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| Quarter | Site | Title | Description | |
|---|---|---|---|---|
| 05000293/FIN-2017001-02 | 2017Q1 | Pilgrim | Failure to Follow Procedures for Controlled Shutdown | Green. The inspectors identified a Green NCV of TS 5.4.1 Procedures, when Entergy did not follow the site procedures for limiting condition for operation (LCO) entries, Technical Specification (TS) usage, and procedure adherence. Specifically, on March 1, 2017, Entergy did not implement procedure 1.3.6, Technical Specifications-Adherence and Clarifications, and perform the procedural required preparation steps to commence a controlled and orderly shutdown when required by TS LCOs. Additionally, Entergy did not properly exit a TS LCO, based on procedure 1. 3.34.2, Limiting Conditions for Operation Log, requirements. Entergy entered the issue into the corrective action program (CAP) as condition report (CR) 2017-3724. The performance deficiency is more than minor because if left uncorrected, would have the potential to lead to a more significant safety concern. Specifically, the Entergy operations staff exited the LPCI LCO without personal observation by the senior reactor operator (SRO) signing off the work order (WO) that the maintenance postwork testing was complete and failed to implement the procedural required preparation steps to perform a controlled and orderly shutdown when required by TS LCOs. Inspectors evaluated this finding using IMC 0609.04, Initial Characterization of Findings, and IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, issued June 19, 2012, and determined that the 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, and did not screen as potentially risk significant due to external initiating events. The inspectors determined that this finding had a cross-cutting aspect in the area of Human Performance, Procedure Adherence, in that individuals follow processes, procedures, and work instructions. Specifically, Entergy did not us e procedural guidance explicitly put in place to provide operators clear direction on how to prepare and perform an orderly shutdown upon entering a TS LCO with shutdown requirements. (H.8) |
| 05000293/FIN-2017001-03 | 2017Q1 | Pilgrim | Untimely Corrective Actions associated with Boraflex degradation in the Spent Fuel Pool | Green. The inspectors identified a Green NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Actions, when Entergy did not take timely corrective action to correct a condition adverse to quality. Specifically, when BADGER testing results revealed gaps in 4 neutron absorber material that exceeded spent fuel storage design feature assumptions and therefore did not ensure compliance with TSs, the station did not establish corrective actions to ensure configurations and limitations would meet subcriticality analysis beyond September 2017. Entergy entered this into the CAP as CR 2017-1650 and is performing a root cause evaluation to evaluate options and establish corrective actions to ensure compliance is met beyond this timeframe. The performance deficiency was more than minor because it was associated with the Barrier Integrity cornerstone attribute of configuration control (reactivity control) and adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 3 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, the inspectors determined that this finding is of very low safety significance (Green) because the finding did not adversely affect any of the barrier integrity screening questions. The inspectors determined this finding had a cross-cutting aspect in Problem Identification and Resolution, Evaluation, because the organization did not thoroughly evaluate issues to ensure that resolutions address causes and extent of conditions commensurate with their safety significance. Specifically, the casual evaluation written to address the boraflex degradation was focused on restoring compliance and correcting immediate condition, and did not include longer term corrective actions to mitigate the likelihood of recurrence. (P.2) |
| 05000293/FIN-2017001-04 | 2017Q1 | Pilgrim | Failure to Submit a Required 50.72 Notification | Severity Level lV. The inspectors identified a Severity Level IV NCV of 10 CFR 50.72, Immediate Notification Requirements for Operating Nuclear Power Reactors, because a TS required shutdown was not reported to the NRC within four hours of the occurrence, as required by 10 CFR 50.72(b)(2)(i). Specifically, on December 16, 2016, PNPS initiated a shutdown, as required by TS, as a result of the discovery of leakage associated with main steam isolation valves (MSIVs) 2C and 2D, leadi ng to the required isolation of the C and D main steam lines. Entergy entered the issue into the CAP as CR 2017-3723. Inspectors determined the issue had the potential to affect the NRCs ability to perform its regulatory function, therefore, the inspectors evaluated this performance deficiency in accordance with the traditional enforcement process. Using example 6.9.d.9 from the NRC Enforcement Policy (the failure of a licensee to make a report as required by 10 CFR 50.72 or 10 CFR 50.73), the inspectors determined that the violation was a Severity Level IV violation. Because this violation involves the traditional enforcement process and does not have an underlying technical violation, inspectors did not assign a cross-cutting aspect to this violation in accordance with IMC 0612, Appendix B |
| 05000293/FIN-2017001-01 | 2017Q1 | Pilgrim | Concern Regarding Ability to Declare EALs during Loss of Control Room Air Conditioning | Inspection Scope The inspectors reviewed the samples listed below to assess the effectiveness of maintenance activities on structure, system, and component (SSC) performance and reliability. The inspectors reviewed system health reports, CAP documents, maintenance WOs, and maintenance rule (MR) basis documents to ensure that Entergy was identifying and properly evaluating performance problems within the scope of the MR. For each sample selected, the inspectors verified that the SSC was properly scoped into the MR in accordance with 10 CFR 50.65 and verified that the (a)(2) performance criteria established by Entergy staff was reasonable. As applicable, for SSCs classified as (a)(1), the inspectors assessed the adequacy of goals and corrective actions to return these SSCs to (a)(2). Additionally, the inspectors ensured that Entergy staff was identifying and addressing common cause failures that occurred within and across MR system boundaries. HPCI stop valve grease on February 17, 2017 (quality control) Main control room ventilation the week of March 6, 2017 9 b. Findings Introduction. The inspectors identified that Entergy made alterations on February 2, 2017, to procedure 2.4.149, Loss of Control Room Air Conditioning, that had the potential to render several emergency action levels (EALs) ineffective. As a result, the NRC opened an unresolved item related to this concern. Description. The inspectors identified a concern regarding Entergys ability to declare several EALs based on the actions required by site procedure 2.4.149, Loss of Control Room Air Conditioning. Specifically, procedure 2.4.149 directs numerous loads to be shed in order to maintain the main control room temperature below 120 degrees Fahrenheit upon loss of control room air conditioning during extended period of outside temperature of 90 degrees Fahrenheit and above, as per FSAR section 7.1.8. Main control room air conditioning is not consider ed important to safety, based on the ability to control the heat up rate in the main control room, through the actions described in procedure 2.4.149. Upon updating the calculation to determine how much load must be shed to ensure design requirements were met, procedure 2.4.149 was updated with an attachment directing which loads that are required to be shed in order to meet the design calculation S&SA056, Control Room and Cable Spreading Room Heatup Calculations, Revision 6. The main control room is required to remain at or below 120 degrees Fahrenheit to ensure the main control room equipment remains operable. Main control room equipment temperatures above 120 degrees Fahrenheit can result in multiple control equipment failures which could result in misleading indications and inadvertent system actuation. The inspectors questioned how the procedure would be implemented, based on the lack of specific guidance in the procedure. The procedure includes the load shedding of numerous components, including both trains of reactor protection system, average power range monitors, intermediate range power monitors, source range power monitors, and process radiation monitors. Inspectors questioned how the site would declare numerous EALs without supporting equipment that has no redundancy or pre- established compensatory measures, as proceduralized in EN-AD-270, Equipment Important to Emergency Response. Inspectors questioned at what point would the operators be required to shed equipment that is required to support the HOT (greater than 212 degrees Fahrenheit) condition EAL classifications. The inspectors questioned whether or not operators would be able to verify that the plant conditions were consistent with applicable EALs at the time the components were removed from service. Entergy is reviewing the calculations to determine when load shedding of loads without compensatory measures would have been required and intends to report the results to the NRC by June 2, 2017. Inspectors verified that the procedure was changed to ensure minimum instrumentation requirements were maintained to declare EALs. The inspectors determined that procedure 2.4.149 had the potential to render EALs ineffective and is an unresolved item pending Entergy completing their evaluation of load shedding impact on the main control room heat up and NRC review of the evaluation and procedure implementation. (URI 05000293/2017001-01, Concern Regarding Ability to Declare EALs during Loss of Control Room Air Conditioning) |
| 05000293/FIN-2016004-01 | 2016Q4 | Pilgrim | Failure to Promptly Perform an Operability Evaluation for a Recirculation Flow Converter | Green. The inspectors identified a Green NCV of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, because Entergy did not perform a prompt operability determination and adequately evaluate the operability of a recirculation flow converter in a timely manner in accordance with procedure EN-OP-104, Operability Determination Process. As a result, Entergy allowed this flow converter to remain in service, without reasonable assurance of its capability to perform its required safety function, from the time the adverse condition was discovered on October 3, 2016, until the component was declared inoperable and replaced on October 21, 2016. Entergy entered the initial equipment failure into the CAP as CR 2016-07622 and CR 2017-0854. Entergy took corrective actions to replace the inoperable flow converter. The inspectors determined that this performance deficiency was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and it adversely affected the cornerstone objective of ensuring the reliability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). The issue is also similar to the more than minor example in IMC 0612, Appendix E, Examples of Minor Issues, issued August 11, 2009, Example 3j because the flow converters capability to perform its required safety function could not be reasonably assured. The inspectors screened this finding in accordance with IMC 0609, Appendix A, The Significance Determination Process for Findings At- Power, issued June 19, 2012, Exhibit 2, Mitigating Systems Screening Questions, and determined that this finding was of very low safety significance (Green) because the finding affected a single reactor protection system (RPS) trip signal to initiate a reactor scram, but did not affect 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. The inspectors determined that this finding had a -cutting aspect in the area of Human Performance, Conservative Bias, because Entergy did not use decision makingpractices that emphasize prudent choices over those that are simply allowable. Specifically, Entergy did not take a conservative approach in making the decision to keep the A recirculation flow converter in service when available information regarding its operability was incomplete. Operators continued to act based on the assumption that the flow converter would remain operable, without reasonable assurance. Management did not adequately prioritize the completion of the operability evaluation for this safetyrelated component. Instead, the completion of the evaluation was delayed due to a heavy workload on the available staff who were qualified to provide the necessary input. (H.14) |
| 05000293/FIN-2016004-02 | 2016Q4 | Pilgrim | Ineffective Corrective Actions to Correct High Pressure Coolant Injection System Vibrations | Green. A self-revealing Green NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, was identified in that Entergy did not identify and correct a condition adverse to quality related to high pressure coolant injection (HPCI) pump degraded performance, as required by EN-LI-102, Corrective Action Program. EN-LI-102, requires, in part, that individuals closing corrective actions verify that the required action has been taken ensuring that the response is adequate, answers all aspects of the assigned action, and the intent of the action is met. Specifically, vibrations on the HPCI main pump to speed reducer coupling were not addressed during HPCI system maintenance, despite a degrading trend starting May 21, 2015. This led to the HPCI system being declared inoperable on November 7, 2016, after vibration levels exceeded the in-service testing (IST) action range threshold. Entergys corrective actions included modeling vibrations of the HPCI system during operation and installing a stiffening plate on the HPCI pump support pedestal in order to dampen vibrations associated with the system. Entergy has entered this into their CAP as CR 2016-8657. The inspectors determined that this performance deficiency was more than minor because it is associated with the equipment performance 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 (i.e., core damage.) Specifically, Entergy did not address the increase in HPCI pump vibrations from May 21, 2015, to November 7, 2016, when the vibrations increased into the IST Action range and resulted in pump inoperability. In accordance with IMC 0609.04, Initial Characterization of Findings, issued October 7, 2016, and 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 did not affect the design or qualification of a mitigating structure, system, or component (SSC), represent a loss of system and/or function, involve an actual loss of a function of at least a single train or two separate safety systems for a greater time than allowed by technical specifications (TS), or represent an actual loss of function of one or more non-TS trains of equipment designated as high safety-significant in accordance with the licensees maintenance rule program. The inspectors determined that this finding had a cross-cutting aspect in the area of Human Performance, Design Margins, in that the organization operates and maintains equipment within design margins, and margins are carefully guarded and changed only through a systematic and rigorous process. Specifically, Entergy did not demonstrate that the work process supports nuclear safety and maintenance of design margins by minimizing long-standing equipment issues, preventive maintenance (PM) deferrals, and maintenance and engineering backlogs. Entergys failure to effectively manage design margins regarding HPCI system vibrations led to a continuing degradation of the system, and the eventual need to declare the HPCI system inoperable on November 7, 2016. (H.6) |
| 05000293/FIN-2016004-03 | 2016Q4 | Pilgrim | Failure to Properly Assess and Manage Risk Associated with Shutdown Transformer Protective Relay Testing | Green. The inspectors identified a Green NCV of 10 CFR 50.65(a)(4), Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, for Entergys failure to properly assess and manage the increase in risk due to performing protective relay calibration and functional testing associated with the shutdown transformer (SDT) on seven occasions from December 9, 2005, through August 27, 2014. Specifically, Entergy did not identify that the performance of calibration and functional testing of 6 protective relays associated with the SDT would prevent the 4160V safety buses from being automatically powered by other required sources, and consequently, did not properly assess and manage the increase in risk. Entergys corrective action requires the unit to be in an outage to perform the tests. Entergy entered the issue into the CAP under CR 2017-0856. The inspectors determined that this performance deficiency was more than minor because it is associated with the configuration control 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. Additionally, the finding was similar to Example 7e of NRC IMC 0612, Appendix E, Examples of Minor Issues, in that the overall elevated plant risk would have put the plant into a higher licensee-established risk category and would have required additional risk mitigating actions (RMAs). The inspectors evaluated the finding using the Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, issued October 7, 2016. Because the finding involved a maintenance rule risk assessment, it was screened through IMC 0609, Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process, issued May 19, 2005. The finding screened as very low safety significance (Green) using Flowchart 1 of Appendix K because the incremental core damage probability deficit (ICDPD) was determined to be greater than 1E-6 and less than 1E-5, and three or more RMAs were taken. The inspectors concluded this finding had a crosscutting aspect in the area of Human Performance, Avoid Complacency, in that individuals did not recognize and plan for the possibility of mistakes, latent issues, and inherent risk, even while expecting successful outcomes. Specifically, the unavailability of the startup transformer (SUT) and emergency diesel generators (EDGs) during portions of testing was a latent issue that Entergy did not identify, and the associated increase in risk was not assessed and managed. (H.12) |
| 05000293/FIN-2016004-04 | 2016Q4 | Pilgrim | Failure to Correct a Condition Adverse to Quality Associated with Main Steam Isolation Valve | Green. A self-revealing Green NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, was identified in that Entergy did not promptly correct a condition adverse to quality associated with the operability of a MSIV. Specifically, Entergy did not take timely corrective actions to inspect and remove debris from air tubing that supplied air to a valve actuator after the associated MSIV failed a surveillance test on March 29, 2016. This uncorrected condition subsequently led to a repeat failure of the valve on August 16, 2016. Entergy entered these issues into their CAP as CR 2016-2250 and CR 2016-5987 and developed corrective actions to revise associated procedures as needed, replaced the affected MSIV air pack manifold, cleared loose debris from the affected air tubing, and scheduled the replacement of affected air tubing during the next refueling outage. The inspectors determined that this performance deficiency was more than minor because it was associated with the barrier performance attribute of the Barrier Integrity cornerstone and it adversely affected the cornerstone objective of providing reasonable assurance that physical design barriers (fuel cladding, reactor coolant system, and containment) protect the public from radionuclide releases caused by accidents or events. Specifically, when MSIV-1C failed to meet its surveillance requirements on March 29, 2016, Entergy did not take corrective actions necessary to adequately identify and resolve the underlying issue of system debris being present in air tubing, which affected the valve actuator and caused a slow closing time for the valve. This inaction led to continued valve inoperability, for a duration greater than that allowed by TS, which presented itself during a subsequent operability test on August 16, 2016. The inspectors screened this finding in accordance with IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power; using Exhibit 3, Barrier Integrity Screening Questions. The inspectors determined that this finding was of very low safety significance (Green) because the finding did not involve an actual open pathway in the physical integrity of reactor containment or involve an actual reduction in function of hydrogen igniters in the reactor containment. The inspectors determined that this issue had a cross-cutting aspect in the area of Human Performance, Conservative Bias, because Entergy did not use decision-making practices that emphasize prudent choices over those that were simply allowable. Specifically, when the MSIV initially failed its surveillance in March 2016, Entergy did not take a conservative approach in their operability determination and immediate response to the issue. This was demonstrated by the fact that, following the March 2016 valve failure, when a cause evaluation identified the likelihood of debris in air tubing affecting valve operability, individuals rationalized that the degraded condition had been resolved on its own and would not recur. Entergy acted on this assumption, rather than making the conservative determination that the effect of present debris could impact continued operability in an unpredictable manner, as it did during the subsequent failed surveillance test in August 2016. (H.14) |
| 05000293/FIN-2016004-05 | 2016Q4 | Pilgrim | Feedwater Regulating Valve Failure Results in Reactor Scram | Green. A self-revealing Green finding was identified for the inadequate implementation of a work order on the A feedwater regulating valve (FRV) encoder as required by ENWM- 102. Specifically, Entergy did not install a wire assembly on the A FRV encoder as required by the work instructions located in the vendor manual. The wire loosened, resulting in the A FRV failing open and the operators inserting a manual scram. In response to the loose connection, Entergy added a sealant to the connector to ensure all wires remain in place on both FRVs. Entergy entered the issue into the corrective action program (CAP) under condition report (CR) 2016-6635. The inspectors determined that the finding is more than minor because it is associated with the equipment performance attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during a shutdown as well as power operations. Specifically, the performance deficiency affected the reliability and capability of the A FRV which led to a plant scram, tripping of the reactor feed pumps, and closure of the main steam isolation valves (MSIVs). The inspectors evaluated this finding using IMC 0609.04, Initial Characterization of Findings, issued October 7, 2016, and IMC 0609, Appendix A, Exhibit 1, Initiating Events Screening Questions, issued June 19, 2012, and determined a detailed risk evaluation was required because the A FRV failure caused a reactor trip and partial loss of feedwater (power conversion system). A Region I senior reactor analyst (SRA) used the Standardized Plant Analysis Risk (SPAR) model for Pilgrim, Version 8.24, and SAPHIRE, Version 8.1.4, to complete the detailed risk evaluation. The estimated increase in core damage frequency (CDF) was calculated to be 4E-7/year, or very low safety significance (Green). For issues resulting in an increase in CDF > 1E-7, IMC 0609 requires an evaluation of large early release frequency (LERF) using the guidance of NUREG-1765, Basis Document for LERF Significance Determination Process, and IMC 0609, Appendix H, Containment Integrity Significance Determination Process, issued May 6, 2004. The performance deficiency associated with the failure of the A FRV and resultant reactor trip would be considered a Type A finding and, as such, the calculated increase in CDF value is used in conjunction with an appropriate LERF factor (multiplier) to determine the estimated increase in LERF associated with the issue. In the absence of early core damage sequences for this event, LERF is not a significance risk contributor and the safety significance of this performance deficiency is defined by the estimated increase in CDF (4E-7/year) or Green. This finding has a cross-cutting aspect of Human Performance, Work Management, in that Entergy did not adequately implement the process of planning, controlling, and executing work activities such that nuclear safety is the overriding priority. Specifically, maintenance staff were provided a work order that did not meet station requirements to ensure the work could be adequately performed. Specific steps of the vendor manual were not used to direct work by staff and led to an installation error. The work planning process also did not implement the engineering recommendation to perform a practice installation on the equipment prior to installing equipment in the field. (H.5) |
| 05000293/FIN-2016004-06 | 2016Q4 | Pilgrim | Licensee-Identified Violation | TS 3.9.B.2 requires that when incoming power is not available from both startup and shutdown transformers, continued operation is permissible, provided both diesel generators and associated emergency buses remain operable, all core and containment cooling systems are operable, and reactor power level is reduced to 25% of design. Contrary to the above, on seven occasions between 2005 and August 27, 2014, for an average of 3.6 hours, Entergy conducted test Procedures 3.M.3-1, A5/A6 Buses 4kV Protective Relay Calibration/Functional Test and Annunciator Verification Critical Maintenance, and 3.M.3-29, Shutdown Transformer and 23kV Relay Calibration and Functional Test, that placed the plant in a condition not allowed by TS 3.9.B.2. Specifically, the testing would have prevented emergency buses A5 and A6 from automatically transferring to their backup power supplies. Entergy entered this condition into their CAP as CR 2016- 2735. A Region I SRA conducted a detailed risk evaluation for this issue using IMC 0609, Appendix A, Significance Determination Process for Findings At-Power, issued June 19, 2012. Using the average time from above, along with operator recovery actions, the SRA calculated the change in core damage probability to be <1E-7, which was considered to be of very low safety significance (Green) |
| 05000443/FIN-2015004-02 | 2015Q4 | Seabrook | Licensee-Identified Violation | Title 10 CFR 50.55a (g)(4), Inservice Inspection Requirements, requires, in part, that throughout the service life of a boiling or pressurized water-cooled nuclear power facility, components (including supports) that are classified as ASME Code Class 1, must meet the requirements set forth in Section XI of editions and addenda of the ASME Boiler Pressure and Vessel Code. Section XI of the ASME Boiler Pressure and Vessel Code, 2001 Edition with 2003 Addenda, Table IWF-2500-1, Examination Category F-A Supports, requires VT-3 examination of 100 percent of the ASME Class 1 supports, other than piping supports, every ISI Interval (examination item F1.40). Contrary to this requirement, from initial commercial operation until October 14, 2015, (when NextEra staff completed the initial required VT-3 examinations) NextEra did not perform the required ASME Section XI VT-3 examination of ASME Class 1 supports (i.e. seismic support plates and associated load path components) on the CRDM assemblies of Seabrook Unit 1. NextEra staff entered the issue into their CAP as AR 01991880 and completed the VT-3 examinations during the October 2015 refueling outage. The finding is more than minor because it was associated with the protection against external factors attribute of the Mitigating Systems cornerstone and adversely affected the objective to ensure reliability and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors determined that this finding is of very low safety significance (Green) in accordance with IMC 0609, Appendix A, Exhibit 2, Mitigating Systems, because the finding did not involve the loss or degradation of equipment or function specifically designed to mitigate a seismic initiating event. NextEra completed the required examinations on October 14, 2015. |
| 05000293/FIN-2016010-01 | 2015Q4 | Pilgrim | Failure to perform hourly fire watches | 10 CFR 50.48(a)(1) requires that each holder of an operating license must have a fire protection plan that: (i) describes the overall fire protection program for the facility; (ii) identifies the various positions within the licensee's organization that are responsible for the program; (iii) states the authorities that are delegated to each of these positions to implement those responsibilities; and (iv) outlines the plans for fire protection, fire detection and suppression capability, and limitation of fire damage. Pilgrim Nuclear Power Station (PNPS) Technical Specification 5.4.1.d requires that written procedures shall be established, implemented, and maintained covering Fire Protection Program implementation. ' PNPS implementing procedure 8.8.14, "Fire Protection Technical Requirements," Section 7.5, "Completing Attachment 1 (Hourly Fire Watch)," requires, in part, that fire watch personnel examine the area involved in the posting for evidence of fire or conditions that may lead to a fire. This section further requires that the posting should be visited once every hour such that no fewer than 24 patrols are completed in a 24-hour period at approximately 60-minute intervals. Contrary to the above, on occasions between June 1, 2012, and June 26, 2014, the licensee did not implement a provision of a written procedure covering implementation of the fire protection program as it pertains to fire detection. Specifically, although hourly fire watches were established, fire watch personnel did not examine the areas involved in the hourly fire watch postings for evidence of fire or conditions that may lead to a fire. As a result, for the involved areas, fewer than 24 patrols were completed in 24-hour periods. |
| 05000443/FIN-2015004-01 | 2015Q4 | Seabrook | Issue of Concern Regarding Implementation of the Seabrook Structures Monitoring Program and structural evaluations of the CEB and RHR/CS Vault | During the week of October 26, 2015, the NRC audit team observed the last planned large-scale specimen testing at FSEL, reviewed test program results and analyses completed, to date, and interviewed NextEra staff and their consultants. Audit team activities and conclusions are documented in an NRC audit report (ADAMS Accession No. ML15307A019) dated December 17, 2015. No significant observations or concerns were identified related to the conduct of testing to appropriate quality assurance criteria. NextEra staff planned to have the test data analyses completed by the end of 2015, in support of submitting to the NRC a license amendment request in 2016, to address an ASR-related non-conforming condition with the current licensing basis. NRC inspectors conducted in-office reviews of the root cause evaluation for the Containment Enclosure Building Local Deformation, Event Dated December 19, 2014, completed per AR 02014325, and the Condition Assessment of Cracking in RHR and CS Equipment Vault, documented in Foreign Print (FP) 100903, dated March 17, 2015. NextEras CEB RCE described two root causes. First, regarding the physical causes of CEB deformation, NextEra staff concluded that internal expansion (strain) produced by ASR in the CEB concrete (in-plane direction of the CEB shell) and ASR expansion in the backfill concrete, coincident with a unique building configuration, resulted in CEB deformation. Second, regarding NRC identification of this issue, NextEra concluded this was not identified by plant staff due to an organizational mindset that viewed conditions such as concrete cracks, water infiltration, and misalignment issues as acceptable and inconsequential. Additionally, the RCE identified that NextEra staff did not perform and document comprehensive evaluations of building conditions that could have potentially revealed more significant underlying conditions, such as localized deformation of the CEB. These NRC-identified performance deficiencies were previously dispositioned as non-cited violation (NCV) 2015002-01 and NCV 2015002-02 in NRC inspection report 05000443/2015002 (ADAMS Accession No. ML15217A256). The inspectors determined NextEra corrective actions to address these problems included: 1) a revision to their design control procedures to require pozzolanic materials like fly ash or slag cement to be added to concrete mixes to prevent ASR in any new concrete structures; and, 2) the implementation of multiple training and program changes to correct the organizational mindset issues and strengthen individual responsibilities and accountability for implementation of the Seabrook Structures Monitoring Program. The inspectors concluded the RCE was reasonably thorough and utilized a cause and effect methodology that was appropriate to the problem statement. However, NextEras RCE, dated December 19, 2014, concluded that the reason that NRC inspectors, and not plant staff, identified the presence of localized ASR-induced deformation in Seabrooks concrete structures was due to an organizational mindset that viewed conditions such as concrete cracks, water infiltration, and misalignment issues as acceptable and inconsequential. The inspectors concluded the RCE was reasonably thorough and utilized a cause and effect methodology that was appropriate to the problem statement. The planned and in-process organizational and program related corrective actions appeared appropriately focused on the identified causes of the problem. However, the inspectors concluded that the corrective actions, taken to date, to implement multiple training, program and oversight changes to correct the organizational mindset issues and strengthen individual responsibilities and accountability for implementation of the Seabrook Structures Monitoring Program have either not been implemented or are not yet effective and thus require additional management attention near-term. The inspectors noted that the CEB RCE referenced the results of a Finite Element Analysis (FEA) model of the CEB. The FEA and results were documented in FP 100985. The inspectors review of FP 100985 identified that the FEA model simulated ASR expansion to assess the impact of expansion induced deformation on the structural performance of the CEB. The FEA evaluated CEB design capacity against assumed loading, based on ACI 318-71 criteria, including simulated loads associated with the as-deformed condition. As documented in FP 100985, the FEA model also simulated the impact of the external structural loading due to ASR expansion of the backfill concrete. Based upon the review of the CEB structural assessment described in FP 100985 and the limited structural analysis of the RHR/CS vault documented in FP100903, the inspectors had multiple follow-up questions regarding the CEB and RHR/CS vault structural assessments and the potential impact of these evaluation results on NextEras open Immediate Operability Determinations and Prompt Operability Determinations (PODs) for these ASR-affected structures (reference AR 01664399, AR 01929460, AR 01977456, AR 02004749, and AR 02044627). The follow-up questions were developed via a collegial review by the Region 1 Senior Reactor Analyst and structural engineers from NRC Offices of Nuclear Reactor Regulation and Region 2, under the auspices of the Seabrook ASR Technical Team (ADAMS Accession No. ML14014A378). The questions were documented and shared with the NextEra staff on December 23, 2015 (ADAMS Accession No. ML15357A326). NextEras responses and the inspectors review are planned for the first quarter of 2016 and will be documented in an NRC inspection report. Following the guidance of IMC 0612, Power Reactor Inspection Reports, the inspectors identified an issue of concern regarding NextEras implementation of their Seabrook Structures Monitoring Program. Specifically, the structural evaluations, performed by contractors and accepted by NextEra staff via the FP process, included discussions that identified the potential to exceed limits in the applicable design code (ACI 318-71) for specific locations in the CEB and RHR/CS vault walls. The evaluations further recommended actions to determine whether this was the case. The inspectors noted that the Seabrook staff screened or reviewed these evaluations without documenting a justification in a revision or update to the open PODs for these structures. The additional information requested on December 23, 2015 is required for the inspectors to determine whether this issue involves a performance deficiency. As a result, the NRC opened an unresolved item (URI). The inspectors identified an issue of concern regarding NextEras implementation of the Seabrook structures monitoring program and acceptance of evaluations via the FP and CAP. Additional inspection is warranted to determine whether a performance deficiency exists related to NextEras disposition of FP 100985 for the CEB condition and FP 100903 for the RHR/CS vault condition. Specifically, further inspection is warranted to determine whether NextEra staff properly implemented the Seabrook structures monitoring program for the acceptance and review of structural evaluations potentially impacting the functionality of the CEB and RHR/CS vault, as currently documented in open PODs. |
| 05000425/FIN-2013002-01 | 2013Q1 | Vogtle | Inadequate Operations and Maintenance Procedures Results in High RCP Seal Leakoff Flow and Manual Reactor Trip | A self-revealing non-cited violation (NCV) of 10 CFR 50 Appendix B Criterion V, Instructions, Procedures, and Drawings was identified for failure to provide adequate work instructions in the operations procedure used to change out the reactor coolant system (RCS) filter. Specifically, operations procedure 13213-1/2, Backflushable Filter System, which is used to change out the RCS filter, did not provide adequate instructions and/or precautions to prevent excessive air intrusion (and the subsequent localized crud burst within the chemical and volume control system (CVCS) late in core life) when flushing and venting the RCS filter housing. The licensee conducted a root cause investigation and entered the event into their corrective action program (condition report (CR) 597293). The licensee immediately created a Standing Order for Operation of CVCS in relation to RCP seals, and revised procedure 13213-1/2, Backflushable Filter System to provide instructions to significantly reduce the amount of air intrusion from changing out the RCS filter. The finding was more than minor because it was associated with the procedure quality attribute of the reactor safety - initiating events cornerstone and it adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the failure to provide adequate work instructions to operations personnel resulted in a localized crud burst at the reactor coolant pump (RCP) seals causing RCP seal leakoff flow rates to exceed administrative limits for continued pump operation and a subsequent manual reactor trip. Because the inspectors answered No to all of the IMC 0609 Appendix A (dated June 19, 2012) Exhibit 1, Section B, Initiating Events Screening Questions, the inspectors concluded that the finding was of very low safety significance (Green). Since the inadequate procedures have existed since plant startup, this violation is not indicative of current licensee performance and does not have an associated cross-cutting aspect assigned. |
| 05000424/FIN-2013002-02 | 2013Q1 | Vogtle | Inadequate Maintenance Procedures Results in Failure of the Inboard Bearing on the Unit 1A CCW Pump #1 | A self-revealing non-cited violation (NCV) of 10 CFR Part 50 Appendix B, Criterion V, Instructions, Procedures, and Drawings was identified for failure to provide appropriate quantitative or qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished. Specifically, procedure 27080-C, CCW Pump Maintenance, did not provide adequate direction as to the duration of and instrumentation required to properly perform a post-maintenance test that would detect a misalignment between the pump and motor shafts. The licensee entered this issue into their corrective action program as CR 526268, and revised maintenance procedure 27080-C to specify the proper post maintenance testing required after rebuilding CCW pumps. The finding was more than minor because it was associated with the equipment performance attribute of the mitigating systems cornerstone and it adversely 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, the post-maintenance test performed after rebuilding the Unit 1A component cooling water (CCW) pump #1 failed to identify excessive misalignment between the motor and pump shafts, which subsequently resulted in the catastrophic failure of the inboard pump bearing once the pump was returned to service. Because the inspectors answered No to all of the IMC 0609 Appendix A (dated June 19, 2012) Exhibit 2, Section A, Mitigating Systems Screening Questions, the inspectors concluded that the finding was of very low safety significance (Green). The inspectors determined that the cause of this finding was related to the work control component of the human performance cross-cutting area due to less-than-adequate procedures. Specifically, the maintenance procedures used to reassemble the CCW pumps did not provide adequate direction as to the duration of and instrumentation required to properly perform an adequate post-maintenance test. |
| 05000424/FIN-2013002-03 | 2013Q1 | Vogtle | Human Performance Error Renders 1A CS Pump Inoperable | A self-revealing non-cited violation (NCV) for failure to meet the requirements of plant Technical Specification (TS) 5.4, Procedures was identified. While realigning equipment to support the filling and venting of the Unit 2 containment spray header the system operator inadvertently closed 1HV-9017A, refueling water storage tank (RWST) suction to Unit 1 containment spray (CS) pump A. As a result, the 1A CS pump was temporarily rendered inoperable. The valve was subsequently re-opened and the pump was declared operable. The licensee entered the issue into their corrective action program (CR 608718). This finding is more than minor because it is associated with the human performance attribute of the barrier integrity cornerstone and it adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers (fuel cladding, reactor coolant system, and containment) protect the public from radionuclide releases caused by accidents or events. Specifically, the performance deficiency is a human performance error which affected the availability, reliability, and capability of the Unit 1 A train containment spray system to limit and maintain post accident conditions to less than containment design values. Because the inspectors answered No to all of the IMC 0609 Appendix A (dated June 19, 2012) Exhibit 3, Section B, Barrier Integrity Cornerstone Screening Questions, the inspectors concluded that the finding was of very low safety significance (Green). The inspectors determined that the cause of this finding was related to the work practices component of the human performance crosscutting area due to less-than-adequate human error prevention techniques. Specifically, peer checking techniques were less than adequate. |