IR 05000272/2013004

NRC Integrated Inspection Report 05000272/2013004 and 05000311/2013004

ML13323A526
Person / Time
Site:	Salem
Issue date:	11/19/2013
From:	Dentel G T Reactor Projects Branch 3
To:	Joyce T P Public Service Enterprise Group
DENTEL, GT
References
IR-13-004
Download: ML13323A526 (36)

Text

November 19, 2013

Mr. Thomas President and Chief Nuclear Officer PSEG Nuclear LLC - N09 P.O. Box 236 Hancocks Bridge, NJ 08038

SUBJECT: SALEM NUCLEAR GENERATING STATION, UNIT NOS. 1 AND 2 NRC INTEGRATED INSPECTION REPORT 05000272/2013004 AND 05000311/2013004

Dear Mr. Joyce:

On September 30, 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 October 24, 2013, with Mr. Wagner, Plant Manager of Salem Operations, and other members of your staff. The inspection examined activities conducted under your license as they relate to safety and license. The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel. This report documents one self-revealing finding of very low safety significance (Green). This finding did not involve a violation of NRC requirements. If you contest the finding 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 the 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. enclosure, and your response (if any) will be available electronically for public inspection in the Agencywide Documents Access and Management System (ADAMS). ADAMS is accessible from the NRC website at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/ Glenn T. Dentel, Chief Reactor Projects Branch 3 Division of Reactor Projects Docket Nos: 50-272, 50-311 License Nos: DPR-70, DPR-75 Enclosure: Inspection Report 05000272/2013004 and 05000311/2013004 w/Attachment: Supplementary Information cc w/encl: Distribution via ListServ

ML13323A526 SUNSI Review Non-Sensitive Sensitive Publicly Available Non-Publicly Available OFFICE RI/DRP RI/DRP RI/DRP NAME PFinney/RB for RBarkley/RB GDentel/GTD DATE 11/19/13 11/19/13 11/ 19/13 1 Enclosure U.S. NUCLEAR REGULATORY COMMISSION REGION I Docket Nos: 50-272, 50-311 License Nos: DPR-70, DPR-75 Report No: 05000272/2013004 and 05000311/2013004 Licensee: PSEG Nuclear LLC (PSEG) Facility: Salem Nuclear Generating Station, Units 1 and 2 Location: P.O. Box 236 Hancocks Bridge, NJ 08038 Dates: July 1, 2013 through September 30, 2013 Inspectors: P. Finney, Senior Resident Inspector A. Ziedonis, Resident Inspector J. Hawkins, Acting Senior Resident Inspector P. McKenna, Resident Inspector F. Ramirez, Acting Hope Creek Senior Resident Inspector R. Barkley, Senior Project Engineer M. Draxton, Project Engineer R. Nimitz, Senior Health Physicist J. Laughlin, Emergency Preparedness Inspector Approved By: Glenn T. Dentel, Chief Reactor Projects Branch 3 Division of Reactor Projects 2 Enclosure

SUMMARY

IR 05000272/2013004, 05000311/2013004; 07/01/2013 - 09/30/2013; Salem Nuclear Generating Station, Units 1 and 2; Follow-Up of Events and Notices of Enforcement Discretion. This report covered a three-month period of inspection by resident inspectors and announced inspections performed by regional inspectors. Inspectors identified one finding 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 --dated October 28, 2011. All violations of NRC requirements are dispositioned in accordance icy, dated July 9safe operation of commercial nuclear power reactors is described in NUREG-

Cornerstone: Initiating Events

Green.

The inspectors identified a self-revealing Green finding when PSEG did not provide appropriate air-operated valve program setpoint control, and ensure adequate packing consolidation of the Unit 1 pressurizer spray valve (1PS1), in accordance with station procedure, ER-AA-410, Air Operated Valve Program Implementing Procedure, Revision 4. This resulted in a packing leak in excess of the Technical Specification (TS) allowable unidentified reactor coolant system (RCS) leak rate on August 22, 2013, and subsequently required an unplanned unit shutdown. PSEG isolated the leak and entered this issue in the corrective action program (CAP) via Notifications 20618913 and 20618915. This finding was more than minor because it was associated with the equipment performance attribute of the Initiating Events cornerstone, and adversely affected the associated cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Using IMC 0609, the inspectors determined that this finding was of very low safety significance (Green) using Exhibit 1 - Initiating Events Screening Questions. Specifically, after a reasonable assessment of degradation, the inspectors determined the finding would not exceed the RCS leak rate for a small loss-of-coolant accident (LOCA), and the finding would not have affected other systems used to mitigate a LOCA. The inspectors determined that this finding had a cross-cutting aspect in the area of Human Performance, Operating Experience (OE), because PSEG did not implement vendor recommendations through changes to station processes and procedures. P.2(b) (Section 4OA3)

Other Findings

None

REPORT DETAILS

Summary of Plant Status Unit 1 began the inspection period at 100 percent power and operated at full power until August 22, 2013, when the unit was shutdown for RCS leakage attributed to the packing area of a pressurizer spray valve. A reactor startup was commenced on August 24, 2013, and the unit returned to 100 percent power on August 25, 2013. 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 and 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 Summer Readiness of Offsite and Alternate Alternating Current (AC) Power Systems

a. Inspection Scope

The inspectors performed a review of plant features and procedures for the operation and continued availability of the offsite and alternate AC power system to evaluate readiness of the systems prior to seasonal high grid loading. The inspectors reviewed tocols between the transmission system operator and PSEG. This review focused on changes to the established program and material condition of the offsite and alternate AC power equipment. The inspectors assessed whether PSEG established and implemented appropriate procedures and protocols to monitor and maintain availability and reliability of both the offsite AC power system and the onsite alternate AC power system. The inspectors evaluated the material condition of the associated equipment by interviewing the responsible system manager, reviewing condition reports and open work orders, and walking down portions of the offsite and AC power systems, including the 500 kilovolt (kV) switchyard. Documents reviewed for each section of this inspection report are listed in the Attachment.

b. Findings

No findings were identified.

=

a. Inspection Scope

The inspectors performed partial walkdowns of the following systems:

Unit 1, 11 service water (SW) ventilation/bay Unit 2, 22 containment spray pump Common, control air during station air reliability challenges The inspectors selected these systems based on their risk-significance relative to the Reactor Safety cornerstones at the time they were inspected. The inspectors reviewed applicable operating procedures, system diagrams, the Updated Final Safety Analysis Report (UFSAR), TSs, work orders (WOs), notifications, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have impacted system performance of their intended safety functions. The inspectors also performed field walkdowns of accessible portions of the systems to verify system components and support equipment were aligned correctly and were operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no deficiencies. The inspectors also reviewed whether PSEG staff had properly identified equipment issues and entered them into the CAP for resolution with the appropriate significance characterization.

b. Findings

No findings were identified.

1R05 Fire Protection 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 (OOS), 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, 460 Volt switchgear (SWGR) room Unit 1, m Unit 2, turbine building (TB) Unit 2, TB, elevat Unit 2, TB

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Quarterly Review of Licensed Operator Requalification Testing and Training

a. Inspection Scope

The inspectors observed licensed operator simulator training on September 4 and 24, 2013, which included a requalification examination and scenarios on a station blackout and feed pump trip, respectively. 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 (CR) supervisor. The inspectors verified the accuracy and timeliness of the emergency classification made by the shift manager and the TS action statements entered by the shift technical advisor. Additionally, the inspectors assessed the ability of the crew and training staff to identify and document crew performance problems.

b. Findings

No findings were identified.

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

a. Inspection Scope

The inspectors observed and reviewed the Unit 1 shutdown and startup on August 22 and 24, 2013, respectively, for the 1PS1 pressurizer spray valve leak. The inspectors observed infrequently performed test or evolution briefings, pre-shift briefings, and reactivity control briefings to verify that the briefings met HU-AA--job Briefingsoperator performance to verify that procedure use, crew communications, and coordination of activities between work groups similarly met established expectations and standards.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed the samples listed below to assess the effectiveness of maintenance activities on structure, system, and component (SSC) performance and reliability. The inspectors reviewed system health reports, CAP documents, maintenance 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, 13 charging pump failure to start Common, station air compressor performance

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed station evaluation and management of plant risk for the maintenance and emergent work activities listed below to verify that PSEG performed the appropriate risk assessments prior to removing equipment for work. The inspectors selected these activities based on potential risk significance relative to the Reactor Safety cornerstones. As applicable for each activity, the inspectors verified that PSEG personnel performed risk assessments as required by 10 CFR 50.65(a)(4) and that the assessments were accurate and complete. When PSEG performed emergent work, the inspectors verified that operations personnel promptly assessed and managed plant risk. The inspectors reviewed the scope of maintenance work and discussed the results of 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, transition from Mode 3 to Mode 1 with 13 chiller inoperable Unit 1, overhead alarm 12VDC PS-2 failure Unit 1, 1PS1 pressurizer spray valve emergent work Unit 2, elevated risk during 23 auxiliary feedwater work window Unit 2, emergent work on 22CA330 containment isolation valve Common, elevated risk with 500 kV Bus #1 OOS Common, station air compressor unreliability and overhauls

b. Findings

No findings were identified.

1R15 Operability Determinations and Functionality Assessments

a. Inspection Scope

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

Unit 1, 13 chiller low suction pressure Unit 1, 1R46A (C, D) main steam line radiation monitor inoperability Unit 1, auxiliary building ventilation #12 supply fan failure to start Unit 1, 1PS1 pressurizer spray valve extent of condition Unit 2, emergency diesel generator (EDG) following control area ventilation fan failure to run Unit 2, 4 kV vital buses with 24 station power transformer load tap changer in manual Unit 1, operation until 1R23 with the 1PS1 pressurizer spray valve isolated The inspectors selected these issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the ODs 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 systems were operable. The inspectors compared the local leak rate testing limits in whether the components or systems remained 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.

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 were 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, 12 component cooling water (CCW) room cooler solenoid valve replacement Unit 1, 12 auxiliary building vent supply fan starting replay replacement Unit 1, 13 chiller relay and compressor replacement Unit 2, corrective maintenance Unit 2, #2 reactor trip bypass breaker replacement Unit 2, containment control air valve 22CA330, solenoid valve replacement

b. Findings

No findings were identified.

1R20 Refueling and Other Outage Activities

a. Inspection Scope

The inspectors reviewed forced outage, which was conducted August 22 through August 24. The inspectors verify that risk, industry experience, previous site-specific problems, and defense-in-depth were considered. During the outage, the inspectors observed portions of the shutdown and cooldown processes and monitored controls associated with the following outage activities: Configuration management, including maintenance of defense-in-depth, commensurate with the outage plan for the key safety functions and compliance with the applicable TSs when taking equipment OOS Implementation of clearance activities and confirmation that tags were properly hung and that equipment was appropriately configured to safely support the associated work or testing Status and configuration of electrical systems and switchyard activities to ensure that TSs were met Monitoring of decay heat removal operations Reactor water inventory controls, including flow paths, configurations, alternative means for inventory additions, and controls to prevent inventory loss Activities that could affect reactivity Tracking of startup prerequisites, walkdown of the primary containment to verify that debris had not been left which could block the emergency core cooling system suction strainers, and startup and ascension to full power operation Identification and resolution of problems related to refueling outage (RFO) activities

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors observed performance of surveillance tests (STs) 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 the current calibration, 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 STs: Unit 1, 1B 4kV Vital bus ESFAS Instrumentation Monthly Functional Test Unit 1, Diesel area CO2 systems operability and partial discharge test Unit 1, Inservice testing of miscellaneous valves (IST) Unit 1, 12 CCW pump surveillance (IST) Unit 1, RCS leakage (RCS) Unit 2, Surveillance test on chilled water valves

b. Findings

No findings were identified.

RADIATION SAFETY

a.

b.

- a.

--- b.

- a.

- b.

===Cornerstone: Emergency Preparedness

1EP4 Emergency Action Level and Emergency Plan Changes

a. Inspection Scope

The Office of Nuclear Security and Incident Response headquarters staff performed an in-office review of the latest revisions of various Emergency Plan Implementing Procedures and the Emergency Plan located under ADAMS accession number ML130520717. PSEG 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.

4OA1 Performance Indicator Verification

.1 Mitigating Systems Performance Index

a. Inspection Scope

The inspe for the Mitigating Systems Performance Index for the following systems for the period of July 1, 2012, through June 30, 2013.

Units 1 and 2, heat removal systems Units 1 and 2, RHR systems To determine the accuracy of the performance indicator (PI) data reported during those periods, inspectors used definitions and guidance contained in Nuclear Energy Institute (NEI) Document 99-inspectors reviewed condition reports, mitigating systems performance index derivation reports, event reports, and NRC integrated inspection reports to validate the accuracy of the submittals.

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution

.1 Routine Review of Problem Identification and Resolution Activities

a. Inspection Scope

As required by Inspection Procedure 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 (CR) screening meetings.

b. Findings

No findings were identified.

.2 Annual Sample:

Corrosion of Service Water Air Operated Valves (AOVs)

a. Inspection Scope

The inspectors performed an in-extent of condition (EOC) reviews and corrective actions associated with issues related to degraded service water (SW) AOVs. These AOVs experience a build-up of debris in the stainless steel valves causing pitting of the valve stem and binding of the valve affecting valve motion and travel. The issues were captured in past PSEG Notifications 20608514, 70118364, 70120002, and 70154085. The inspectors extent of condition (EOC) reviews, compensatory actions, and the prioritization and identifying, characterizing, and correcting problems associated with this issue and whether the planned and completed corrective actions were appropriate. The inspectors CAP and 10 CFR Part 50, Appendix B. In addition, the inspectors interviewed engineering and operations personnel to assess the effectiveness of the implemented corrective actions.

b. Findings and Observations

No findings were identified. In response to issues concerning the build-up of debris in stainless steel SW AOVs causing pitting of the valve stem and binding of the valve affecting valve motion and travel, PSEG has performed multiple apparent cause evaluations (ACEs), EOC reviews and corrective actions since 2003. PSEG most recently performed an ACE documented in notification 70154085 for the 21 CCW room cooler inlet AOV (21SW129) not going full PSEG documented in an AOV WO (30118934) from 2008 that packing leaks on SW AOVs result in the build-up of debris due to the valve being constructed of stainless increasing packing friction and preventing full valve travel.

pump room cooler SW isolation valve (11SW153) to close during quarterly IST testing documented an ACIT to review the current PM strategy for SW AOVs to determine if additional PM activities are required. This action was scheduled to be completed June 1, 2011, but was not completed until August 2, 2012.

The assigned ACIT above identified that there were no open and inspect PMs for the SW room cooler valves and that these PMs (30 total valves) were deactivated by PSEG inadvertently by Orders 80076274 and 80059932 in 2003. Both 21SW129 and 11SW153 had their PMs deactivated in 2003. These PMs included a packing check for these valves which would have caught the stem degradation prior to failure.

strategy review identified the 30 deactivated PMs, but was not performed prior to the failure of the valve on April 17, 2013 (it had been scheduled for 2R21 in the Fall of 2015). After the inspectors discussed this with PSEG, the PMs that had been deactivated were re-reviewed to ensure the schedule had been prioritized to prevent future AOV failures from valve binding. The inspectors determined that re-prioritized PM schedule would not have prevented the 21SW129 failure.

The inspectors discussed these issues with the EQACE team and system engineers to a non-susceptible material (AL6XN), and the re-planned and prioritized PM schedule for these valves, was adequate to address the valve stem pitting issue with the affected SW AOVs. No new issues were identified by the inspectors during the review.

.3 Review of Operator Work Arounds (OWAs)

a. Inspection Scope

The inspectors reviewed the cumulative effects of the existing OWAs, operator burdens, existing operator aids and disabled alarms, and open main control room (MCR) deficiencies to identify any effect on emergency operating procedure operator actions, and any impact on possible initiating events and mitigating systems. The inspectors evaluated whether station personnel had identified, assessed, and reviewed OWAs as specified in Salem procedure OP-AA-102-103, Revision 2, Program.

Throom distractions to minimize operator burdens. The inspectors reviewed the system used to track these OWAs. The inspectors also toured the control room and discussed the current operator workarounds with the operators to ensure the items were being addressed on a schedule consistent with their relative safety significance.

b. Findings

No findings were identified. The inspectors concluded that PSEG was properly identifying, prioritizing, and resolving MCR distractions. However, the inspectors observed that implementation and adherence to station procedures regarding their OWA program, while minor, was less than adequate. Some examples include: Procedure OP-AA-102-103-1001, Operator Burdens Program, Revision 1, Attachment 1, provides guidance on periodically assessing the aggregate effect of operator burdens. When the outstanding Aggregate Impact Items list exceeds the OO.2: MCR distractions metric by 10, the procedure calls for an evaluation to determine whether these quarterly assessments need to be completed more often. By procedure, the Aggregate Impact Items includes, among other items, OWAs and operator cOWAs included 36 operator challenges in August 2013, an increase from 16 in May 2013. The MCR distractions metric goal was 14. Based on Challenges alone, the procedural requirement for an evaluation had been met.

OP-AA-102-103-1001, Attachment 1, Section 3, discusses the aggregate impact CRCR operators could not locate the assessment when requested by inspectors. In June of 2012, Standing Order (SO) 12-12 was issued regarding the Operations Burden Program. This SO established an expectation that operators would use CAP codes to support the program that were in conflict with or in addition to those established by the OP-AA-102-103-1001 procedure. OP-AA-102-104, Pertinent Information Program, Revision 1, section 2.3, states that SOs existing procedures, TSs, administrative technical requirements, or ODCM. They shall not be used OP-AA-102-103-1001, does not define its use of the term Operator Burden. Despite MCR distractions as part of the burdens program, they are not listed as elements of the program in the procedure.

The inspectors also noted that similar observations had been made in 2011 (IR 05000272, 311/2011005) regaThe inspectors confirmed that PSEG had not captured these prior observations in their CAP. In response, PSEG captured these new observations as Notifications 20624037 and 20626619, and is reviewing their approach to observations made in NRC inspection reports. The inspectors concluded that these performance deficiencies were not more than minor based on a review of IMC 0612.

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

.1 Plant Events

a. Inspection Scope

For the plant events listed below, the inspectors reviewed and/or observed plant parameters, reviewed personnel performance, and evaluated performance of mitigating systems. The inspectors communicated the plant events to appropriate regional personnel, and compared the event details with criteria contained in IMC 0309, inspection activities. As applicable, the inspectors verified that PSEG made appropriate emergency classification assessments and properly reported the event in accordance with 10 CFR 50.72. The inspectors reviewed PSEG-up actions related to the events to assure that PSEG implemented appropriate corrective actions commensurate with their safety significance.

Unit 1, manual reactor shutdown for pressurizer spray valve packing leakage on August 22, 2013

b. Findings

IntroductionAOV program setpoint control to ensure adequate packing consolidation, in accordance with ER-AA-410, constituted a self-revealing Green Finding. This resulted in a packing leak in excess of the Technical Specification (TS) allowable unidentified reactor coolant system (RCS) leak rate on August 22, 2013, and subsequently required an unplanned unit shutdown.

Description.

Following the unplanned shutdown on August 22, 2012, PSEG discovered the as-found packing nut torque on the Unit 1 pressurizer spray valve number 1 (1PS1) to be less than 10 ft.-lbs. The packing vendor installation instructions specify a minimum torque value of 16 ft.-lbs. Packing nut torque is one of several parameters available to measure packing consolidation. The packing vendor recommends a minimum packing gland stress of 1.5 times system pressure, or 3728 psi as determined by PSEG (1.5 times primary system design pressure of 2485 psi), to provide adequate consolidation for the 1PS1 packing configuration. PSEG established a minimum gland stress of 4000 psi, and a maximum gland stress of 5000 psi, when the packing was first installed under design change package (DCP) 80098748, in 2010. PSEG also incorporated the minimum and maximum gland stress values into the valve packing data sheet, which is used under WO instruction during the performance of valve packing. The packing vendor provides theoretical calculations to determine packing gland stress, as well as packing friction, based on packing nut torque. The inspectors noted that these calculations are also provided in readily available industry documentation. Based on the theoretical calculations, 16 ft-bs of packing nut torque would correspond to a packing gland stress of 3728 psi, and a packing friction of 653 lbs. Additionally, PSEG utilizes industry standard diagnostic testing software to measure actual friction values during valve stroking. During as-left diagnostic testing of 1PS1 on April 22, 2013, following planned maintenance to replace the packing during the 2013 refueling outage, the as-left friction value on 1PS1 was determined to be 424 lbs. This correlates to a packing gland stress of only 2400 psi, which is below the maximum primary system design pressure of 2485 psi. Additionally, the as-left packing nut torque value was not required to be recorded in the work order following the April 22, 2013, maintenance on 1PS1. Through interviews with maintenance technicians, PSEG concluded that 16 ft-lbs of torque was achieved on the 1PS1 packing nuts, as specified in the 1PS1 valve packing data sheet, following the April 22, 2013 maintenance. The inspectors performed independent interviews and -lbs was reasonable. Although PSEG maintenance technicians determined that the packing nut torque specification had been met, PSEG AOV diagnostic data from actual stroking of the 1PS1 indicated that the packing gland stress was well below the value corresponding to adequate packing consolidation. the 1PS1 Packing Leak under Notification 20618915. PSEG determined the most probable apparent cause of the packing leak was attributed to current industry and valve user group standards not using stem friction values to verify proper packing consolidation. PSEG also determined that the PSEG air-operated valve (AOV) program procedures did not specify a minimum as-left friction value as measured by diagnostic testing. The inspectors noted that PSEG generated many corrective actions as a result of this EQACE. The inspectors noted specific corrective actions to revise AOV program procedures and diagnostic testing software output data to include acceptance criteria for friction and packing consolidation, and to revise pressurizer spray valve maintenance procedures to include detailed procedural guidance for packing consolidation. Additionally, the inspectors noted that an action was created to revise the maintenance planning process for all orders involving valve repacks and packing torque checks to create a dedicated WO operation for the as-left packing torque value. Finally, the -left friction value on evaluation was appropriate to the circumstances.

The inspectors performed an independent review of PSEG AOV program procedures. ER-AA--AA-410-1001, AOV Design Basis Review and Setpoint Control, step 4.7.2, describes the program requirements for setpoint control of packing configuration. The inspectors noted that step 4.7.2 contains no application of setpoint control for packing consolidation. PSEG determined, via EQACE 20618915, that ER-AA-410-does not include any guidance or instruction for evaluating packing friction in AOV testing. The inspectors also reviewed industry documentation for valve packing, and PSEG WO instructions from the April 22, 2013, maintenance to repack 1PS1. The inspectors also interviewed maintenance technicians that worked on 1PS1 on April 22, 2013, as well as on August 22, 2013. The inspectors concluded that the 1PS1 low packing gland The inspectors also noted that PSEG used vendor information to establish a minimum and maximum gland stress when the packing was first installed in the 2010 design change package (DCP), and PSEG incorporated the minimum and maximum gland stress values into the valve packing data sheet. The inspectors also noted that readily available industry documentation, dating back to 2002, also contained information and guidance regarding the use of diagnostic friction values to evaluate packing consolidation, and specifically discussed that low friction values could result in valve packing leaks. Therefore, the inspectors concluded that PSEG had an opportunity to evaluate the low as-left friction values measured by diagnostic testing on April 22, 2013, following planned maintenance to repack the valve. The inspectors determined that this EQACE, nor in the corrective actions, and therefore would be characterized as a self-revealing finding.

Analysis.

Tde the appropriate AOV program setpoint control to ensure adequate packing consolidation on the Unit 1 pressurizer spray valve (1PS1) constituted a performance deficiency. Specifically, on April 22, 2013, PSEG as-left diagnostic testing on the 1PS1 valve determined that the AOV friction value was 424 lbs, which is below the minimum friction value of 701 lbs specified by the vendor. As a consequence of the inadequate packing consolidation, 1PS1 experienced a packing leak in excess of the TS allowable unidentified RCS leak rate on August 22, 2013, which subsequently required an unplanned shutdown of Unit 1. This finding was more than minor because it was associated with the equipment performance attribute of the Initiating Events cornerstone, and adversely affected the associated cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Using IMC 0609, A-finding was of very low safety significance (Green) using Exhibit 1 - Initiating Events Screening Questions. Specifically, after a reasonable assessment of degradation, the inspectors determined the finding would not exceed the RCS leak rate for a small LOCA, and the finding would not have affected other systems used to mitigate a LOCA.

The inspectors determined that this finding had a cross-cutting aspect in the area of Human Performance, OE, because PSEG did not implement vendor recommendations through changes to station processes and procedures P.2(b). Specifically, PSEG did not incorporate into procedures or work order instructions the minimum packing gland stress, as specified by the packing manufacturer, to properly consolidate the 1PS1 valve packing.

Enforcement.

This finding does not involve an enforcement action because no violation of a regulatory requirement was identified. PSEG entered this issue in the CAP in accordance with Notifications 20618913 and 20618915. Because this finding does not involve a violation and is of very low safety significance, it is identified as a FIN. (FIN 05000272/2013004-01, Inadequate Maintenance Procedure to Reconsolidate Pressurizer Spray Valve Packing)

.2 (Closed) Licensee Event Report (LER) 05000311/2007003-01, Reactor Trip Due to

Spurious Feedwater (FW) Interlock Signal (1 sample)

a. Inspection Scope

On August 6, 2007, the Salem Unit 2 reactor tripped due to 22 steam generator (SG) water level reaching its low-low level set point. The cause of SG low-low level was faulty solid state protection system output driver card A517 that initiated a spurious FW isolation signal and resulted in the closure of the FW regulating valves. The failed circuit card was removed, inspected, and tested by PSEG personnel. Inspection of the card performed at increased magnification identified a defective solder joint. The card was replaced and the system tested satisfactorily. Subsequent to that LER review, PSEG supplemented the LER via Revision 1 to incorporate results of a root cause evaluation. PSEG determined that the direct cause was a defective solder joint and the root cause was inadequate post-soldering test practices. This issue was inspected at the time of the occurrence and was discussed in section 4OA3.1 of NRC Inspection Report 05000272, 311/2007004. The LER was reviewed and no findings or violations of NRC requirements were identified. This LER is closed. This LER revision was reviewed at this time due to a prior administrative oversight.

4OA5 Other Activities

.1 Institute of Nuclear Power Operations (INPO) Report Review

a. Inspection Scope

The inspectors reviewed the final report for the INPO plant assessment of Salem conducted in August 2012. The inspectors evaluated this report to ensure that NRC perspectives of PSEG performance were consistent with any issues identified during this assessment. The inspectors also reviewed this report to determine whether INPO identified any significant safety issues that required further NRC follow-up.

b. Findings

No findings were identified.

.2 Ground Water Monitoring Program

a. Inspection Scope

-- -- b.

- --- -

4OA6 Meetings, Including Exit

On October 24, 2013, the inspectors presented the inspection results to Mr. Wagner, Plant Manager of Salem Operations, 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. Perry, Site Vice President

C. Fricker, Former Site Vice-President

D. McCollum, Principle Engineer, CMO

K. Musante, AOV Program Engineer

D. Price, CMO Supervisor

J. Bergeron, I&C Supervisor

T. Boker, I&C Technician

J. Palombo, Mechanical Maintenance Supervisor

R. DeSanctis, Assistant Operations Manager Services

J. Stead, Senior Engineer

J. Schneider, Nuclear Maintenance Supervisor

R. DeNight Jr., Operations Director

K. Chambliss, Regulatory Affairs Manager

D. LaFleur, Regulatory Assurance

C. Dahms, Regulatory Assurance

S. Thomassen, Emergency Preparedness Station Manager

NRC Personnel

P. Finney, Senior Resident Inspector

A. Ziedonis, Resident Inspector

J. Hawkins, Acting Senior Resident Inspector

E. Bonney, Acting Senior Resident Inspector

P. McKenna, Resident Inspector

F. Ramirez, Acting Hope Creek Senior Resident Inspector

R. Barkley, Senior Project Engineer

M. Draxton, Project Engineer

R. Nimitz, Senior Health Physicist

J. Laughlin, Emergency Preparedness Inspector, NSIR

Attachment

LIST OF ITEMS OPENED, CLOSED, DISCUSSED, AND UPDATED

Opened/Closed

05000272/2013004-01 FIN Inadequate Maintenance Procedure to Reconsolidate Pressurizer Spray Valve Packing (Section 4OA3.1)

Closed

05000311/LER-2007-003-01 LER Reactor Trip Due to Spurious Feedwater Interlock Signal (Section 4OA3.2)

LIST OF DOCUMENTS REVIEWED

• Indicates NRC-identified

Section 1R01: Adverse Weather Protection

Procedures

OP-AA-108-107-1001, Electric System Emergency Operations and Electric System, Revision 3 S1 (2).OP-AB.GRID-0001, Abnormal Grid, Revision 21 (18)

OP-AA-108-107-1002, Salem and Hope Creek 500 kV Switchyard Operations Interface Procedure, Revision 1, S1 (2).OP-TM.22-0003, Electric System Operating Curves, Revision 2

OP-AA-101-112-1002, Online Risk Assessment, Revision 7,

Notifications

20616907*

20617832*

20617830*

Other Documents

Generic Letter (GL) 2006-02 PJM Manual M-39, Revision 6, Nuclear Plant Interface PSEG Response to

GL 2006-02 (LRN060131, LRN0700006)

ML 071070006

Attachment

Section 1R04: Equipment Alignment

Procedures

S2.OP-AR.CA-0001, Alarm Response Procedure No. 2 Emergency Control Air Compressor Panel, Revision 4 S1.OP-AR.ZZ-0002, Overhead Annunciators Window H, Revision 27 S1.OP-SO.SW-0005, Service Water System Operation, Revision 39

SC.OP-DL.ZZ-0008, Circulating / Service Water Log, Revision 45

SC.MD-PM.CS-0001, Containment Spray Pump Internal Inspection, Revision 10

Notifications20576262

20617756

20617574

20617514

20617766

20617646

20615169

20618133*

20618309*

20618307*

20618297*

20618143*

20618142*

20618049*20176570

20613625

Maintenance Orders/Work Orders

60098366

60106112

70018521

Drawings

203897, Unit 1 SW Intake No. 11&12 Vent Fan Miscellaneous Damper Cont., Revision 13

220948, Unit 2 SW Intake No. 23&24 SW Vent Fan, Revision 13

Other Documents

S-C-SWV-MDC-1996, SW Ventilation System Performance under Various Fan and Damper

Configurations, Revision 1

VTD 301100, Containment Spray Pumps, Revision 10

9601132275 Condition Report Corrective Action (CRCA) 11

70036820, CRCA

SW Intake Vent Operability Guidelines

Section 1R05: Fire Protection

Procedures

FP-AA-001, Precautions against Fire, Revision 1

CC-AA-211, Fire Protection Program, Revision 4

FRS-II-512, Revision 2, Pre-

FRS-ll-211, Salem Unit 1 (Unit 2) Pre-Fire Plan, Turbine Generator Area Elevation: 88',

Revision 5

FRS-Il-221, Salem Unit 1 (Unit 2) Pre-Fire Plan, Turbine Generator Area Elevation: 100', Revision 4 FRS-ll-231, Salem Unit 1 (Unit 2) Pre-Fire Plan, Turbine Generator Area Elevation: 120', Revision 4 FRS-ll-611, Salem Unit 1 (Unit 2) Pre-Fire Plan, Reactor Containment Elevations: 78', 100', & 130', Revision 5 FRS-ll-815, Salem Unit 1 (Unit 2) Pre-Fire Plan, Fire Fresh Water Pump House, Revision 1 FRS-ll-421, Salem Unit 1 (Unit 2) Pre-Fire Plan, 416p V Switchgear Rooms & Battery Rooms Elevation: 64', Revision 6

FRS-II-431, Salem Unit 1 (Unit 2) Pre-Fire Plan, 460V

Revision 8

Attachment

FP-M-011, Control of Transient Combustible Material, Revision 2

NC.DE-PS.ZZ-0001, Programmatic Standard for Fire Protection, Revision 3

NC.NA-AP.ZZ-0025, Operational Fire Protection Program, Revision 8

Notifications

20620678*

20619520

20620764*

20621931*

20621647*

Other Documents

FSAR 9.5

FP-M-002-F5, Form 5, Transient Combustible in Safety Related Areas impairment Log, Revision 0

FP-M-011-F1, Form 1, Transient Combustible Permit, Revision 0

Section 1R11: Licensed Operator Requalification Program

Procedures

2-EOP-LOPA-1, Loss of All AC Power, Revision 27 2-EOP-TRIP-1, Reactor Trip or Safety Injection, Revision 28 S2.OP-AB.SW-0001, Loss of SW Header Pressure, Revision 16 S2.OP-AB.CN-0001, MFW/Condensate System Abnormality, Revision 26 S2.OP-AB.CC-0001, Component Cooling Abnormality, Revision 14 S1.OP-AB.RAD-0001(Q), Abnormal Radiation, Revision 31 S1.OP-AB.RC-0001(Q), Reactor Coolant System Leak, Revision 10 S1.OP-AB.LOAD-0001(Q), Rapid Load Reduction, Revision 14

Other Documents

09/04/13 LORT Exam Scenario, 2013 Annual

ESG-1306, Revision 1 Scenario S-RSG-084

Notifications

20619899

20621805

20622153

20618913

Section 1R12: Maintenance Effectiveness

Procedures

MA-AA-716-230-1001, Oil Analysis Interpretation Guideline, Revision 9 S1.OP-SO.CVC-0002, Charging Pump Operation, Revision 37 S1.OP-ST.CVC-0005, In-service Testing

13 Charging Pump, Revision 19

Notifications20547864

20549396

20551995

20594606

20598923

20601766

20610353

20624057

20623938

20623786*

20622656

20620058

20622582

20622404

20622299

20622337

20621625

20620339

20619789

20619809

20619926

20618425

20618040

20618039

20618004

20617788

20617714

20617661

20617619

Attachment

Maintenance Orders/Work Orders

30159437

60074893

60110996

70150655

60103943

70125500

Other Documents

CVC System Health Report, June 2013 Operator Work Around / Challenges, 7/2/13 Salem Maintenance Strategy, S1CVC-1CVE22, June 2013 Salem Units 1 and 2 Operations Burdens Report, 7/2/13

VTD 301119

VTD 301337

VTD 304209

VTD 901999

OTDM, Degraded Station Air System Station Air Compressor MR Performance Criteria

Section 1R13: Maintenance Risk Assessments and Emergent Work Control

Procedures

S2.OP-AR.CA-0001, Alarm Response Procedure No. 2 Emergency Control Air Compressor Panel, Revision 4 S2.OP-AB.CA-0001, Loss of Control Air, Revision 17

WC-AA-101, On-Line Work Management Process, Revision 21,

OP-AA-108-116, Protected Equipment Program, Revision 7,

OP-AA-101-112-1002, On-Line Risk Assessment, Revision 7

SC.OP-SO.CA-0001, 530 Diesel Control Air Compressor, Revision 14

EP-SA-111-217, EAL Technical Basis, System Malfunction

Instrumentation, Revision 0 S2.OP-AB.ANN-0001, Loss of Overhead Annunciator System, Revision 22

WC-AA-105, Work Activity Risk Management, Revision 2

WC-AA-105-F1, Risk Activity Evaluation Worksheet, Revision 1

SO.OP-SO.500-0001, 500KV Bus Operation, Revision 13

Notifications

20616195

20616196

20622857

20618977

20621227

20620154

20619900

20618980

20619890

20620085

20619961

20621856

20621895

20621944

20622049

20622041

20622093

Maintenance Orders/Work Orders

60112115

4343930

4343929

60112671

60112893

Drawings

ELE-1: 500kV

4kV Overview 203000-SIMP, Salem 500kV

4kV Electrical Distribution

Simplified One Line, Revision 3

Attachment

Other Documents

60112671, Technical Evaluation Closing 1-9 500 kV Breaker with Bus Section 1 De-energized Risk Assessment for Units 1 and 2 for Work Week 337, Revision 0 and 1, respectively Salem Generating Station, Unit 1 and 2 Risk Assessments, dated 7/25/13 Salem Generating Station, Unit 2 Risk Activity Evaluation Worksheet for OHA

PS-2 Failure, dated 7/25/13 Wednesday, September 4, 2013 Protected Equipment List Salem Generating Station, Unit 1 Risk Assessment, Work Week 336, September 1 to 7, 2013 NRC letter to PSEG dated 3/16/95, License Amendment S-C-CA-CEE-0798 S1-MODE-

Salem Generating Station, Unit 1 Control Room Logs, dated August 22-24, 2013

Section 1R15: Operability Determinations and Functionality Assessments

Procedures

SC.MD-PT.CH-0004, Chiller Post-Maintenance Test and Unloader Adjustment, Revision 1 S1.OP-DL.ZZ-0006, Primary Plant Log, Revision 58 S1.OP-ST.500-0001, Electrical Power Systems AC Sources Alignment, Revision 15 S2.OP-SO.CAV-0001, Control Area Ventilation Operation, Revision 39 S2.OP-AB.CA-0001, Loss of Control Air, Revision 17

RP-SA-603, Routine Radiation Monitoring System (RMS) Surveillance, Revision 2 S1.OP-DL.ZZ-0003, Control Room Log

Modes 1-4, Revision 70

EP-SA-111-130, Salem ECG Wall Chart, Revision 0

EP-SA-111-203, Offsite Radiological Conditions, Revision 0

OP-AA-108-- OTDM S-13-007 - Salem Unit 1 operation till 1R23 with the S1RC-1PS1 pressurizer spray valve isolated, dated August 22, 2013

Notifications

20617274*

20618281*

20614389

20614777

20614642

20595674

20619962

20622321

20622693

20621856

20617512

20617511

20618125

20621347

20617467

20619277

20618980

20622823*

20623530*

20620692 2062147120588555

20588575

20599662

20618911

20618913

Maintenance Orders/Work Orders

70157183

70157108

Drawings

205347, Unit 2 Reactor Containment and Penetration Area Control Air, Sheet 1, Revision 42

205347, Unit 2 Reactor Containment and Penetration Area Control Air, Sheet 3, Revision 36

Attachment

Other Documents

Operability Evaluation 13-006, S1CH-1CHE9-COMP (20614777 / 70155989), Revision 0 PSEG Response to

NCV 50-311/99-07-01, dated October 28, 1999 PSEG Request for License Amendment

Containment System, dated March 2, 2000 Salem Common Station Standing Order: 2VC5, Cont Vent Iso Damper

Containment Isolation

Administrative Controls

04/20/12 USNRC Letter to Salem Units 1 and 2

Issuance of Amendments Re: Containment Isolation

Valve TSs

70157183, Technical Evaluation of 12 Auxiliary Building Supply Fan Failure to Start and

Associated Start Logic PSEG P.O. P3

0897020 for F&H C of C #96808.52: 12 Auxiliary Building Supply Fan Start

Circuit Relays Operability Evaluation 13-008, 2C Emergency Diesel Generator Control Area

Section 1R19: Post-Maintenance Testing

Procedures

S1.OPST.SW-0014, IST Room Cooler Valves Modes 1-6, Revision 5

MA-AA-723-303, Inspection/Instructions for Crimping and Lugging of Wiring, Revision 4

SC.MD-PM.RCP-0003, Reactor Trip Bypass Breaker Semi-Annual Inspection, Lubrication and Testing, Revision 1

SC.DE-TS.ZZ-2039, Cable Termination Methods Salem Generating Station, Revision 6 S1.IC-ST.SSP-0013, Reactor Trip Breakers and Reactor Bypass Breakers Operability Test

Train A and B, Revision 16 S1.OP-ST.ABV-0001, Plant Systems

Auxiliary Building Ventilation, Revision 9, Terminated 8/09/13 S1.OP-ST.ABV-0001, Plant Systems

Auxiliary Building Ventilation, Revision 9, Complete 08/14/13

MA-AA-716-012, Post-Maintenance Testing, Revision 19 S1.OP-ST.CH-0004, Chilled Water System

Chillers, Revision 12

Notifications

20617413

20612445

20617512

20617511

20618125

20621347

20617467

20619277

Maintenance Orders/Work Orders

3023243

30248318

6105792

30188597

Drawings

203646

Other Documents

ACM 12-006, ASCO

NPK 8342 SOV Overheating

ACM 13-005, Biofouling Monitoring of Room Coolers,

Revision 3, Vendor Technical Document

127879, Reactor Trip Breakers Attachment

Section 1R20: Refueling and Other Outage Activities

Procedures

CC-AA-5001, Post Transient or Scram Walkdown, Revision 5

Notifications

20618983

20618984

20618985

20618986

20618987

20618988

20618989

20618990

20618991

20618992

20618994

20618995

20619034

20619035

20619149

20619150

20619225

20619226

20619227

20619228

Section 1R22: Surveillance Testing

Procedures

S1.RA.ST.CC-0002, Revision 14,

IST 12 Component Cooling Pump Acceptance Criteria S1.OP-ST.CC-0002, Revision 24,

IST 12 Component Cooling Pump

ER-AA-321, Administrative Requirements for Inservice Testing, Revision 11

OP-AA-102-103, OWA Program, Revision 2

OP-SA-470-1001, Cyclic Data Monitoring Program, Revision 2 S2.OP-SO.CH-0001, Chilled Water System Operation, Revision 30 S2.OP-ST.CH-0003, IST Chilled Water Valves Modes 1-6, Revision 17 S1.MD-FT.4KV-0002, ESFAS Instrumentation Monthly Functional Test 1B 4KV Vital Bus Undervoltage, Revision 27 S1.MD-FT.SEC-Procedure, Revision 21 S1.OP-ST.ZZ-0003, IST Miscellaneous Valves, Revision 12 S1.RA-IS.ZZ-0001, Type B and C Leak Rate Test, Revision 14 S1.RA-ST.ZZ-0003, Inservice Testing Miscellaneous Valves Acceptance Criteria, Revision 12

SC.MD-PM.ZZ-0076, Air Operated ITT Grinnell Diaphragm Valves, Revision 3 S1.FP-ST.FS-0021, Diesel Area CO2 Systems Operability and Partial Discharge Test,

Revision 7

Notifications

20475997

20500543

20524646

20544806

20561216

20568041

20587672

20617585*

20617920*

20620349*

20610830

20462274

20462105

20587752

20612144

20001754

20610347

Maintenance Orders/Work Orders

50159575

60099187

60111698

70140699

50158332

60071067

30172256

70109986

4304072

Attachment

Drawings

205216, No. 1 and 2 Units Chilled Water, Revision 64

236250, No. 1A, 1B, &1C Vital Buses Safeguard Equipment Control System, Revision 14

205239, Unit 1

Waste Disposal Liquid, Revision 49

207480, Reactivator Control Waste Disposal Gas, Revision 18

228268, Unit 1 Reactor Containment Waste Disposal

Gas, Revision 19

614507, Unit 1 Radiological Waste Liquid RCDT to N2 Manifold Valve, Revision 1

600257, No.1 Unit Carbon Dioxide Fire Protection System, Revision 19

226942, Unit 1 Fire Protection System CO2 Instrument Schematic, Revision 8

205231, No.1 Unit Component Cooling, Sheets 1, 2 & 3, Revisions 66, 44 & 45

Other Documents

Drawing

205231, Revision 66 (44, 45), Sh. 1-3, No.1, Unit Component Cooling IST Results for Chilled Water Check Valves 1(2) CH55, -61 and -232 from 01/01/2011 through

07/01/2013 (Spreadsheet) Salem Unit 2 Operations Burdens Report, 7/2/13 S-C-CH-MEE-1139, Chilled Water System (CH)

Single Failure Criteria Vulnerability

Assessment, Revision 1

VTD 142026, Operation and Service Manual

Cardox Fire Extinguishing Systems

Section 1EP4: Emergency Action Level and Emergency Plan Changes

Evacuation Time Estimate Study Update

Section 2RS4: Occupational Dose Assessment

--- -- --

Section 2RS5: Radiation Monitoring Instrumentation

-- -- -- -- -- -- -- -- --

Attachment -- --- -- -- -- -- -- -

Section 2RS6: Radioactive Gaseous and Liquid Effluent Treatment

-- --- ---

Notifications

20568914

20576340

20596163

20611117

20611118 --- ---

Section 4OA1: Performance Indicator Verification

Procedures

LS-AA-2200, MSPI Data Acquisition and Reporting, Revision 4

NEI 99-02, Regulatory Assessment PI Guideline, Revision 6

SC-MSPI-001, Salem Generating Station MSPI Basis Document, Revision 8-5

Attachment

Other Documents

Salem 1 and Salem 2 - MSPI Derivation Reports, Heat Removal System, July 2012

June 2013 Salem 1 and Salem 2 - MSPI Derivation Reports, RHR System, July 2012

June 2013 Salem Engineering Raw Supporting MSPI Data, Heat Removal System, July 2012

June 2013 Salem Engineering Raw Supporting MSPI Data, RHR System, July 2012

June 2013

Section 4OA2: Problem Identification and Resolution

Procedures

ER-SA-310-1009, Salem Generating Station

MR Scoping, Revision S1.OP-ST.SW-0008, Inservice Testing Service Water Valves (Aux. Bldg) Mode 1-4, Revision 15 S1.OP-ST.SW-0014, Inservice Testing Room Cooler Valves Modes 1-6, Revision 5

SC.MD-PM.ZZ-0098, Disassembly, Inspection and Reassembly of Standard Trim Masoneilan

Control Valves, Revision 2

OP-AA-102-103, OWA Program, Revision 2

OP-AA-102-103-1001, Operator Burdens Program, Revision 1

OP-AA-108-105, Equipment Deficiency Identification and Documentation, Revision 4

OP-AA-115-001, Operator Aid Postings, Revision 3

Notifications20588864

20616579*

20616678*

20617398*

20617535*

20585761

20585831

20606004

20570390

20570413

20603820

20608514

20586233

20598949

20578160

20602826

20585052

20593582

20580964

20361896

20608514

20617545*

20617538*

20617539*

20618281*

20617540*

20617541*

20618049*

20617542*

20617543*

20503860

20624037*

20622573*

20622155*

20621712*

20588864

20617545*

20609074

20617119

20610245

Other Documents

AR 239632-19 Engineering Support Document

Excel Spreadsheet

Salem MRS Files: SW OP Evals: 12-026, -27, -34 Standing Order 12-12 Salem Metrics

OO.2 and

OO.3 for August 2013 Station Plan of the Day for September 9 and 26, 2013 IRs

05000272, 311;

2011005 and

2012004 PSEG Program Reference and Data Dictionary Section C Tier 3 Definitions dated April 30, 2011 -

Attachment

Maintenance Orders/Work Orders

30118934

60094418

70118364

70118674

70120002

70143350

70143367

70146516

70154085

80059932

80059933 80102290

Section 4OA3: Follow-up of Events and Notices of Enforcement Discretion

Procedures:

ER-AA-410, AOV Program Implementing Procedure, Revision 4

ER-AA-410-1001, AOV Design Basis Review and Setpoint Control, Revision 4

ER-AA-410-1002, AOV Testing Requirements, Revision 5

MA-AA-716-009, Use of Maintenance Procedures

MA-AA-734-437, General Instructions for Valve Packing, Revision 0 S1.OP-ST.RC-0008, RCS Water Inventory Balance, Revision 25

SC.IC-PM.RC-0003, 1PS1, 2PS2 and 2PS3 Pressurizer Spray Valve Operator Maintenance,

Revision 0

SC.MD-CM.RC-0002, Pressurizer Spray Valve PS1 and PS3 Repair, Revision 6

Notifications

20618915

20619948

20620336

20620422

20620557

20620611

20622061

20623942

Maintenance Orders/Work Orders

30218047

60109671

60083557

60083558

70157547

80098324

Other Documents: 1PS1 Valve Packing SAP Data Report Sheet AP Services, Inc. (ARGO / InterTech / Curtis Wright) Packing Guide, Revision 1, April 27, 2010 EPRI Technical Report

1000923, Valve Packing Performance Improvement, dated March 2002

ER-AA-331-1002, Attachment 3, Boric Acid Evaluation following 1PS1 Packing Leakage and

Containment Walkdown with Unit 1 Shutdown to Mode 3, dated 08/22/2013 Event Report 49300, Salem Unit 1 Commenced a TS Required Shutdown due to Unidentified RCS Leakage > 1 GPM, dated 08/22/2013 MR Condition Monitoring Criteria for 1SP1

MC.DE-TS.ZZ-3071, Valve Packing Salem and Hope Creek Generating Stations, Revision 5

NCV 05000387/2012005-04, Improper Stress Intensification Factor Results in RCS Pressure

Boundary Leak Notification

20618913, Prompt Investigation

Salem Unit 1 Shutdown to Mode 3 due to 1PS1

Packing Leakage Notification

20618915, Order

70157547, ACE

1PS1 Pressurizer Spray Valve Packing Leak

Leading to Plant Shutdown OCC Instructions for 08/22/13 1PS1 Local Inspection and As-Found Torque Check in Response to Discovery of Packing Leakage Order

70157108, Technical Evaluation

PS1 Packing Failure EOC for Unit 1 OTDM S-13-007, Determine if Salem Unit 1 Can Acceptably Operate Until 1R23 with the 1PS1

Isolated, dated 08/22/13

Attachment

PSED Nuclear LLC VTD Number

901826, PSEG Specification Number S-C-RC-MDS-0486,

Assembly and Actuator Setup Instructions for Pressurizer Spray Control Valves without a Bellows Assembly, dated 08/08/09 Regulatory Guide 1.33, Quality Assurance Program Requirements, Revision 2, February 1978 SAP ZCD2 Fastpath Component Classification for 1PS1 SAP List of Notifications for 1PS1 and 1PS3 Issues Since 11/01/10 Start-up PORC Action Items, 08/23/13

CC-AA-5001, Post-Transient or Scram Walkdown, Revision 5

OP-AA-108-108, Unit Restart Review, Revision 11

OP-AA-108-114, Post-Transient Review, Revision 4 Teleconference Meeting Minutes for 1PS1 Packing Failure Training Simplified Diagram

PZR-1: Pressurizer and Pressurizer Relief Tank, Revision 3

Section 4OA5: Other Activities

Salem ODCM Salem/Hope Creek 2012 Annual Radiological Environmental Monitoring Report 2013

Salem Effluent Release Report 2012

Ground Water Remedial Action Progress Report NRC Information Notice 2004-005

LIST OF ACRONYMS

AC alternating current

ACE apparent cause evaluation

ADAMS Agency-wide Documents Access and Management System

AOV air operated valves

CAP corrective action program

CCW component cooling water

CFR Code of Federal Regulations

CR condition report

DCP design change package

DRS Division of Reactor Safety

EQACE equipment apparent cause evaluation

EDG emergency diesel generator

EOC extent of condition

EPIP Emergency Plan Implementing Procedures

FIN finding

IMC inspection manual chapter

INPO Institute of Nuclear Power Operations

IP inspection procedure kV kilovolt

LER licensee event report

LOCA loss-of-coolant accident

MR maintenance rule

NCV non-cited violation

Attachment

NEI Nuclear Energy Institute

NRC Nuclear Regulatory Commission

NSIR Office of Nuclear Security and Incident Response

OE operating experience

OOS out of service

OWA operator work-arounds

PARS publicly available records

PSEG Public Service Enterprise Group Nuclear

LLC [[]]

RG regulatory guide

SDP significance determination process -

TS technical specification

UFSAR Updated Final Safety Analysis Report

WO work order