IR 05000272/2013005

IR 05000272-13-005 05000311-13-005 10/01/2013 - 12/31/2013; Salem Nuclear Generating Station Units 1 and 2; Fire Protection, Plant Modifications

ML14037A204
Person / Time
Site:	Salem
Issue date:	02/06/2014
From:	Glenn Dentel Reactor Projects Branch 3
To:	Joyce T Public Service Enterprise Group
dentel, gt
References
IR-13-005
Download: ML14037A204 (63)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION ary 6, 2014

SUBJECT:

SALEM NUCLEAR GENERATING STATION, UNIT NOS. 1 AND 2 -

NRC INTEGRATED INSPECTION REPORT 05000272/2013005 AND 05000311/2013005

Dear Mr. Joyce:

On December 31, 2013, 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 January 9, 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 two NRC-identified findings of very low safety significance (Green).

Both of these findings were determined to involve violations of NRC requirements. However, because of the very low safety significance and because they are entered into your corrective action program (CAP), the NRC is treating these findings as non-cited violations (NCVs)

consistent with Section 2.3.2 of the NRCs Enforcement Policy. If you contest any NCV in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the 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 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. As a result of the Safety Culture Common Language Initiative, the terminology and coding of cross-cutting aspects were revised beginning in calendar year (CY) 2014. New cross-cutting aspects identified in CY 2014 will be coded under the latest revision to IMC 0310. Cross-cutting aspects identified in the last six months of 2013 using the previous terminology will be converted to the latest revision in accordance with the cross-reference in IMC 0310. The revised cross-cutting aspects will be evaluated for cross-cutting themes and potential substantive cross-cutting issues in accordance with IMC 0305 starting with the CY 2014 mid-cycle assessment review.

In accordance with 10 Code of Federal Regulations 2.390, Public Inspections, Exemptions, Requests for Withholding, of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records System (PARS) component of NRC's Agencywide Documents Access and Management System (ADAMS). ADAMS is accessible from the NRC Web site 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 05000272/2013005 and 05000311/2013005 w/Attachment: Supplementary Information

REGION I==

Docket Nos.: 50-272, 50-311 License Nos.: DPR-70, DPR-75 Report No.: 05000272/2013005 and 05000311/2013005 Licensee: PSEG Nuclear LLC (PSEG)

Facility: Salem Nuclear Generating Station, Units 1 and 2 Location: P.O. Box 236 Hancocks Bridge, NJ 08038 Dates: October 1, 2013 through December 31, 2013 Inspectors: P. Finney, Senior Resident Inspector A. Ziedonis, Resident Inspector J. Furia, Senior Health Physicist R. Barkley, Senior Project Engineer A. DeFrancisco, Project Engineer H. Gray, Senior Reactor Inspector R. Nimitz, Senior Health Physicist J. Schoppy, Senior Reactor Inspector K. Young, Senior Reactor Inspector M. Modes, Senior Reactor Inspector D. Silk, Operator License Examiner J. Laughlin, Senior EP Inspector, NSIR Approved By: Glenn T. Dentel, Chief Reactor Projects Branch 3 Division of Reactor Projects Enclosure

SUMMARY

Inspection Report (IR) 05000272/2013005 05000311/2013005 10/01/2013 - 12/31/2013; Salem

Nuclear Generating Station Units 1 and 2; Fire Protection, Plant Modifications.

This report covered a three-month period of inspection by resident inspectors and announced inspections performed by regional inspectors. Inspectors identified two NCVs 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, Components Within Cross-Cutting Areas, dated October 28, 2011. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy, dated January 28, 2013. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.

Cornerstone: Mitigating Systems

Green.

The inspectors identified a Green NCV of Unit 2 license condition 2.C.(10), Fire Protection, when PSEG did not adequately assess fire brigade performance during an unannounced drill on November 18, 2013, as required by the fire protection program.

Specifically, PSEG did not adequately assess the selection, placement and use of equipment and fire-fighting strategies, conformance with established plant fire-fighting procedures, and the use of fire-fighting equipment, including communication equipment.

PSEG entered this into their CAP as notification 20632422 and chartered an apparent cause evaluation.

The inspectors determined that the issue was more than minor since it was associated with the protection against external events (fire) attribute of the Mitigating Systems cornerstone and impacts its objective of ensuring the availability, reliability, and capability of systems, such as the fire brigade, that respond to initiating events to prevent undesirable consequences. The finding was determined to be of very low safety Significance (Green) in accordance with D.1 of IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions. Because the finding involved fire brigade training requirements, the fire brigade demonstrated the ability to meet the required times for fire extinguishment for the fire drill scenarios, and the finding did not significantly affect the fire brigades ability to respond to a fire, the finding was of very low safety significance (Green). The finding was determined to have a cross-cutting aspect in the area of Problem Identification and Resolution, Self and Independent Assessments, in that licensees conduct assessments of their activities to assess performance and identify areas of improvement. Specifically, the PSEG self-evaluation of fire brigade performance was not of sufficient depth, appropriately objective, and self-critical. P.3(a) (Section 1R05)

Green.

The inspectors identified a Green NCV of TS 6.8.1, Procedures and Programs, as described in Regulatory Guide (RG) 1.33, Revision 2, when PSEG did not properly implement high energy line break (HELB) barrier controls in accordance with CC-AA-201,

Plant Barrier Control, during maintenance activities that affected the performance of safety-related equipment on October 1, 2 and 17, 2013. PSEG entered the issue into the CAP under notifications 20623371 and 20633614.

This finding was more than minor because it was associated with the configuration control 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 to prevent undesirable consequences. Specifically, improper barrier controls could potentially affect the operating equipment in the case of a HELB. This performance deficiency required a detailed risk evaluation (DRE) in accordance with IMC 0609, Appendix A, screening questions in Exhibits 2, Mitigating Systems, because of an assumed loss of the AFW system decay heat removal safety function. The inspectors and a Region I Senior Reactor Analyst (SRA) conducted a bounding DRE and determined this finding to be of very low safety significance (Green). This finding had a cross-cutting aspect in the area of Human Performance, Work Control, in that licensees plan and coordinate work activities by incorporating the need for planned contingencies, compensatory actions, and abort criteria.

Specifically, PSEG did not properly plan and coordinate compensatory actions via station procedures for HELB barrier impairments. H.3(a) (Section 1R18)

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period at 100 percent power. 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 October 14, the unit was reduced to approximately 85 percent power for 500 kV line outage planned maintenance. The unit was restored to full power on October 16. On November 27, the unit was reduced to approximately 55 percent power in response to failure of the 2A main bus duct cooling fan. Full power was restored later the same day. 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

.1 Readiness for Impending Adverse Weather Conditions

a. Inspection Scope

The inspectors reviewed PSEGs preparations for Units 1 and 2 during a tornado watch on October 7, 2013. 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 circulating water system, protected area, and emergency service water 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.

b. Findings

No findings were identified.

.2 External Flooding

a. Inspection Scope

During the week of November 8, the inspectors performed an inspection of the external flood protection measures for Salem Units 1 and 2. The inspectors reviewed technical specifications, procedures, design documents, and the UFSAR, which depicted the design flood levels and protection areas containing safety-related equipment to identify areas that may be affected by external flooding. The inspectors conducted a general site walkdown of all external areas of the plant, including the turbine building, auxiliary building, and berm to ensure that PSEG erected flood protection measures in accordance with design specifications. The inspectors also reviewed operating procedures for mitigating external flooding during severe weather to determine if PSEG planned or established adequate measures to protect against external flooding events.

b. Findings

No findings were identified.

1R04 Equipment Alignment

.1 Partial System Walkdowns

a. Inspection Scope

The inspectors performed partial walkdowns of the following systems:

Unit 1, auxiliary feedwater (AFW) during steam generator control valve, 14AF21, repairs Unit 1, 11, 13, 14, and 15 containment fan cooler units (CFCUs) during 12 CFCU emergent repair Unit 1, Safety injection following restoration from planned maintenance Unit 1, 125 VDC following PSEG identification of degraded battery cells Unit 2, auxiliary building ventilation (ABV) during 23 ABV exhaust fan inoperability 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 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.

.2 Full System Walkdown

a. Inspection Scope

On December 10, 11 and 12, the inspectors performed a complete system walkdown of accessible portions of the Unit 2 Auxiliary Feedwater system to verify the existing equipment lineup was correct. The inspectors reviewed operating procedures, surveillance tests, drawings, equipment line-up check-off lists, and the UFSAR to verify the system was aligned to perform its required safety functions. The inspectors also reviewed electrical power availability, component lubrication and equipment cooling, hanger and support functionality, and operability of support systems. The inspectors performed field walkdowns of accessible portions of the systems to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no deficiencies. Additionally, the inspectors reviewed a sample of related notifications and work orders to ensure PSEG appropriately evaluated and resolved any deficiencies.

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, AFW pumps area

(84) Unit 2, Electrical penetration area

(78) Unit 2, Mechanical piping penetration area

(78) Unit 2, AFW pumps area

(84) Units 1 and 2, 460V switchgear

(84) and relay rooms (100)

b. Findings

No findings were identified.

.2 Fire Protection - Drill Observation

a. Inspection Scope

The inspectors observed a fire brigade drill scenario conducted on November 18 that involved a simulated fire in the Unit 2 waste evaporator room. The inspectors evaluated the readiness of the plant fire brigade to fight fires. The inspectors verified that PSEG personnel identified deficiencies, openly discussed them in a self-critical manner at the debrief, and took appropriate corrective actions as required. The inspectors evaluated specific attributes as follows:

Proper wearing of turnout gear and self-contained breathing apparatus Proper use and layout of fire hoses Employment of appropriate fire-fighting techniques Sufficient fire-fighting equipment brought to the scene Effectiveness of command and control Search for victims and propagation of the fire into other plant areas Smoke removal operations Utilization of pre-planned strategies Adherence to the pre-planned drill scenario Drill objectives met The inspectors also evaluated the fire brigades actions to determine whether these actions were in accordance with PSEGs fire-fighting strategies.

b. Findings

Introduction.

The inspectors identified a Green NCV for the inadequate assessment of fire brigade performance during an unannounced fire drill, as required by the fire protection program. Specifically, PSEG did not adequately assess the selection, placement and use of equipment and fire-fighting strategies, conformance with established plant fire-fighting procedures, and the use of fire-fighting equipment, including communication equipment.

Description.

On November 18, 2013, the inspectors observed an unannounced fire brigade drill involving a simulated fire in the Unit 2 waste evaporator room in the auxiliary building. The inspectors observed the drill in and around the fire area and noted a number of discrepancies:

There was an insufficient length of hose to enter the fire area. After simulating charging the hose, the brigade recognized the need for more hose, returned to the fire pumper, acquired the additional hose, and reassembled the hose line.

The pre-fire plan did not address a fire in the drill area. For example, the pre-fire plan designated the command center inside the building, while the only means of access to the fire area was from outside the auxiliary building. The designated suppression equipment was fire hoses located inside the auxiliary building, but were beyond the reach of the brigade. The inspectors determined that the lack of a pertinent pre-fire plan section was a direct contributor to the fire brigade having inadequate sections of fire hose for the area. According to NC.DE-PS.ZZ-0001-A6-GEN, Salem Fire Protection Report - General, Appendix 6, Revision 2, the purpose of pre-fire plans are to provide a reference document indicating information useful to the plant fire department for conducting a safe and effective attack on a fire in a particular plant area. The plans are developed for emergency fire ground operations. SH.FP-EO.ZZ-0002, Fire Department Fire Response, Revision 3, step 3.12, requires the brigade leader to reference the applicable pre-fire plans.

Lack of line of sight between the fire brigade leader, who was at the fire pumper, and the brigade at the fire scene. SH.FP-EO.ZZ-0002, step 3.15, requires the brigade leader to utilize a command check sheet, maintain firefighter accountability, and conduct periodic checks of personnel on scene to benchmark progress and allow for continuous safety checks of personnel.

The lead brigade member on the hose attempted to enter the fire space without gloves and was coached by a drill monitor.

Contrary to requirements of OP-AA-101-111, Roles and Responsibilities of On-Shift Personnel, Revision 4, the liaison was not qualified as an equipment operator, reactor operator, or senior reactor operator. Additionally, the Fire Brigade Liaison had a cell phone but no radio. S2.OP-AB.FIRE-0002, Control Room Fire Response, Revision 8, step 3.4 designates the position as having a radio call sign. The procedure designates this as critical support to the Fire Department.

The ambulance was not dispatched in accordance with SH.FP-EO.ZZ-0002, step 2.4.1.

The inspectors observed the post-drill critique and then reviewed the completed drill evaluation package. PSEG entered the observation on the gloves in an enhancement database, despite issues with gloves and personal protective equipment observed by PSEG on three prior drills since August 2013. None of the discrepancies identified by the inspectors were captured or documented by PSEG. At the post-drill critique, brigade members discussed how some brigade members had drilled in this area on a number of previous occasions. This meant that brigade teams had prior opportunities to identify that the pre-fire plan was inadequate. Finally, there were no failure criteria designated for unannounced drills.

NC.DE-PS.ZZ-0001-A6-GEN section 5.2.7(c) describes fire drills. It states, in part, drill scenarios are to allow for assessment of the following:selection, placement, and use of equipment including communication equipment, fire-fighting strategies, use of procedures and pre-fire plan. FP-AA-014, Fire Protection Training Program, Revision 1, step 4.7.3, states that unannounced fire drills shall be conducted to test the readiness of the fire brigade, shall include objectives, and should be evaluated. Step 4.7.1.5 states, in part, conditions, which are adverse to quality, shall be documented in accordance with LS-AA-120, Issue Identification and Screening Process. Enclosure 5, Evaluation of Unannounced Fire Drills, states that the following items shall be assessed when conducting a fire drill and includes selection, placement, and use of equipment and fire-fighting strategies, conformance with established plant fire-fighting procedures and use of fire-fighting equipment, including communication equipment.

The inspectors determined that PSEGs assessment of fire brigade performance was not self-critical and of sufficient depth to identify discrepancies in accordance with fire protection program procedures and consequently not corrected without NRC identification and prompting. PSEG entered this issue in their CAP as notification

===20632422.

Analysis.

The inspectors determined that the inadequate assessment of fire brigade performance was a performance deficiency within PSEGs ability to foresee and correct.

The issue was more than minor since the deficiency was associated with the protection against external events (fire) attribute of the Mitigating Systems cornerstone and impacted its objective of ensuring the availability, reliability, and capability of systems, such as the fire brigade, that respond to initiating events to prevent undesirable consequences. The finding was determined to be of very low safety Significance (Green) in accordance with D.1 of IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions. Because the finding involved fire brigade training requirements, the fire brigade demonstrated the ability to meet the required times for fire extinguishment for the fire drill scenarios, and the finding did not significantly affect the fire brigades ability to respond to a fire, the finding screened to Green.

This finding was determined to have a cross-cutting aspect in the area of Problem Identification and Resolution, Self and Independent Assessments, in that licensees conduct assessments of their activities to assess performance and identify areas of improvement. Specifically, the PSEG self-evaluation of fire brigade performance was not of sufficient depth, appropriately objective, and self-critical (P.3(a)).

Enforcement.

The Salem Unit 2 Operating License Condition 2.C.10, Fire Protection, requires that PSEG shall implement and maintain in effect all provisions of the approved fire protection program as described in the UFSAR. Implementing procedure FP-AA-014, Fire Protection Training Program, Enclosure 5, requires that the following items shall be assessed when conducting a fire drill and includes selection, placement, and use of equipment and fire-fighting strategies, conformance with established plant fire-fighting procedures and use of fire-fighting equipment, including communication equipment. Contrary to the above, during the unannounced fire drill on November 18, 2013, the fire brigade's performance was not adequately assessed. Because the finding was of very low safety significance, was entered into PSEG's CAP as Notification 20632422, and prompted an apparent cause evaluation, this violation is being treated as an NCV consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000311; 2013005-01, Inadequate Assessment of Fire Brigade Performance during an Unannounced Drill)

1R06 Flood Protection Measures

Annual Review of Cables Located in Underground Bunkers/Manholes

a. Inspection Scope

The inspectors conducted an inspection of underground bunkers/manholes subject to flooding that contain cables whose failure could affect risk-significant equipment. The inspectors performed walkdowns of risk-significant areas, SWI-1, TG-2, and GBT 13 and 24, to verify that the cables were not submerged in water, that cables and/or splices appeared intact, and to observe the condition of cable support structures. When applicable, the inspectors verified proper sump pump operation and verified level alarm circuits were set in accordance with station procedures and calculations to ensure that the cables will not be submerged. The inspectors also ensured that drainage was provided and functioning properly in areas where dewatering devices were not installed.

For those cables found submerged in water, the inspectors verified that PSEG had conducted an operability evaluation for the cables and were implementing appropriate corrective actions.

b. Findings

No findings were identified.

1R07 Heat Sink Performance

.1 Annual Heat Sink Performance

a. Inspection Scope

The inspectors reviewed the Unit 1, 11 chiller condenser, 1CHE14, (work order 30189793) on October 3, to determine its readiness and availability to perform its safety functions. The inspectors reviewed the design basis for the component and verified PSEGs commitments to NRC Generic Letter 89-13. The inspectors discussed the results of the most recent inspection with engineering staff and reviewed the as-found and as-left conditions. The inspectors verified that PSEG initiated appropriate corrective actions for identified deficiencies. The inspectors also verified that the number of tubes plugged within the heat exchanger did not exceed the maximum amount allowed.

b. Findings

No findings were identified.

.2 Triennial Heat Sink Performance

a. Inspection Scope

Based on a plant specific risk assessment, previous inspections, recent operational experience, and resident inspector input, the inspectors selected the following heat sink samples:

Unit 1, 12 charging pump gear oil cooler (1CVE42)

Unit 2, 22 safety injection (SI) pump lubricating oil cooler (2SJE101)

Unit 2, auxiliary feedwater (AFW) pump room cooler (2SWE17)

The Delaware River functions as the ultimate heat sink (UHS) for both Salem units. The safety-related service water (SW) pumps take suction from the Delaware River and supply cooling to the SI pump lubricating oil coolers, AFW room coolers, and centrifugal charging pump gear oil coolers. The lubricating oil and gear oil coolers transfer pump heat to the UHS to ensure the respective pumps can perform their emergency core cooling system (ECCS) functions under all design basis conditions. The primary function of the AFW room cooler is to remove heat from the AFW pump area in the auxiliary building, which contains the safety-related AFW pumps and other essential plant equipment.

The inspectors reviewed PSEGs methods (inspection, cleaning, maintenance, and performance monitoring) used to ensure heat removal capabilities for the selected heat exchangers (HXs) and compared them to PSEGs commitments made in response to NRC Generic Letter 89-13, Service Water System Problems Affecting Safety-Related Equipment. The inspectors reviewed associated inspection work orders and eddy current test results to verify that the as-found and as-left condition of the HXs were bounded by assumptions in the engineering analyses and provided reasonable assurance of continued operability. The inspectors verified that PSEG initiated appropriate corrective actions for identified deficiencies. The inspectors also verified that the number of tubes plugged within the respective HXs did not exceed the maximum amount assumed in the design analysis. The inspectors reviewed PSEGs HX inspection guidance and sampled documented results to ensure that PSEG established appropriate visual inspection acceptance criteria and to verify that the associated HX had not degraded to the point that it could not perform its intended safety function.

The inspectors reviewed HX differential pressure (D/P) and flow rate trending data to assess HX condition and potential macrofouling. The inspectors reviewed applicable D/P trending calculations and biofouling performance test (PT) procedures to ensure that PSEG used appropriate design assumptions, established adequate test control, and adequately translated the design basis into the PT acceptance criteria. The inspectors also reviewed recent Technical Specification surveillance test results for the associated SI, AFW, and charging pumps to verify that the results were acceptable and that operation was consistent with the design.

The inspectors performed a walkdown of accessible areas containing SW piping to look for indications of piping leakage and/or degradation. The inspectors walked down control room instrument panels, accessible portions of SW piping in the U1 and U2 auxiliary buildings (including the SI lubricating oil coolers, charging pump gear oil coolers, and AFW room coolers), the Unit 2 SW pipe tunnel, and the intake area (including the trash racks, SW pumps and strainers, SW traveling water screens, and structural supports) to assess the material condition and configuration control of these structures, systems, and components (SSCs). The inspectors also reviewed a sample of corrective action notifications (NOTFs) related to the selected HXs and SW system to ensure that PSEG appropriately identified, characterized, and corrected problems related to these essential SSCs.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program (71111.11Q - 2 samples, 71111.11B - 1

sample)

.1 Quarterly Review of Licensed Operator Requalification Testing and Training

a. Inspection Scope

The inspectors observed licensed operator simulator training on December 6, 2012, which included a seismic event coincident with a fuel failure, steam generator tube rupture, stuck open steam generator safety valve and the failure of selected components to automatically start as required. 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 technical specification 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 Unit 2 reactor shutdown for a refueling outage on October 14, 2012, Unit 2 B train mode operations test conducted on October 16, 2012, and the Unit 1 reactor startup transition from auxiliary feedwater to main feedwater conducted on November 2, 2012. The inspectors observed infrequently performed test or evolution briefings, procedure use, crew communications, coordination of activities between work groups, and the oversight and direction provided by the control room supervisor to ensure it met Operations Fundamentals, OP-AA-101-111-1002, Steam Generator Feed Pump Operation, S2.OP-CN-0002, and Cold Shutdown to Hot Standby, S2.OP-IO.ZZ-0002.

b. Findings

No findings were identified.

.3 Biennial Review by Regional Specialist

a. Inspection Scope

The following inspection activities were performed using NUREG-1021, "Operator Licensing Examination Standards for Power Reactors," Revision 9, Supplement 1, Inspection Procedure Attachment 71111.11, Licensed Operator Requalification Program.

Examination Results The operating tests for the weeks of August 19, 2013, and September 16, 2013 were reviewed for quality and performance.

On November 4, 2013, the results of the annual operating tests were reviewed to determine if pass fail rates were consistent with the guidance of NUREG-1021, "Operator Licensing Examination Standards for Power Reactors," Revision 9, Supplement 1, and NRC Manual Chapter 0609, Appendix I, Operator Requalification Human Performance Significance Determination Process. (There was no written requalification examination administered in 2013.) The review verified that the failure rate (individual or crew) did not exceed 20%.

10 out of 68 operators failed at least one section of the Annual Examination. The overall individual failure rate was 14.7%.

1 out of 11 crews failed the simulator test. The crew failure rate was 9.9%

Observations were made of the dynamic simulator examinations and job performance measures (JPM) administered during the week of September 16, 2013. These observations included facility evaluations of crew and individual performance during the dynamic simulator examinations and individual performance of five JPMs.

Written Examination Quality The inspector reviewed two written examinations administered during the 2012 examination cycle for qualitative and quantitative attributes as specified on Appendix B of Attachment 71111.11, Licensed Operator Requalification.

Operating Test Quality Ten JPMs and five scenarios were reviewed for qualitative and quantitative attributes as specified in Appendix C of Attachment 71111.11, Licensed Operator Requalification.

Licensee Administration of Operating Tests Observations were made of the dynamic simulator examinations and JPMs administered during the week of September 16, 2013. These observations included facility evaluations of crew and individual performance during the dynamic simulator examinations and individual performance of five JPMs.

Examination Security The inspectors assessed whether facility staff properly safeguarded examination material. JPMs, scenarios, and written examinations were checked for excessive overlap of test items.

Remedial Training and Re-Examinations The remediation plans for a two senior reactor operators (SROs) individual dynamic simulator failures and one SRO written failure were reviewed to assess the effectiveness of the remedial training.

Conformance with Operator License Conditions Medical records for eight SRO licenses and six reactor operator licenses were reviewed to assess conformance with license conditions.

Proficiency watch standing records were reviewed for 2011, 2012, and the first 2 quarters of 2013.

The reactivation plan for one SRO license was reviewed to assess the effectiveness of the reactivation process.

Records for the participation of licensed operators in the requalification program from January 1, 2011, through August 31, 2013 were reviewed. Records for the performance of licensed operators on annual requalification operating test and biennial requalification written examinations were reviewed.

Simulator Performance Simulator performance and fidelity was reviewed for conformance to the reference plant control room. A sample of simulator deficiency reports was also reviewed to ensure facility staff addressed identified modeling problems. Simulator test documentation was also reviewed.

Problem Identification and Resolution A review was conducted of recent operating history documentation found in inspection reports, the licensees corrective action program, and the most recent NRC plant issues matrix. The inspectors also reviewed specific events from the PSEGs CAP which indicated possible training deficiencies, to verify that they had been appropriately addressed. The senior resident inspector was also consulted for insights regarding licensed operators performance.

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 SSC performance and reliability. The inspectors reviewed system health reports, CAP documents, maintenance WOs, and maintenance rule (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 1, reactor trip breakers Unit 2, 2B fan belt failure Unit 2, 2C EDG control area fan failure

b. Findings

Introduction.

Inspectors identified an Unresolved Item (URI) concerning Maintenance Rule functional failure determinations of Unit 1 reactor trip breakers. PSEG commenced re-evaluating the equipment issues and entered the concerns in their CAP as 20634111 and 2064110.

Description.

During the inspection period, inspectors selected the Unit 1 reactor trip breakers as a Maintenance Effectiveness inspection sample in accordance with IP 71111.12. The inspectors questioned PSEG concerning two notifications written on the 1B normal and 1A bypass reactor trip breakers that did not meet as-found acceptance criteria during semi-annual maintenance. Specifically, the 1B normal reactor trip breaker failed undervoltage (UV) trip time response and trip bar force criteria on December 11, 2012, and the 1A reactor trip bypass breaker failed the UV trip assembly degradation value on July 16, 2013. Within 15 days of these discoveries, in accordance with procedure ER-AA-310-1004, Maintenance Rule - Performance Monitoring, Revision 10, PSEG determined that both of these issues were not Maintenance Rule Functional Failures (MRFFs).

The inspectors reviewed the Maintenance Rule aspects of these issues and developed concerns regarding the same. The inspectors questioned whether the breakers met the MRFF criteria. Specifically, one of the MRFF examples was failure to meet acceptance criteria in SC.MD-PM.RCP-0001, Reactor Trip Breaker Semi-Annual Inspection, Lubrication, and Testing, Revision 19, for trip bar force, UV trip bar force, ten times testing, and trip time response. The 1B normal reactor trip breaker issue matched the criterion. The 1A bypass breaker also met the criterion with the exception that it was covered by a separate maintenance procedure (SC.MD-PM.RCP-0003). The acceptance criteria for normal and bypass breakers were the same and the bypass breakers perform the same function of the normal breakers during their substitution.

The 1B normal trip breaker evaluation stated that the apparent cause was due to insufficient lubrication of trip latch during prior preventive maintenance. The inspectors considered this a potential for the failure to be a maintenance-preventable functional failure (MPFF). The rod control system performance criterion (PC) was 6 MPFFs in 36 months. The inspectors considered this a high threshold for a component whose high risk function is to remove power from control rod drive mechanisms on valid manual or automatic trip signals. Since there are four breakers per unit that undergo semi-annual testing, an assessment of performance under 10 CFR 50.65(a)(1) would require a 25%

failure rate that was also attributable to maintenance. The inspectors found no evidence that this issue was captured previously in PSEGs CAP. Finally, ER-AA-310-1003, Maintenance Rule - Performance Criteria Selection, Revision 6, directs that Maintenance Rule SSCs with a risk achievement worth (RAW) greater than 10 require both reliability and condition-monitoring performance criteria. The Unit 1 reactor trip breakers have a RAW on the order of 1200. Condition-monitoring PC did not exist and this had not been documented in PSEGs CAP. The inspectors presented these concerns to PSEG on December 20, 2013.

During an inspector discussion with PSEG engineering on the issues, PSEG provided notification 20627747 written on October 30, 2013, which needed additional information to document the basis for the Maintenance Rule determination that included the two issues mentioned above. PSEG stated that this CAP item was written to revisit the MRFF determinations previously completed. The inspectors reviewed the notification and noted that 60 days later, the MRFFs had not been revisited, the assigned action was to enhance MRule screening vice a re-evaluation, and that it was due on December 20, 2014. Following inspector questioning, PSEG re-evaluated the issues and determined that the 1B normal reactor trip breaker had been an MRFF. PSEG is in the process of further evaluating the 1B normal breaker MRFF to determine whether it was a maintenance-preventable functional failure (MPFF). PSEGs re-evaluation of the 1A bypass breaker as an MRFF was that it was still not one based on the MRFF criteria currently written in specific to the reactor trip breaker procedure and not the trip bypass breaker procedure. The inspectors pointed out that the MRFF criteria included a statement that said Functional failures include, but are not limited to... prior to the list.

A URI was identified because additional NRC review and evaluation is needed to determine if the issue is more than minor and whether the issue of concern constitutes a violation. The inspectors need to review PSEGs ultimate determination of the MRFF and MPFF aspects of these breakers to determine if performance was being effectively controlled and monitored. The inspectors will also assess whether additional monitoring is warranted under 10 CFR 50.65(a)(1) and thus any violations existed of this criteria.

As a result, this issue will be considered unresolved pending inspector review of the MRFF determinations and any consequent evaluations of causes and maintenance rule re-classification. Pending resolution of this issue and determination of any potential enforcement actions, this item is a URI. (URI 05000272/2013005-02, Performance Monitoring of Reactor Trip Breakers)

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, solid state protection system (SSPS) B power supply failure Unit 2, 22 CFCU motor unsatisfactory megger check

b. Findings

No findings were identified.

1R15 Operability Determinations and Functionality Assessments

a. Inspection Scope

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

Unit 1, AMSAC functional test failure Unit 2, 24 CFCU flowing leak repair Unit 2, 23 ABV exhaust fan vibrations Unit 2, Reactor coolant system instrument vent cap leakage Common, PORV block valves exceeded EQ service life Common, Unit 3 jet functionality following failure to start 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 to a Unit 2 turbine-driven auxiliary feedwater (TDAFW) high energy line break damper, a Unit 1 & 2 auxiliary building ventilation pressure transmitter replacement, and a reduction in the frequency of Safeguards Equipment Control (SEC) Sequencer surveillance (SR 4.3.2.1.1.6.6) common to both units. 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

Introduction.

The inspectors identified a Green NCV of TS 6.8.1, Procedures and Programs, as described in Regulatory Guide (RG) 1.33, Revision 2, February 1978, when PSEG did not properly implement high energy line break (HELB) barrier controls in accordance with CC-AA-201, Plant Barrier Control, Revision 4, during maintenance activities that affected the performance of safety-related equipment on October 1, 2 and 17, 2013.

Description.

On October 1 and 2, 2013, PSEG performed planned maintenance on the Unit 2 turbine driven auxiliary feedwater (TDAFW) pump HELB enclosure damper 2ABS3. During the planned maintenance, the inspectors observed the HELB enclosure door opened for up to approximately two hours at a time, welding power cables were periodically routed through the door opening, and the dedicated barrier attendant was located inside the HELB enclosure at the end opposite of the door. The enclosure is credited to mitigate a design basis HELB of the TDAFW steam line, as described in UFSAR section 3.6.5.6, and the enclosure is credited as a steam barrier, as described in section 3.6.5.10. UFSAR sections 3.6.5.6 and 10.4.7.2.2 state that a rupture of the steam supply to the turbine will not result in a loss of the two motor-driven AFW pumps, and the motor-driven AFW pumps are credited to deliver adequate flow to the steam generators following a rupture in the steam line to the turbine pump. The motor-driven AFW pumps are located outside and adjacent to the HELB enclosure.

On October 17, 2013, the inspectors observed maintenance on a valve inside a service water vault on Unit 1 mechanical penetration elevation 78. During the activity, technicians left a watertight door opened, without a dedicated attendant, on two separate occasions for up to 20 minutes. When the inspectors questioned the technicians, they cited a placard on the door that read, This door must remain closed with all dogs latched except for access and maintenance activities. With this door open in Modes 1 to 4, continuous area monitoring is required. In case of any pipe break in this room or adjacent room(s), warn others to leave the area, close the door if possible, and inform the control room immediately. Reference 70047142 Operation 0050 S1-OP-05-001.

The technicians explained that since they were doing maintenance, they were exempt from requirements associated with barrier control. A review of the evaluation cited on the placard revealed that the door had two design functions: to protect equipment outside the vault from a moderate energy line break (MELB) of the service water piping inside the vault, and to protect equipment inside the vault from an outside HELB event.

PSEGs evaluation determined that a continuous area monitor was required to close the door, and in the case of a rupture, warn others to leave the area and inform the Control Room during operation in Modes 1 through 4.

CC-AA-201 implements compensatory measures when HELB barriers are impaired.

Step 3.5.2 requires, in part, that credited design barriers have an attendant stationed at the opening with a means to rapidly close the opening and restore the barrier function to a condition equivalent to the design condition. The inspectors determined that, for the examples presented above, PSEG was not properly implementing their Barrier Control Program as required under CC-AA-201. For the example involving the TDAFW enclosure, the inspectors determined that PSEG had not stationed an attendant at the enclosure opening, and when the power cables were routed through the doorway, it prevented rapid closure of the opening to a condition equivalent to the design similar to an example described in RIS 2001-09. For the service water vault example, the inspectors determined that PSEG did not implement compensatory measures as required by procedure and a corresponding engineering evaluation. PSEG entered these issues into the CAP under notifications 20623371 and 20633614 respectively.

Analysis.

The inspectors determined that PSEGs improper implementation of barrier controls during maintenance activities, in accordance with CC-AA-201, Plant Barrier Control, constituted a Green NCV of TS 6.8.1, Procedures and Programs, and as described in Regulatory Guide (RG) 1.33, Revision 2, February 1978. This finding was more than minor because it was associated with the configuration control attribute of the Mitigating System cornerstone, and adversely affected the associated cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, improper barrier controls could potentially affect the operating equipment lineup in the case of a HELB.

This performance deficiency required a detailed risk evaluation (DRE) in accordance with IMC 0609, Appendix A, screening questions in Exhibit 2, Mitigating Systems, because of an assumed loss of the AFW system decay heat removal safety function.

Specifically, there was no engineering assurance that both motor driven AFW pumps would continue to operate, due to environmental conditions, if the turbine drive AFW pump main steam piping ruptured while the HELB door was open. Additionally, the AFW HELB loss of function bounded the HELB example at the service water vault.

The inspectors and a Region I Senior Reactor Analyst (SRA) conducted a bounding DRE determining this finding to be of very low safety significance (Green). The analysis estimated a very low chance of a steam line rupture for the limited time that the HELB door was open, based on an assumed pipe failure rate of 3E-7 per ft-year, a piping length of 20 feet and that the door was open for up to 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> per year. It was further assumed that a rupture of the MS piping, with the HELB door open, would result in: an automatic or manual plant trip based on #11 and #13 steam generator conditions and unavailability of the TD and both MD AFW pumps. The estimated increase in core damage frequency was negligible (less than 1 E-09). The dominate core damage sequence included a plant transient with the failure of all AFW, the inability to recover feedwater and failure of the operators to initiate once through cooling (feed and bleed).

This finding had a cross-cutting aspect in the area of Human Performance, Work Control, that states licensees plan and coordinate work activities by incorporating the need for planned contingencies, compensatory actions, and abort criteria. Specifically, PSEG did not properly plan and coordinate compensatory actions via station procedures for HELB barrier impairments H.3(a).

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 (RG) 1.33, Revision 2, February 1978. Section 9, Procedures for Performing Maintenance, states, in part, that maintenance that can affect the performance of safety-related equipment should be properly preplanned and performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances. PSEG procedure CC-AA-201, Plant Barrier Control Program, describes the requirements for plant design barrier controls during the performance of maintenance activities that can affect the performance of safety-related equipment. CC-AA-201, step 3.5.2, requires, in part, that credited design barriers have an attendant stationed at the opening with a means to rapidly close the opening and restore the barrier function to a condition equivalent to the design condition. Contrary to the above, PSEG conducted maintenance that could have affected the performance of safety-related equipment and did not implement barrier controls in accordance with CC-AA-201, step 3.5.2. Specifically, on October 1, 2 and 17, 2013, PSEG conducted maintenance activities that impacted HELB barriers without a dedicated barrier attendant stationed at the openings with a means to rapidly close the openings and restore the barrier function to a condition equivalent to the design condition. Because this finding was of very low safety significance and was entered into PSEGs CAP via notifications 20627657, 20633614, and 20635656, this violation is being treated as an NCV consistent with Section 2.3.2 of the NRCs Enforcement Policy.

(NCV 05000272; 311/2013005-03, Inadequate HELB Barrier Controls)

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors reviewed the post-maintenance tests 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, steam generator level control valve, 14AF21, repair Unit 1, Bank D control rod stepping following rod position indication calibration Unit 1, 12 CFCU outlet flow control valve, 12SW223, replacement following leakage Unit 1, SSPS B power supply replacement following failure Unit 2, 22 CFCU motor cable repair Unit 2, 23 Chiller action pack repairs Common, 1 SAC following overhaul

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, Room cooler valves surveillance testing Unit 2, Spent fuel pool area radiation monitor 2R5 calibration

b. Findings

No findings were identified.

Cornerstone: Emergency Preparedness

1EP4 Emergency Action Level and Emergency Plan Changes (IP

==71114.04 - 1 Sample)

a. Inspection Scope

==

The NSIR headquarters staff performed an in-office review of the latest revisions of various Emergency Plan Implementing Procedures (EPIPs) and the Emergency Plan located under ADAMS accession number ML121320593 as listed in the Attachment.

The licensee determined that in accordance with 10 CFR 50.54(q), the changes made in the revisions resulted in no reduction in the effectiveness of the Plan, and that the revised Plan continued to meet the requirements of 10 CFR 50.47(b) and Appendix E to 10 CFR Part 50. The NRC review was not documented in a safety evaluation report and did not constitute approval of licensee-generated changes; therefore, this revision is subject to future inspection.

b. Findings

No findings were identified.

1EP6 Drill Evaluation

.1 Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors evaluated the conduct of a routine PSEG emergency drill on November 12 to identify any weaknesses and deficiencies in the classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the simulator and technical support center to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures. The inspectors also attended the station drill critique to compare inspector observations with those identified by PSEG staff in order to evaluate PSEGs critique and to verify whether the PSEG staff was properly identifying weaknesses and entering them into the corrective action program.

b. Findings

No findings were identified.

.2 Training Observations

a. Inspection Scope

The inspectors observed a simulator training evolution for Unit 2 licensed operators on October 14, which required emergency plan implementation by an operations crew.

PSEG planned for this evolution to be evaluated and included in performance indicator data regarding drill and exercise performance. The inspectors observed event classification and notification activities performed by the crew. The inspectors also attended the post-evolution critique for the scenario. The focus of the inspectors activities was to note any weaknesses and deficiencies in the crews performance and ensure that PSEG evaluators noted the same issues and entered them into the CAP.

b. Findings

No findings were identified

2RS1 Radiological Hazard Assessment and Exposure Controls

a. Inspection Scope

During the period December 16-19, 2013, the inspectors reviewed and assessed 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 for determining compliance.

Inspection Planning

The inspectors reviewed 2013 performance indicators for the occupational exposure cornerstone, RP program audits, corrective action documents, and reports of operational occurrences in occupational radiation safety since the last inspection.

Radiological Hazard Assessment The inspectors reviewed the following:

Changes in radiological hazards for onsite workers or members of the public and potential impact of the changes Conducted walk-downs and made independent radiation measurements and reviewed survey documentation to determine thoroughness and frequency of the surveys Risk-significant work activities including radiological surveys performed to identify and quantify the radiological hazard and to establish adequate protective measures Instructions to Workers The inspectors reviewed labeling of non-exempt licensed radioactive material containers.

Contamination and Radioactive Material Control The inspectors reviewed the following:

Observed various locations where potentially contaminated 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 and evaluated whether the work was performed in accordance with plant procedures Assessed whether the radiation monitoring instrumentation used for equipment release and personnel contamination surveys had appropriate sensitivity Reviewed sealed source inventory audits and assessed whether the sources were accounted for and were tested for loose surface contamination Reviewed recent transactions involving nationally tracked sources Radiological Hazards Control and Work Coverage The inspectors reviewed the following:

Evaluation of radiological conditions and performance of independent radiation measurements during walk-downs of the facility Evaluation of the use of dosimetry to monitor personnel working in significant dose rate gradients Postings and physical controls for high radiation areas (HRAs), locked high radiation areas (LHRAs) and very high radiation areas (VHRA)

Risk-Significant HRA and VHRA Controls The inspectors reviewed and discussed with the Radiation Protection Manager (RPM)the supervisor controls and procedures for high-risk HRAs and VHRAs including any changes to relevant procedures.

Radiation Worker Performance and RP Technician Proficiency The inspectors reviewed the following:

Observation of the performance of radiation workers and RP technicians with respect to procedure requirements and awareness of radiological conditions Evaluation of available 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 at an appropriate threshold and placed in the corrective action program.

b. Findings

No findings were identified.

2RS2 Occupational ALARA Planning and Controls

a. Inspection Scope

During the period December 16-19, 2013, 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:

Information regarding collective dose history, current exposure trends, ongoing and planned activities, and the plants three year rolling average collective exposure Changes in the radioactive source term, and site-specific procedures associated with maintaining occupational exposures ALARA Radiological Work Planning The inspectors reviewed the following:

Results achieved for completed work compared to the intended dose in ALARA planning for high collective dose work activities, work-in-progress and post job reviews, comparison of planned person-hour estimates versus actual person-hours, and evaluation of the accuracy of these estimates Determined whether post-job reviews were conducted to identify lessons learned Source Term Reduction and Control The inspectors reviewed the following:

Source term reduction and records of historical trends and current status of plant source term 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 at an appropriate threshold and were placed in the corrective action program.

b. Findings

No findings were identified.

2RS3 In-Plant Airborne Radioactivity Control and Mitigation

a. Inspection Scope

During the period December 16 - 19, 2013, the inspectors reviewed controls for work in airborne radioactivity areas 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:

Use of the respiratory protection program and a description of the types of devices used including location and adequacy of storage facility and quantity of respiratory protection devices stored Procedures for maintenance, inspection, and use of respiratory protection equipment including self-contained breathing apparatus (SCBA)

Reported performance indicators to identify any related to unintended dose resulting from intakes of radioactive material Engineering Controls The inspectors reviewed the following:

Assessed whether PSEG had established threshold criteria for evaluating levels of airborne beta-emitting and alpha-emitting radionuclides Use of Respiratory Protection Devices The inspectors reviewed the following:

Assessment of the storage and physical condition of respiratory protection devices staged and ready for use in the plant and records of equipment inspection for each type Equipment storage, maintenance, and quality assurance including training of onsite personnel conducting maintenance and repair of such equipment SCBA for Emergency Use The inspectors reviewed and discussed with PSEG procedures for surveillance of SCBAs staged in-plant for use during emergencies.

Problem Identification and Resolution The inspectors evaluated whether problems associated with the control and mitigation of in-plant airborne radioactivity were being identified at an appropriate threshold and were placed in the corrective action program.

b. Findings

No findings were identified.

2RS4 Occupational Dose Assessment

a. Inspection Scope

During the period December 16-19, 2013, 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 PSEG procedures for determining compliance.

Inspection Planning

The inspectors reviewed the following:

Radiation protection program audits Procedures associated with dosimetry operations, including issuance/use of external dosimetry, and assessments of dose for radiological incidents Dosimetry occurrence reports and corrective action program documents for adverse trends related to EPDs Internal Dosimetry Routine Bioassay (In-Vivo)

The inspectors reviewed the following:

Procedures to assess dose from internally deposited radionuclides including the release of contaminated individuals Available worker dose assessments Internal Dose Assessment - Whole Body Count (WBC) Analyses The inspectors reviewed dose assessments performed using the results of WBC analyses.

Special Dosimetric Situations The inspectors reviewed training on the risks of radiation exposure, regulatory aspects of declaring a pregnancy, exposure controls, and the specific process to be used for voluntarily declaring a pregnancy.

Shallow Dose Equivalent The inspectors reviewed dose assessments for shallow dose equivalent.

Problem Identification and Resolution The inspectors assessed whether problems associated with occupational dose assessment were being identified an appropriate threshold and were placed in the corrective action program.

b. Findings

No findings were identified.

2RS5 Radiation Monitoring Instrumentation

a. Inspection Scope

During the period December 16 - 19, 2013, the inspectors reviewed the accuracy and operability of radiation monitoring instruments that were used to protect occupational workers and members of the public. 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.

Inspection Planning

The inspectors reviewed the following:

Procedures that govern instrument source checks and calibrations Effluent monitor alarm set-points and the calculation methods provided in the ODCM Walkdowns and Observations The inspectors reviewed the following:

Portable survey instruments in use and assessed calibration and source check stickers for currency, instrument material condition and operability Compared monitor response (via local readout) with actual area radiological conditions for consistency Personnel contamination monitors, portal monitors, small article monitors (SAMs),and bag monitors to evaluate whether the periodic source checks and calibrations were performed in accordance with requirements.

Calibration and Testing Program Portal Monitors, Personnel Contamination Monitors, and SAMs The inspectors reviewed the following:

Instruments in use and verification that the alarm set-point values were reasonable to prevent licensed material from being released Calibration documentation for each instrument selected and associated calibration methods.

Calibration and Check Sources The inspectors reviewed the PSEGs 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 the PSEG at an appropriate threshold and were placed in the corrective action program.

b. Findings

No findings were identified.

2RS6 Radioactive Gaseous and Liquid Effluent Treatment

a. Inspection Scope

During the period December 16-19, 2013, the inspectors reviewed the monitoring and evaluation of gaseous and liquid effluents. 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:

2012 Radioactive Effluent Release Report to determine if the report was submitted as required including anomalous results, unexpected trends, and abnormal releases Abnormal effluent results were evaluated, were entered in the corrective action program, and were adequately resolved Offsite Dose Calculation Manual (ODCM) and Final Safety Analysis Report (FSAR)

Review The inspectors reviewed the following:

Changes to the ODCM made since the last inspection The technical basis of any changes and determined whether they were technically justified and maintained effluent releases ALARA Walk-downs and Observations The inspectors walked-down portions of the facility to identify potential unmonitored release points or whether changes were made to release points.

Procedures, Special Reports, and Other Documents The inspectors reviewed PSEG event reports and/or special reports related to the effluent program issued since the previous inspection.

Sampling and Analyses The inspectors reviewed and discussed with PSEG the inter-laboratory and intra-laboratory comparison program to verify the quality of the radioactive effluent sample analyses. The inspectors also discussed plans associated with program enhancements and changes.

Dose Calculations The inspectors reviewed the following:

Significant changes in reported dose values compared to the previous radioactive effluent release report to evaluate the factors which may have resulted in the change Changes in methodology for offsite dose calculations since the last inspection. The inspectors reviewed and discussed meteorological dispersion and deposition factors used in the ODCM and effluent dose calculations Changes in the latest Land Use Census to verify changes have been incorporated into the effluent release and environmental programs Ground Water Protection Initiative (GPI) Implementation The inspectors reviewed PSEG implementation of the GPI including monitoring results, changes to the program, and efforts to identify and control contaminated spills/leaks to ground water.

Problem Identification and Resolution Inspectors assessed whether problems associated with the effluent monitoring and control program are being identified by the PSEG at an appropriate threshold and placed in the corrective action program.

b. Findings

No findings were identified.

2RS7 Radiological Environmental Monitoring Program (REMP)

a. Inspection Scope

This area was inspected during the week of December 16-20, 2013 to verify that the REMP appropriately quantifies the impact of radioactive effluent releases to the environment and sufficiently validates the integrity of the radioactive gaseous and liquid effluent release program. The inspectors used the requirements in 10 CFR Part 20; 40 CFR Part 190; 10 CFR 50 Appendix I, and the sites TSs, ODCM, and station program procedures to determine acceptability.

Inspection Planning

The inspectors reviewed the 2012 annual radiological environmental and effluent operating report to verify that the REMP was implemented in accordance with the TS and ODCM. The inspectors reviewed the ODCM to identify environmental monitoring and sampling locations stations.

b. Findings

No findings were identified

2RS8 Radioactive Solid Waste Processing and Radioactive Material Handling, Storage, and

Transportation (71124.08 - 1 sample)

a. Inspection Scope

During the week of December 2 - 6, 2013, the inspectors verified the effectiveness of PSEGs programs for processing, handling, storage, and transportation of radioactive material. The inspectors used the requirements of 10 CFR Parts 20, 61, and 71, and 10 CFR Part 50, Appendix A, Criterion 63, Monitoring Fuel and Waste Storage, and PSEG procedures required by TSs/Process Control Program (PCP), as criteria for determining compliance.

The inspectors reviewed the solid radioactive waste system description in FSAR, the PCP, and the recent radiological effluent release report for information on the types, amounts, and processing of radioactive waste disposed.

The inspectors reviewed the scope, the results, and the adequacy of PSEGs corrective actions from quality assurance (QA) audits performed for this area since the last inspection.

Radioactive Material Storage The inspectors inspected areas where containers of radioactive waste were stored. The inspectors verified that the radioactive materials storage areas were controlled and posted as appropriate. The inspectors verified that PSEG had established a process for monitoring the impact of long-term storage (e.g., buildup of any gases produced by waste decomposition, chemical reactions, container deformation, loss of container integrity, or re-release of free-flowing water). The inspectors verified that there were no signs of swelling, leakage, or deformation.

Radioactive Waste System Walkdown The inspectors walked down accessible portions of liquid and solid radioactive waste processing systems to verify and assess that the current system configuration and operation agree with the descriptions in the FSAR, offsite dose calculation manual, and PCP.

The inspectors identified radioactive waste processing equipment that was not operational and/or was abandoned in place and verified that PSEG had established administrative and/or physical controls for the protection of personnel from unnecessary exposure.

The inspectors reviewed the adequacy of any changes made to the radioactive waste processing systems since the last inspection. The inspectors verified that changes from what was described in the FSAR were reviewed and documented.

The inspectors identified processes for transferring radioactive waste resin and/or sludge discharges into shipping/disposal containers. The inspectors verified that the waste stream mixing, sampling procedures, and methodology for waste concentration averaging were consistent with the PCP, and provided representative samples of the waste product for the purposes of waste classification.

For these systems that provide tank recirculation, the inspectors verified that the tank recirculation procedure provide sufficient mixing.

The inspectors verified that PSEGs PCP correctly described the current methods and procedures for dewatering waste.

Waste Characterization and Classification The inspectors identified radioactive waste streams, and verified that PSEGs radiochemical sample analysis results were sufficient to support radioactive waste characterization. The inspectors verified that PSEGs use of scaling factors and calculations to account for difficult-to-measure radionuclides was technically sound and based on current analyses.

The inspectors verified that changes to plant operational parameters were taken into account to:

(1) maintain the validity of the waste stream composition data between the annual or biennial sample analysis update; and,

(2) verified that waste shipments continued to meet applicable requirements.

The inspectors verified that PSEG had established and maintained an adequate QA program to ensure compliance with applicable waste classification and characterization requirements.

Shipment Preparation The inspectors reviewed the records of shipment packaging, surveying, labeling, marking, placarding, vehicle checks, emergency instructions, disposal manifest, shipping papers provided to the driver, and PSEG verification of shipment readiness. The inspectors verified that the requirements of any applicable transport cask certificate of compliance had been met. The inspectors verified that the receiving licensee was authorized to receive the shipment packages.

The inspectors verified that the shippers were knowledgeable of the shipping regulations and that shipping personnel demonstrated adequate skills to accomplish the package preparation requirements for public transport. The inspectors verified that PSEGs training program provided training to personnel responsible for the conduct of radioactive waste processing and radioactive material shipment preparation activities.

Shipping Records The inspectors identified non-excepted package shipment records and verified that the shipping documents indicate the proper shipper name; emergency response information and a 24-hour contact telephone number; accurate curie content and volume of material; and appropriate waste classification, transport index, and international shipping identification number. The inspectors verified that the shipment placarding was consistent with the information in the shipping documentation.

Identification and Resolution of Problems The inspectors verified that problems associated with radioactive waste processing, handling, storage, and transportation were being identified by PSEG at an appropriate threshold and were properly characterized, and verified the appropriateness of the corrective actions for a selected sample of problems. PSEG generated six condition reports to document material condition deficiencies identified during this inspection.

b. Findings

No findings were identified.

4OA1 Performance Indicator Verification

.1 Mitigating Systems Performance Index (6 samples)

a. Inspection Scope

The inspectors reviewed PSEGs submittal for the Mitigating Systems Performance Index for the following systems and periods.

Units 1 and 2, Emergency AC Power System, October 1, 2012 - September 30, 2013, MS06 Units 1 and 2, High Pressure Injection System, October 1, 2012 - September 30, 2013, MS07 Units 1 and 2, Cooling Water Systems, July 1, 2012 - September 30, 2013, MS10 To determine the accuracy of the PI data reported during those periods, inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment PI Guideline, Revision 7. The inspectors reviewed PSEGs operator narrative logs, condition reports, mitigating systems performance index derivation reports, event reports, and NRC integrated inspection reports to validate the accuracy of the submittals.

During the period December 16-19, 2013, the inspectors reviewed various corrective action documents to determine if issues met the report threshold for the occupational exposure control effectiveness PI or the threshold for the public exposure control effectiveness PI. The inspectors used PI definitions and guidance contained in the Nuclear Energy Institute Document 99 02, Regulatory Assessment Performance Indicator Guideline, Revision 7, dated August 31, 2013, to determine the accuracy of the PI data reported.

b. Findings

No findings were identified.

.2 Occupational Exposure Control Effectiveness (1 sample)

a. Inspection Scope

The inspectors reviewed the scope and breadth of the PSEG data review and the results of those reviews. The inspectors reviewed electronic personal dosimeter (EPD) dose alarms, dose reports, and dose assignments for any intakes that occurred during the time period reviewed to determine if there were any potentially unrecognized PI occurrences. The inspectors also conducted walk-downs of accessible locked High and Very High Radiation Area entrances to determine the adequacy of the controls in place for these areas.

b. Findings

No findings were identified.

.3 RETS/ODCM Radiological Effluent Occurrences (1 sample)

a. Inspection Scope

The inspectors reviewed the corrective action report database and individual reports generated since this indicator was last reviewed to identify any potential occurrences such as unmonitored, uncontrolled, or improperly calculated effluent releases that may have impacted offsite dose. The inspectors reviewed gaseous and liquid effluent summary data and the results of associated offsite dose calculations to determine if indicator results were accurately reported. The inspectors also reviewed methods for quantifying gaseous and liquid effluents and determining effluent dose.

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 IP 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 Semi-Annual Trend Review

a. Inspection Scope

The inspectors performed a semi-annual review of site issues, as required by Inspection Procedure 71152, Problem Identification and Resolution, to identify trends that might indicate the existence of more significant safety issues. In this review, the inspectors included repetitive or closely-related issues that may have been documented by PSEG outside of the corrective action program, such as trend reports, performance indicators, major equipment problem lists, system health reports, maintenance rule assessments, and maintenance or corrective action program backlogs. The inspectors also reviewed PSEGs corrective action program database for the third and fourth quarters of 2013 to assess notifications written in various subject areas (equipment problems, human performance issues, etc.), as well as individual issues identified during the NRCs daily condition report review (Section 4OA2.1). The inspectors reviewed PSEGs quarterly trend reports for the first through third quarters of 2013, conducted under LS-AA-125, to verify that PSEG personnel were appropriately evaluating and trending adverse conditions in accordance with applicable procedures.

b. Findings and Observations

No findings were identified.

Trending program: LS-AA-125, CAP Procedure, Revision 17, describes trending of CAP issues. Under this procedure, department CAP coordinators are charged with monitoring CAP performance, maintaining proficiency in trending, monitoring the CAP for potential department trends, and taking action to resolve adverse trends. LS-AA-125-1005, Coding and Analysis Manual, Revision 6, supports the CAP by providing guidance on performing trend analysis. LS-AA-125-1006, Performance Improvement Integrated Matrix (PIIM), Revision 5, uses a matrix to track performance gaps and implement solutions. A number of discrepancies with the CAP trending process were noted:

In preparation for the Biennial NRC PI&R inspection in July 2013, PSEG performed a focused area self-assessment. During that assessment, PSEG determined that:

1) Trending is not consistently utilized to gain the maximum value, 2) Trending Analysis rigor was not able to be demonstrated at the department or station level, and, 3) None of the station PIIM items were identified via trending. In response, notification 20608333 was written to identify gaps in the PIIM process. Inspectors identified that the action had been extended four times and it was extended again beyond this inspection period.

There was no evidence of trend analysis in the single-page quarterly trend reports reviewed. While evidence of trending results was evident in the PIIMs, PSEG could not provide evidence of the associated trend analysis as discussed in the procedures. PSEG entered this in their CAP as 20635823.

A number of steps in LS-AA-125 refer to LS-AA-125-1005 for guidance on undesirable performance and require CAP coordinators to perform trend coding and periodic analysis of CR data. However, PSEG uses the PIIM in LS-AA-125-1006 as its trending product. There were no procedural ties between the -1005 and -

1006 procedures and the PIIM is not referenced in steps of the CAP procedure, LS-AA-125. PSEG entered this in their CAP as 20635826.

LS-AA-125-1005, section 4.3, directs that once trend analysis is complete, each department is to identify their top adverse trends as focus areas that should be evaluated and reviewed for effectiveness. Inspectors reviewed notifications from January through December 2013 and identified eight with a title of adverse trend.

All adverse trends were assigned the lowest CAP significance level. Contrary to section 4.3, six of the adverse trends did not have an evaluation performed. One of the remaining adverse trends referenced a previous adverse trend on a related matter, but did not validate whether the actions from that issue would address the new adverse trend.

During CAP review, the inspectors identified a 2-month delay in identifying elevated main generator end-turn vibrations that PSEG subsequently classified as an adverse trend (20631354).

LS-AA-125-1005 directs that department CAP coordinators are to trend quarterly.

The inspectors noted the absence of guidance for trending frequency by the site CAP coordinator.

While inspectors did not identify any issues that were more than minor in accordance with IMC 0612, the inspectors concluded that challenges exist in the stations trending program, specifically in the area of evaluation.

Operability Determinations: The inspectors provided numerous observations to PSEG during the 2nd half of 2013 regarding operability determinations of equipment deficiencies documented in notifications. The observations were categorized in the following areas:

Lack of rigor in documenting an operability position commensurate with the implications of the degradation Inconsistent use of the term operability for degraded fire protection equipment Use of an operability determination for degraded components that are not required under Technical Specifications Absence of procedural guidance in referencing the Technical Requirements Manual and ISFSI TSs for operability (notification 20618281)

Use of N/A in the operability screenings when an operability determination is warranted (e.g., degraded equipment that provides supporting functions to Technical Specification equipment)

Salem Common Standing Order 2013-023 created additional requirements regarding documentation of reasonable assurance of operability. When documenting the operability basis, it provided a list of items that should be considered and appropriately documented. After issuance, the inspectors observed that operability documentation in accordance with the standing order was inconsistent.

In response to inspector observations, PSEG documented a gap in their operability determination process as compared to the industry and NRC IMC 9900 guidance under notification 20623530. PSEG also developed an Operability Assessment Improvement Plan. None of the observations were associated with performance deficiencies that were more than minor in accordance with IMC 0612.

Flange leaks on SW valves: The inspectors noted there were two flange leaks on Unit 1 CFCU SW outlet valves (SW223) during the fourth quarter of 2013. The inspectors performed a CAP review and noted 11 flange leaks associated with these valves since January 2010, and two cases were repeat leaks. MA-AA-716-230-1010, Fluid Leak Management Program, Revision 3, step 6.6.2, directs that leaks identified as repeat leaks shall have a Condition Report evaluation performed. In June 2011, notification 20515452 was written to review SW223 repetitive flange leaks. It was screened as a significance level 5 (enhancement), outside of the CAP. In October 2013, the 12SW223 valve also had a repeat leak (20625500). An evaluation was not completed in either case. Separately, PSEG had developed a long-term asset management plan to upgrade these valves. Notwithstanding, the inspectors observed that PSEG was not in compliance with station procedures on fluid leaks in that required evaluations were not performed or referenced to the upgrade plan. PSEG entered this issue in their CAP under notification 20635575.

.3 Annual Sample: Spent Fuel Pool Leakage Detection (1 sample)

a. Inspection Scope

During the week of December 16 - 19, 2013, inspectors met with PSEG staff to review the condition and activities related to Salem Units 1 and 2 Spent Fuel Pool (SFP) leak detection system (tell-tale drain pipes). The inspectors focused on PSEG staffs implementation of their long term corrective actions to address previously corrected blockage in the Unit 1 tell-tale drain system, discovered in 2003, that resulted in onsite groundwater contamination in the vicinity of the fuel handling building and into the adjacent seismic gap. The seismic gap is a 6-inch Styrofoam filled area between each fuel handling building and auxiliary building. As a corrective action PSEG installed a pipe from the seismic gap to drain water into the auxiliary building for processing. NRC Inspection Report 272/2003-006 dated October 15, 2003, describes this previous condition and PSEGs actions to characterize the on-site contamination and establish a remediation program involving monitoring wells and the pumping of contaminated groundwater for processing (ADAMS ML032890212).

The scope of this inspection included a historical review of the spent fuel pool leakage condition of Salem Units 1 and 2 since 2003, the effects on ground water, the current condition of each SFP tell-tale drain system and PSEGs maintenance plans. In addition, the inspectors reviewed the results of PSEGs ground water monitoring program. In particular, the inspectors examined the sampling results associated with a newly installed 80-foot deep well (AA-V), placed in the Vincentown formation, in June 2013, within the site Radiological Restricted Area. The inspectors reviewed sampling results for Salem Units 1 and 2 seismic gap drains and other sampling wells. In addition, the inspectors reviewed the status and results of PSEGs ground water remediation efforts.

The inspectors observed PSEG maintenance staff activities to internally inspect the tell-tale drain pipes using a boroscope with video recording capability. Work orders provided instructions for visual examination of piping prior to and after flushing each of the 17 tell-tale pipes of both Units 1 and 2 with pressurized demineralized water. The inspectors reviewed the video record for all of the Unit 1 pre-flush as found examinations and observed the video examinations in-progress for the telltale piping of Unit 2.

Additionally, the inspectors reviewed procedure SC.MD-PM.SF-0008(Q), Revision 0, and observed the tell-tale cleaning process on several of the tell-tale pipes in Unit 2.

During the video and flushing operations, the inspectors observed that a radiation protection technician measured the radiological conditions in the work area and of both the boroscope and hydro-cleaning probes during the exit from each pipe. Additionally, the condition of both Unit 1 and 2 tell-tale drain troughs and the adjacent spent fuel pool vertical walls were observed.

The inspectors reviewed this area relative to 10 CFR 20, applicable PSEG procedures and Technical Specification, the site Offsite Dose Calculation Manual, and applicable Regulatory Guides.

b. Findings and Observations

No findings were identified.

The inspectors determined PSEG had significantly remediated the extent and concentrations of tritium in ground water contamination within the shallow aquifer near Salem Unit 1 station. PSEGs sampling and evaluations, in accordance with the Offsite Dose Calculation Manual, did not identify any radionuclides, other than tritium, beyond the coffer dams associated with Unit 1 seismic gap. PSEG conducted bounding public dose calculations and determined that the dose projections were well below applicable 10 CFR 50, Appendix I, ALARA dose criteria. PSEG staff were reviewing the concentrations of radioactivity collected via the Unit 1 seismic gap drain, which drains to the Unit 1 Auxiliary Building, for controlled collection and processing. The seismic gap was considered part of the pathway for the previous ground water contamination.

The inspectors determined that the Salem staff had continued to implement their 2003 plans to verify the condition of the SFP tell-tale drain piping by routine internal visual examination and water flush cleaning using documented inspection and maintenance procedures. The plans for work on-going from 2003 included monitoring and mitigation processes to address the onsite ground water plume containing tritium. The inspectors noted that the periodic work scope, planned in 2003, was still being performed in 2013.

However, the inspectors determined that PSEG staff had not completed a recent systematic review of the overall SFP leakage conditions, and the related water flow in the seismic gap, as well as associated radioactivity concentrations, to determine if the original work scope should be changed or additional actions were needed. Specifically, the inspectors determined that PSEG staff had not evaluated the adequacy of the SFP tell-tale drain maintenance program considering the apparent increased tritium concentration in seismic gap drain samples and indications of potentially impeded flow from the seismic gap drain.

At the conclusion of the inspection, PSEG formed a multi-discipline team to review the current status of the leak management as well as the need to conduct further radiological characterization and evaluations. PSEG initiated planning to determine the near term and long term action plans including efforts to enhance draining of the Unit 1 seismic gap. In addition, PSEG was evaluating vendor proposals to support location and repair of the Unit 1 Spent Fuel Pool liner leak(s) which was contributing contamination to the seismic gap. The inspectors did not identify any issues that were more than minor in accordance with IMC 0612 since the dose projections were well below applicable 10 CFR 50 Appendix I, ALARA dose criteria.

.4 Annual Sample: Emerging Trend in Cross-Cutting Aspect H.2(C) (1 sample)

a. Inspection Scope

The inspectors reviewed an emerging trend in the cross-cutting aspect of Human Performance - Resources, H.2(c), as recommended in IP 71152, to develop insights into PSEGs progress in addressing the potential theme. A theme exists in the area of human performance when at least four findings are assigned the same cross-cutting aspect during a mid-cycle or end-of-cycle assessment period. During the first two quarters of 2013, inspectors identified three findings associated with the cross-cutting component, specifically the aspect of ensuring accurate and up-to-date procedures and work packages. The inspection focused on PSEGs review of NRC findings associated with human performance cross-cutting aspects. PSEG performed a common cause analysis (CCA) on those findings and one issue in the cross-cutting area of the problem identification and resolution (CR 70156124) over a twelve month period from July 2012 to July 2013, entitled NRC Cross Cutting Issue trend analysis. The inspector reviewed the CCA and related documents, and interviewed Regulatory Assurance staff responsible for the development of the CCA.

b. Findings

No findings were identified.

PSEGs CCA identified a common cause was that a lack of commitment to program implementation has led, in some cases, to engineers failing to adequately incorporate program requirements into the implementing documents, and ensure full understanding by the end user. The primary corrective action to address the common cause was to develop and facilitate case study training for planning, maintenance, operations and engineering staff, and was assigned a due date of March 31, 2014. At the time of the inspection, the case study was being developed and was still a draft.

The inspectors reviewed LS-AA-125-1002, Common Cause Evaluation Manual, Revision 7, to assess the quality of the CCA. The inspectors determined that the CCA did not meet LS-AA-125-1002, section 2.4.4, which directs that operating experience be reviewed for useful lessons learned, and to look for similar corrective actions which should be implemented. Specifically, the CCA documents an occurrence of a cross-cutting theme in H.2(c) at another licensee facility, and notes that planned corrective actions included planner continuing training, metrics established to quantify work package quality, and development of examples of quality work instructions to ensure a common understanding between document developers and end users. PSEGs CCA did not identify any actions to be taken that were directly associated with addressing documentation-related issues, or for measuring the success of interdepartmental coordination and communication between the engineering department and the end users. PSEGs CCA was broadly applied to all of the human performance related findings, and might have missed an opportunity to apply applicable operating experience specific to the H.2(c) emerging theme. The inspectors determined that this issue was of minor significance and not subject to enforcement action in accordance with IMC 0612 and the NRCs Enforcement Policy.

.5 Annual Sample: Unit 1 Reactor Trip and Safety Injection (SI) for Potential Solid State

Protection System (SSPS) Universal Logic Board Failure ===

a. Inspection Scope

The inspectors performed an in-depth review of PSEGs root cause evaluation (RCE)and corrective actions associated with notification 20557491. The notification documented on April 30, 2012, a Unit 1 reactor trip and safety injection occurred in SSPS train A on High Steam Flow and Low-Low Tavg or Low Steam Line Pressure.

The event occurred while turbine impulse testing was in progress. All systems responded as expected. The notification required a RCE be conducted to determine the cause of the event and identify potential corrective actions.

The inspectors assessed PSEGs problem identification threshold, cause evaluations, extent of condition reviews, compensatory actions, and the prioritization and timeliness of corrective actions to determine whether PSEG was appropriately identifying, characterizing, and correcting problems associated with this issue. The inspectors compared the actions taken to the requirements of PSEGs CAP and 10 CFR 50, Appendix B, Criterion XVI, Corrective Action. In addition, the inspectors reviewed documentation associated with this issue, including the RCE, operability determination, and revised surveillance and maintenance procedures. They interviewed site engineering, maintenance, and I&C personnel to assess the effectiveness of the implemented corrective actions to complete full resolution of the issue. The inspectors performed a walkdown of the Unit 1 SSPS to assess if abnormal conditions existed.

Additionally, the inspectors toured the warehouse to ensure sufficient spare original style SSPS cards were available in the event other logic card failures occurred. The inspectors verified that universal logic cards were being maintained onsite and refurbishments of the cards were being tracked in the warehouse by serial number.

b. Findings and Observations

No findings were identified.

While the root cause of the event was not positively identified, PSEG determined that the most probable cause was a tin whisker or loose wire in the SSPS logic panel wiring electrically shorted or grounded the Low-Low Tavg or Low Steam Line Pressure associated circuit cards input or output, thus establishing the permissive for the High Steam Flow reactor trip and SI signals. This determination was made based, in part, on evaluations of the SSPS circuitry and onsite/vendor testing of the old/new style universal logic cards. This additional testing did not replicate the failure conditions observed during the event. PSEGs immediate corrective actions included resetting the SSPS Train A logic and re-performing a functional test of the system. The systems tested satisfactorily and no further anomalies were noted. PSEG removed and quarantined the new style universal logic cards (1 under-voltage driver card, 1 tester card, and 3 safeguard driver cards) associated with the High Steam Flow Trip and the SI in Train A, and replaced them with the original cards to prevent an intermittent fault from originating from those cards. Additionally, the remaining old style logic cards in Train A were replaced with cards from the warehouse. The new style cards were also removed from Train B thus returning Unit 1 SSPS to its original configuration. The Unit 1 SSPS system was re-tested with satisfactory results and returned to service. The old and new style cards associated with the trip were tested at the site and sent to the vender for further evaluation. No new style cards were installed in the Unit 2 SSPS. Additional corrective actions included cleaning and inspection of the SSPS Train A and Train B logic panels wiring area. PSEG also marked the removed, old-style logic cards For Training Use Only and provided them to the maintenance training department so that they would not be re-installed in the SSPS. PSEG submitted LER 50000272/2012-001-00 regarding this issue. The inspectors dispositioned this LER in inspection report 05000272;311/2012-003 in sections 4OA3 and 4OA7.

The new style logic cards were installed in Unit 1 during refueling outage 1R20 for Train B and 1R21 for Train A (design change package 80096586). They are digital devices (complex programmable logic devices (CPLD)) that require an application-specific software (data file) to configure the boards logic functions. There is the potential that software related failures could occur on each of the redundant safety trains in the SSPS if the new style logic cards are installed. The NRC and the Pressurized Water Reactor Owners Group (PWROG) are engaging in discussions to resolve this potential issue.

PSEG issued notifications 20619003 and 20632198 to track the progress and resolution of this issue, and will not consider re-installing the new style universal logic cards until this issue is resolved.

The inspectors found that corrective actions included cleaning and inspecting Train A and Train B logic panel wiring area for the Unit 1 SSPS and Train A for the Unit 2 SSPS. The Unit 2 Train B is scheduled to be completed in the spring of 2014. All of the logic cards (old and new style) in Unit 1 were removed from service and will not be reinstalled in the plant. Preventive maintenance procedures were revised to perform cleaning of the SSPS logic panel wiring areas on a periodic basis for both units. The inspectors found that SSPS old-style cards have operated satisfactorily in Unit 1 since the cards from the event have been replaced. Unit 2 has had no universal logic card issues. PSEG is currently monitoring SSPS performance as a part of their effectiveness review for the corrective actions identified in the root cause evaluation.

The inspectors determined PSEGs overall response to the issue was timely, commensurate with the safety significance and the actions taken and planned were reasonable to preclude the potential of the SSPS to initiate a random SI signal and to prevent recurrence.

4OA6 Meetings, Including Exit

On January 9, 2014, the inspectors presented the inspection results to Mr. John Perry, Salem 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.

ATTACHMENT:

SUPPLEMENTARY INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

J. Sindoni, Director, Regulatory Affairs

J. Perry, Site Vice President

L. Wagner, Plant Manager, Salem

K. King, Regulatory Assurance, Technical Analyst, Salem

R. DeNight Jr., Operations Director

K. Chambliss, Regulatory Affairs Manager

D. LaFleur, Regulatory Assurance

C. Dahms, Regulatory Assurance

S. Thomassen, Emergency Preparedness Station Manager

J. Frick, Radioactive Materials Shipper

K. Down, System Manager (SW)

K. King, Design Engineering

G. Pahwa, GL 89-13 Program Manager

D. Best, Nuclear Specialist, Engineering

T. Cachaza, Licensing

A. Collins, I&C Technician

B. Leyden, I&C Technician

S. Nedd, Nuclear Engineer

S. Goss, Nuclear Engineer

D. McCollum, Principal Nuclear Engineer

W. Strudwick, I&C Technician (Warehouse)

J. Thompson, Design Manager, Procurement Engineering

M. Lenoir, Mechanical Maintenance Supervisor

A. Crampton, Senior Reactor Operator

T. Clark, Nuclear Equipment Operator

S. Taylor, Radiation Protection Manager, Salem

L. Curran, Assistant Director Engineering, Salem

C. Wend, Hope Creek Radiological Engineering

G. Rich, Chemistry Manager

M. Pyle, Principal Engineer

T. Neufang, Rad Engineering Superintendent

C. Aung, Salem Chemistry Engineer

A. Ochoa, Senior Engineer

M. Bacca, Dosimetry Supervisor

J. Russell, Nuclear Environmental Specialist

W. Gropp, Radiation Protection Supervisor, Salem

A. Kraus, Manager, Nuclear Environmental Affairs (NEA)

B. Daly, Environmental Sustainability Manager

E. Gallagher, Nuclear Training Instructor

G. Gauding, Examination Developer

G. Marshall, Nuclear Training Instructor

P. Williams, Nuclear Training Instructor

Others

K. Tuccillo, Supervisor, Nuclear Environmental Engineering Section, State of New Jersey

J. Vouglitois, Nuclear Engineer, Nuclear Environmental Engineering Section State of New

Jersey Department

LIST OF ITEMS OPENED, CLOSED, DISCUSSED, AND UPDATED

Opened/Closed

05000311/2013005-01 NCV Inadequate Assessment of Fire Brigade Performance during an Unannounced Drill (Section 1R05)

05000272; 311/2013005-03 NCV Inadequate HELB Barrier Controls (Section 1R18)

Opened

05000272/2013005-02 URI Performance Monitoring of Reactor Trip Breakers (Section 1R12)