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05000244/FIN-2013005-012013Q4GinnaFailure to Identify and Correct Non-Hydrostatically Sealed Penetrations into Battery Room ?BThe inspectors identified a finding associated with an apparent violation of Title 10 of the Code of Federal Regulations (10 CFR) 50, Appendix B, Criterion XVI, Corrective Action, for Constellation Energy Nuclear Group, LLC (CENG) staffs failure to assure that conditions adverse to quality were promptly identified and corrected. Specifically, CENG failed to identify the need to hydrostatically seal two cable penetrations between manhole 1 and battery room B after the sites design basis flood height was changed during the NRC Systematic Evaluation Program (SEP) in 1983; promptly correct the significant adverse condition in May 2013 when the condition was identified and take timely action in early September 2013 when CENG was presented with evidence challenging its May 2013 evaluation related to manhole 1 and the improperly sealed penetrations. As a result, various Deer Creek flooding scenarios could have resulted in flooding of both battery rooms. Immediate corrective actions included placing this issue in the corrective action program (CAP) as condition report (CR)-2013-003407, CR-2013- 005262, and CR-2013-005643; and hydrostatically sealing the penetrations on October 4, 2013. This finding is more than minor because it is associated with the protection against external factors attribute of the Mitigating Systems cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, propagating flood water could damage mitigating equipment needed to prevent core damage with a flood below the design basis level of 273.8 feet because of the unsealed penetrations in manhole 1. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 2 of IMC 0609, Appendix A, The Significance Determination Process For Findings At-Power, the inspectors utilized Section B, External Event Mitigation Systems (Seismic/Fire/Flood/Severe Weather Protection Degraded), of Appendix A and determined the finding involved the loss or degradation of equipment or function specifically designed to mitigate a flooding initiating event, which requires the inspector to go to Exhibit 4, External Events Screening Questions. The inspectors determined that a detailed risk evaluation (DRE) was needed because the loss of equipment and function would degrade two or more trains of a multi-train system or function, and the loss of equipment and function would degrade one or more trains of a system that supports a risk-significant system or function. The staff determined that, currently, there is not an existing SDP risk tool that is suitable to assess the significance of this finding with high confidence, mainly because of the uncertainties associated with extreme flood frequency extrapolations based on limited available historical data. Therefore, the risk evaluation was performed using IMC 0609, Appendix M, Significance Determination Process Using Qualitative Criteria. The change in core damage frequency (CDF) estimates ranged from Green, a finding of very low safety significance, to Yellow, a finding of substantial safety significance. A significance and enforcement review panel (SERP) held on January 28, 2014, made a preliminary determination that the finding was of low to moderate safety significance (White) based on quantitative and qualitative evaluations. This finding has a cross-cutting aspect in the area of Problem Identification and Resolution, Corrective Action Program, because CENG personnel did not thoroughly evaluate problems such that the resolutions addressed causes. Such evaluations should include properly classifying, prioritizing, and evaluating operability and reportability of conditions adverse to quality. Specifically, CENG personnel had an opportunity to thoroughly evaluate and assess impacts to the plant such that resolutions addressed causes, when two unsealed penetrations into battery room B were identified in May 2013; CENGs evaluation associated with CR-2013-003407 was not thorough and did not consider all flow paths for flooding through manhole 1. Additionally, the condition adverse to quality was not properly evaluated for operability. CENG personnel had an additional opportunity to thoroughly evaluate and assess impacts to the plant such that resolutions addressed causes and properly evaluate for operability when inspectors presented evidence of degraded manhole 1 conditions, e.g., clogged manhole drains, to CENG management on September 5, 2013 (P.1(c)).
05000247/FIN-2008012-012008Q3Indian PointInadequate Design Control of Internal Recirculation PumpsThe team identified a non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion III, Design Control, because Entergy did not verify the adequacy of the internal recirculation pump minimum flow rates. Specifically, Entergy did not verify the adequacy of the pump minimum flow rates for sustained operation under low flow rate conditions or for strong-pump to weak-pump interactions which could result in dead-heading the weaker pump during parallel pump operation. Following identification of the issue, Entergy revised the Emergency Operating Procedures (EOP) to not start a second internal recirculation pump during conditions of high head recirculation, submitted a licensee event report (LER) for each generating unit, and entered the issue into the corrective action program. The finding was determined to be more than minor because it is associated with the design control attribute of the Mitigating Systems (MS) Cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. On Unit 2, the team determined the finding was of very low safety significance because it was a design or qualification deficiency confirmed not to result in loss of operability or functionality. On Unit 3, the finding was determined to be of very low safety significance based on a Significance Determination Process (SDP) Phase 3 risk assessment. Also, the Unit 3 finding had a crosscutting aspect in the area of Problem Identification and Resolution because Entergy did not implement operating experience information through changes to station processes, procedures, and equipment. (IMC 0305 aspect P.2 (b)
05000271/FIN-2008004-012008Q3Vermont YankeeLicensee-Identified ViolationThe following violation of very low safety significance was identified by the licensee and meets the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as a Non-Cited Violation. Two examples were identified in which the licensee failed to report potentially disqualifying licensed operator medical conditions to the NRC as required by 10CFR55.25 and 10CFR50.74. Contrary to these requirements, in the first instance, notification of a potentially disqualifying condition related to prescription medication was delayed for 15 months. The notification of a second operators potentially disqualifying physical condition was delayed for six months. The issues have been entered in the licensees corrective action program as site condition reports CR-2008-02901 and CR-2008-3429. Corrective actions included obtaining a peer review of medical records from another site, and a corporate level condition report CR-HQN-2008-00724 to review medical records at all Entergy sites for two years. The issues were of very low safety significance because the first individual did not stand watch since his diagnosis. The second individual made no operator errors to indicate potential impairment from failure to take prescribed medication, and the ultimate license restriction added was simply the requirement to take the medication as prescribed (EA- 2008-277)
05000272/FIN-2007003-012007Q2SalemFailure to obtain code relief for incomplete inspections of Class 1 and Class 2 welds during the second ISI interval within the required time period. (Section 1R08)During an NRC inspection conducted between April 2, 2007, and April 27, 2007, a violation of NRC requirements was identified. In accordance with the NRC Enforcement Policy, the violation is listed below: 10 CFR 50.55a(g)(5)(iv) states in part that where an examination requirement by the code or addenda is determined to be impractical by the licensee and is not included in the revised inservice inspection (ISI) program as permitted by paragraph (g)(4) of this section, the basis for this determination must be demonstrated to the satisfaction of the Commission not later than 12 months after the expiration of the initial 120-month period of operation from start of facility commercial operation and each subsequent 120-month period of operation during which the examination is determined to be impractical. 10 CFR 50.55a(g)(5)(iii) states in part that if the licensee has determined that conformance with certain code requirements is impractical for its facility, the licensee shall notify the Commission and submit, as specified in Section 50.4, information to support the determinations. Contrary to the above, PSEG Nuclear LLC determined that conformance with the code requirement for 100% inspection of 69 Class 1 welds and 29 Class 2 welds at Salem Nuclear Generating Station, Unit 2, during ISI interval 2 (May 10, 1992 - November 23, 2003), was impractical, however, (1) the basis for the termination was not demonstrated to the satisfaction of the Commission within 12 months after the expiration of ISI interval 2; and, (2) while PSEG notified the Commission of its determination on March 21, 2006, 28 months after the end of ISI interval 2, it did not submit the information necessary to support the determinations. This is a Severity Level IV violation (Supplement I). Pursuant to the provisions of 10 CFR 2.201, PSEG Nuclear LLC is hereby required to submit a written statement or explanation to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001 with a copy to the Regional Administrator, Region I, and a copy to the NRC Resident Inspector at the facility that is the subject of this Notice, within 30 days of the date of the letter transmitting this Notice of Violation (Notice). This reply should be clearly marked as a Reply to a Notice of Violation EA-07-149 and should include: (1) the reason for the violation, or, if contested, the basis for disputing the violation or severity level; (2) the corrective steps that have been taken and the results achieved; (3) the corrective steps that will be taken to avoid further violations; and (4) the date when full compliance will be achieved.
05000272/FIN-2008003-012008Q2SalemSalen Unit 2 Loss of All Three ChillersA self-revealing non-cited violation of Technical Specification (TS) 6.8.1.a, Procedures and Programs, was identified because PSEG did not maintain adequate control of the system configuration for the Unit 2 chill water system during maintenance on the 21 chiller. Specifically, on May 27, 2008, all three Unit 2 chill water system chillers tripped due to an error in the safety tagging sequence specified by the work control documents for maintenance on the 21 chiller. This finding is more than minor because it is associated with the configuration control attribute of the Initiating Events cornerstone, and it adversely affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, unavailability of all three chillers increased the likelihood of a loss of control air that could result in a complicated plant trip. Per Inspection Manual Chapter (IMC) 0609, Attachment 0609.04, initial screening and characterization of findings, the inspectors conducted a Phase 1 analysis and determined that this finding required a Phase 2 analysis because the finding contributed to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions will not be available. The inspector determined that the finding was of very low safety significance (Green) using the Salem plant specific Phase 2 pre-solved worksheets in accordance with IMC 0609, Appendix A, Determining the Significance of Reactor Inspection Findings for At-Power Situations. This finding has a cross-cutting aspect in the area of human performance because PSEG personnel did not follow procedures (H.4(b)). Specifically, revisions to the work control document for tagging the 21 chiller did not comply with the requirements of PSEG procedure SH.OP-AP.ZZ-0051, Safety Tagging Operations. (Section 1R13
05000272/FIN-2008003-022008Q2SalemSalem Unit 2 Loss of Reactor Vessel Level Indication SystemA self-revealing non-cited violation of Technical Specification (TS) 6.8.1.a, Procedures and Programs, was identified because PSEG did not adequately maintain the calibration of the Unit 2 reactor vessel level indication system (RVLIS). Specifically, scaling for both RVLIS dynamic range channels was not completed when required. This resulted in Unit 2 RVLIS being inoperable for 13-days. The finding is more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone and because it affected the cornerstone objective of ensuring the reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, operators were not aware that both channels of RVLIS were inoperable and could have taken non-conservative actions during an inadequate core cooling or loss of coolant inventory event. Per inspection manual chapter (IMC) 0609.04, Initial Screening and Characterization of Findings, the inspectors conducted a Phase 1 screen and determined the finding to be of very low safety significance (Green). This finding has a cross-cutting aspect in the area of human performance because PSEG did not appropriately coordinate work activities as necessary to keep personnel apprised of work status and the operational impact of work activities (H.3(b)). Specifically, PSEG did not ensure RVLIS scaling was completed per the established work control process because engineering did not adequately communicate the importance of entering the new dynamic range coefficients to the operability of the RVLIS system. (Section 1R15
05000272/FIN-2008003-032008Q2SalemSalem Unit 2 22 Cfcu Valves MispositionedA self-revealing non-cited violation of TS 6.8.1.a, Procedures and Programs was identified because the 22 Containment Fan Coil Unit (CFCU) had cooling water flow to the motor cooler inadvertently isolated during a routine surveillance test. Specifically, the surveillance procedure did not include steps to operate specific gage isolation valves to place a test gage in service, and as a result technicians repositioned the wrong valves. This finding is more than minor because it is associated with the system, structure, and component (SSC) and barrier performance attribute of the Barrier Integrity cornerstone and it affects the cornerstone objective of providing reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, unavailability of the 22 CFCU represented an actual loss of defense in depth of a system that controls containment pressure. Per inspection manual chapter (IMC) 0609, Attachment 0609.04, Determining the Significance of Reactor Inspection Findings for at-power Situations, the inspectors conducted a Phase 1 screen and determined the finding to be of very low safety significance (Green) because the finding did not represent an actual open pathway in the physical integrity of reactor containment isolation system and heat removal components, did not involve an actual reduction in function of hydrogen igniters in containment, and did not screen as potentially risk significant due to external initiating events. This finding has a cross-cutting aspect in the area of human resources because PSEG did not provide complete and accurate procedures for the performance of this surveillance test (H.2(c)). Specifically, the continuous use procedure Service Water Fouling Monitoring Containment Fan Coil Units, revised on May 31, 2008, did not contain procedure steps to direct the opening and closing of valves that must be manipulated to successfully perform the procedure. (Section 1R22
05000272/FIN-2008003-042008Q2SalemSalem Unit 2 Steam Flow Feed Flow MismatchDuring the sixteenth refueling outage at Unit 2, all four steam generators and the high pressure turbine were replaced. These replacements resulted in changes to various plant parameters, including main steam flow rate and pressure. PSEG developed post modification acceptance test procedure S2.PI-SP.ZZ-0001, Power Ascension Test for HP Turbine and Steam Generator Replacement, to support this work. The purpose of power ascension testing was to validate predicted values for reactor coolant flow rate, pressurizer water level, main steam flow rates and main steam inlet pressure to the high pressure turbine. Power ascension testing was to be initiated at 18% reactor power and was to be performed in conjunction with normal plant startup procedures. During startup power ascension testing was not implemented as planned and as a result operators did not recognize that all Unit 2 high steam flow protection channels were inoperable until the plant reached 84% power. Operators ultimately identified the condition because the steam flow rate measurement used for protection and indication was outside of acceptable limits, and entered TS 3.0.3 and conducted a plant shutdown. PSEG completed troubleshooting and determined that a number of engineering deficiencies and incomplete post modification test plan implementation ultimately resulted in the inoperable high steam flow protection channels. This issue is unresolved pending PSEGs completion of its root cause evaluation, inspector review of the root cause evaluation and additional inspector review of design control practices associated with the steam generator replacement project. (URI 05000311/2008003-04, Salem Unit 2 Steam Flow Feed Flow Mismatch
05000272/FIN-2013004-012013Q3SalemInadequate Maintenance Procedure to Reconsolidate Pressurizer Spray Valve PackThe 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.
05000272/FIN-2013005-022013Q4SalemPerformance Monitoring of Reactor Trip BreakersInspectors 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. 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.
05000272/FIN-2013005-032013Q4SalemInadequate HELB Barrier ControlsThe 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 safetyrelated 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.
05000272/FIN-2014002-012014Q1SalemFailure to Follow Fire Protection Test Procedure Resulted in Fuel Oil SpillThe inspectors determined there was a Green, self-revealing violation of Technical Specification (TS) 6.8.1, Procedures and Programs, as described in Regulatory Guide 1.33, Revision 2, February 1978, when PSEG failed to adequately implement procedure steps associated with fire protection hose flow verification testing on March 6, 2014. Consequently, a fuel oil day tank was overfilled, resulting in approximately 3000 gallons of fuel oil on the pump house roof, leaks through the roof onto the fire pumps, and Salem fire water suppression system unavailability for approximately two days. PSEG stopped the leak, entered this issue in their CAP, and completed a Prompt Investigation. The inspectors determined that the performance deficiency was more than minor because it was associated with the Protection Against External Factors attribute of the Mitigating System cornerstone and adversely its cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events (fire) to prevent undesirable consequences. The inspectors determined that the finding was of very low safety significance (Green) because it did not impact the ability of Salem Units 1 or 2 to achieve and maintain safe shutdown. The inspectors determined that this finding had a cross-cutting aspect in the area of Human Performance, Avoid Complacency, because PSEG fire protection operators did not recognize and plan for the possibly of mistakes, latent issues, and inherent risk, even while expecting successful outcomes of procedure steps to refill the fuel oil day tank. Further, they did not implement appropriate error reduction tools.
05000272/FIN-2014002-022014Q1SalemInadequate Online Risk Assessment for an Adverse Change in Grid ConditionsThe inspectors identified a Green NCV of Title 10 of the Code of Federal Regulations (10 CFR) 50.65(a)(4) when PSEG inadequately assessed risk during a period of adverse grid conditions. On January 7, 2014, the regional transmission organization declared a Maximum Emergency Generation Action, a condition that PSEG was procedurally required to consider a high risk evolution (HRE) for a loss of offsite power (LOOP). Specifically, PSEG was to elevate online risk to a Yellow condition; however, PSEG did not assess risk as Yellow. PSEG subsequently elevated their risk condition, protected equipment, took other risk management actions (RMAs), and entered the issue in their CAP. The issue was more than minor since it was associated with the Protection Against External Factors attribute of the Initiating Events cornerstone and adversely affected its objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the extreme cold weather conditions indirectly were affecting grid stability and required risk assessment and management. Additionally, it was similar to IMC 0612, Appendix E, example 7.e, in that an inadequate risk assessment is not minor if the overall plant risk would put the plant into a higher licensee-established risk category. In this case, plant risk was reclassified from Green to Yellow when properly assessed. Specifically, the extreme cold weather conditions indirectly were affecting grid stability. The inspectors evaluated the finding using IMC 0612, Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process. Since the incremental core damage probability deficit was less than 1 E-6 and the incremental large early release probability deficit was less than 1 E-7, this finding was determined to be of very low safety significance (Green). The finding was determined to have a cross-cutting aspect in the area of Human Performance, Teamwork, in that individuals and work groups communicate and coordinate their activities within and across organizational boundaries to ensure nuclear safety is maintained. Specifically, PSEG staff in the Electric System Operations Center (ESOC), Salem control room, and Hope Creek control room did not appropriately communicate across organizational boundaries to ensure that risk was appropriately assessed.
05000272/FIN-2014002-052014Q1SalemFailure to establish appropriate MR performance goalsThe inspectors identified a Green NCV of 10 CFR 50.65(a)(1) associated with Unit 1. Specifically, PSEG did not establish appropriate performance goals in response to positive displacement pump (PDP) performance issues that resulted in significant emergent unavailability and a repeat maintenance preventable function failure (RMPFF). PSEG entered this issue into their CAP to evaluate PDP performance goals and action plans. The finding was more than minor because it was associated with the Equipment Performance attribute of the Mitigating System cornerstone and affected its objective to ensure the availability and reliability of systems (safe shutdown charging cross-connect) that respond to initiating events (fire) to prevent undesirable consequences (i.e., core damage). The inspectors evaluated the finding in accordance with IMC 0609, Appendix F, Fire Protection Significance Determination Process. The inspectors determined that Finding Category 1.4.5 (post-fire, safe shutdown) applied as the finding potentially impacted a system credited for post-fire, safe shutdown. The inspectors determined that the finding was of very low safety significance (Green) because the Unit 2 reactor would have been able to reach and maintain safe shutdown, crediting the Unit 1 operating centrifugal charging pump as necessary (based on a yes response to question 1.3.1.A). This finding has a cross-cutting aspect in the area of Human Performance, Procedure Adherence, in that PSEG personnel did not follow Maintenance Rule (MR) processes and procedures. Specifically, PSEG personnel did not follow MR program procedure guidance to set appropriate (a)(1) monitoring goals or revise existing (a)(1) monitoring goals to monitor the effectiveness of actions taken to restore PDP performance.
05000272/FIN-2014002-062014Q1SalemFailure to take adequate corrective actions following a PDP failure to couple-ondemand eventThe inspectors identified a Green FIN associated with Unit 1 for PSEGs failure to take adequate corrective actions in accordance with procedure LS-AA-125, Corrective Action Program, Attachment 1 guidance following a PDP failure to couple-on-demand event, and to preclude subsequent failures during other couple-on-demand events and additional unplanned PDP unavailability. PSEG entered this issue into their CAP, implemented a compensatory measure, and initiated actions to correct the condition causing the failure to couple events. The performance deficiency was more than minor because it was associated with the Equipment Performance attribute of the Mitigating Systems cornerstone and affected its objective to ensure the availability and reliability of systems (safe shutdown charging crossconnect) that respond to initiating events (fire) to prevent undesirable consequences (i.e., core damage). The inspectors determined that the finding was very low safety significance as the Unit 2 reactor would have been able to reach and maintain safe shutdown. This finding has a cross-cutting aspect in the area of Problem Identification and Resolution, Resolution, in that PSEG did not take effective corrective actions to address issues in a timely manner commensurate with their safety significance. Specifically, PSEG did not take adequate corrective actions in response to a PDP failure-on-demand event in February 2013 to preclude several additional unexpected PDP failure-on-demand events which resulted in additional unplanned unavailability.
05000272/FIN-2014002-092014Q1SalemLicensee-Identified Violation10 CFR 50, Appendix B, Criterion XVI, requires that measures shall be established to assure that conditions adverse to quality ... are promptly identified and corrected. Contrary to these requirements, PSEG did not correct a condition adverse to quality identified in 2006 regarding excessive stanchion corrosion that impacted 12 SW strainer cable support capability during a seismic event until December 2010. As a result, PSEG also violated TS 3.7.4.1, Service Water System, which requires two independent SW loops to be operable. On eight separate occasions between 2007 and December 2010, a SW loop was out-of-service for greater than 72 hours due to SW strainer inoperability concurrent with other SW pump/strainer inoperability. PSEG entered this issue into their CAP as notification 20491305. The inspectors determined that the finding was of very low safety significance (Green) in accordance with IMC 0609, Attachment A, following a risk evaluation performed by a senior reactor analyst. That evaluation determined that, although degraded, the No. 12 SW strainer was still capable of performing its safety function during a design basis seismic event. Accordingly, full mitigation capability of the SW system was maintained during the subject period from 2007 to 2010 and, consequently, there was no increase in risk to plant operations due to the degraded SW strainer cable support condition.
05000272/FIN-2014004-012014Q3SalemImproper Risk Assessment and Risk Management Actions for a Reheater Drain ValveA self-revealing, Green NCV of 10 CFR 50.65(a)(4) was identified when PSEG did not properly assess and manage risk on Salem Unit 1 during an evolution with the potential to cause a reactivity change and overpower event. Specifically, while working on a moisture separator reheater (MSR) drain valve, it failed closed, reduced MSR reheat efficiency, led to turbine control valves opening further, and resulted in an overpower event. Consequently, this resulted in violating the thermal power limit in license condition 2.C.(1). PSEG took actions in accordance with procedures to place the valve in manual and lower power to restore it within the license limit. Additionally, they classified this as a reactivity event, entered it in their corrective action program, and performed an apparent cause evaluation. The issue was more than minor since it was associated with the configuration control attribute of the barrier integrity and adversely affected its objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, the system alignment was impacted during maintenance, resulting in an overpower event. It was also similar to IMC 0612, Appendix E, Example 8.a. The finding was then evaluated using IMC 0609, Attachment 4 and Appendix A, Exhibit 3, where it screened to Green since it was only associated with the fuel cladding barrier. The finding was determined to have a cross-cutting aspect in Human Performance, Avoid Complacency, in that individuals recognize and plan for the possibility of mistakes, latent issues, and inherent risk even while expecting successful outcomes. Individuals are expected to consider potential undesired consequences and implement appropriate error reduction tools. Specifically, PSEG staff relied on past successes and assumed conditions working on this and similar drain valves and did not perform adequate, successive activity reviews when the valve exhibited unexpected responses.
05000272/FIN-2014004-022014Q3SalemInadequate Corrective Action to Prevent Recurrence of Silent Steam Generator Feed Pump Coast-DownsA Green, self-revealing FIN was identified against NC.WM-AP.ZZ-0002, Performance Improvement Process, Revision 6, because PSEG did not adequately correct and prevent recurrence of steam generator feedpump (SGFP) silent coast-down events. Consequently, on April 8, 2014, PSEG operators manually tripped the Unit 1 reactor in response to lowering level in the 13 steam generator that was caused by a coast-down of the 11 SGFP. PSEG created new overhead alarms dedicated to a loss of power to SGFP governor controls, trained licensed operators on a silent SGFP coastdown event, and created a long term corrective action to automate SGFP runbacks on loss of power to the governor controls. This issue was more than minor since it was associated with the equipment performance attribute of the Initiating Events cornerstone and adversely impacted its objective to limit the likelihood of events that upset plant stability and challenge critical safety functions. In accordance with IMC 0609, Attachment 4 and Exhibit 1 of Appendix A, the inspectors determined that this finding is of very low safety significance, or Green, because the finding did not cause both a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. The inspectors determined there was no cross-cutting aspect associated with this finding since it was not representative of current PSEG performance. Specifically, in accordance IMC 0612, the causal factors associated with this finding occurred outside the nominal three-year period of consideration and were not considered representative of present performance.
05000272/FIN-2014004-032014Q3SalemIncomplete Corrective Action on Current Transformers Results in Reactor TripA Green, self-revealing finding against PSEG procedure NC.WM-AP.ZZ-0002, Performance Improvement Process, Revision 3, was identified for incomplete corrective actions when a Unit 1 main generator phase C differential current lockout relay tripped and resulted in a reactor trip. Specifically, a design change package had not been properly implemented in 2004 in response to a similar 2001 reactor trip. PSEG conducted repairs, visual inspections, and testing, entered this matter in its corrective action program, and completed a root cause analysis. The issue was more than minor since it was associated with the design control attribute of the initiating events cornerstone and adversely affected its objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. In accordance with IMC 0609, Attachment 4 and Exhibit 1 of Appendix A, the inspectors determined that this finding is of very low safety significance, or Green, because the finding did not cause both a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. The inspectors determined there was no cross-cutting aspect associated with this finding since it was not representative of current PSEG performance. Specifically, in accordance IMC 0612, the causal factors associated with this finding occurred outside the nominal three-year period of consideration and were not considered representative of present performance.
05000272/FIN-2014004-042014Q3SalemInadequate Interim Corrective Actions on Current Transformers Result in Reactor TripA Green, self-revealing finding against PSEG procedure LS-AA-120, Issue Identification and Screening Process, Revision 12, was identified for inadequate interim corrective actions when a Unit 1 main generator phase A differential current lockout relay tripped and resulted in a reactor trip on May 7, 2014. Specifically, interim corrective actions had not been properly implemented in response to a similar trip on April 13, 2014 for the same failure mechanism. PSEG conducted repairs, entered this matter in its corrective action program, and completed a root cause analysis. The issue was more than minor since it was associated with the equipment attribute of the initiating events cornerstone and adversely affected its objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, interim corrective actions did not adequately ensure the near-term reliability of transformer connections following an April 2014 failure, leaving the unit susceptible to a similar failure and a reactor trip in May 2014. In accordance with IMC 0609, Attachment 4 and Exhibit 1 of Appendix A, the inspectors determined that this finding is of very low safety significance, or Green, because the finding did not cause both a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. The finding was determined to have a cross-cutting aspect in Human Performance, Conservative Bias, in that individuals use decision-making practices that emphasize prudent choices over those that are simply allowable. That is, proposed actions are determined to be safe in order to proceed rather than unsafe in order to stop. Specifically, PSEG did not take a conservative approach to decisions regarding the scope of repairs given the unusual condition, did not consider the longer-term consequences when determining how to resolve the emergent CT concern, and did not take timely action to address the degraded condition commensurate with its significance, namely vulnerability to a further failure and a consequent reactor trip.
05000272/FIN-2014005-012014Q4SalemProcedural Non-Compliance Resulted in Low Temperature Overpressure Relief LiftingA self-revealing, Green NCV of TS 6.8.1, Procedures and Programs, was identified when PSEG did not correctly implement procedures associated with Safeguard Equipment Control (SEC) surveillance testing during solid reactor coolant system (RCS) operations. Consequently, this resulted in lifting a low temperature over-pressure protection valve during solid pressurizer operations. PSEG immediately stabilized reactor pressure, completed a prompt investigation and an apparent cause evaluation, submitted a Special Report to the NRC in accordance with TS 6.9.2, and entered this in their CAP (20665897). Non-compliance with TS 6.8.1 procedures was a performance deficiency. This issue was determined to be more than minor because it was associated with the human performance attribute of the Barrier Integrity cornerstone, and adversely affected its objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. It was also similar to IMC 0612, Appendix E, example 4.b, in that not accomplishing activities in accordance with procedures is more than minor if it results in a trip or transient. Specifically, not following procedures resulted in an RCS pressure transient that caused a protective relief valve to lift. Since the finding was not associated with a freeze seal, nozzle dam, criticality drain-down path, leakage path, or safety injection actuation, and did not involve or result in PORV unavailability or a setpoint issue, it screened to Green. The finding had a cross-cutting aspect in the area of Human Performance, Procedure Adherence, in that individuals are expected to follow processes, procedures, and work instructions. Specifically, PSEG operators did not follow procedures nor review procedures before work to validate appropriateness and timing.
05000272/FIN-2014005-022014Q4SalemFailure to Implement Procedures during Shutdown Results in ESF ActuationThe inspectors identified a Green NCV of TS 6.8.1, Procedures and Programs, when PSEG operators did not implement the procedure steps to trip the main turbine, and manually initiate auxiliary feedwater (AFW), during shutdown for a refueling outage on October 19, 2014. Consequently, operator response to degrading equipment conditions resulted in an unplanned manual reactor trip and coincident AFW actuation. PSEGs immediate corrective actions included conducting crew performance reviews documented as part of the post-trip review by the sites Plant Operations Review Committee (PORC), and subsequent coaching of operator performance. The inspectors determined PSEGs failure to trip the main turbine and establish AFW flow on October 19, in accordance with (IAW) abnormal and shutdown procedures, constituted a performance deficiency. The finding was more than minor because it was associated with the Human Performance attribute of the Initiating Event cornerstone, and adversely affected its objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, not following procedures in response to the 1B main power transformer (MPT) challenges resulted in an unplanned manual reactor trip and coincident Engineered Safety Features (ESF) AFW system actuation. In accordance with IMC 0609, Attachment 4, and Exhibit 1 of Appendix A, the inspectors determined that this finding is of very low safety significance, or Green, because the finding did not cause both a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. The inspectors determined that this finding had a cross-cutting aspect in the area of Human Performance, Procedure Adherence, because PSEG operators did not follow procedures in response to degrading 1B MPT conditions during shutdown for a refueling outage on October 19.
05000272/FIN-2014005-032014Q4SalemFailure to Implement TS Locked High Radiation Area ControlsThe inspectors identified NCV of very low safety significance (Green) associated with failure to implement TS 6.12.2 access controls for a High Radiation Area (HRA) exhibiting accessible radiation dose rates exceeding 1 rem/hr at 30 cm. Specifically, on October 28, 2014, NRC inspectors found the access door to the Unit 1 Containment Regenerative Heat Exchanger Room unlocked and unguarded, and the area exhibited accessible radiation dose rates of up to 1.4 rem/hr at 30 cm. PSEG immediately locked access to this area and entered this issue into its CAP (Notification 20667323). The failure to establish and implement TS 6.12 HRA access controls is a performance deficiency (PD) which was within PSEGs ability to foresee and correct and should have been prevented. The PD was determined to be more than minor because, if left uncorrected, the PD had the potential to lead to a more significant safety concern if personnel were exposed to elevated radiation dose rates. Further, the PD was related to the programs and process attribute of the Occupational Radiation Safety cornerstone, and adversely affected the cornerstone objective to ensure adequate protection of worker from radiation exposure. The finding was assessed using IMC 0609, Appendix C, Occupational Radiation Safety Significance Determination Process, and was determined to be of very low safety significance (Green) because the finding did not involve: (1) As-Low-As-Reasonably Achievable (ALARA) planning and controls; (2) a radiological overexposure; (3) a substantial potential for an overexposure; or (4) a compromised ability to assess dose. This finding was associated with the Resolution aspect of the Problem Identification and Resolution crosscutting area in that PSEG did not take effective corrective actions to address issues in a timely manner commensurate with their safety significance. Specifically, PSEG did not repair a long standing broken High Radiation Area access door lock resulting in extended use of an alternate lock and chain remedy that could not be readily verified in the locked condition and led to human error in not successfully locking the door from prior egress.
05000272/FIN-2014005-052014Q4SalemFailure to Report a Manual Reactor TripInspectors identified a Severity Level IV (SLIV) NCV of 10 CFR 50.72(b)(2)(iv)(B) when PSEG failed to make the required event notification within four hours for a valid actuation of the reactor protection system (RPS) when the reactor was critical. Inspectors determined that a manual reactor trip on October 19, 2014, was not in accordance with PSEGs preplanned documented procedural sequence and, therefore, reportable. PSEG entered this in their CAP (20668967) and reported this RPS actuation by updating a previous report (EN 50550) on November 24, 2014. Failing to submit an event notification in accordance with 10 CFR 50.72 within the required time was a performance deficiency that was reasonably within PSEGs ability to foresee and correct, and should have been prevented. Since the failure to submit a required event report impacts the regulatory process, traditional enforcement applied and the violation was assessed using Section 2.2.4 of the NRCs Enforcement Policy. Using the example listed in Section 6.9.d.9, A licensee fails to make a report required by 10 CFR 50.72, the issue was determined to be a Severity Level IV violation. The inspectors reviewed the condition for reactor oversight process significance and concluded there was no associated finding. Because this violation involves the traditional enforcement process and does not have an underlying technical violation that would be considered more-than-minor, a cross-cutting aspect is not assigned to this violation in accordance with IMC 0612.
05000272/FIN-2015001-012015Q1SalemFailure to Ensure Adequate Negative Differential Pressure During Fuel MovementsThe inspectors identified a Green NCV of TS 3.9.12, Fuel Handling Area Ventilation System, when PSEG did not suspend Unit 1 fuel movement operations when the fuel handling area ventilation system was inoperable. Specifically, differential pressure exceeded its alarm setpoint, and at times, was positive during irradiated fuel movements. Once aware of the issue, PSEG immediately suspended fuel movement, placed fuel assemblies in a safe condition, and entered the issue in their CAP as notifications 20677427 and 20678063. The issue was determined to be more than minor since it affected the configuration control/barrier performance attribute of the Barrier Integrity cornerstone and adversely affected its objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. The finding was screened using IMC 0609, Attachment 4 and Appendix A, Exhibit 3.C for Barrier Integrity screening questions involving the spent fuel pool building. Since the finding only represented a degradation of the radiological barrier function provided for the spent fuel pool, the finding screened to Green. This finding had a cross-cutting aspect in Human Performance, Procedure Adherence, in that individuals follow processes, procedures, and instructions. Specifically, PSEG operators did not follow alarm response and general operating procedures, did not use human error reduction techniques with respect to receipt of multiple low FHB D/P alarms, and manipulated irradiated fuel when not appropriately authorized and directed by procedures.
05000272/FIN-2015001-022015Q1SalemInadequate Corrective Actions for HELB Barrier ControlsInspectors identified a Green NCV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, when PSEG did not implement adequate corrective actions from a previous Green NCV in a timeframe commensurate with its safety significance. Specifically, inadequate corrective actions resulted in high energy line break (HELB) and moderate energy line break (MELB) barriers being unsecured without implementing the associated station process. PSEG immediate corrective actions were to secure the affected barriers and enter these examples in their CAP as notifications 20677643, 20683127, 20680283, and 20680680. The issue was evaluated in accordance with IMC 0612, Appendix B, and determined to be more than minor since it was associated with the configuration control attribute of the Mitigating Systems cornerstone and adversely affected its objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using IMC 0609, Appendix A, it screened to Green since it was not associated with a design or qualification deficiency or loss of system or function. The issue had a cross-cutting issue in Problem Identification and Resolution, Evaluation, in that organizations thoroughly evaluate issues to ensure that resolutions address causes and extent of conditions commensurate with their safety significance. Specifically, PSEG did not thoroughly investigate and evaluate the previous NCV issues in order to understand the bases for staff decisions and the underlying organizational and safety culture contributors.
05000272/FIN-2015002-022015Q2SalemFailure to Correct a Condition Adverse To Quality Associated With 12 Chiller MotorA self-revealing Green NCV of Title 10 of the Code of Federal Regulations (10 CFR), Part 50, Appendix B, Criterion XVI, Corrective Action, was identified for PSEGs failure to take timely corrective action to correct a condition adverse to quality (CAQ). Specifically, PSEG failed to replace the 12 chiller motor as a corrective action to address extent of condition following a 13 chiller motor failure in 2008. The 12 chiller motor subsequently failed on March 27, 2015. PSEG replaced the 12 chiller motor and the stationary and movable contacts in the main contactor panel. This issue was more than minor because it was associated with the equipment performance 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, the untimely corrective action resulted in emergent unavailability and associated inoperability of the 12 chiller. The inspectors determined that the finding was of very low safety significance (Green) in accordance with Exhibit 2 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, dated June 19, 2012, because the finding was not a design or qualification deficiency, did not represent a loss of safety system function, did not represent the loss of function for any technical specification (TS) system, train, or component beyond the allowed TS outage time, and it did not represent an actual loss of function of any non TS trains of equipment designated as high safety significance in accordance with PSEGs maintenance rule program. The inspectors determined that this finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Resolution, because PSEG did not take effective corrective actions to address issues in a timely manner commensurate with their safety significance. Specifically, PSEG did not replace the motor over a six year period despite having numerous opportunities to replace the 12 chiller motor prior to its failure.
05000272/FIN-2015002-032015Q2SalemInadequate Seismic EAL SchemeThe inspectors identified a Green NCV of 10 CFR 50.54(q)(2) when PSEG did not maintain an adequate emergency classification and action level scheme that met the planning standards of 10 CFR 50.47(b). Specifically, PSEG did not establish an effective emergency plan with respect to declaring an Alert for seismic activity in excess of an operating basis earthquake (OBE), specifically vertical acceleration. PSEG entered this issue into their CAP as notification 20691160 and developed a temporary Operations standing order. The issue was determined to be more than minor since it was associated with the procedure quality attribute of the Emergency Preparedness cornerstone, and adversely affected its objective to ensure that licensees are capable of implementing adequate measures to protect the health and safety of the public in the event of radiological emergency. Specifically, PSEG would not declare on Alert based on exceeding their OBE without actuation of the Hope Creek seismic switch. The issue was reviewed in accordance with IMC 0609, Appendix B, Emergency Preparedness Significance Determination Process, issued September 26, 2014, where it screened to very low safety significance (Green) since the seismic Alert emergency action level (EAL) had been rendered ineffective such that it would not be declared for seismic activity for the OBE vertical acceleration level. The inspectors determined this finding has a cross-cutting aspect in the area in Problem Identification and Resolution, Operating Experience, in that the organization systematically and effectively collects, evaluates and implements relevant external operating experience in a timely manner. The inspectors determined that PSEG staff did not thoroughly evaluate NRC Information Notice (IN) 2012-25, Performance Issues with Seismic Instrumentation and Associated Systems for Operating Reactors, published on February 1, 2013. Specifically, PSEG initiated CAP notification 20594195 in response to IN 2012-025, and took credit for previous actions completed to adjust SC.OP-AB.ZZ-0004, Earthquake, but did not account for the vertical direction ground motion acceleration differences between Salem and Hope Creek.
05000272/FIN-2015002-042015Q2SalemInadequate HRA ControlsThe inspectors identified a Green NCV of TS 6.12, High Radiation Area, when PSEG did not apply appropriate controls to high radiation areas. Specifically, the Unit 1 and 2 reactor cavities in containment, which are areas that exceed 1.0 rem/hour at 30 centimeters, were not properly controlled to prevent unauthorized personnel access. PSEG entered this issue in their CAP as notification 20682903 and installed six foot high scissor fences around each reactor cavity. The issue was determined to be more than minor since it was associated with the program and process attribute of the Occupational Radiation Safety cornerstone, and adversely affected its objective to ensure the adequate protection of the worker health and safety from exposure to radiation from radioactive material during routine civilian nuclear reactor operation. Specifically, high radiation areas with dose rates greater than 1.0 rem/hour at 30 centimeters were not properly controlled to prevent unauthorized personnel access. It was also similar to IMC 0612, Appendix E, example 6.g, in that access to a posted high radiation area (HRA) was not controlled in accordance with site TSs, a HRA actually existed, and it was not properly barricaded. The finding was then evaluated using IMC 0609, Appendix C, Occupational Radiation Safety Significance Determination Process, issued August 19, 2008, where it screened to very low safety significance (Green) since it was not associated with an as low as is reasonably achievable (ALARA) issue, did not involve an overexposure, did not constitute a substantial potential for overexposure, and did not compromise PSEGs ability to assess dose. The inspectors determined this finding has a cross-cutting aspect in the area of Human Performance, Avoid Complacency, in that individuals recognize and plan for the possibility of latent problems, even while expecting successful outcomes. Specifically, PSEG was not sufficiently aware of latent deficiencies in HRA access control given opportunities to identify the inadequate HRA controls when performing containment entries during normal plant operation and when routinely establishing the reactor cavities as locked high radiation areas following refueling outages.
05000272/FIN-2015002-052015Q2SalemFailure to Establish Appropriate Breaker Preventive Maintenance PeriodicityA self-revealing Green NCV of 10 CFR 50, Appendix B, Criterion V, Instruction, Procedures, and Drawings, was identified because PSEG did not establish an appropriate interval to overhaul 4kV General Electric (GE) Magne-Blast breakers. As a result, the safety-related breakers for the 12 safety injection (SI) pump and 11 component cooling water (CCW) pump were operated beyond the industry recommended overhaul interval and subsequently failed. PSEGs corrective actions included replacing the 12 SI pump and 11 CCW pump breakers, and reducing the overhaul preventive maintenance (PM) frequency to 12 years. This finding is more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone, and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, PSEG did not consider industry recommendations nor develop a basis when establishing 4kV GE Magne-Blast breaker overhaul intervals, which resulted in failure of the 12 SI pump and 11 CCW pump breakers. In accordance with Exhibit 2 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, issued June 19, 2012, the inspectors determined that the finding was of very low safety significance (Green), because the finding was not a deficiency affecting the design or qualification of the mitigating system; it did not represent a loss of system function; it did not represent the loss of function for any TS system, train, or component beyond the allowed TS outage time; and it did not represent an actual loss of function of any non TS trains of equipment designated as high safety significance in accordance with PSEGs maintenance rule program. The inspectors determined this finding has a cross-cutting aspect in the area of Problem Identification and Resolution, Operating Experience, because PSEG did not systematically and effectively collect, evaluate, and implement relevant internal and external operating experience in a timely manner. Specifically, the overhaul frequencies assigned to safety-related 4KV breaker inspections were inadequate to ensure the breakers would operate properly.
05000272/FIN-2015002-062015Q2SalemInadequate Chiller Maintenance ProcedureThe 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 performed chiller water system maintenance activities that were not properly preplanned in accordance with documented instructions, resulting in multiple chiller system trips on both units. Specifically, PSEG maintenance procedure SC.MD-PM.CH-0001, ACME Chiller Compressor Inspection and Repair, did not incorporate documented instructions from the vendor technical document. PSEG performed an apparent cause evaluation (ACE) 70171934, and revised the maintenance procedure that included detailed vendor instructions. This finding was more than minor because it was associated with the equipment performance attribute of the Mitigating System cornerstone, and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, failure to install the chiller evaporator gasket in accordance with written instructions from the vendor manual resulted in multiple chiller failures. Using IMC 0609, Attachment 4, Initial Characterization of Findings, and Exhibit 2 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, dated June 19, 2012, the inspectors determined that this finding was of very low safety significance (Green) because the finding was not a design or qualification deficiency, did not represent a loss of safety system function, did not represent the loss of function for any TS system, train, or component beyond the allowed TS outage time, and it did not represent an actual loss of function of any non TS trains of equipment designated as high safety significance in accordance with PSEGs maintenance rule program. This finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Evaluation, in that licensees thoroughly evaluate issues to ensure that resolutions address causes and extent of conditions commensurate with their significance. Specifically, PSEG did not thoroughly evaluate chiller divider plate head gasket failures in 2012, such that the resolution addressed the inadequate maintenance procedure instructions.
05000272/FIN-2015003-012015Q3SalemFailure to Establish Measures for the Selection and Review for Suitability of a TDAFW Room Cooler Temperature SwitchA self-revealing, Green NCV of 10 CFR 50, Appendix B, Criterion III, Design Control, was identified when PSEG selected a temperature control switch for the auxiliary feedwater (AFW) pump area room cooler that was not suitable for its application. Specifically, installation of a temperature control switch with an inadequate reset deadband resulted in excessive cycling of the room cooler, failure of its associated turbine-driven AFW (TDAFW) pump enclosure inlet damper to fully open, and subsequent inoperability of the TDAFW pump. PSEG entered this issue into their corrective action program (CAP), performed immediate repairs to the failed damper, performed an apparent cause evaluation (ACE), and created corrective actions to replace the temperature switches on both units. This issue was more than minor because it was associated with the equipment performance 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. The finding was evaluated in accordance with IMC 0609, Attachment 4 and Appendix A, Exhibit 2, and screened to Green. Specifically, this finding was a design deficiency whereby the TDAFW pump did not maintain operability; however, this finding did not represent a loss of system or function, and TDAFW did not exceed its Technical Specification (TS) allowed outage time. The inspectors determined that this finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Resolution, because PSEG did not take effective corrective actions to address issues in a timely manner commensurate with their safety significance. Specifically, PSEG did not complete corrective actions in a timely manner to resolve and correct excessive damper cycling, as identified in 2013; did not ensure that work order operation deferrals to address excessive cycling were minimized; and did not address the fundamental cause of excessive damper cycling while an interim corrective action was established to minimize excessive damper cycling.
05000272/FIN-2015003-032015Q3SalemFailure to Correct Chronic Chiller Relief Valve Freon LeaksA self-revealing, Green NCV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, was identified when the 13 chiller tripped on freeze protection due to insufficient refrigerant. Specifically, timely corrective actions were not implemented in response to repetitive Freon leaks that ultimately rendered the 13 chiller inoperable. In response, PSEG initiated a prompt investigation, conducted troubleshooting and repairs, entered the issue in their CAP, and completed an ACE. The issue was determined to be more than minor since it affected the equipment performance 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 (i.e., core damage). The finding was evaluated in accordance with IMC 0609, Attachment 4 and Appendix A, Exhibit 2, and screened to Green since it was not a qualification or design deficiency, did not represent a loss of system or function, and did not exceed its TS allowed outage time. The issue was determined to have a cross-cutting aspect in Human Performance, Design Margins, in that a licensee organization operates and maintains equipment within design margins, and places special attention on maintaining safety related equipment. Specifically, PSEG did not minimize a long-standing equipment issue nor carefully maintain its operating margin.
05000272/FIN-2015004-022015Q4SalemInadequate Maintenance Effectiveness of Control Room Ventilation Radiation MonitorsInspectors identified a Green NCV of 10 CFR 50.65(a)(2) when control area ventilation (CAV) radiation monitor (RM) performance was not being effectively controlled through appropriate PM. Specifically, there were repetitive foil issues and a repeat maintenance preventable functional failure (RMPFF) during the monitoring period. PSEG placed the system in monitoring under 10 CFR 50.65(a)(1) and entered this in their CAP. The issue was more than minor since it was associated with the barrier performance attribute of the Barrier Integrity cornerstone and adversely affected its objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. The finding was screened in accordance with IMC 0609, Attachment 4 and Appendix A, Exhibit 3, where it screened to Green since it only represented a degradation of the radiological barrier function provided for the control room. The finding has a cross-cutting aspect in Human Performance, Conservative Bias, in that licensees take timely action to address degraded conditions commensurate with their safety significance and take a conservative approach to decision making.
05000272/FIN-2015004-032015Q4SalemImproper PM Deletion Resulted in Plant Shutdown Required by Technical SpecificationsA self-revealing Green NCV of Technical Specification (TS) 6.8.1, Procedures and Programs, as described in Regulatory Guide (RG) 1.33, Revision 2, February 1978, was identified when PSEG did not maintain an appropriate preventive maintenance (PM) schedule for Salem containment fan cooling units (CFCUs). Specifically, PSEG did not incorporate vendor recommendations and industry operating experience (OE) in 2003 when modifying PM schedules to delete motor air gap measurements for CFCUs. The 14 CFCU subsequently failed to start in low speed for scheduled testing on March 8, 2015. PSEG entered this in their corrective action program (CAP) as notification 20681031, replaced the 14 CFCU motor, completed an apparent cause evaluation (ACE), and re-initiated CFCU motor air gap measurement PMs. PSEGs inadequate analysis of PM deletion was a performance deficiency within PSEGs ability to correct and should have been prevented. This issue was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and affects its cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors determined that the finding was of very low safety significance (Green) in accordance with IMC 0609, Attachment 4 and Appendix A, Exhibit 2, because the finding was not a design or qualification deficiency, did not represent a loss of safety system function, did not represent the loss of function for any TS system, train, or component beyond the allowed TS outage time, and it did not represent an actual loss of function of any non-TS trains of equipment designated as high safety significance in accordance with PSEGs maintenance rule (MR) program. The inspectors determined that there was no cross-cutting aspect associated with this finding since it was not representative of current PSEG performance. Specifically, in accordance with IMC 0612, the causal factors associated with this finding occurred outside the nominal three-year period of consideration and were not considered representative of present performance.
05000272/FIN-2015004-042015Q4SalemInadequate Post Maintenance Testing on OTDT ChannelsA self-revealing Green NCV of Title 10 of the Code of Federal Regulations (10 CFR) 50, Appendix B, Criterion XI, Test Control, and associated NCV of TS 3.3.1.1 was identified, with two examples, for not ensuring that all testing required to demonstrate that nuclear instrumentation (NI) would perform satisfactorily in service was identified and performed. As a result, inoperable Over-Temperature Delta-Temperature (OTDT) channels were not placed in the tripped condition within the timeframe required by TS limiting condition for operation (LCO) 3.3.1.1, on January 20 and April 21, 2015, respectively. PSEG entered this issue in their CAP and developed corrective actions to provide improved retest requirements for all maintenance performed on the NI system. The inspectors determined that the failure to ensure the NI channels were operable upon restoration to service was a performance deficiency. The performance deficiency is more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone and affected its cornerstone objective to ensure the availability of systems that respond to initiating events to prevent undesirable consequences. Inspectors evaluated the findings significance in accordance with IMC 0609, Attachment 4 and Appendix A, and determined that the finding did not affect a single reactor protection system (RPS) trip signal to initiate a reactor scram and the function of other redundant trips or diverse methods of reactor shutdown, did not involve control manipulations that unintentionally added positive reactivity and did not result in a mismanagement of reactivity by operator(s). Therefore, the finding screened to Green, or very low safety significance. The finding has a cross-cutting aspect in the area of Human Performance, Documentation, because PSEG did not ensure that plant activities were effectively governed by comprehensive, high-quality, programs, processes and procedures. Specifically, subsequent to completion of calibration and replacement work and post-maintenance testing (PMT) per Instrumentation and Controls (I&C) surveillance procedures, work packages did not adequately address or specify activities related to verifying potentially affected RPS indications.
05000272/FIN-2015004-052015Q4SalemLicensee-Identified ViolationFrom 2010 to 2014, Salem Units 1 and 2, made a total of 8 shipments of radioactive waste for disposal which contained category 2 levels of radioactive material quantity of concern, but did not implement a transportation security plan for these shipments in violation of the requirements of 10 CFR 71.5, Transportation of Licensed Material, and 49 CFR 172, Subpart I, Safety and Security Plans. This performance deficiency adversely affected the Public Radiation Safety cornerstone attribute of Program and Process based on inadequate procedures associated with the transportation of radioactive material. The finding was determined to be of very low safety significance (Green) because Salem had an issue involving transportation of radioactive material, but it did not involve: (1) a radiation limit that was exceeded; (2) a breach of package during transport; (3) a certificate of compliance issue; (4) a low level burial ground nonconformance; or (5) not making notifications or not providing emergency information. This issue was documented in the PSEGs CAP as notification 20674767. Corrective actions included issuance of new procedure RP-AA-600-1009, revision of procedure LS-AA-1020, Implementation of Significant Rules and Orders, Revision 1, and contracting with a vendor to receive regular, prompt notifications of potentially applicable rule changes in the Federal Register.
05000272/FIN-2015008-012015Q2SalemInadequate Maintenance Rule System Performance Criteria SelectionThe inspectors identified a URI associated with inadequate Maintenance Rule Performance Criteria selection. Specifically, the inspectors determined that PSEG did not follow station procedures to: 1) determine that the number of maintenance preventable functional failures (MPFF) allowed per 10 CFR 50.65(a)(3) evaluation period was consistent with the assumptions in the probabilistic risk assessment (PRA); and 2) review and approve reliability performance criteria (PC) that was higher than the number of PRA-supplied basic event failures. The inspectors determined that additional information was needed to determine if these performance deficiencies were more than minor. The inspectors performed a review of PSEGs Focused Area Self-Assessment (FASA) of the Maintenance Rule (MRule) Program, completed August 30, 2014, to determine if PSEG was appropriately assessing MRule program performance in accordance with LS-AA-126-1001, Self-Assessments. The purpose of PSEGs FASA was to ensure the MRule Program was implemented in accordance with 10 CFR 50.65, as well as PSEG program procedures. The inspectors noted that the MRule Program FASA met the requirements of LS-AA-126-1001, was sufficiently critical, identified several deficiencies that were entered into the CAP, and resulted in multiple recommendations. As a result of the FASA, PSEG determined that multiple structures, systems, and components (SSCs) in (a)(2) status had to be re-evaluated for (a)(1) status, due to those SSCs having had their Functional Failure Cause Determinations (FFCDE) and unavailability (UA) amounts incorrectly assessed in the past. The inspectors reviewed the list of systems re-evaluated for (a)(1) status due to the FASA, as well as a listing of systems that remained in (a)(2) status and actual SSC performance data against the PC established under ER-AA-310-1003, Maintenance Rule Performance Criteria Selection. During this review the inspectors noted approximately 25 high safety significant systems (HSS) with reliability PC greater than two maintenance preventable functional failures (MPFFs). According to ER-AA-310-1003, Attachment 3, flowchart Process for Selecting Reliability Performance Criteria, HSS SSCs, with reliability PC greater than or equal to two MPFFs require SSC past performance documentation. Additionally, Attachment 1, steps 2.B.3 and 2.B.4, state that for HSS SSCs with high risk achievement worth (RAW) values, a reliability PC greater than or equal to zero or one MPFF requires SSC past performance documentation. The inspectors requested that PSEG provide past performance documentation for the HSS SSCs with reliability PC greater than two MPFFs. PSEG provided documentation of HSS SSC PC approval from 1997, when the MRule Program was first implemented by PSEG. The inspectors determined this documentation did not support the assigned PC, because it did not consider the last 18 years of SSC past performance. The inspectors also reviewed ER-AA-310-1007, Maintenance Rule Periodic (a)(3) Assessment. Step 5.11.1.4 states Determine that the number of MPFFs allowed per evaluation period is consistent with the assumptions in the PRA. Contrary to ER-AA-310-1007, step 5.11.4, the last two periodic (a)(3) assessments performed by PSEG: April 1, 2011 through September 9, 2012; and October 1, 2012 through June 30, 2014; did not verify that the number of MPFFs allowed per evaluation period was consistent with the assumptions in the PRA. Additionally, ER-AA-310-1003, step 4.3.2, states, in part, that Unless justified and approved by the Maintenance Rule Expert Panel, the number of MPFFs selected, as a Reliability PC, may not be higher than the PRA-supplied number of Functional Failures (FFs). The inspectors then reviewed SC-MRULE-002, Maintenance Rule Performance Criteria Verification Following Salem SA112A PRA Update, subsequent to the most recent update performed in October 2014. The inspectors noted that to complete this verification, PSEG requantified the PRA model by changing the failure probabilities of the basic events to reflect the MRule PC. The result was a 98% increase in the Salem base core damage frequency (CDF) of 1.55E-05. The inspectors determined that this data was reflective of SSC reliability PC above the PRA-supplied number of basic event failures. As such, contrary to ER-AA-310-1003, step 4.3.2, the number of MPFFs selected as reliability PC was higher than the PRA-supplied number of FFs, and, based on the lack of documentation supplied by PSEG, the inspectors concluded this was not justified or approved by Maintenance Rule Expert Panel. The inspectors determined that the failure to meet ER-AA-310-1007, step 5.11.4, and ER-AA-310-1003, step 4.3.2, was a performance deficiency. However, at the time of inspection, the inspectors did not have the information needed to determine the consequence of the performance deficiency. Information was needed to determine whether the performance deficiency was more than minor. Specifically, PSEG did not provide SSC past performance documentation for HSS SSCs with reliability PC greater than the PRA-supplied number of basic event failures in accordance with ER-AA-310-1003 Attachment 1 and 3. The inspectors will use this information to determine whether the performance or condition of HSS SSCs was effectively controlled through the performance of appropriate preventive maintenance under 10 CFR 50.65(a)(2), and also to determine if those HSS SSCs being monitored under 10 CFR 50.65(a)(1) were assigned appropriate goals and monitoring when considered against the appropriate reliability PC threshold. This issue was determined to be a URI IAW Inspector Manual Chapter (IMC) 0612.
05000272/FIN-2015008-022015Q2SalemFailure to Correct a Condition Adverse to the Quality of the ChillersThe inspectors identified a Green NCV of 10 CFR, Part 50, Appendix B, Criterion XVI, because PSEG did not assure that an identified condition adverse to quality was corrected. The condition adverse to quality was associated with improper maintenance of the 12 chiller which led to the chiller failure on August 23, 2014. Specifically, a procedure related to compressor rebuilds was not effectively updated to address the improper maintenance practice. PSEG entered this violation into the CAP as notification 20690927, has placed compressor rebuilds that would require use of this procedure on hold, and has purchased new compressors for contingent replacement pending completion of the compressor maintenance procedure changes. The inspectors determined this performance deficiency was more than minor because it was associated with the procedure quality attribute of the Mitigating System cornerstone, and adversely affected the cornerstone objective of ensuring the reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, improper torqueing of the No. 4 discharge valve plate bolts for the 12 chiller caused the trip of that chiller on August 23, 2014, and, absent the procedural change, the vulnerability continued to exist for the occurrence of future improper torqueing and subsequent chiller failure. The inspectors determined that this finding screened to Green in accordance with IMC 0609, Appendix A, because the finding did not represent an actual loss of function of at least a single train for greater than its technical specification allowed outage time. The inspectors determined that this finding had a cross-cutting aspect in evaluation, because PSEG Root Cause 70169007 did not identify the improper torqueing of the discharge plate bolts as a condition adverse to quality. Consequently, PSEG assigned an action (ACIT) to address the problem, rather than a corrective action (CA) which, per LS-AA-125, requires additional reviews that verify the quality of completed corrective actions before closure.
05000272/FIN-2015008-032015Q2SalemLicensee-Identified Violation10 CFR Part 50, Appendix B, Criterion XVI requires, in part, that measures shall be established to assure that conditions adverse to quality are promptly identified and corrected. Contrary to the above, PSEG did not establish measures to assure that a condition adverse to the quality related to safety-related chillers was promptly corrected. Specifically, PSEG determined that previous corrective actions for chiller operating temperature setpoint overlap, which were directed in several previous CAP evaluations that were completed between 2009 and 2013, were not implemented in a timely manner. This caused excessive chiller cycling and load sharing and prolonged and cyclic operation at low load conditions, which caused component fatigue and compressor damage. In response to this issue, PSEG completed a root cause evaluation and established corrective actions to develop and install a chiller operating setpoint design change package. The inspectors determined that this finding screened to Green in accordance with IMC 0609, Appendix A, because the finding did not represent an actual loss of function of at least a single train for greater than its technical specification allowed outage time. This issue is tracked in the corrective action program under RCE 70169007.
05000272/FIN-2016001-012016Q1SalemFailure to Correct Chiller Failures due to Gasket LeakageA self-revealing Green non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion XVI, was identified when PSEG did not assure that an identified condition adverse to quality was corrected. Specifically, PSEG closed a corrective action to address chiller gasket leakage without performing the designated action. This resulted in four subsequent chiller trips due to gasket failures. PSEG entered this issue in the CAP under notification 20708693, and completed ACE 70181604 on December 21, 2015. Corrective actions from the ACE were completed on February 25, 2016, and included: obtaining the proper gasket material; testing an alternative gasket material (Teflon); and establishing interim performance monitoring under Order 80115963. The inspectors determined that closing a corrective action to correct a condition adverse to quality evaluated by an ACE without implementing the corrective action was a performance deficiency. This performance deficiency was more than minor because it was associated with the equipment performance attribute of the Mitigating System cornerstone, and adversely affected the cornerstone objective of ensuring the availability and reliability of systems that respond to initiating events to prevent undesirable consequences, in that safety-related chillers were subsequently rendered inoperable as a result of not having the proper gasket material. The inspectors determined that this finding screened to Green in accordance with IMC 0609, Appendix A, because the finding did not represent an actual loss of function of at least a single train for greater than its technical specification allowed outage time. The inspectors determined that this finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Resolution, because PSEG did not take effective corrective action to address recurring chiller evaporator head gasket leaks in a timely manner.
05000272/FIN-2016001-032016Q1SalemUntimely Identification and Correction of Unsatisfactory Control Room Ventilation Charcoal TestingA self-revealing Green non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion XVI, was identified when PSEG did not promptly identify and correct a condition adverse to quality (CAQ). Specifically, PSEG did not promptly identify that negative results of a control room emergency air conditioning system (CREACS) charcoal filtration sample had Technical Specification (TS) implications and correct it prior to violating TSs. In response, PSEG entered Unit 1 TS 3.0.3, suspended irradiated fuel movements on Unit 2 to comply with Unit 2 TS 3.7.6, and commenced actions to re-align control area ventilation to Unit 2 supplying in the maintenance mode. Unit 1 TS 3.0.3 was exited at 7:55 a.m. that morning and PSEG reported this via an 8-hour report to the NRC under ENS 51504. PSEG revised the associated surveillance procedure to write a NOTF to replace the charcoal bank in the next system window if methyl iodide results are greater than or equal to 2 percent penetration (0.5% margin). PSEG documented and evaluated the issue in their CAP as Notifications (NOTFs) 20707922, 20707650, and 20712068. Untimely identification and correction of the charcoal filter performance was a performance deficiency. The issue was more than minor since it was similar to IMC 0612, Appendix E, example 2.a in that a TS limit was exceeded. Further, it was more than minor since it was associated with the system performance attribute of the Barrier Integrity cornerstone and adversely affected its cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, unsatisfactory charcoal filter performance resulted in inoperability of the single filtration train that was in service. The finding was reviewed in accordance with IMC 0609, Attachment 4 and Appendix A, where it was screened to Green since it only represented a degradation of the radiological barrier function provided for the control room. The finding had a cross-cutting issue in Human Performance, Teamwork, in that PSEG staff did not collaborate and cooperate in connection with operational activities, such as CAP entry and notification of the control room, associated with the CREACS filter testing and results.
05000272/FIN-2016001-042016Q1SalemLicensee-Identified ViolationTS LCO action statement 3.6.2.2.a requires that with the spray additive system inoperable, action shall be taken to restore the system to operable status within 72 hours, or be in at least hot standby within the next 6 hours. Contrary to the above, on June 22, 2015, PSEG determined that the spray additive system was inoperable for a period of time greater than allowed by TS. Specifically, PSEG review of past CS additive tank level versus estimated NaOH concentration by weight indicated that the NaOH concentration in the tank had decreased below the TS limit of 30 percent by weight on January 15, 2015, based on dilution from in-leakage. On June 23, 2015, following chemical addition, NaOH concentration was verified to be 31.4 percent by weight NaOH, and Salem Unit 1 exited TS action statement 3.6.2.2.a. PSEG reported this event as an LER, as documented in Section 4OA3 of this report. The inspectors determined that the finding was of very low safety significance (Green) in accordance with Section A of Exhibit 2 in Appendix A of IMC 0609, "The Significance Determination Process for Findings at Power, because PSEG determined under ACE 70178077 that design calculations confirmed the spray additive system will perform its safety function within the range of 28 to 36 percent by weight NaOH solution. Because this finding is of very low safety significance and has been entered into PSEG's CAP under NOTF 20694465, this violation is being treated as a Green NCV consistent with the NRC Enforcement Policy.
05000272/FIN-2016002-012016Q2SalemBaffle-Former Bolts with Identified AnomaliesThe inspectors determined the level of degradation of Unit 1 baffle bolts reported to the NRC as a condition not previously analyzed is an issue of concern that warrants additional inspection to determine whether a performance deficiency exists. As a result, the NRC opened a unresolved item (URI). Additional inspection is warranted to determine whether a performance deficiency exists related to Event Notification 51902, dated May 3, 2016, in which PSEG reported to the NRC that the level of degradation of baffle bolts was a condition not previously analyzed. The baffle bolts secure plates in the reactor core barrel to form a shroud around the fuel core to direct reactor coolant flow upward through the fuel assemblies. In order to determine if a performance deficiency exists, the inspectors will review the results of PSEGs RCE which will be completed at a later date.
05000272/FIN-2016003-012016Q3SalemMisclassification of and Lack of Preventative Maintenance for SWC Valve 2GW75 and Relay S62-C1The inspectors documented a self-revealing, Green finding (FIN) because PSEG did not classify plant equipment in accordance with procedure ER-AA-1001, Component Classification, Revision 0, step 4.5. Specifically, PSEG did not appropriately classify a valve and relay within the stator water cooling (SWC) system, and subsequently did not perform the appropriate periodic maintenance. As a result of the absence of maintenance, the valve developed a packing leak, which dripped onto the trip relay and caused the relay to internally fill with water. On February 14, 2016, the trip relay contacts experienced an electrical short, which led to a turbine trip and a reactor trip from 100 percent power. PSEG entered this issue into the corrective action program (CAP) under notifications 20720566 and 20745264, performed apparent cause evaluation (ACE) 70184453, replaced the failed relay, and repaired the packing leak on the SWC valve. The inspectors determined that a performance deficiency existed because PSEG did not properly classify the SWC relay and valve in accordance with station procedures to ensure the components would receive the appropriate preventive maintenance (PM). The finding was more than minor because it was associated with the equipment performance attribute of the Initiating Events cornerstone and adversely impacted its objective to limit the likelihood of events that upset plant stability (main generator and turbine trip) and challenge critical safety functions. Using IMC 0609, Attachment 4 and Appendix A, Exhibit 1, the inspectors determined that this finding was of very low safety significance, or Green, since mitigating equipment relied up to transition the plant to stable shutdown remained available. The inspectors determined there was no cross-cutting aspect associated with this finding since it was not representative of current PSEG performance.
05000272/FIN-2016003-022016Q3SalemLicensee-Identified Violation10 CFR 72.150 requires that each licensee shall prescribe activities affecting quality by documented instructions, procedures, or drawings of a type appropriate to the circumstances and shall require that these instructions, procedures, and drawings be followed. Holtec HI-STORM Certificate of Compliance 72-1014 Amendment 5, Final Safety Analysis Report for the HI-STORM 100 Cask System, Revision 7, Section 2.1.9.1.2, specifies the required helium backfill pressure range for loaded canisters. Contrary to the above, PSEG selected the incorrect helium backfill pressure range table in Attachment 9 of SC.MD-FR.DCS-0006(Q), Sealing, Drying, and Backfilling of a loaded multi-purpose canister (MPC) for two MPCs, one on June 20, 2016, and the other on June 25, 2016. The NRC inspectors evaluated this violation as having very low safety significance because a thermal analysis performed by Holtec determined the resulting fuel cladding temperatures and the cask/MPC component temperatures would not exceed the applicable design limits for normal long-term storage with the current helium pressure. In accordance with the NRC Enforcement Policy Section 2.2, Part 72, Independent Spent Fuel Storage Installation inspection findings follow the traditional enforcement process and are not dispositioned through the reactor oversight process or the significance determination process. The violation was determined to be a Severity Level IV violation of the NRC requirements. The licensee entered the issue into their CAP as NOTF 20735208. This Severity Level IV violation was treated as a NCV, consistent with Section 2.3.2.a of the NRC Enforcement Policy. CAs for this issue included the Holtec thermal analysis and a revision of the MPC loading procedure SC.MD-FR.DCS-0006, Sealing, Drying, and Backfilling of a Loaded MPC.
05000272/FIN-2016004-012016Q4SalemInadequate Maintenance Procedure for Steam Generator Feedwater Pump Coupling Hub Set Screw InstallationGreen: A self-revealing Green finding (FIN) against MA-AA-716-010, Maintenance Planning Process, step 4.2.3, Revision 18, was identified for PSEGs inadequate maintenance guidance that resulted in 11 steam generator feedwater pump (SGFP) elevated vibrations and required an emergent down power to be taken out of service due to a coupling and shaft failure. PSEG entered this issue in their CAP as notification (NOTF) 20739299, conducted a prompt investigation, troubleshooting, repairs, and a completed a causal evaluation under Order 70189096. This issue was more than minor since it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and adversely impacted its objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding screened to Green in accordance with IMC 0609, Appendix A, because the finding did not represent an actual loss of function of one or more non-TS equipment trains designated as high safety-significant in accordance with PSEGs Maintenance Rule (MR) program. The finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Operating Experience (OE), because PSEG did not ensure that the organization systematically and effectively collects, evaluates, and implements relevant internal and external operating experience in a timely manner. (P.5)
05000272/FIN-2016004-032016Q4SalemLicensee-Identified ViolationThe following PSEG-identified violation of NRC requirements was determined to be of very low safety significance (Green) and meet the NRC Enforcement Policy criteria for being dispositioned as an NCV. As a result of a Salem Post-Fire Safe Shutdown Analysis update, PSEG submitted LER 272/1999-009-00 when they identified that cables for pressurizer PORVs and associated block valves were routed in the same containment cable trays, a fire-induced spurious operation concern, that could result in a pathway for a loss of reactor coolant inventory and pressure control. A similar condition was also identified for a fire in the control or relay rooms that could affect alternate shutdown capability. The NRC dispositioned this issue in IR 05000272;311/1999-010. On August 26, 2015, PSEG identified that they had not adequately completed corrective actions associated with the relay rooms. Specifically, a fire scenario involving cables within cabinets existed that could result in spurious PORV operation while preventing the ability to manually close block valves. At the time of this discovery, the safe shutdown analysis did not include the evaluations required to credit closure of both PORVs and block valves in the main control room prior to evacuation. Local, manual closure of the block valves had been incorporated into procedures but could be delayed up to 40 minutes in the scenario while EDGs were restored. The loss of reactor coolant inventory and pressure control had not been accounted for during this timeframe. The issue was determined to be more than minor since it was associated with the protection against external factors (Fire) attribute of the Mitigating Systems cornerstone and adversely affected its objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding was evaluated in accordance with IMC 0609, Appendix A, Attachment 4, and Appendix F. The IMC 0609, Appendix F, Attachment 1, Step 1.6, permits screening of the issue with PSEG fire PRA results provided there is an approved fire PRA for the plant. PSEG provided a fire PRA evaluation for the degraded condition but since the PRA results were not from a finalized, approved fire PRA, additional evaluation was required. The Senior Reactor Analyst (SRA) conducted a detailed assessment of the issue using the External Initiator Risk Informed Inspection Notebook for Salem Generating Station (Revision 1). Fires of concern were determined to be those confined to the Unit 1 and Unit 2 Relay Rooms. This is modeled in table 3.3.13 of the notebook as Fire Group M. For evaluation, it was assumed that Spurious PORV Due to Hot Short had a probability of 1.0. For this model, this would indicate a condition in which a PORV and its associated block valve were open. Given the exposure period of greater than 30 days, this would result in a change in core damage frequency of approximately 1E-8, Green, for Unit 1 and Unit 2. The notebook was conservative since the evaluation assumed the failure of the PORV to close as opposed to the more realistic probability that fire would cause a spurious failure of a PORV and hot short resulting in failure of the block valve. The dominant sequences included: 1) Fire in the relay room with a failure of the PORV to close and a failure of high pressure injection and 2) Fire in the relay room with a failure of the PORV to close and a failure of high pressure recirculation. PSEGs results were consistent with the SRAs analysis. Title 10 CFR Part 50, Appendix B, Criterion XVI, requires, in part, that conditions adverse to quality are promptly identified and corrected. Salem Unit 1 and 2 license conditions 2.(C).5 and 2.(C).10 respectively require, in part, that PSEG shall implement and maintain all provisions of the fire protection program. PSEGs Quality Assurance Topical Report states that the Quality Assurance Program is applied to the Fire Protection Program consistent with Branch Technical Position APCSB 9.5-1 Appendix A, Section C requirements that include, under Corrective Action, that conditions adverse to fire protection are promptly identified, reported, and corrected. Contrary to this, from about 1999 to August 2015, actions from a previous, related fire-induced circuit failure scenario did not completely correct the condition resulting in the inability to credit manual closure of PORV and PORV block valves in an associated fire scenario. PSEG entered this in their CAP as NOTFs 20700943 and 20750010.
05000272/FIN-2017001-012017Q1SalemLoss of Unit 1C 4kV Vital Bus due to Inadequate Activity Risk ScreeningA self-revealing Green finding (FIN) was identified when PSEG did not screen the risk associated with replacing the Unit 1C emergency diesel generator (EDG) output breaker in accordance with WC-AA-105, "Work Activity Risk Management." Specifically, on December 14, 2016, the Unit 1C 4 kilovolt (kV) vital bus was inadvertently de-energized when the Unit 1 C EDG output breaker, which was removed without adequate risk mitigation actions, made contact with the switchgear (SWGR) cubicle door containing relays for bus differential current protection. PSEG entered this issue into their corrective action proggram (CAP) as NOTF 20751669 and performed apparent cause evaluation (ACE) 70191319. PSEG's corrective actions (CA) included inspecting the involved relay and re-energizing the vital bus. The finding was determined to be more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and affected the cornerston's objective of ensuring the availability, reliability, and capability of systems relied upon to mitigate the consequences of an accident. The inspectors evaluated the finding in accordance with IMC 0609, Appendix A, Exhibit 2, and determined the finding was Green because it did not affect the design of qualification of a mitigating SSC, and did not represent an actual loss of function or system. The finding had a cross cutting aspect in the area of Human Performance, Work Management, because the work process did not include the identification and management of risk commensurate to the work and the need for coordination with different groups or job activities. Specifically, PSEG did not identify the level of medium risk associated with the work activity, did not manage the level of risk commensurate wiht the work, and did not coordinate appropriate mitigating actions with different work groups.
05000272/FIN-2017001-022017Q1SalemInadequate Fire Risk Assessment and ManagementInspectors identified a Green non-cited violation (NCV) of Title 10 of the Code of Federal Regulations (10 CFR) 50.65(a)(4) when PSEG did not adequately assess and manage the risk of online maintenance activities associated with the 13 and 23 charging (CV) positive displacement pumps (PDPs) and the 16 service water (SW) pump. Consequently, this resulted in the approval of hot work and the introduction of unaccounted for transient combustibles into a restricted fire area. PSEG wrote notifications (NOTFs) 20758370, 20759221, and 20761411 to document the observations and fire risk program gaps. On March 9, a roving fire watch was implemented as previously planned by PSEG. The finding was more than minor given its similarity to IMC 0612, Appendix E, example 7.e, in that had an adequate risk assessment been performed, it procedurally would have required additional risk management actions (RMAs). Additionally, this finding was more than minor because it adversely impacted the protection against external factors (fire) attribute of the Initiating Events cornerstone objective to limit the likelihood of events that upset plan stability and challenge critical safety functions during shutdown as well as power operations. The inspectors evaluated the finding in accordance with IMC 0609, Attachment 4 and Appendix K, since it involved a maintenance rule (MR) risk assessment. Since the performance deficiency was related to maintenance activities affecting structures, systems, and components (SSCs) needed for fire mitigation, Appendix K directed the significance to be determined by an internal NRC management review using risk insights. A Senior Reactor Analyst used risk insights from IMC 0609, Appendix F and its Attachment 2, to inform the significance and determined the issue screened to Green given that the combustible conditions and quantities were predominantly representative of a Low degradation rating.
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