problem Identification and Resolution,

Resolution, in that PSEG did not take effective corrective actions to address issues in a timely manner commensurate with their safety significance. Specifically, PSEG did not take adequate corrective actions in response to a PDP failure-on-demand event in February 2013 to preclude several additional unexpected PDP failure-on-demand events which resulted in additional unplanned unavailability. [P.3] (Section 4OA2)

Green.

A self-revealing, Green NCV of 10 CFR 50, Appendix B, Criterion XI, Test Control, was identified when PSEG did not perform adequate post-maintenance testing (PMT) of the 22 chiller. The chillers cool safety-related loads in the auxiliary building during normal and emergency conditions. After failing to pump-down, corrective maintenance, and restoration, the chiller failed to pump-down again three days later. PSEG entered this in their CAP, backdated inoperability, performed a crew clock reset, and investigated the issue.

The finding was more than minor since it affected the Equipment Performance attribute of the Mitigating Systems cornerstone and its objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

Specifically, the inadequate PMT resulted in additional inoperability and unavailability of the 22 chiller. The finding was evaluated in accordance with IMC 0609, Appendix A, and screened to Green since it was not a design or qualification deficiency, not a loss of function, and did not involve equipment or function designed to mitigate a seismic, flooding, or severe weather initiating event. The finding was determined to have a cross-cutting aspect in the area of Human Performance, Consistent Process, in that individuals use a consistent, systematic approach to make decisions. Specifically, PSEG did not use a systematic approach to make decisions regarding the proper PMT. [H13] (Section 1R19)

Other Findings

Violations of very low safety significance or Severity Level IV that were identified by PSEG staff were reviewed by the inspectors. Corrective actions taken or planned by PSEG staff have been entered into PSEGs CAP. These violations and corrective action tracking numbers are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period at 100 percent power. The unit was reduced to approximately 66 percent power over 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> on February 7 to support a 500kV transmission line outage. The unit remained at or near 100 percent power for the remainder of the inspection period.

Unit 2 began the inspection period at 100 percent power. On January 31, control rod 1D2 partially fell into the core during a control rod surveillance. Power was reduced in response to the issue and the reactor was, subsequently, manually tripped. A reactor startup was commenced the following evening and the unit reached 100 percent power on February 3. On February 11, the unit was reduced to approximately 45 percent power to support entry into containment to isolate the 22 reactor coolant pump (RCP) seal water differential pressure transmitter tube leak. The unit returned to 100 percent power on February 13. The unit remained at or near 100 percent power for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

Readiness for Impending Adverse Weather Conditions

a. Inspection Scope

The inspectors reviewed PSEGs preparations during a winter storm warning on January 2, 2014. The inspectors reviewed the implementation of adverse weather preparation procedures before the onset of and during this adverse weather condition.

The inspectors walked down the service water (SW) intake structure, SW accumulators, freshwater pumphouse, and effluent radiation monitors to ensure system availability.

The inspectors verified that operator actions defined in PSEGs adverse weather procedure maintained the readiness of essential systems. The inspectors discussed readiness and staff availability for adverse weather response with operations and work control personnel. Documents reviewed for each section of this inspection report are listed in the Attachment.

b. Findings

No findings were identified.

1R04 Equipment Alignment

Partial System Walkdowns (71111.04Q - 5 samples)

a. Inspection Scope

The inspectors performed partial walkdowns of the following systems:

Unit 1, 12 and 13 Auxiliary Feedwater (AFW) trains with 11 AFW pump out of service, on January 29 Unit 2, SW with 25 SW pump out of service, on January 14-16 Unit 2, 23 station power transformer (SPT) vital bus power supply with 24 SPT de-energized, on February 2 Common, fire protection system during extended maintenance on the No. 1 fire water pump with the cross-tie open, on March 3-5 Common, control room emergency ventilation system during isolation damper replacement, on March 25-26 The inspectors selected these systems based on their risk-significance relative to the Reactor Safety cornerstones at the time they were inspected. The inspectors reviewed applicable operating procedures, system diagrams, the Updated Final Safety Analysis Report (UFSAR), TSs, work orders, notifications, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have impacted system performance of their intended safety functions. The inspectors also performed field walkdowns of accessible portions of the systems to verify system components and support equipment were aligned correctly and were operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no deficiencies. The inspectors also reviewed whether PSEG staff had properly identified equipment issues and entered them into the CAP for resolution with the appropriate significance characterization.

b. Findings

No findings were identified.

1R05 Fire Protection

.1 Resident Inspector Quarterly Walkdowns

a. Inspection Scope

The inspectors conducted tours of the areas listed below to assess the material condition and operational status of fire protection features. The inspectors verified that PSEG controlled combustible materials and ignition sources in accordance with administrative procedures. The inspectors verified that fire protection and suppression equipment was available for use as specified in the area pre-fire plan, and passive fire barriers were maintained in good material condition. The inspectors also verified that station personnel implemented compensatory measures for out of service, degraded or inoperable fire protection equipment, as applicable, in accordance with procedures and discussed with station personnel the repair plans for degraded equipment.

Unit 1, emergency diesel generators (EDGs)(elevations 100 and 122), on January 16-17 Unit 1, switchgear room (elevation 64), on January 27-28 Unit 1, control room area (elevation 122), on March 4-5 Unit 2, EDGs (elevations 100 and 122), on January 16-17 Unit 2, switchgear room (elevation 64), on January 27-28 Unit 2, control room area (elevation 122), on March 4-5

b. Findings

Introduction.

The inspectors determined there was a Green, self-revealing violation of TS 6.8.1, Procedures and Programs, as described in Regulatory Guide 1.33, Revision 2, February 1978, when PSEG failed to adequately implement procedure steps associated with fire protection hose flow verification testing on March 6, 2014.

Consequently, a fuel oil day tank was overfilled, resulting in fuel oil on the pump house roof, leaks through the roof onto the fire pumps, and Salem fire water suppression system unavailability for approximately two days.

Description.

On March 6, 2014, PSEG Fire Protection Operators (FPOs) performed periodic test S2.FP-PT.FS-0024, Fire Hose Station Flow Verification. The test required running the #2 diesel driven fire pump (DDFP). Upon test completion, FPOs secured the pump and refilled the associated fuel oil day tank. Later in the same shift, PSEG operators discovered a large fuel oil spill originating from the #2 DDFP day tank flame arrestor on the fire pump house roof. Due to long-standing, uncorrected fire pump house roof leaks based on CAP entries in 2009, 2011, and 2013, the fuel oil leaked through the fire pump house roof onto both DDFPs inside. Additionally, the fuel oil sprayed onto the surrounding area. PSEG operators promptly isolated the fuel oil leak, estimated at 3000 gallons, and de-energized the #2 DDFP. The #1 DDFP had been previously removed from service for planned maintenance. There were no personnel injuries or offsite releases during the event. In response, PSEG initiated a Prompt Investigation in accordance with their CAP.

PSEG determined that the direct cause of the spill was two mispositioned valves during the fuel oil day tank refill. Once the refill was complete, an FPO used a step ladder to access the valve handle reach-rods from above, and mistakenly positioned the valves from a mid-throttle position to the full open position rather than closed. PSEG also determined that the FPO did not obtain an independent verification of valve positions.

This was contrary to S2.FP-PT.FS-0024, step 5.4.2, which requires closing the fire pump fuel oil day tank isolation valves as well as an independent verification of completion.

On March 8, 2014, PSEG restored the #2 DDFP to available status after cleaning fuel oil from the pump and roof, and restoring power to the pump. On the following day, PSEG restored the #2 DDFP to operable status after completing a PMT. At the time of the leak, the yard cross-tie with Hope Creek was already opened, in accordance with FP-SA-003, Actions for Inoperable Fire Protection - Salem Station, due to the #1 DDFP being out of service for greater than seven days for planned maintenance. Nonetheless, the inspectors determined that approximately two days of Salem fire water suppression system unavailability and subsequent reliance on a compensatory measure constituted an adverse effect on the availability and capability of the Salem fire water suppression system to respond to a fire event.

Analysis.

The inspectors determined PSEGs failure to adequately implement procedure steps in accordance with S2.FP-PT.FS-0024 was a performance deficiency. The finding was more than minor because it was associated with the Protection Against External Factors attribute of the Mitigating System cornerstone and adversely affected its objective to ensure the availability, reliability, and capability of systems that respond to initiating events (fire) to prevent undesirable consequences. Specifically, the finding impacted fire suppression availability and capability. Using IMC 0609, Attachment 4, Initial Characterization of Findings, and IMC 0609, Appendix F, Fire Protection Significance Determination Process, the inspectors determined that this finding was of very low safety significance (Green) because it did not impact the ability of Salem Units 1 or 2 to achieve and maintain safe shutdown.

The inspectors determined that this finding had a cross-cutting aspect in the area of Human Performance, Avoid Complacency, because PSEG FPOs did not recognize and plan for the possibly of mistakes, latent issues, and inherent risk, even while expecting successful outcomes of procedure steps to refill the fuel oil day tank. Further, FPOs did not implement appropriate error reduction tools. [H.12]

Enforcement.

TS 6.8.1, Procedures and Programs, states, in part, that written procedures shall be established, implemented and maintained covering the applicable procedures recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978. Regulatory Guide 1.33, Section 8, Procedures for control of measuring and test equipment and for surveillance tests, procedures, and calibrations, subpart (b)(1)(h), includes Fire Protection System Functional Tests. PSEG procedure S2.FP-PT.FS-0024, Unit 2 Fire Hose Station Flow Verification, step 5.4.2, requires closing fire pump fuel oil day tank isolation valves and an independent verification. Contrary to the above, PSEG did not properly implement step 5.4.2 on March 6, 2014. Specifically, PSEG FPOs did not close isolation valves and did not obtain an independent verification. The valves were closed later that day, after fuel oil spilled onto the DDFPs, and rendered the Salem fire water suppression system unavailable. Because this finding is of very low safety significance (Green) and was entered into PSEGs CAP as notification 20642368, this violation is being treated as an NCV consistent with Section 2.3.2 of the NRCs Enforcement Policy. (NCV 05000311/2014002-01, Failure to Follow Fire Protection Test Procedure Resulted in Fuel Oil Spill).

1R11 Licensed Operator Requalification Program

.1 Quarterly Review of Licensed Operator Requalification Testing and Training

a. Inspection Scope

The inspectors observed licensed operator simulator training on January 14, 2014 which included a requalification examination and a scenario covering the following major events: fuel handling building explosion, flooding and small break loss of coolant accident (LOCA). The inspectors evaluated operator performance during the simulated event and verified completion of risk significant operator actions, including the use of abnormal and emergency operating procedures. The inspectors assessed the clarity and effectiveness of communications, implementation of actions in response to alarms and degrading plant conditions, and the oversight and direction provided by the control room supervisor. The inspectors verified the accuracy and timeliness of the emergency classification made by the shift manager and the TS action statements entered by the shift technical advisor. Additionally, the inspectors assessed the ability of the crew and training staff to identify and document crew performance problems.

b. Findings

No findings were identified.

.2 Quarterly Review of Licensed Operator Performance in the Main Control Room

a. Inspection Scope

The inspectors observed and reviewed the operators response to the Unit 2 dropped control rod and subsequent reactor trip on January 31, 2014. The inspectors observed infrequently performed test or evolution briefings, pre-shift briefings, and reactivity control briefings to verify that the briefings met HU-AA-1211, Pre-job Briefings.

Additionally, the inspectors observed operator performance to verify that procedure use, crew communications, and coordination of activities between work groups similarly met established expectations and standards.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed the samples listed below to assess the effectiveness of maintenance activities on structure, system, and component (SSC) performance and reliability. The inspectors reviewed system health reports, CAP documents, maintenance work orders, and MR basis documents to ensure that PSEG was identifying and properly evaluating performance problems within the scope of the MR.

For each sample selected, the inspectors verified that the SSC was properly scoped into the MR in accordance with 10 CFR 50.65 and verified that the (a)(2) performance criteria established by PSEG staff was reasonable. As applicable, for SSCs classified as (a)(1),the inspectors assessed the adequacy of goals and corrective actions to return these SSCs to (a)(2). Additionally, the inspectors ensured that PSEG staff was identifying and addressing common cause failures that occurred within and across MR system boundaries.

Unit 2, 24 containment fan cooler unit motor cooler leak and emergent repair, on March 27

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed station evaluation and management of plant risk for the maintenance and emergent work activities listed below to verify that PSEG performed the appropriate risk assessments prior to removing equipment for work. The inspectors selected these activities based on potential risk significance relative to the Reactor Safety cornerstones. As applicable for each activity, the inspectors verified that PSEG personnel performed risk assessments as required by 10 CFR 50.65(a)(4) and that the assessments were accurate and complete. When PSEG performed emergent work, the inspectors verified that operations personnel promptly assessed and managed plant risk.

The inspectors reviewed the scope of maintenance work and discussed the results of the assessment with the stations probabilistic risk analyst to verify plant conditions were consistent with the risk assessment. The inspectors also reviewed the TS requirements and inspected portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met.

Unit 1, removal of backup effluent radiation monitors, on January 10 Unit 1, 13 chiller emergent work with the 22 chiller out of service, on February 25-26 Unit 1, 13 SW pump control power off during bay ventilation maintenance, on March 12 Unit 2, emergent work control for the 2B EDG field flash relay failure to reset, on January 6-7 Unit 2, yellow risk during emergent de-energization of the 24 SPT, on February 14 Common, yellow risk during maximum emergency generation actions, on January 23-24

b. Findings

===.1

Introduction.

The inspectors identified a Green NCV of 10 CFR 50.65(a)(4) on Units 1===

and 2 when PSEG inadequately assessed risk during a period of adverse grid conditions. PSEG subsequently entered the Yellow risk condition, protected equipment, and took other RMAs.

Description.

On January 6, 2014, extreme cold weather conditions were forecasted.

That evening, cold weather conditions drove PJM, the regional transmission organization, to declare a Maximum Emergency Generation Action at 7:33 p.m. PSEG defines this term as a grid condition where required generation exceeds maximum scheduled generation. PSEG monitors and controls the PSEG bulk electric system from the PSEG ESOC. The ESOC notified PSEG who appropriately assessed Salem on-line risk for both units as Yellow and implemented RMAs. At 10:10 p.m., the ESOC notified PSEG that the Action was no longer in effect and PSEG appropriately re-evaluated the on-line risk condition as Green. On January 7, at 3:58 a.m., the ESOC contacted the shift manager and requested that Salem Unit 3, an onsite gas turbine jet, be placed in service and synchronized to the grid. At approximately 4:32 a.m., PJM declared a subsequent Maximum Emergency Generation Action. The ESOC contacted the Hope Creek station who appropriately re-evaluated the on-line risk condition as Yellow.

However, the Salem shift manager did not receive a phone call. At 4:35 a.m., the shift manger contacted the ESOC regarding Salem Unit 3 status since the A engine had started but the B engine had failed to start. When inspectors attended the 6:30 a.m.

status meeting, PSEG stated the on-line risk condition was Green. At 7:13 a.m., after completing a plant status tour, inspectors contacted the Unit 1 senior reactor operator and inquired why Salem was not in a Yellow on-line risk condition. This question was based, in part, on Hope Creek operating logs that cited the Action and their own Yellow on-line risk condition. PSEG subsequently revised their on-line risk condition to Yellow at 7:32 a.m. and implemented RMAs that included equipment protection. Per WC-AA-101, Online Work Management Process, Revision 22, step 4.2.3, PSEG protected the EDGs, diesel fuel oil transfer pumps, the steam generator power-operated relief valves, the station blackout air compressor, the Baldor battery charger diesel generator, Salem Unit 3, and the Salem switchyard. Some of the EDGs and fuel oil transfer pumps were already protected due to the already unavailable 2B EDG. Following this, PSEG learned that the ESOC had a list of email addresses for key Salem associates and had emailed the pertinent information to all of the shift managers except the one not on the list who was on-shift.

PSEG procedure OP-AA-108-107-1001, Electric System Emergency Operations and Electric Systems Operator Interface, Revision 1, Attachment 1, summarizes electrical system alerts, warnings, and emergency procedures. Section 3 of this attachment defines a maximum emergency generation action as required generation exceeds maximum scheduled generation and refers staff to OP-AA-101-112-1002, On-Line Risk Assessment, and consider this a LOOP HRE. OP-AA-102-112-1002, Revision 8, step 5.2.3, states in event of LOOP HRE refer to step 5.2.5. Step 5.2.5 notes that the increased grid risk by itself will be Yellow. Step 5.4.6 directs that for emergent conditions that result in a Yellow Risk Assessment, implement compensatory actions.

Specifically, if a suspected Yellow Risk Condition exists, perform the following as soon as possible - evaluate protecting additional equipment while the higher risk conditions exists and evaluate work week schedule and determine if impending work should be postponed. When a Maximum Generation Action is declared, the action updates the sites Probabilistic Risk Assessment tool to reflect the potential reduction to grid reliability which changes the risk color to yellow. The yellow risk color indicates that a LOOP is more likely to occur based on the challenges to the grid.

The inspectors determined that this issue was within PSEGs ability to foresee and correct since the Hope Creek station had adequately determined risk was Yellow, the extreme weather conditions had continued to exist since the earlier Action declaration, PSEG key associates had been notified via email, and the ESOC call for Salem Unit 3 to be synchronized to the grid confirmed generation issues on the grid. PSEG entered this item in their CAP as notification 20635632, evaluated the issue, and developed an immediate corrective action of adding the shift manager to the email list and ensuring all shift managers were on the list.

Analysis.

Improper assessment of the on-line risk condition was a performance deficiency. The issue was more than minor since it was associated with the Protection Against External Factors attribute of the Initiating Events cornerstone and adversely affected its objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations.

Specifically, the extreme cold weather conditions indirectly were affecting grid stability and required risk assessment and management. Additionally, it was similar to IMC 0612, Appendix E, example 7.e, in that an inadequate risk assessment is not minor if the overall plant risk would put the plant into a higher licensee-established risk category. In this case, plant risk was reclassified from Green to Yellow when properly assessed. The inspectors evaluated the finding using IMC 0612, Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process. Since the incremental core damage probability deficit was less than 1 E-6 and the incremental large early release probability deficit was less than 1 E-7, this finding was determined to be of very low safety significance (Green).

The finding was determined to have a cross-cutting aspect in the area of Human Performance, Teamwork, in that individuals and work groups communicate and coordinate their activities within and across organizational boundaries to ensure nuclear safety is maintained. Specifically, PSEG staff in the ESOC, Salem control room, and Hope Creek control room did not appropriately communicate across organizational boundaries to ensure that risk was appropriately assessed. [H.4]

Enforcement.

10 CFR 50.65(a)(4) states, in part, that before performing maintenance activities, the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activities. Contrary to this, from 4:32 a.m. to 7:24 a.m.

on January 7, 2014, PSEG had not adequately assessed the increase in Unit 1 and 2 risk due to grid conditions and an associated Maximum Emergency Generation Action declaration by PJM. PSEG added the shift manager missing from a notification email list and ensured all shift managers were on the list. Because of the very low safety significance of this finding and because the finding was entered into PSEGs CAP as notification 20635632, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Manual. (NCV 05000272;311/2014002-02, Inadequate Online Risk Assessment for an Adverse Change in Grid Conditions)

===.2

Introduction.

Inspectors identified a Green NCV of 10 CFR 50.65(a)(4) when PSEG did===

not properly assess Unit 2 risk and implement RMAs in accordance with station procedures. PSEG conducted UV surveillance testing on a 4kV vital bus without considering plant conditions to include operations without a redundant offsite power source and work on or near protected equipment.

Discussion. On February 13, 2014, PSEG took the 24 SPT out of service due to elevated gassing levels. This placed Unit 2 in a Yellow online risk condition due to all three 4kV vital busses being powered by one offsite power source via the 23 SPT.

PSEG implemented RMAs by protecting the single offsite power supply breaker to the vital busses as well as the EDG supply breakers to the same. Vital bus 2C UV surveillance testing had already been scheduled under work order 50164553 for the following morning. The 31-day TS surveillance had previously been completed on January 17. Inspectors asked operators on two occasions prior to the work whether they intended to complete the surveillance out of concern for the potential risk. The inspectors learned that the testing was due February 17 but, with the 25 percent grace allowed by Surveillance Requirement 4.3.2.1.1, could be extended to February 24. After PSEG completed the work later that morning, the inspectors reviewed the work order and noted that the work had not been considered work on or near protected equipment. OP-AA-108-116, Protected Equipment Program, Revision 9, step 4.3.9, states, in part, If an entire bus, load center, or motor control center (MCC) is not protected but a single breaker on the bus, load center, or MCC is protected, then breaker compartment work that could in no way affect the entire bus can be considered but needs to be evaluated in accordance with step 4.4.3. Step 4.4.3 covers work on or near protected equipment and imposes additional RMAs to include shift manager authorization and documentation, a pre-job briefing from Operations Shift Management, Shift manager designation of the level of work group supervisory oversight, consideration of additional posting, periodic monitoring of work in the affected area, and assessment of whether the task could be performed at another time or location. Additionally, WC-AA-105, Work Activity Risk Management, Revision 2, exhibit 1, designates work near protected equipment as Medium risk and work on protected equipment as High risk. As a Medium risk evolution, the procedure requires execution of form 2, Look Ahead Planning, that questions undesirable outcomes and implements RMAs such as identification of critical steps and designation of contingency/compensatory measures. As a HRE, the procedure requires execution of form 2, including its section on HREs, as well as execution of form 3, Risk Management Plan. Collectively, this would entail identification of prevention, detection, and corrective actions, management review, and a risk management challenge board. Implemented RMAs would include such actions as a management sponsor, just-in-time training, a high level awareness briefing, and review of operating experience. While the 2C 4kV UV testing is a recurring task, step 4.6.1.2 states, if the conditions for this performance of the work are determined to be sufficiently different such that the previous risk documented evaluation is inadequate, then a new risk analysis shall be completed prior to performing the task. In this case, the inspectors determined that the surveillance should not have been considered based on procedural guidance but, at a minimum, would have been considered work on or near protected equipment. Given that, station procedures required a new risk analysis that would have required additional RMAs associated with Medium or High risk along with those of working on or near protected equipment. PSEG entered this in their CAP (20640080) and completed a crew clock reset. Operations and Maintenance departments reviewed the procedural requirements with their staff.

Analysis.

Failure to assess risk and implement RMAs in accordance with station procedures for a licensee-established elevated level of risk was a performance deficiency. The issue was more than minor since it was associated with the Equipment Performance attribute of the Initiating Events cornerstone and adversely affected its objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, UV testing of a vital bus when powered by a single offsite power source had the potential to result in a loss of vital bus power or a LOOP. Additionally, the issue was more than minor based on similarity to IMC 0612, Appendix E, examples 7.e and 7.f. Specifically, the overall elevated plant risk placed the plant into a higher licensee-established risk category and required, under plant procedures, RMAs that were not implemented. The inspectors evaluated the finding using IMC 0612, Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process. A senior reactor analyst considered the base condition of an increased probability of a LOOP and the lack of RMAs as two order of magnitude increases. Since the incremental core damage probability deficit was less than 1 E-6 and the incremental large early release probability deficit was not applicable for this issue, this finding was determined to be of very low safety significance (Green).

The finding was determined to have a cross-cutting aspect in the area of Human Performance, Conservative Bias, in that individuals use decision making-practices that emphasize prudent choices over those that are simply allowable. Specifically, PSEG did not implement procedurally driven decision-making that would have emphasized prudent choices regarding UV testing under different plant conditions. [H.14]

Enforcement.

10 CFR 50.65(a)(4) states, in part, that before performing maintenance activities, the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activities. Contrary to this, on February 14, 2014, PSEG did not adequately assess and manage the risk of performing UV testing on a 4kV vital bus containing protected equipment with all 4kV vital busses powered by one offsite power supply. Specifically, proper assessment and management of Unit 2 risk would have resulted in a higher risk category and required additional RMAs. As an interim corrective action, PSEG Operations and Maintenance departments reviewed the procedural requirements with their staff. Because of the very low safety significance of this finding and because the finding was entered into PSEGs CAP as notification 20640080, the finding is being treated as an NCV consistent with Section 2.3.2 of the NRC Enforcement Manual. (NCV 05000311/2014002-03, Inadequate Risk Assessment and Risk Management Actions for UV Testing)

1R15 Operability Determinations and Functionality Assessments

a. Inspection Scope

The inspectors reviewed operability determinations for the following degraded or non-conforming conditions:

Unit 1, high-efficiency particulate air supply damper 1ABV6 failure to open, on January 23 Unit 1, 12AFW21 demand signal low out of band, on January 4-6, 22, and 27 Unit 2, 22 chiller failure to pump down, on January 14 and 17 Unit 2, shutdown margin during January 31, 2014 control rod drop, on February 4 and 7 Unit 2, 22 RCP seal differential pressure tubing leak, on February 11 Common, control room envelope isolation damper replacement, on March 25-26 The inspectors selected these issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the operability determinations to assess whether TS operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the TSs and UFSAR to PSEGs evaluations to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled by PSEG. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations.

b. Findings

No findings were identified.

1R18 Plant Modifications

Permanent Modifications

a. Inspection Scope

The inspectors evaluated modifications in PSEGs replacement of the Unit 2 24 SPT on February 14-18, and Units 1 and 2 chiller motor contact replacements on February 26.

The inspectors verified that the design bases, licensing bases, and performance capability of the affected systems were not degraded by the modification. In addition, the inspectors reviewed modification documents associated with the design change.

The inspectors reviewed selected post-installation or removal test results as appropriate to evaluate whether the actual impact of the change or removal had been adequately demonstrated by the test.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors reviewed the PMTs for the maintenance activities listed below to verify that procedures and test activities ensured system operability and functional capability.

The inspectors reviewed the test procedure to verify that the procedure adequately tested the safety functions that may have been affected by the maintenance activity, that the acceptance criteria in the procedure was consistent with the information in the applicable licensing basis and/or design basis documents, and that the procedure had been properly reviewed and approved. The inspectors also witnessed the test or reviewed test data to verify that the test results adequately demonstrated restoration of the affected safety functions.

Unit 1, 14 SW pump following motor replacement, on January 16 Unit 1, 13 chiller following SW leak, on February 21 and 24 Unit 1, 13 SW pump motor bearing cooling leak repair, on March 6 and 7 Unit 2, 2B EDG following K1C relay replacement, on January 7 Unit 2, 22 chiller following failure to pump down, on January 15 Unit 2, control rod 1D2 drive mechanism cable replacement, on February 1 Unit 2, 22 RCP seal differential pressure tubing replacement, on February 12 Unit 2, 24 SPT replacement, on February 16 and 17

b. Findings

Introduction.

A self-revealing, Green NCV of 10 CFR 50, Appendix B, Criterion XI, Test Control, was identified on Unit 2 when PSEG did not perform adequate PMT of the 22 chiller. The chillers cool safety-related loads in the auxiliary building during normal and emergency conditions. After failing to pump-down, corrective maintenance, and restoration, the chiller failed to pump-down again three days later. PSEG entered this in their CAP (20637052), backdated inoperability, performed a crew clock reset, and investigated the issue again.

Description.

On January 14, 2014, PSEG was preparing to tune the 23 chiller in accordance with procedure SC.MD-PT-CH-0004, Chiller Post Maintenance Test and Unloader Adjustment, Revision 1. Steps 5.2.5 and 5.2.6 direct that the other chillers be placed in pump-down. When the 22 chiller was placed in pump-down, it did not stop in the pump-down position. Step 5.2.5.b directs placing the chiller in the Off position, declaring the chiller inoperable, and notifying the control room. PSEG entered TS 3.7.10, declared the 22 chiller inoperable, entered the issue in their CAP (20636483),and deferred tuning of the 23 chiller. PSEG replaced the R1 relay and bench-tested the removed relay. PSEG determined that the cause was the R1 relay having high resistance on its contacts. PMT was performed by completing S2.OP.ST.CH-0004, Chilled Water System - Chillers, Revision 18, the next morning and the 22 chiller was declared operable.

The inspectors selected the issue as a PMT sample. The work order PMT and retest sections stated Required testing to be determined based on extent of repairs: verify proper operation/indication per plant conditions and Ops to verify proper in-service operation and indication as per plant conditions respectively. The inspectors reviewed the completed work package and did not find evidence of re-testing the pump-down feature. They reviewed the clearance document and noted that its tagged position was the lockout position and its restored position was position per info page. The inspectors reviewed the completed PMT, S2.OP-ST.CH-0004. The documented, as-found position of the control switch was lockout and the as-left position was run. The procedure placed the chiller directly in the run position and did not test the pump-down feature. On January 17, the inspectors went to the control room and asked the Unit 2 senior reactor operator how the pump-down feature had been re-tested. At that time, the inspectors were told that the 22 chiller had been declared inoperable about an hour prior based on exhibiting the same inability to pump-down as before. PSEG entered this in their CAP (20637052), backdated inoperability to January 14, performed Operations and Maintenance crew clock resets, and investigated the issue again. During troubleshooting, PSEG determined that the liquid line solenoid valve was not closing thus preventing the chiller from pumping down and turning off when the pump pressure setpoint was reached. Overall, the chiller was inoperable for approximately 5.5 days and was unavailable for an additional 3 days. The inspectors determined that the inadequate PMT was a performance deficiency.

The inspectors considered the designated PMT and retest as insufficiently specific.

MA-AA-716-012, Post Maintenance Testing, Revision 19, steps 1.2.2, 1.2.6, 4.1.3, and 4.2.5 state, in part, Post Maintenance Testing is a controlled process, the test performed should be commensurate with the maintenance work performed, accurate, complete, and consistent PMT involves specifying an appropriate test, and Post Maintenance Testing should be tailored to the specific maintenance performed, respectively. In addition, MA-AA-716-004, Conduct of Troubleshooting, Revision 12, step 3.5.6, states that the Shift Manager or designee shall review retest and PMT specified in troubleshooting plan with a focus on original symptom resolution and return to operability. The inspectors determined that PSEG did not use a systematic approach to make decisions regarding the proper PMT.

Analysis.

Inadequate PMT was a performance-deficiency within PSEGs ability to foresee and correct and should have been prevented. The issue was more than minor since it affected the Equipment Performance attribute of the Mitigating Systems cornerstone and its objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

Specifically, the inadequate PMT resulted in additional inoperability and unavailability of the 22 chiller. The finding was evaluated in accordance with IMC 0609, Appendix A, and screened as very low safety significance since it was not a design or qualification deficiency, not a loss of function, not a loss of a single train for greater than its TS allowed outage time, and did not involve equipment or function designed to mitigate a seismic, flooding, or severe weather initiating event.

The finding was determined to have a cross-cutting aspect in the area of Human Performance, Consistent Process, in that individuals use a consistent, systematic approach to make decisions. Specifically, PSEG did not use a systematic approach to make decisions regarding the proper PMT. [H.13]

Enforcement.

10 CFR 50, Appendix B, Criterion XI, states, in part, that "all testing required to demonstrate that structures, systems, and components will perform satisfactorily in service is identified and performed in accordance with written test procedures" and that "test results shall be documented and evaluated to assure that test requirements have been satisfied." Contrary to this, on January 15, 2014, PSEG did not perform adequate testing required to demonstrate satisfactory maintenance and operability of the 22 chiller. Consequently, the 22 chiller remained inoperable until recognized on January 17, 2014. PSEG conducted further troubleshooting, appropriate subsequent repairs and testing, and restored operability of the 22 chiller. Because this issue was of very low safety significance (Green) and entered in PSEG's CAP as notification 20637052, this issue is being treated as an NCV in accordance with section 2.3.2 of the NRC Enforcement Policy. (NCV 05000311/2014002-04, Inadequate Post-Maintenance Testing of a Chiller)

1R20 Refueling and Other Outage Activities

a. Inspection Scope

On January 31, 2014, Salem Unit 2 experienced a partially dropped rod while performing monthly control rod surveillance testing. PSEG conducted a load reduction using boration and turbine load adjustments in response. At approximately 20 percent reactor thermal power, the reactor was manually tripped. PSEG attributed the dropped rod to a short-to-ground in the movable gripper cable that resulted in two blown fuses. A short-to-ground on the power cable from the rod control containment cabinet to the reactor head was also identified. PSEG replaced the power cable and fuses, performed surveillance testing, and returned the control rod to service. During the outage, the inspectors observed portions of the shutdown process, repair activities, and immediate corrective actions, and monitored controls associated with the following outage activities:

Configuration management, including maintenance of defense-in-depth, commensurate with the outage plan for the key safety functions and compliance with the applicable TSs when taking equipment out of service Status and configuration of electrical systems and switchyard activities to ensure that TSs were met Monitoring of decay heat removal operations Activities that could affect reactivity Tracking of startup prerequisites, walkdown of the primary containment to verify that debris had not been left which could block the emergency core cooling system suction strainers, and startup and ascension to full power operation Identification and resolution of problems related to outage activities

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors observed performance of surveillance tests and/or reviewed test data of selected risk-significant SSCs to assess whether test results satisfied TSs, the UFSAR, and PSEG procedure requirements. The inspectors verified that test acceptance criteria were clear, tests demonstrated operational readiness and were consistent with design documentation, test instrumentation had current calibrations and the range and accuracy for the application, tests were performed as written, and applicable test prerequisites were satisfied. Upon test completion, the inspectors considered whether the test results supported that equipment was capable of performing the required safety functions. The inspectors reviewed the following surveillance tests:

Unit 1, 11 AFW pump flow surveillance (IST), on January 29-30 Unit 1, Reactor coolant system (RCS) activity, on March 18 Unit 1, 1PT516, 14 Steam Generator Pressure Protection Channel IV, on March 19 Unit 1, 125 VDC [volts direct current] battery inspection, on January 21, 29 and 30 Unit 2, 21 charging pump vibrations in alert range, on January 17 Unit 2, 22 chiller surveillance run, on February 25-27 Unit 2, 21 diesel fuel oil transfer pump operability test (IST), on March 5-6 Unit 2, 2C EDG 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> endurance run, on March 12 Unit 2, Solid State Protection System (SSPS) A, Reactor Trip Breaker Undervoltage Coil and Auto-Shunt Trip, on March 20 Unit 2, SSPS A, Reactor Trip and Bypass Breaker P-4 Permissive Test, on March 20

b. Findings

No findings were identified.

1EP4 Emergency Action Level and Emergency Plan Changes

a. Inspection Scope

PSEG implemented various changes to the Salem Emergency Action Levels (EALs),

Emergency Plan, and Implementing Procedures. PSEG had determined that, in accordance with 10 CFR 50.54(q)(3), any change made to the EALs, Emergency Plan, and its lower-tier implementing procedures, had not resulted in any reduction in effectiveness of the Plan, and that the revised Plan continued to meet the standards in 50.47(b) and the requirements of 10 CFR 50, Appendix E.

The inspectors performed an in-office review of all EAL and Emergency Plan changes submitted by PSEG as required by 10 CFR 50.54(q)(5), including the changes to lower-tier emergency plan implementing procedures, to evaluate for any potential reductions in effectiveness of the Emergency Plan. This review by the inspectors was not documented in an NRC Safety Evaluation Report and does not constitute formal NRC approval of the changes. Therefore, these changes remain subject to future NRC inspection in their entirety. The requirements in 10 CFR 50.54(q) were used as reference criteria.

b. Findings

No findings were identified.

2RS1 Radiological Hazard Assessment and Exposure Controls

a. Inspection Scope

During the period March 4-6, 2014, inspectors reviewed PSEGs performance in assessing and controlling radiological hazards in the workplace. The review was against criteria contained in 10 CFR Part 20, TSs, applicable Regulatory Guides, and PSEG procedures.

Inspection Planning

The inspectors reviewed 2013 and 2014 performance indicators for the occupational exposure cornerstone, radiation protection (RP) program audits, and reports of operational occurrences in occupational radiation safety since the last inspection.

Radiological Hazard Assessment The inspectors reviewed the following aspects and associated documentation:

changes in radiological hazards for onsite workers or members of the public and potential impact of the changes conducted walk-downs and independent radiation measurements and reviewed survey documentation.

risk-significant work activities (e.g., Unit 2 reactor containment entries at power)radiological surveys work in potential airborne radioactivity areas and evaluated air samples including continuous air monitoring monitoring of loose surface contamination in areas of the plant Instructions to Workers The inspectors reviewed the following aspects and associated documentation:

labeling of radioactive material containers radiation work permits (RWP) used to access high radiation areas (HRA)use of permissible dose under RWPs including electronic personal dosimeter (EPD)alarm set-points occurrences of EPD alarms communications to workers of radiological hazards.

Contamination and Radioactive Material Control The inspectors reviewed the following aspects and associated documentation:

observed locations where material was monitored and released from the radiological control area and inspected methods used for control, survey, and release observed the performance of personnel surveying and releasing material for unrestricted use radiation monitoring instrumentation used for equipment and personnel release for adequate sensitivity for release and for alarm response sealed sources were accounted for and tested recent transactions involving nationally tracked sources Radiological Hazards Control and Work Coverage The inspectors reviewed the following aspects and associated documentation:

radiological conditions and performed independent radiation measurements during walk-downs of the facility radiological controls, including: surveys, radiation protection job coverage, contamination controls, and use of EPDs in high noise areas airborne radioactivity monitoring and controls posting and physical controls for HRAs and locked HRAs Risk-Significant HRA and Very High Radiation Area (VHRA) Controls The inspectors reviewed the following aspects and associated documentation:

discussed with the Radiation Protection Manager the controls and procedures for high-risk HRAs and VHRAs Radiation Worker Performance and RP Technician Proficiency The inspectors reviewed the following aspects and associated documentation:

radiological problem reports since the last inspection Problem Identification and Resolution The inspectors evaluated whether problems associated with radiation monitoring and exposure control were being identified by at an appropriate threshold and were properly addressed for resolution in PSEGs CAP. The inspector assessed the appropriateness of the corrective actions for problems that involve radiation monitoring and exposure controls. The inspector assessed the process for applying operating experience to their plant.

b. Findings

No findings were identified.

2RS2 Occupational ALARA Planning and Controls

a. Inspection Scope

During the period March 4-6, 2014, the inspectors assessed performance with respect to maintaining occupational individual and collective radiation exposures as low as is reasonably achievable (ALARA). The inspectors used the criteria in 10 CFR 20, applicable Regulatory Guides, TSs, and PSEG procedures for determining compliance.

Inspection Planning

The inspectors reviewed the following aspects and associated documentation:

collective dose history, current exposure trends, ongoing and planned work activities, and the plants three year rolling average collective exposure compared the site-specific trends in collective exposures against the industry average values and those values from similar vintage reactors changes in the radioactive source term, and site-specific procedures associated with maintaining occupational exposures ALARA Radiological Work Planning The inspectors reviewed the following ALARA aspects and associated documentation:

work activities and ALARA work activity evaluations, exposure estimates, and exposure reduction requirements use of dose reduction techniques; and estimated dose goals worker efficiency from use of respiratory protective devices and/or heat stress mitigation equipment and the use of remote technologies, and operating experience to reduce dose integration of ALARA requirements into work procedure and RWP documents (e.g.,

reactor disassembly, transfer canal work, insulation work, RCP seal/motor change out)

Verification of Dose Estimates and Exposure Tracking Systems The inspectors reviewed the following aspects and associated documentation:

current annual collective dose estimate and applicable procedures to determine the methodology for estimating dose measures to track, trend, and reduce occupational doses for ongoing work activities Source Term Reduction and Control The inspectors reviewed the following aspects and associated documentation:

source term reduction, historical trends and current status of plant source term licensee contingency plans for expected changes in the source term as the result of changes in plant fuel performance issues or changes in plant primary chemistry current 10 CFR 61 waste stream source term data Problem Identification and Resolution The inspectors evaluated whether problems associated with ALARA planning and controls are being identified by PSEG at an appropriate threshold and were properly addressed for resolution in PSEGs CAP. The inspectors assessed the process for applying operating experience to their plant.

b. Findings

No findings were identified.

2RS3 In-Plant Airborne Radioactivity Control and Mitigation

a. Inspection Scope

During the period March 4-6, 2014, the inspectors reviewed controls for potential airborne radioactivity work and the use of respiratory protection devices. The inspectors used the criteria in 10 CFR Part 20, the guidance in applicable Regulatory Guides, TSs, and PSEG procedures for determining compliance.

Inspection Planning

The inspectors reviewed the following aspects and associated documentation:

storage of non-emergency respiratory protection equipment performance indicators to identify any related to unintended dose resulting from intakes of radioactive material Problem Identification and Resolution The inspectors evaluated whether problems associated with the control and mitigation of in-plant airborne radioactivity were being identified by PSEG at an appropriate threshold and were properly addressed for resolution in their CAP.

b. Findings

No findings were identified.

2RS4 Occupational Dose Assessment

a. Inspection Scope

During the period March 4-6, 2014, the inspectors reviewed the monitoring, assessment, and reporting of occupational dose. The inspectors used the criteria in 10 CFR 20, applicable Regulatory Guides, TSs, and procedures for determining compliance.

Inspection Planning

The inspectors reviewed the following aspects and associated documentation:

RP program audits dosimetry occurrence reports and CAP documents Internal Dosimetry Routine Bioassay (In-Vivo)

The inspectors reviewed the following aspects and associated documentation:

procedures to assess dose from internally deposited radionuclides, including the release of contaminated individuals portal radiation monitors used as a passive monitoring system Internal Dose Assessment - Airborne Monitoring The inspectors reviewed the program for dose assessment based on airborne monitoring and calculations of internal dose and associated documentation.

Problem Identification and Resolution The inspectors assessed whether problems associated with occupational dose assessment are being identified by PSEG at an appropriate threshold and were properly addressed for resolution in the CAP.

b. Findings

No findings were identified.

2RS5 Radiation Monitoring Instrumentation

a. Inspection Scope

During the periods March 4-6, 2014, the inspectors reviewed the accuracy and operability of radiation monitoring instruments that were used to protect occupational workers. The review was against criteria contained in 10 CFR Part 20, applicable Regulatory Guides and industry standards, TSs, and PSEG station procedures for determining compliance.

Inspection Planning The inspector reviewed the following aspects and associated documentation:

UFSAR to identify radiation instruments associated with monitoring area radiation, airborne radioactivity, process streams, effluents, materials/articles, workers, and post-accident monitoring records of in-service survey instrumentation including: air samplers, small article monitors (SAM), radiation monitoring instruments, personnel contamination monitors, portal monitors, and whole-body counters procedures that govern instrument source checks and calibrations Walkdowns and Observations The inspectors reviewed the following aspects and associated documentation:

portable survey instruments in use and assessed calibration and source check stickers for currency, as well as, instrument material condition and operability compared monitor response (via local readout) with actual area radiological conditions Calibration and Testing Program Portal Monitors, Personnel Contamination Monitors, and SAMs The inspectors reviewed the following aspects and associated documentation:

various types of instruments in use and their alarm set-point values for the release of material from the site Portable Survey Instruments, ARMs, Electronic Dosimetry, and Air Samplers/Continuous Air Monitors The inspectors reviewed calibration documentation and source checks for various portable instruments in use.

Instrument Calibrator

The inspectors reviewed neutron monitoring survey meter calibration to determine if instruments had been calibrated by a facility using National Institute for Standards Technology traceable sources that were appropriate for the source term.

Calibration and Check Sources

The inspectors reviewed the licensees source term or waste stream characterization per 10 CFR Part 61, Licensing Requirements for Land Disposal of Radioactive Waste, to assess whether calibration sources used were representative of the types and energies of radiation encountered in the plant.

Problem Identification and Resolution The inspectors evaluated whether problems associated with radiation monitoring instrumentation were being identified by PSEG at an appropriate threshold and were properly addressed for resolution in their CAP.

b. Findings

No findings were identified.

2RS6 Radioactive Gaseous and Liquid Effluent Treatment

a. Inspection Scope

During the period March 4-6, 2014, the inspectors reviewed ground water contamination monitoring. The review was against criteria contained in 10 CFR Part 20, 10 CFR Part 50, 40 CFR 190, applicable Regulatory Guides and industry standards, TSs/Offsite Dose Calculation Manual (ODCM), and PSEG station procedures for determining compliance.

Event Report and Effluent Report Reviews The inspectors reviewed the following aspects and associated documentation:

2012 Radioactive Effluent Release Report for anomalous results, unexpected trends, and abnormal releases abnormal effluent results were evaluated, were entered in the CAP, and were adequately resolved ODCM and UFSAR Review The inspectors reviewed the following aspects and associated documentation:

changes to the ODCM made since the last inspection Groundwater Protection Initiative (GPI) Program The inspectors reviewed groundwater monitoring results and changes to the GPI program for identifying and controlling contaminated spills/leaks to groundwater.

Procedures, Special Reports, and Other Documents The inspectors reviewed the following aspects and associated documentation:

Licensee Event Reports (LERs), event reports and/or special reports related to the effluent program issued since the previous inspection Walkdowns and Observations The inspectors reviewed the status and efficacy of ground water remediation efforts associated with Salem Unit 1.

GPI Implementation The inspectors reviewed the following aspects and associated documentation:

monitoring results of the voluntary Nuclear Energy Institute (NEI) GPI and assessed whether PSEG has identified and addressed deficiencies through its CAP Problem Identification and Resolution The inspectors assessed whether problems associated with the effluent monitoring and control program are being identified by PSEG at an appropriate threshold and are properly addressed for resolution in their CAP. In addition, the inspectors evaluated the appropriateness of the corrective actions for a selected sample of problems documented.

b. Findings

No findings were identified.

4OA1 Performance Indicator Verification

.1 Safety System Functional Failures (2 samples)

a. Inspection Scope

The inspectors sampled PSEGs submittals for the Safety System Functional Failures performance indicator for both Unit 1 and Unit 2 for the period of January 1 through December 31, 2013. To determine the accuracy of the performance indicator data reported during those periods, inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, and NUREG-1022, Event Reporting Guidelines 10 CFR 50.72 and 10 CFR 50.73." The inspectors reviewed PSEGs operator narrative logs, operability assessments, MR records, maintenance work orders, condition reports, event reports and NRC integrated inspection reports to validate the accuracy of the submittals.

b. Findings

No findings were identified.

.2 RCS Specific Activity and RCS Leak Rate (4 samples)

a. Inspection Scope

The inspectors reviewed PSEGs submittal for the RCS specific activity and RCS leak rate performance indicators for both Unit 1 and Unit 2 for the period of January 1 through December 31, 2013. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7. The inspectors also reviewed RCS sample analysis and control room logs of daily measurements of RCS leakage, and compared that information to the data reported by the performance indicator. Additionally, the inspectors observed surveillance activities that determined the RCS identified leakage rate, and chemistry personnel taking and analyzing an RCS sample.

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution

.1 Routine Review of Problem Identification and Resolution Activities

a. Inspection Scope

As required by Inspection Procedure 71152, Problem Identification and Resolution, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that PSEG entered issues into the CAP at an appropriate threshold, gave adequate attention to timely corrective actions, and identified and addressed adverse trends. In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the CAP and periodically attended condition report screening meetings.

b. Findings

No findings were identified.

.2 Annual Sample: 13 Charging Pump Failure to Couple During Pump Start Demand

a. Inspection Scope

From January 6 through January 10, 2014, the inspectors performed an in-depth review of PSEGs evaluations and corrective actions associated with several Unit 1 PDP failure to couple-on-demand events in 2013. The inspectors assessed PSEGs problem identification threshold, cause analysis, extent-of-condition reviews, and the prioritization and timeliness of corrective actions to evaluate whether PSEG was appropriately identifying, characterizing, and correcting problems associated with this issue and whether the planned and/or completed corrective actions were appropriate. The inspectors compared the actions taken to the requirements of PSEGs CAP, PSEGs operability assessment and equipment control program, PSEGs operator work-around program, 10 CFR 50.65, and Salem TSs. The inspectors observed an equipment operator simulate associated compensatory measures locally at the 13 PDP to independently verify that the operator guidance was adequate, appropriate, and could be implemented as written under worst case conditions if necessary. In addition, the inspectors performed a walkdown of the accessible portions of the Unit 1 and Unit 2 chemical and volume control systems (CVCS), including control room instrumentation, to independently assess material condition, the operating environment, and configuration control.

b. Observations In 2001, during the re-validation of the Salem post-fire shutdown analysis under the 10 CFR Part 50, Appendix R Program, Salem fire protection personnel determined that greater plant safety could be achieved by implementing a CVCS cross-tie design change than by protecting safety-related cables with additional fire wrap, sprinklers, detection systems, or the construction of new fire barriers. Completion of the associated CVCS cross-tie design changes (Design Change package (DCP) 80029150 for Unit 1 & DCP 80029155 for Unit 2) resulted in the PDPs being dedicated to providing the post-fire, safe shutdown, charging functions that include reactivity management, RCP seal injection, and RCS make-up for the opposite unit in Modes 1 through 4. Accordingly, PSEGs MR scope includes a high risk function for the PDPs to provide seal injection to the opposite unit RCPs via the CVCS cross-tie to maintain seal integrity and provide RCS make-up. In 2007, based on Salem operating experience and the projected PDP on-line maintenance schedule, the Salem MR Expert Panel established a PDP unavailability performance criterion (PC) of 400 hours0.00463 days <br />0.111 hours <br />6.613757e-4 weeks <br />1.522e-4 months <br /> per 18-month period.

On February 8, 2013, the 13 PDP failed to couple-on-demand and the motor tripped when operators attempted to start it from the control room. Operators initiated a corrective action notification (20594606), and entered a TS 3.1.2.2 tracking action statement (13-050) for the inoperable charging pump and a post-fire, safe shutdown interim compensatory measures tracker for Unit 2. PSEG performed a variety of troubleshooting activities including motor breaker overload testing, suction valve inspections, and a discharge valve pull test; however, PSEG was not able to identify the cause of the failure. On February 16, operators exited the associated TS tracking action statement and declared the pump operable following a successful retest. On March 13, 2013, the 13 PDP again had difficulty starting on demand; however, it did start after approximately two minutes when operators raised the demand to 40 percent (notification 20598923). Typically, the PDP starts at less than 20 percent demand. Engineering had originally attributed the February motor trip and March starting difficulty to the pump loading/demand and the startup methodology. However, on April 1, a meeting involving engineering, maintenance, and operations identified that no changes were needed to the operating procedures, noted that the adverse condition remained, and recommended additional troubleshooting following the Spring 2013 Unit 1 refueling outage, 1R22 (notification 20601766).

On June 3, 2013, the 13 PDP failed to couple-on-demand when operators attempted to start it from the control room (notification 20610353). Operators entered a TS 3.1.2.2 tracking action statement (13-211) for the inoperable charging pump and a post-fire, safe shutdown interim compensatory measures tracker for Unit 2. During the June 2013 emergent unavailability work window, PSEG performed a variety of additional troubleshooting activities including fluid drive air-operator, linkage, and controls functional checks; however, PSEG was not able to identify the cause of the failure.

However, based on field observations, engineering identified that the pressure between the pump discharge and discharge check valve remained approximately at RCS pressure. On June 20, additional troubleshooting revealed that the pump could be successfully started at 20 percent demand when the discharge pressure was relieved (vented off). On June 21, operators exited the associated TS tracking action statement and declared the pump operable following a successful retest. On June 27, the Station Ownership Committee (SOC) directed an equipment apparent cause evaluation (EQACE) to investigate and evaluate the repeat PDP failure to couple events.

During a planned PDP preventive maintenance (PM) window (September 29 - August 3, 2013), PSEG performed additional troubleshooting including a discharge check valve leakage verification, fluid drive position indicator checks, oil side and RCS fluid drive side internal inspections (without component disassembly), and a breakaway torque measurement; however, PSEG was not able to identify the cause of the previous failures. On August 9, the 13 PDP failed to couple-on-demand and the motor tripped when operators attempted to start it from the control room (notification 20617597).

Based on engineering input, control room operators maintained ready access to the June 2013 troubleshooting work order that detailed the successful start following discharge pressure venting, and directed equipment operators to relieve the PDP discharge pressure. Following discharge header venting, operators were able to successfully start the PDP at 20 percent demand, 2.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> after the initial failed start attempt. On August 11, operations approved and implemented Temporary Standing Order (TSO) 2013-016 to direct equipment operators to vent the 13 PDP discharge pressure to less than 500 psig prior to starting the pump. Since implementing this compensatory measure, the 13 PDP had not experienced any additional failure to couple-on-demand events.

On November 21, engineering completed EQACE 70155459 and determined that the most probable causal factor of the failure to couple events was additional internal friction within the oil side of the PDP. Engineering identified the apparent cause as an inadequate PM to periodically inspect the internal clearances on the oil side.

Engineering identified that PSEGs PDP performance centered maintenance template recommended an internal inspection of the oil side of the pump on a 6-year frequency; however there was no PM in place to perform this activity. PSEG corrective actions included an extent-of-condition check on the 23 PDP, a planned internal inspection (without disassembly) to gather additional data (scheduled for February 2014), the planned development of an internal inspection PM, and an oil side internal inspection (requiring complete pump disassembly) to repair/replace components as necessary to correct clearance issues (scheduled for December 2015).

The inspectors noted that PSEG performed extensive troubleshooting in a controlled and methodical manner in an attempt to identify the cause of the failure to couple events. In general, the inspectors determined that PSEGs associated EQACE was sufficiently thorough and based on the best available information, sound judgment, and relevant industry operating experience.

Notwithstanding, PSEG did not demonstrate an appropriate level of self-critical assessment regarding several PSEG performance deficiencies evident in the documented history of the issue. Specifically, the inspectors noted that:

(1) engineering had previously identified the potential adverse impact of elevated PDP discharge pressure during pump starts in March 2012, but failed to re-evaluate for applicability in a timely manner (see finding in Section 4OA2.2.c.2 below);

(2) PSEG missed an opportunity to identify the oil side PM deficiency when reviewing the PDP PM for adequacy following the RCS fluid side valve issues in March 2012 (70136857-140); and

(3) PSEG incurred additional unplanned unavailability on August 9, 2013, as operators attempted to start the pump without relieving the discharge pressure due to less than adequate guidance to ensure effective, repeatable implementation of the needed compensatory measure (see finding in Section 4OA2.2.c.2 below). The inspectors found no evidence that PSEG had entered any of these issues into their CAP for follow-up and/or trending. The inspectors also noted that an administrative processing error unnecessarily delayed the associated EQACE. In particular, on June 27, 2013, PSEG created notification 20613456 from notification 20610353 to drive the SOC directed EQACE; however, on August 13, PSEG identified that it was never rolled into an EQACE order. Subsequently, PSEG staff added the EQACE assignment to engineering evaluation 70155459. The inspectors found no evidence that PSEG had separately entered this process delay issue into their CAP for follow-up and/or trending.

In addition, the inspectors identified several instances in which PSEGs MR actions and/or evaluations were not completely aligned with PSEGs MR program, NUMARC 93-01 guidance, and/or 10 CFR 50.65 requirements. Specifically, PSEG:

(1) did not establish appropriate goals for the 13 PDP to address performance issues that resulted in significant emergent unavailability and a RMPFF (see finding in Section 4OA2.2.c.1 below);

(2) did not properly account for all the emergent unavailability (2.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> missed for the August 2013 failure);

(3) did not provide appropriate justification for their functional failure determination associated with the August 9 failure;

(4) originally determined that the February 8 failure to couple event was a maintenance preventable functional failure (MPFF) (70150655-020), but did not provide adequate justification why the June 3 repeat occurrence did not represent a RMPFF; and

(5) did not appropriately reclassify the June 3 failure as a RMPFF following completion of the associated EQACE.

The inspectors concluded that PSEG did not take timely and appropriate actions, commensurate with the potential safety significance, following the February 2013 failure to more effectively balance 13 PDP reliability and unavailability. Specifically, it was reasonable for PSEG to identify and establish PDP discharge pressure venting compensatory measures following the February 2013 failure to preclude additional emergent unavailability, functional failures, and unrecognized unavailability while in standby (see finding in Section 4OA2.2.c.2 below). Based on the documents reviewed, control room and plant walkdowns, and discussions with engineering and operations personnel, the inspectors noted that PSEG personnel generally identified problems and entered them into the CAP at a low threshold, except as noted above. Based on a CAP and operations log review, the inspectors noted that, in general, PSEG promptly initiated notifications for identified issues. However, during this problem identification and resolution inspection, PSEG personnel did not promptly document conditions adverse to quality in the CAP. In addition, the inspectors noted that delaying the oil side repair/replacement activity until December 2015 did not appear timely, commensurate with safety, for an adverse condition requiring operator compensatory measures to start the 13 PDP which may be needed in response to a fire affecting Unit 2. Following the inspectors management debrief of the above observations on January 14, 2014, PSEG personnel documented the PSEG performance deficiencies discussed above in the CAP for those issues not previously captured.

Except for the two findings documented below, the inspectors determined that the PSEG performance deficiencies discussed above were of minor significance in accordance with IMC 0612, Power Reactor Inspection Reports, and any associated violations were not subject to enforcement action in accordance with the Enforcement Policy or the issues were considered in the development of the other findings. The inspectors also assessed the additional PDP emergent unavailability incurred in the associated corrective action finding documented below.

c. Findings

===.1

Introduction.

The inspectors identified a Green NCV of 10 CFR 50.65(a)(1) associated===

with Unit 1. Specifically, PSEG did not establish appropriate performance goals in response to PDP performance issues that resulted in significant emergent unavailability and a RMPFF. PSEG entered this issue in their CAP as notification 20636958 to evaluate PDP performance goals and action plans.

Description.

On September 28, 2012, the Salem MR Expert Panel approved Revision 3 to the 13 PDP MR(a)(1) action plan and goals (70125500-010). On April 4, 2013, engineering placed the Unit 1 CVCS into MR(a)(1) monitoring using approved performance goals. This followed completion of MR(a)(1) actions to address previous repeat failures of the PDP relief valve (1CV141) and discharge pulsation dampener that had resulted in accumulated unavailability hours exceeding the 400 hour0.00463 days <br />0.111 hours <br />6.613757e-4 weeks <br />1.522e-4 months <br /> PC. The inspectors noted that despite Unit 1 CVCS being in MR(a)(1) monitoring for failures mentioned above, there were no MR(a)(1) action plan revisions and/or MR Expert Panel discussions on performance since September 28, 2012. Specifically, there were PDP couple-on-demand failures on February 8, March 13, June 3, and August 9, 2013, that resulted in significant emergent unavailability (~ 500 hours0.00579 days <br />0.139 hours <br />8.267196e-4 weeks <br />1.9025e-4 months <br />), several functional failures, and at least one RMPFF. The inspectors determined that PSEG did not establish appropriate performance goals to monitor the 13 PDP performance in a manner sufficient to provide reasonable assurance that the PDP was capable of fulfilling its intended function.

The inspectors noted that as of June 15, 2013, engineering had attributed approximately 500 hours0.00579 days <br />0.139 hours <br />8.267196e-4 weeks <br />1.9025e-4 months <br /> of unavailability to two failures (which exceeded the 400 hour0.00463 days <br />0.111 hours <br />6.613757e-4 weeks <br />1.522e-4 months <br /> PC). In addition, following the completion of an apparent cause (70155459-080) on November 21, 2013, PSEG did not reclassify the February 8 failure as an MPFF and the June 3 failure as an RMPFF, which procedurally required another MR(a)(1).

The inspectors determined that PSEGs procedures contained sufficient guidance to prompt Engineering to revise their existing MR(a)(1) action and monitoring plan to include appropriate actions and goals for the failure to couple-on-demand issues.

Specifically, ER-AA-310, Implementation of the Maintenance Rule, Revision 12, step 4.5.3, requires the monthly evaluation of assigned SSCs against established MR performance criteria to determine if the system should be placed or maintained in MR (a)(2), MR (a)(1) action, or MR (a)(1) monitoring. Step 4.5.5.3 requires a MR (a)(1)evaluation for RMPFFs. Step 4.6.6 requires PSEG to set (a)(1) monitoring goals or revise existing (a)(1) monitoring goals to monitor the effectiveness of actions taken to restore SSC performance. ER-SA-310-1005, Maintenance Rule - Dispositioning Between (a)(1) and (a)(2), Revision 9, step 4.1.1 requires a notification to perform an (a)(1) evaluation when any of the following conditions exist:

(1) PC have been exceeded,

(2) the system has experienced an RMPFF, or

(3) the system has demonstrated an adverse trend or degrading system performance such that the aggregate demonstrates ineffective maintenance. ER-SA-310-1005, step 4.5.3, states that if the system experiences additional performance issues not addressed by the (a)(1) action plan, then the action plan may require a change.

The inspectors also noted that PSEGs MR functional failure cause determination evaluation (70155459-010) for the June 2013 failure represented a missed opportunity.

In particular, a step asked Does this failure result in performance criteria being exceeded or is failure an RMPFF? If answered yes, it requires Engineering to initiate a notification to perform an (a)(1) evaluation. Engineering answered no to this question and discussed the number of functional failures, but not the unavailability time attributed to the February and June 2013 failures. Engineering considered the June failure as a MPFF and noted the first occurrence was on February 8; however, PSEG did not consider the June failure as an RMPFF.

With Unit 1 in Modes 1 - 4, PSEG credits the 13 PDP with providing the post-fire, safe shutdown, charging functions that include reactivity management, RCP seal injection, and reactor coolant make-up for a Unit 2 fire in multiple areas. Although PSEG only credits the 13 PDP, the inspectors noted that procedure S1.OP-SO.CVC-0023, CVCS Cross-Connect Alignment to Unit 2, provides direction for operators to open the cross-connect valve if a centrifugal charging pump is in service (with the PDP in standby) to allow the in-service charging pump to promptly provide the charging cross-connect supply to Unit 2 until the PDP can be aligned to perform its credited function. In this case, even if the PDP failed to start in standby, the post-fire, safe shutdown cross-connect function would not be lost; however, the alignment would require Unit 1 to enter TS 3.0.3 (due to failure to meet TS 3.5.2 with an emergency core cooling system centrifugal pump cross-connected to Unit 2) and Unit 1 to shutdown if the PDP was not restored within seven hours. Thus, as long as the PDP discharge isolation valve (1CV64) is maintained open (as it normally is), the in-service centrifugal charging pump can help mitigate a Unit 2 fire in one of the critical plant areas mentioned above. Based on a tagging system and Unit 1 narrative log review, the inspectors determined that operators maintained 1CV64 open with Unit 1 in Modes 1 - 4 during the period February 16 through June 3, 2013.

Analysis.

The failure to establish appropriate MR performance goals for the 13 PDP failure to couple-on-demand issue was a performance deficiency within PSEGs ability to foresee and correct. The performance deficiency was more than minor because it was associated with the Mitigating System equipment performance attribute and affected the cornerstones objective to ensure the availability and reliability of systems (safe shutdown charging cross-connect) that respond to initiating events (fire) to prevent undesirable consequences (i.e., core damage). The inspectors evaluated the finding in accordance with IMC 0609, Appendix F, Fire Protection Significance Determination Process. The inspectors determined that Finding Category 1.4.5 (post-fire, safe shutdown) applied as the finding potentially impacted a system credited for post-fire, safe shutdown. The inspectors determined that the finding was of very low safety significance because the Unit 2 reactor would have been able to reach and maintain safe shutdown, crediting the Unit 1 operating centrifugal charging pump as necessary (based on a yes response to question 1.3.1.A). Traditional enforcement did not apply since the finding was not willful, did not impact the regulatory process, did not have actual safety consequence, or result in a Severity Level IV violation without a performance deficiency.

This finding had a cross-cutting aspect in the area of Human Performance, Procedure Adherence, in that PSEG personnel did not follow MR processes and procedures.

Specifically, PSEG personnel did not follow MR program procedure guidance to set appropriate (a)(1) monitoring goals or revise existing (a)(1) monitoring goals to monitor the effectiveness of actions taken to restore PDP performance. (H.8)

Enforcement.

10 CFR 50.65 (a)(1) states, in part, that each licensee shall monitor the performance or condition of SSCs against licensee-established goals, in a manner sufficient to provide reasonable assurance that such SSCs are capable of fulfilling their intended functions. Contrary to this, from June 3, 2013, through January 2014, PSEG did not monitor the 13 PDP performance against PSEG-established goals, in a manner sufficient to provide reasonable assurance that the PDP was capable of fulfilling its intended post-fire, safe shutdown function despite failure to couple-on-demand events occurring on February 3, March 13, June 3, and August 9, 2013, and unavailability hours that exceeded performance criteria. PSEG entered this issue in their CAP (20636958)to evaluate PDP performance goals and action plans. Because this finding was of very low safety significance (Green) and was entered into PSEGs CAP, this violation is being treated as an NCV consistent with Section 2.3.2 of the Enforcement Policy. (NCV 05000272/2014002-05, Failure to Establish Appropriate MR Performance Goals)

===.2

Introduction.

The inspectors identified a Green FIN associated with Unit 1 for PSEGs===

failure to take adequate corrective actions in accordance with the LS-AA-125, Corrective Action Program, Attachment 1 guidance following a PDP failure to couple-on-demand event, and to preclude subsequent failures of other couple-on-demand events and additional unplanned PDP unavailability. PSEG entered this issue in their CAP as notification 20638484, implemented a compensatory measure, and initiated actions to correct the condition causing the failure to couple events.

Description.

On February 8, 2013, the 13 PDP failed to couple-on-demand and the motor tripped when operators attempted to start it from the control room. Operators entered a TS 3.1.2.2 action statement for this inoperable charging pump at Unit 1 and a safe shutdown interim compensatory measures tracker for Unit 2. PSEG performed a variety of troubleshooting activities, but were not able to identify the cause of the failure.

On February 16, operators exited the TS action statement and declared the pump operable following a successful retest. On March 13, the 13 PDP again had difficulty starting on demand; however, it did start after approximately two minutes when operators raised pump demand to 40 percent. On April 5, PSEG initiated notification 20601766 to perform additional troubleshooting following the spring 2013 refueling outage. On April 12, operators removed the 13 PDP from service and maintained it in standby to support Unit 2 post-fire, safe shutdown as Unit 1 prepared to enter its refueling outage. Following the Unit 1 refueling outage, on June 3, the 13 PDP failed to couple-on-demand when operators attempted to start it. Operators entered a TS 3.1.2.2 action statement for the inoperable charging pump and a safe shutdown interim compensatory measures tracker for Unit 2. During the June emergent unavailability troubleshooting, engineering identified that the pressure between the pump discharge and discharge check valve remained approximately at RCS pressure. On June 20, additional troubleshooting revealed that the pump could be successfully started at 20 percent demand when the discharge pressure was relieved. On June 21, operators exited the associated TS action statement and declared the pump operable following a successful retest. On August 9, the 13 PDP failed to couple-on-demand and the motor tripped when operators attempted to start it from the control room. Based on engineering input, control room operators had maintained access to the June 2013 troubleshooting work order that detailed the successful start following discharge pressure venting, and directed equipment operators to relieve the PDP discharge pressure. Following discharge header venting, operators were able to successfully start the PDP at 20 percent demand, 2.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> after the initial failed-start attempt. On August 11, operations approved and implemented TSO 2013-016 to direct equipment operators to vent the 13 PDP discharge pressure to less than 500 psig prior to starting the pump. Since implementing this compensatory measure, the 13 PDP has not experienced any additional failure to couple-on-demand events.

In reviewing the 13 PDP, operating history for the last six years, the inspectors determined that appropriate and timely corrective actions following the February 2013 failure-on-demand event could have precluded the emergent unavailability associated with the June and August 2013 failures, improved PDP starting reliability, and eliminated the unrecognized unavailability while in standby. Moreover, the inspectors concluded that it was reasonable for PSEG to identify and take appropriate compensatory measures for the adverse impact caused by the elevated discharge pressure on the PDP starting capability in February 2013 vice August 2013. Specifically, on March 5, 2012, the 13 PDP experienced a failure to couple-on-demand event (notification 20549396). In response to this event, PSEG technical evaluation 70135614-010 determined that the elevated discharge pressure prevented the 13 PDP from coupling-on-demand when starting and that the 13 PDP should be considered unavailable if the pump was in standby in Modes 1 through 4. The chronology of events in the associated apparent cause evaluation (70136857-010) documented that the pump was returned to service on March 10, 2012, with special operational guidance to reduce pump discharge pressure. In April 2012, PSEG corrected the condition causing the failure to couple issue (a discharge valve seating issue).

The inspectors noted that when the PDP failed to couple again on February 8, 2013, under similar conditions (swapping back to the PDP from a centrifugal pump), PSEG did not re-visit the previous March 2012 technical guidance and/or test the 13 PDPs ability to start with elevated discharge pressure as designed. The inspectors noted that initial troubleshooting in February 2013 was focused on ensuring that the failure to couple was not caused by any of the recent PDP performance issues which included discharge valve unseating, discharge relief valve failures, and discharge pulsation dampener degradation. The inspectors found ample CAP documentation of several potential causes that were found not to be the problem; however, the inspectors found no documentation of exactly what was found and corrected (and/or compensated for)before declaring the 13 PDP fully functional on February 16, 2013. Engineering identified the need to vent the PDP before starting following their June 2013 troubleshooting and provided a copy of the troubleshooting work order to Operations.

However, the inspectors identified that Operations did not provide appropriate guidance to control room operators to ensure effective, repeatable implementation of this guidance. This was evidenced by the repeat failure-to-couple event on August 9.

Following that event, PSEG developed and implemented appropriate guidance (TSO 2013-016). The inspectors noted that operators missed an opportunity to challenge Engineering regarding what was done to correct and/or compensate for the adverse condition before operators declared the PDP fully operable (especially when maintained in standby) in February and June 2013.

Approximately 300 hours0.00347 days <br />0.0833 hours <br />4.960317e-4 weeks <br />1.1415e-4 months <br /> of PDP emergent unavailability (nearly 299 hours0.00346 days <br />0.0831 hours <br />4.943783e-4 weeks <br />1.137695e-4 months <br /> between June 3 and June 15, and 2.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> on August 9) could have been precluded had PSEG implemented the Standing Order guidance during February 2013 to direct equipment operators to vent the 13 PDP discharge pressure to less than 500 psig prior to starting the pump. Additionally, since PSEG could have implemented the venting compensatory measure before restoring the 13 PDP in February 2013, time when the 13 PDP was in standby with Unit 1 charging pressure greater than 500 psig (until issuing the TSO on August 11) represented additional PDP unavailability (as the PDP was not able to provide the post-fire, safe shutdown cross-connect function for Unit 2). The inspectors noted that this amounted to approximately 500 hours0.00579 days <br />0.139 hours <br />8.267196e-4 weeks <br />1.9025e-4 months <br /> of unrecognized PDP unavailability between April 12 and June 3.

With Unit 1 in Modes 1 - 4, PSEG credits the 13 PDP with providing the post-fire, safe shutdown, charging functions that include reactivity management, RCP seal injection, and reactor coolant make-up for a Unit 2 fire in multiple areas. Although PSEG only credits the 13 PDP, the inspectors noted that procedure S1.OP-SO.CVC-0023, CVCS Cross-Connect Alignment to Unit 2, provides direction for operators to open the cross-connect valve if a centrifugal charging pump is in service (with the PDP in standby) to allow the in-service charging pump to promptly provide the charging cross-connect supply to Unit 2 until the PDP can be aligned to perform its credited function. In this case, even if the PDP failed to start in standby, the post-fire, safe shutdown cross-connect function would not be lost; however, the alignment would require Unit 1 to enter TS 3.0.3 (due to failure to meet TS 3.5.2 with an emergency core cooling system centrifugal pump cross-connected to Unit 2) and Unit 1 to shutdown if the PDP was not restored within seven hours. Thus, as long as the PDP discharge isolation valve (1CV64) is maintained open (as it normally is), the in-service centrifugal charging pump can help mitigate a Unit 2 fire in one of the critical plant areas mentioned above. Based on a tagging system and Unit 1 narrative log review, the inspectors determined that operators maintained 1CV64 open with Unit 1 in Modes 1 - 4 during the period February 16 through June 3, 2013.

The inspectors noted that PSEG procedure LS-AA-125, Corrective Action Program, Revision 16, step 4.4.1 states, clearly define actions using the SMARTER criteria provided in Attachment 1. Attachment 1, Corrective Action Development Guidance, step 4 states, Carefully consider actions when a cause is not determined. Interim or compensatory actions may be appropriate pending additional evaluation or trending.

Actions may address the likely cause(s) and then follow-up to ensure no unintended consequences. Alternately, no actions may be recommended with appropriate justification. Contrary to this guidance, the inspectors identified that PSEG did not implement appropriate compensatory measures, pending additional evaluation or trending, when the cause of the February and June failures was not determined.

PSEG entered this issue in their CAP (notification 20638484), implemented a compensatory measure (TSO 2013-016), and initiated actions to correct the condition causing the failure-to-couple events.

Analysis.

The failure to take adequate corrective actions in accordance with the LS-AA-125, Corrective Action Program, Attachment 1 guidance following the 13 PDP failure to couple-on-demand on February 8, 2013, was a performance deficiency within PSEGs ability to foresee and correct. The inspectors determined that the performance deficiency was more than minor because it was associated with the Mitigating System equipment performance attribute and affected the cornerstones objective to ensure the availability and reliability of systems (safe shutdown charging cross-connect) that respond to initiating events (fire) to prevent undesirable consequences (i.e. core damage). Traditional enforcement did not apply since the finding was not willful, did not impact the regulatory process, did not have actual safety consequence, or result in a Severity Level IV violation without a performance deficiency. The inspectors evaluated the finding in accordance with IMC 0609, Appendix F, Fire Protection Significance Determination Process. The inspectors determined that Finding Category 1.4.5 (post-fire, safe shutdown) applied as the finding potentially impacted a system credited for post-fire, safe shutdown. The inspectors determined that the finding was of very low safety significance because the Unit 2 reactor would have been able to reach and maintain safe shutdown, crediting the Unit 1 operating centrifugal charging pump as necessary (based on a yes response to question 1.3.1.A).

This finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Resolution, in that PSEG did not take effective corrective actions to address issues in a timely manner commensurate with their safety significance. Specifically, PSEG did not take adequate corrective actions in response to a 13 PDP failure to couple-on-demand event in February 2013 to preclude several additional unexpected PDP failure on demand events, which resulted in additional unplanned unavailability.

[P.3]

Enforcement.

This finding does not involve enforcement action because no violation of a regulatory requirement was identified. Specifically, the 13 PDP pump is not safety-related and not subject to 10 CFR 50, Appendix B requirements. Notwithstanding, PSEG failed to take corrective actions in accordance with the LS-AA-125, Corrective Action Program, Attachment 1 guidance. PSEG entered this issue into their CAP (notification 20638484), implemented a compensatory measure, and initiated actions to correct the condition causing the failure to couple events. Because this finding does not involve a violation and is of very low safety significance, it is identified as a FIN. (FIN 05000272/2014002-06, Failure to Take Adequate Corrective Actions Following a PDP Failure to Couple-on-Demand Event)

.3 Annual Sample: Loss of Unit 2 Main Bus Duct Cooling

a. Inspection Scope

The inspectors performed an in-depth review of a loss of Unit 2 main bus duct cooling.

On November 27, 2013, the Salem Unit 2 control room received an annunciator for Generator Leads Trouble. An equipment operator reported that the cause of the alarm was associated with the isolated phase bus enclosure High Temperature Phase C. The operator also reported that the drive belts on the 2B main bus duct cooling fan motor were broken. No drive belts were installed by practice on the 2A motor. Control room operators initiated a main turbine load reduction as directed by the alarm response procedure at 1 percent per minute to reduce main generator load to reduce bus conductor temperature. Power was ultimately reduced to 51 percent reactor thermal power. The inspectors assessed PSEGs problem identification threshold, cause analyses, extent of condition reviews, compensatory actions, and the prioritization and timeliness of PSEGs corrective actions to determine whether PSEG was appropriately identifying, characterizing, and correcting problems associated with this issue and whether the planned or completed corrective actions were appropriate. The inspectors compared the actions taken to the requirements of PSEGs CAP and 10 CFR 50, Appendix B. In addition, the inspectors performed field walkdowns and interviewed engineering personnel to assess the effectiveness of the implemented corrective actions.

b. Observations The inspectors reviewed the EQACE and determined that PSEGs problem identification threshold, classification, and compensatory and corrective actions were appropriate and commensurate with the issues safety significance. However, the inspectors had the following observations that were determined to be minor in accordance with IMC 0612:

Timeliness: The inspectors noted that the EQACE was not completed in a timely manner. The original milestone for completion was January 23, 2014. LS-AA-125, Correction Action Program, Revision 17, step 4.3.3 recommends that an apparent cause evaluation be completed within 30 calendar days from the creation and that a committee review the apparent cause evaluation within 2 weeks of completion. The completed EQACE was ultimately reviewed on March 13, 2014, almost two months after its original due date and almost four months after the issue occurred.

Charter: In addition to determining cause of the belt failure, the charter also directed investigation of the cause of an associated cooling air flow loss alarm failure. The inspectors determined that this charter task was incomplete. Specifically, an action item was created from the EQACE to troubleshoot and resolve the air flow loss alarm not annunciating. Additionally, field troubleshooting was beyond the teams responsibilities.

Extent of Condition: The extent of condition was limited to belt-driven fans with no standby motor fan unit. Given that the defined condition was broken drive belts, the inspectors determined this extent was not adequately justified and, therefore, narrow in scope. Specifically, PSEG justified the scope based on the limitation to perform belt tension checks and adjustments at elevated power levels. The inspectors considered this especially noteworthy given a potential trend of belt issues as demonstrated by the following notifications:

11 penetration area cooling fan belts broken, October 2, 2013, 20623347 13 penetration area cooling fan thrown belts, December 25, 2013, 20634640 12 outboard penetration fan belts fell off, October 27, 2013, 20627151 17 turbine generating area fan belt broken, December 2, 2013, 20632142 12 fuel handling building belts shredded, December 6, 2013, 20632756 Alpha building ventilation 1 of 3 fan belts off pulley, March 10, 2014, 20642703 22 circulating water motor heating fan belt snapped, February 16, 2014, 20640105 21 penetration area cooling fan belts broken, March 16, 2014, 20643538

Cause:

PSEG determined a contributing cause was failure to perform in-service tension checks after belt replacement. However, the basis stated that the checks were not performed by Operations direction due to plant operating conditions. This PMT was not performed and marked as not required. The inspectors determined that this contributing cause was potentially inadequate. Specifically, applying Why-chart analysis to the lack of tension checks could result in two causes: the check was not tied to the work schedule and the staff accepted non-performance without challenge or evaluation. While PSEG created an action to schedule the checks prior to turbine startup, the acceptance of omitting the PMT could also reasonably be analyzed for an Organizational and Programmatic contributor as a potential contributing cause.

Additionally, the inspectors determined that an additional contributing cause was missed. Specifically, the main bus cooling air flow loss alarm did not annunciate.

Specifically, the failure to alarm resulted in additional exposure time of the bus duct to elevated current and therefore temperature without adequate cooling and had a direct effect on the consequences.

Extent of

Cause:

The extent of cause was limited to belt-driven maintenance by a specific department during two specific refueling outages. Given that the apparent cause was less than adequate inspection, the inspectors determined that this extent was narrow in scope without documented justification.

PSEG identified one Organizational and Programmatic Contributor of organization-to-organization interface deficiencies. Contrary to LS-AA-125-1003, Apparent Cause Evaluation Manual, Revision 13, step 4.2.9.4 recommendations, PSEG did not create a corrective action that described the new standard or behavior nor did it clearly define a period of active reinforcement actions. Specifically, two associated, long-term action tracking items involved a design change to the duct cooling fan system. Step 4.2.9.4 directs that since organizational causes are more difficult to correct, corrective actions should avoid single-shot actions as they influence behaviors for a limited period and do not produce sustained change.

Maintenance Rule: PSEG originally determined the issue was not a functional failure. After inspectors challenged this, PSEG reanalyzed the issue and determined it was a functional failure and was also maintenance-preventable. PSEG entered this in their CAP (20638061).

c. Findings

Introduction.

The inspectors identified a self-revealing Green FIN against PSEG procedure MA-AA-716-009, Use of Maintenance Procedures, Revision 5, step 1.0, when PSEG staff did not follow the rules of usage for Maintenance Department procedures as applied to work on a Unit 2 isolated phase bus cooling fan. Specifically, PSEG staff did not perform inspection and testing as required. Subsequently, the 2B fan belts broke, causing high temperatures in the bus enclosure, control room alarms, and an unplanned reduction to 51 percent reactor thermal power.

Description.

On November 27, 2013, while at 100 percent power, the Salem Unit 2 control room received an overhead alarm for trouble in the main generator leads. An equipment operator reported that the cause was an isolated phase main bus enclosure high temperature on phase C. The operator also reported that the fan belts on the 2B motor were broken. There were no fan belts installed on the 2A motor by practice.

Operators initiated a main turbine load reduction at 1 percent per minute in accordance with procedures until main generator load did not exceed current/temperature restrictions. When complete, reactor power had been reduced to 51 percent. PSEG entered this item in their CAP (20632543), initiated a prompt investigation, installed fan belts and swapped operations to the 2A motor, monitored their condition weekly, and completed an equipment apparent cause evaluation (70161329).

PSEG determined there was one apparent cause and two contributing causes.

Specifically, the apparent cause was less than adequate inspection of the 2B motor sheave. One of the contributing causes was failure to perform 24-hour and 7-day in-service tension checks and adjustments following drive belt replacement. MA-AA-734-463, Maintenance of Fan Drive Belt Systems, Revision 0, step 2.1 identifies a sheave groove and belt gauge as a required tool. Step 4.6.3 states to inspect fan and motor sheave groove(s) and notes that the sheave should be replaced if more than 1/32 inch of wear can be seen between the sheave gauge and the groove side wall. Section 4.11 describes new belt or sheave break-in. After 24-hours and 7-days, steps 4.11.13 and 4.11.20 require staff to check belt tension in accordance with subsection 4.10 and note that a break-in period is required for new belts or sheaves after replacement. Contrary to these procedural requirements, PSEG staff did not perform these steps under work order 30207763. Specifically, in the case of the inspection, the gauge tool was not used.

In the case of the tension checks, the PMT designated was the tension checks. The coincidental main turbine startup operationally precluded performance of the checks so the staff annotated the test as not required without justification. Post-incident inspection of the sheave revealed that the belt grooves were 1/20 inch, dished out, and excessively worn. PSEG determined that given the sheave material, it was unlikely for the wear to degrade as it did from the time of inspection and belt installation in November 2012.

MA-AA-716-009, step 3.1.1, directs staff to follow the procedure exactly as written. If steps are inappropriate at the time and are to be omitted, the steps should be marked N/A, have the reason explained in the section, documented in the comments, ensure the procedure intent is not changed, and obtain management review. MA-AA-716-012, Post-Maintenance Testing, Revision 18, step 4.4.1, states, A PMT may be waived by Engineering and Operations. Justification for waivers shall be documented in the work package. In the case of the motor sheave, PSEG staff did not follow the procedure as written for use of the gauge. In the case of the tension checks, PSEG staff did not follow the guidance for omission of steps nor did they follow the guidance for waiving the PMT.

With respect to cross-cutting aspects, the inspectors determined that teamwork was a common element to the lack of adherence to procedure usage rules. Specifically, PSEG operations, maintenance, and engineering staff did not coordinate to ensure that inspections and testing were completed appropriately or that decisions not to complete steps as required were reviewed by the appropriate departments.

Analysis.

Non-compliance with procedure usage rules was a performance deficiency within PSEGs ability to foresee and correct. The issue was more than minor since it was associated with the Equipment Performance attribute of the Initiating Events cornerstone and adversely impacted its objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the failure of the drive belts resulted in an unplanned downpower. The finding was then evaluated in accordance with IMC 0609, Attachment 4 and Appendix A, and screened as very low safety significance as a support system initiator. Specifically, the finding did not contribute to the likelihood of, or cause, both an initiating event and affect mitigation equipment.

The finding had a cross-cutting aspect in the area of Human Performance, Teamwork, in that individuals and work groups communicate and coordinate their activities within and across organizational boundaries to ensure nuclear safety is maintained. Specifically, PSEG operations, maintenance, and engineering staff did not coordinate to ensure that inspections and testing were completed appropriately or that decisions not to complete steps as required were reviewed by the appropriate departments. [H.4]

Enforcement.

This finding does not involve enforcement action since no regulatory requirement violation was identified. Because the finding does not involve a violation and is of very low safety significance, it is identified as a finding (FIN). (FIN 05000311/2014002-07, Inadequate Inspection of Isolated Phase Main Bus Duct Cooling Fan Sheave)

4OA3 Follow-Up of Events and Notices of Enforcement Discretion

.1 (Closed) LER 05000272/2011-001-00: Service Water Loop Inoperable for Greater Than

Allowed by Technical Specifications

a. Inspection Scope

On December 9, 2010, during a PSEG walkdown of the Salem Unit 1 SW intake structure bay, severe corrosion was observed at the base of a carbon steel stanchion that supports the power cable for the 12 SW strainer motor. Based on the degree of corrosion, the 12 SW strainer and its associated pump were declared inoperable. The stanchion was repaired and returned to service on December 16, 2010.

The stanchion was previously found to have significant corrosion at its base in 2006 and a work order was initiated to repair the stanchion. However, the priority of the work order was not sufficiently elevated to ensure that the stanchion base was repaired until the December 2010 observation. A subsequent engineering evaluation concluded that the stanchion would have been incapable of withstanding the design seismic loads for the period between 2007 and 2010. A review of past SW pump operability determined that concurrent with the 12 stanchion condition, there were occasions when another SW pump in the bay was inoperable for greater than the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. Inoperability of two SW pumps resulted in a SW loop being inoperable for greater than allowed by TS 3.7.4.1.

The average out-of-service length totaled 106 hours0.00123 days <br />0.0294 hours <br />1.752645e-4 weeks <br />4.0333e-5 months <br />, or 34 hours3.935185e-4 days <br />0.00944 hours <br />5.621693e-5 weeks <br />1.2937e-5 months <br /> beyond the TS 3.7.4.1 allowed outage time.

PSEG performed an apparent cause evaluation of this safety system functional failure and identified several corrective actions, including additional training to new system engineers on the work control process to ensure degraded equipment conditions are addressed in a timely manner. PSEG also conducted an extent of condition review of ten major safety systems for corrosion and degraded structural conditions with no similar conditions identified. As a follow-up, the inspectors examined the material condition of all four SW bays (Units 1 and 2) to identify any similar degraded conditions. This LER was reviewed during this inspection period due to an administrative oversight in Inspection Report 2011-003. This LER is closed.

b. Findings

A licensee-identified NCV is associated with this LER. The enforcement aspects of this event are discussed in section 4OA7 of this report.

.2 (Closed) LER 05000272/2013-001-00: Technical Specification Required Shutdown Due

to Pressurizer Spray Valve Packing Leakage

a. Inspection Scope

On August 22, 2013 at 10:29 a.m., Salem Unit 1 was operating in Mode 1 at 100 percent power when operators responded to indications of reactor coolant leakage inside containment. RCS unidentified leakage was subsequently estimated to be approximately 3.5 gallons per minute. Operators entered TS 3.4.6.2(b) which requires that unidentified leakage be reduced to within the limit of 1 gallon per minute within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> or the plant be in at least Hot Standby within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in Cold Shutdown within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />. A containment walkdown revealed the leakage source as packing leakage on a pressurizer spray valve, 1PS1. Unit 1 commenced reducing load in accordance with operating procedures at 4:29 p.m. A 4-hour notification was made to the NRC at 5:08 p.m., under 10 CFR 50.72(b)(2)(i) for "The initiation of any nuclear plant shutdown required by the plant's Technical Specifications."

Unit 1 entered Hot Standby conditions at 8:05 p.m. Pressurizer spray valve, 1PS1, was isolated at 10:12 p.m. and a subsequent RCS water inventory balance indicated that unidentified leakage had reduced to 0.08 gallons per minute. Unit 1 exited TS 3.4.6.2

(b) on August 23, 2013 at 1:59 a.m. This LER is closed.

b. Findings

A self-revealing Green NCV was identified and documented in NRC Inspection Report 05000272;311/2013-004 (ML13323A526). No additional issues were identified.

.3 Plant Events

a. Inspection Scope

For the plant event listed below, inspectors reviewed and/or observed plant parameters, reviewed personnel performance, and evaluated performance of mitigating systems.

The inspectors communicated the plant event to appropriate regional personnel, and compared the event details with criteria contained in IMC 0309, Reactive Inspection Decision Basis for Reactors, for consideration of potential reactive inspection activities.

As applicable, the inspectors verified that PSEGs operators made appropriate emergency classification assessments and properly reported the event in accordance with 10 CFR Parts 50.72 and 50.73. The inspectors reviewed follow-up actions related to the event to assure that PSEG staff implemented appropriate corrective actions commensurate with their safety significance.

Unit 2, partially dropped control rod and subsequent manual reactor trip on January 31

b. Findings

No findings were identified.

.4 Notice of Enforcement Discretion (NOED) 14-1-02: NOED for PSEG Nuclear Regarding

Salem Unit 2

a. Inspection Scope

On February 13, 2014, the 24 SPT was declared inoperable due to elevated transformer combustible gas levels that indicated an active internal thermal fault. Offsite power for all three 4kV vital busses was shifted to the other offsite power source. Because TS 3.8.1.1, Action a.3, required restoration of the 24 SPT to operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, and the estimated time to replace the transformer with an onsite available spare was estimated to take up to 216 hours0.0025 days <br />0.06 hours <br />3.571429e-4 weeks <br />8.2188e-5 months <br />, or nine days, in total, PSEG requested enforcement discretion for six days beginning at the expiration of the TS Action Statement at 1:56 p.m. on February 16. Based on the NRC staffs evaluation of PSEGs request, to include adequately addressing IMC 0410 criteria, the NRC verbally granted the NOED during a subsequent telephone call at 9:15 p.m. on February 15. PSEG subsequently submitted a letter (ML14048A005) on February 17 documenting information previously discussed with the NRC on telephone conferences held on the evenings of February 14 and 15. Due to the successful completion of the replacement of the 24 SPT ahead of schedule, this NOED was terminated at 3:15 a.m. on February 18, after an elapsed time of just over 37 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-5 months <br />. On February 19, the NRC documented the NOED and confirmation that PSEGs letter was consistent with the NOED request made verbally (ML14050A405).

Inspector activities during the NOED process included review and evaluation of technical documents, participation in teleconferences concerning the NOED request, verification, to the extent practicable, of PSEGs oral assertions before the NOED was granted, and verification of PSEG compensatory actions to reduce the risk to the offsite and onsite safety-related power distribution system.

b. Findings

Introduction.

An Unresolved Item (URI) was identified when PSEG requested, and the NRC granted, enforcement discretion from compliance with Salem TS section 3.8.1, "AC Sources - Operating." The 24 SPT was declared inoperable at 1:56 p.m. on February 13, 2014. The 24 SPT was removed from service as required by guidance contained in an Adverse Condition Monitoring and Contingency Plan when transformer combustible gas levels indicated an active thermal fault. PSEG replaced the existing 24 SPT with a like-for-like spare.

Description.

On February 13, 2014, the 24 SPT was declared inoperable due to elevated transformer combustible gas levels that indicated an active internal thermal fault. Offsite power for all three 4kV vital busses was shifted to the other offsite power source. Because TS 3.8.1.1, Action a.3, required restoration of the 24 SPT to operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, and the estimated time to replace the transformer with an onsite available spare was estimated to take up to 216 hours0.0025 days <br />0.06 hours <br />3.571429e-4 weeks <br />8.2188e-5 months <br />, or nine days, in total, PSEG requested enforcement discretion for six days beginning at the expiration of the TS Action Statement at 1:56 p.m. on February 16. Based on the NRC staffs evaluation of PSEGs request, to include adequately addressing IMC 0410 criteria, the NRC verbally granted the NOED during a subsequent telephone call at 9:15 p.m. on February 15.

PSEG subsequently submitted a letter (ML14048A005) on February 17 documenting information previously discussed with the NRC on telephone conferences held on the evenings of February 14 and 15. Due to the successful completion of the replacement of the 24 SPT ahead of schedule, this NOED was terminated at 3:15 am on February 18, after an elapsed time of just over 37 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-5 months <br />. On February 19, the NRC documented the NOED and confirmation that PSEGs letter was consistent with the NOED request made verbally (ML14050A405).

In accordance with IMC 0410, Notices of Enforcement Discretion, the resident inspectors open an URI when an NOED is granted to determine if there is a performance deficiency for causes which led to the need for the NOED. Further, the inspectors are to document staff determinations regarding enforcement, inspection, verification, and resolution activities in the next appropriate inspection report under the URI. Until these activities are completed, this issue will be treated as a URI. (URI 05000311/2014002-08; NOED for Replacement of 24 Station Power Transformer)

4OA5 Other Activities

.1 Cross-Cutting Aspects

a. Inspection Scope

The table below provides a cross-reference from the third and fourth quarter 2013 findings and associated cross-cutting aspects to the new cross-cutting aspects resulting from the common language initiative. These aspects and any others identified since January 2014, will be evaluated for cross-cutting themes and potential substantive cross-cutting issues in accordance with IMC 0305 starting with the 2014 mid-cycle assessment review.

Inspection finding Old Cross- New Cross-Cutting Aspect Cutting Aspect 2013004-01 Inadequate Maintenance Procedure to P.2(b) P.5 Reconsolidate Pressurizer Spray Valve Packing 2013005-01 Inadequate Assessment of Fire Brigade P.3(a) P.6 Performance during an Unannounced Drill 2013005-03 Inadequate HELB Barrier Controls H.3(a) H.5 2013008-01 Failure to Evaluate Performance Deficiency for P.1(a) P.1 FIN 2011004-02 2013008-02 13 Switchgear and Penetration Area Ventilation None None Supply Fan Motor Bearing Failure due to Deletion of Preventative Maintenance Requirement

b. Findings

No findings were identified.

.2 Ground Water Monitoring Program

a. Inspection Scope

During the period March 4-6, 2014, the inspectors reviewed the results of PSEGs ground water monitoring program. This included PSEGs on-going evaluations associated with the identification, on July 8, 2013, of tritium contamination in a new well (AA-V) placed in the Vincentown formation. This matter had been previously discussed in NRC Integrated Inspection Report Nos. 05000272/2013004 and 05000311/2013004 (ML13323A526).

The inspectors reviewed: on-going evaluations; ground water flow measurements; supplemental public dose projections; remediation efforts and minimization of existing contamination; possible sources of contamination; and groundwater characterization.

The inspectors reviewed PSEG sample results relative to the PSEG Ground Water Monitoring Program and NEI-07-07, Industry Ground Water Protection Initiative. The inspectors also reviewed PSEG sampling results for Salem Unit 1 and Unit 2 seismic gap drains.

b. Findings

No findings were identified.

4OA6 Management Meetings

Exit Meeting Summary

On April 10, the inspectors presented the inspection results to Mr. John Perry, Salem Site Vice President, and other members of the PSEG staff. The inspectors verified that no proprietary information was retained by the inspectors or documented in this report.

4OA7 Licensee-Identified Violations

The following violation of very low safety significance (Green) was identified by PSEG and is a violation of NRC requirements which meets the criteria of the NRC Enforcement Policy for being dispositioned as an NCV.

10 CFR 50, Appendix B, Criterion XVI, requires that measures shall be established to assure that conditions adverse to quality are promptly identified and corrected.

Contrary to these requirements, PSEG did not correct a condition adverse to quality identified in 2006 regarding excessive stanchion corrosion that impacted 12 SW strainer cable support capability during a seismic event until December 2010. As a result, PSEG also violated TS 3.7.4.1, Service Water System, which requires two independent SW loops to be operable. On eight separate occasions between 2007 and December 2010, a SW loop was out-of-service for greater than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> due to SW strainer inoperability concurrent with other SW pump/strainer inoperability.

PSEG entered this issue into their CAP as notification 20491305. The inspectors determined that the finding was of very low safety significance (Green) in accordance with IMC 0609, Attachment A, following a risk evaluation performed by a senior reactor analyst. That evaluation determined that, although degraded, the No. 12 SW strainer was still capable of performing its safety function during a design basis seismic event. Accordingly, full mitigation capability of the SW system was maintained during the subject period from 2007 to 2010 and, consequently, there was no increase in risk to plant operations due to the degraded SW strainer cable support condition.

ATTACHMENT:

SUPPLEMENTARY INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

J. Perry, Site Vice President

L. Wagner, Plant Manager, Salem

C. Aung, Chemist

C. Banner, Emergency Preparedness Manager

J. Bergeron, I&C Manager

D. Boyle, Engineering Programs

T. Cachaza, Regulatory Assurance

K. Chambliss, Regulatory Assurance Manager

L. Clark, Instrument Supervisor

M. Cocking, Fire Protection Supervisor

B. Daly, Nuclear Environmental Affairs, Sustainability

C. Dahms, Regulatory Assurance

R. Dawson, I&C Supervisor

D. Denelsbeck, Radiation Protection Superintendent

R. DeNight Jr., Operations Director

D. Franklin, Technical Specialist

J. Garecht, Manager, Work Management Director, Acting Plant Manager

J. Gebley, Fire Protection Supervisor

K. Hantho, Salem Operations

A. Johns, Radiation Protection Supervisor

B. Ketterer, System Manager

K. King, Regulatory Assurance

L. Kern, Assistant Engineering Director

A. Kraus, Manager, Nuclear Environmental Affairs

D. Lafleur, Regulatory Assurance

A. Niemer, I&C Supervisor

M. Pyle, Chemistry Manager

G. Rich, Chemist

G. Rich, Principal Engineer

S. Swenson, Plant Engineering Manager

S. Swenson, Senior Manager Plant Engineering

S. Taylor, Radiation Protection Manager

G. Toft, Acting Radiation Protection Supervisor

Others

J. Vouglitois, Nuclear Engineer

NJ Department of Environmental Protection

Bureau of Nuclear Engineering

LIST OF ITEMS

OPENED, CLOSED AND DISCUSSED

Open and

Closed

05000272;311/2014002-01 NCV Failure to Follow Fire Protection Test Procedure Resulted in Fuel Oil Spill (Section 1R05)

05000272;311/2014002-02 NCV Inadequate Online Risk Assessment for an Adverse Change in Grid Conditions (Section 1R13)

05000311/2014002-03 NCV Inadequate Risk Assessment and Risk Management Actions for UV Testing (Section 1R13)

05000311/2014002-04 NCV Inadequate Post-Maintenance Testing of a Chiller (Section 1R19)

05000272/2014002-05 NCV Failure to establish appropriate MR performance goals (Section 4OA2)

05000272/2014002-06 FIN Failure to take adequate corrective actions following a PDP failure to couple-on-

demand event (Section 4OA2)

05000311/2014002-07 FIN Inadequate Inspection of Isolated Phase Main Bus Duct Cooling Fan Sheave (Section 4OA2)

05000311/2014002-08 URI NOED for Replacement of 24 Station Power Transformer (Section 4OA3)