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| Quarter | Site | Title | Description | |
|---|---|---|---|---|
| 05000348/FIN-2018011-01 | 2018Q3 | Farley | Failure to ensure fire barrier penetrations (including fire dampers) in fire zones protecting safety-related areas shall be functional in accordance with NFPA 805 Section 3.11.3, Fire Barrier Penetrations | The NRC identified a Green finding and associated non-cited violation (NCV) of the Farleys Renewed Operating License Condition 2.C.(4) Fire Protection for U1 and 2.C.(6) Fire Protection for U2. This finding was identified for failure to maintain all provisions of the approved FPP, as described in NFPA 805, 2001 Edition to ensure that all fire barrier penetrations (including fire dampers) in fire zones protecting safety-related areas shall be functional. The functional failure of the two fire dampers in the A and B SWIS Battery Rooms was a performance deficiency and determined to be more-than-minor because it affected the Reactor Safety Mitigating Systems cornerstone attribute of protection against external factors, a fire, and it affected the fire protection Defense in Depth (DID) strategies involving the confinement of fires and to protect systems important to safety. Additionally, if left uncorrected, the issue could potentially lead to a more significant safety concern during fire events. |
| 05000348/FIN-2017009-02 | 2017Q4 | Farley | Failure to Complete Corrective Action to Preclude Repetition of a Significant Conditions Adverse to Quality | The NRC identified a non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, for failure to ensure that a corrective action taken to preclude repetition (CAPR) of a significant condition adverse to quality would be implemented. The licensee closed the CAPR tracking item, Technical Evaluation (TE), prior to all affected Steam Flow Transmitter calibration procedures revisions being completed. The licensee entered this issue in the CAP as CR 10413319.The finding was more than minor because it was associated with the Human Performance attribute of the Mitigating System Cornerstone and adversely affected the cornerstone objective in that the licensee closed the TE prior to all affected Steam Flow Transmitter calibration procedures being revised which could potentially prevent th 3 fulfillment of a safety function needed to mitigate the consequences of an accident. Specifically, the licensee closed out the TE CAPR 980655 tracking item on August 24, 2017, when fourteen safety related steam flow transmitter calibration procedures revisions were not completed. Using IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, dated June 19, 2012, and IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, the finding was determined to have very low safety significance because it was not a design or qualification deficiency, did not represent an actual loss of a safety function of a system or a single train greater than its technical specification allowed outage time, and did not screen as potentially risk significant due to external events. The inspectors reviewed IMC 0310, Aspects Within Cross Cutting Areas, dated December 4, 2014, and determined that this finding had a cross-cutting aspect in the area of Procedure Adherence (H.8) because the licensee closed the tracking item prior to completing the corrective action to prevent recurrence. |
| 05000348/FIN-2017009-01 | 2017Q4 | Farley | Failure to Report a Condition Which was Prohibited by Technical Specifications | The NRC identified a Severity Level IV (SL IV) non-cited violation of 10 CFR 50.73(a)(2)(i)(b) for failure to report plant operation prohibited by Technical Specification (TS) 3.3.2. Specifically, the licensee failed to perform a past operability evaluation and failed to recognize for having two steam flow channels on the 1 C steam generator inoperable longer than allowed by TS 3.3.2. Consequently, this condition was not discussed and reported on the Licensee Event Report (LER) 2016-007-00 or 2016-007-001. The issue was entered into the licensees CAP as condition report 10413856.This violation adversely affected the NRCs ability to perform its regulatory function; the NRC relies on licensees ability to identify and report conditions or events meeting the criteria specified in the regulations. The licensee did not evaluate past operability and failed to recognize, for the purpose of reportability, that the point of discovery occurred when the data was collected. Because this issue affected the NRC's ability to perform its regulatory function, it was evaluated using the traditional enforcement process. Consistent with the guidance in Section 6.9, Paragraph d.9, of the NRC Enforcement Policy and Guidance in Section 2.3.2.a, this finding was determined to be a Severity Level IV non-cited violation. This finding has no cross-cutting aspect as it was strictly associated with a traditional enforcement violation. |
| 05000325/FIN-2017009-01 | 2017Q2 | Brunswick | Inoperability of EDG1 due to Cyclic Fatigue Failure of Hydraulic Fuel Rack Control | Green . A self -revealing Green non- cited violation ( NCV ) of 10 CFR 50 Appendix B Criterion XVI, Corrective Actions, was identified on February 19, 2017, when emergency diesel generator ( EDG ) number one was determined to be inoperable due to an oil leak o n the linkshaft hydraulic control assembly. This violation of regulatory requirement existed from October 27, 2015 u ntil February 20, 2017. The licensee entered this issue in their corrective action program as nuclear condition report ( NCR) 02101084. The inspectors determined that the finding was more than minor because it was associated with the Mitigating Systems cornerstone attribute of Equipment Performance and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, failu re to correct a condition adverse to quality led to the inoperability of EDG1. The inspectors screened this finding using IMC 0609, Appendix A, The Significant Determination Process (SDP) For Findings At -Power, dated June 19, 2012, Based on Exhibit 2, Q uestion A3, the inspectors determined that a detailed risk evaluation was necessary given the uncertainty over how long EDG1 would have operated while leaking oil. A regional senior reactor analyst (SRA) conducted the risk assessment and screened the issu e to Green based on an increase in risk of less than 1E -6. The inspectors determined that this finding did not have an associated cross cutting aspect because this finding was not reflective of current licensee performance due to enhancements of site procedures guiding creation of work orders. |
| 05000293/FIN-2016011-05 | 2017Q1 | Pilgrim | Failure to Establish Corrective Actions to Address Scope of Procedure Quality Issues | The NRC team identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, because Entergy implemented inadequate corrective actions to address the procedure quality issues identified in CR-PNP-2016-02058. Specifically, Entergy inappropriately limited their corrective actions to those procedures that increased integrated risk above normal, and did not include other types of safety-related procedures that did not meet their procedure quality standards and resulted in procedure quality being a problem area. Entergy entered this issue into their corrective action program for further evaluation as CR-PNP-2017-00400. The performance deficiency was more than minor because it affected the procedure quality 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). Entergy limited corrective actions to procedures that increased integrated risk above normal or trip sensitive and failed to include other procedures associated with safety-related components that reflected the broader population reviewed during the collective evaluation. The NRC team evaluated the finding using Exhibit 2, Mitigating Systems Screening Questions, of IMC 0609, Appendix A, Significance Determination Process for Findings At-Power, and determined this finding did not affect the design or qualification of a mitigating structure, system, or component; represent a loss of system and/or function; involve an actual loss of function of at least a single train or two separate safety systems for greater than its technical specificationallowed outage time; or represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant. Therefore, the NRC team determined the finding was of very low safety significance (Green). The NRC team determined that this finding had a cross-cutting aspect related to Human Performance, Resources, because the leaders failed to ensure that personnel, equipment, procedures, and other resources are available and adequate to support nuclear safety. Specifically, based on available resources, Entergy chose to limit the scope of safety-related procedures being revised to only those that resulted in high integrated risk or were trip sensitive (H.1). |
| 05000293/FIN-2016011-07 | 2017Q1 | Pilgrim | Failure to Report Condition Prohibited by Technical Specifications and a Safety System Functional Failure | The NRC team identified a Severity Level IV non-cited violation of 10 CFR 50.73, Licensee Event Report System, associated with Entergys failure to submit a licensee event report within 60 days following discovery of an event meeting the reportability criteria. Specifically, on September 28, 2016, Entergy identified the A emergency diesel generator was inoperable. The NRC team determined that the condition was prohibited by technical specifications and the inoperability of the A emergency diesel generator existed for a period of time longer than allowed by Technical Specification 3.5.F, Core and Containment Cooling Systems. This was also reportable as a safety system functional failure. Entergy entered this issue into the corrective action program as CR-PNP-2016-09552. Because this performance deficiency had the potential to impact the NRCs ability to perform its regulatory function, the NRC team evaluated the performance deficiency using traditional enforcement. The violation was evaluated using Section 2.3.11 of the NRC Enforcement Policy, because the failure to submit a required licensee event report may impact the ability of the NRC to perform its regulatory oversight function. In accordance with Section 6.9.d, Example 9, of the NRC Enforcement Policy, this violation was determined to be a Severity Level IV non-cited violation. Because this violation involves the traditional enforcement process and does not have an underlying technical violation, the NRC team did not assign a cross-cutting aspect to this violation, in accordance with IMC 0612, Appendix B. |
| 05000293/FIN-2016011-13 | 2017Q1 | Pilgrim | Licensee-Identified Violation | 10 CFR 50.54(q)(2) requires, in part, that the licensee follow and maintain the effectiveness of an emergency plan to meet the planning standard of 10 CFR 50.47(b)(4). Specifically, the licensee was to maintain the necessary equipment to support the effectiveness of EALs. Contrary to these requirements, PNPS identified in CR-PNP-2016-01491 that on three past occasions (March 15 through August 8, 2012; September 4 through October 14, 2012; and June 4 through June 14, 2015) both trains of the H2O2 monitors and the Post-Accident Sampling System were unavailable to ensure the effectiveness of EAL 24, Deflagration concentrations exist inside PC, for the potential loss of the containment barrier within the Fission Product Barrier category of the EALs. This issue meets the criteria for very low safety significance (Green) because, due to other EALs, an appropriate emergency declaration could have been made in an accurate and timely manner. |
| 05000293/FIN-2016011-12 | 2017Q1 | Pilgrim | Licensee-Identified Violation | 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, and shall be accomplished in accordance with those structures, procedures, and drawings. Entergy procedure EN-DC-148, Vendor Manuals and Vendor Re-Contact Process, Revision 6, requires, in part, that the station update vendor manuals every three years. Contrary to this, in July 2016, PNPS determined through a self-assessment that they had 13 vendor manuals that had not been evaluated for changes within 3 years. The NRC team determined that this finding did not affect the design or qualification of a mitigating structure, system or component; did not represent a loss of a system and/or function; did not result in loss of a train or two safety systems greater than any technical specification allowed outage time; did not result from an actual loss of safety function; and did not involve loss of any external event mitigating system. Consequently, the NRC team determined that this performance deficiency screened as having very low safety significance (Green). PNPS documented this issue in their corrective action program as CR-PNP-2016-05115. |
| 05000293/FIN-2016011-11 | 2017Q1 | Pilgrim | Failure to Adequately Develop and Implement Targeted Performance Improvement Plans | The NRC team identified a Green finding because Entergy did not adequately develop and implement a CAPR of a root cause related to a Category A CR, as required by Entergy Procedure EN-LI-102, Corrective Action Program. Specifically, Entergy did not adequately develop and implement the Targeted Performance Improvement Plans, which were designated as a CAPR for the root cause for the Nuclear Safety Culture Fundamental Problem. Entergy documented this issue in the corrective action program for further evaluation as CR-PNP-2017-00406. The performance deficiency was more than minor because if left uncorrected, it could lead to a more significant safety concern. Specifically, inadequate implementation of the Targeted Performance Improvement Plans could result in recurrence of a culture in which leaders are not holding themselves and their subordinates accountable to high standards of performance, resulting in continuing performance issues at the station. The NRC team evaluated the finding using Exhibit 2, Mitigating Systems Screening Questions, of IMC 0609, Appendix A, Significance Determination Process for Findings At-Power, and determined this finding did not affect the design or qualification of a mitigating structure, system, or component; represent a loss of system and/or function; involve an actual loss of function of at least a single train or two separate safety systems for greater than its technical specification-allowed outage time; or represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant. Therefore, the NRC team determined the finding was of very low safety significance (Green). This finding had a cross-cutting aspect in the area of Human Resources, Change Management, because leaders did not use a systematic process for evaluating and implementing change so that nuclear safety remains the overriding priority. In this case, PNPS leaders did not apply sufficient rigor in development and implementation of the Targeted Performance Improvement Plans such that they would be an adequate method to drive and sustain positive changes in the stations safety culture (H.3). |
| 05000293/FIN-2016011-10 | 2017Q1 | Pilgrim | Failure to Promptly Correct a Condition Adverse to Quality for the Residual Heat Removal System | The NRC team identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, because Entergy did not take timely corrective action for a previously identified condition adverse to quality. Specifically, Entergy failed to adequately resolve, through repair or adequate evaluation, gasket leakage on the B residual heat removal heat exchanger, which resulted in continued degradation and leakage for the heat exchanger gasket. Entergy did not consider this leakage as a degraded condition, with the potential to impact both the operability of the residual heat removal system, and PNPSs licensing basis with regards to leakage of a closed loop system outside of containment. After the NRC team raised the issue, Entergy performed an operability determination that established a reasonable expectation of operability pending implementation of corrective actions. Entergy entered this issue into their corrective action program as CR-PNP-2016-09725. The performance deficiency was 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 availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to correct identified gasket leakage resulted in continued degradation and leakage of the heat exchanger gasket. The NRC team evaluated the finding using Exhibit 2, Mitigating Systems Screening Questions, of IMC 0609, Appendix A, Significance Determination Process for Findings At-Power, and determined this finding did not affect the design or qualification of a mitigating structure, system, or component; represent a loss of system and/or function; involve an actual loss of function of at least a single train or two separate safety systems for greater than its technical specification-allowed outage time; or represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant. Therefore, the NRC team determined the finding was of very low safety significance (Green). The finding had a cross-cutting aspect in Human Performance, Conservative Bias, because Entergy failed to use decision making practices that emphasize prudent choices over those that are simply allowable (H.14). |
| 05000293/FIN-2016011-09 | 2017Q1 | Pilgrim | Ineffective Corrective Actions to Address Conditions Adverse to Quality Regarding Components in Contact with or Close Proximity to the Drywell Liner | The NRC team identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, associated with Entergys failure to correct a condition adverse to quality affecting safety-related equipment. Specifically, during a previous NRC inspection in August 2016, inspectors identified numerous locations in the drywell where non-seismic equipment was either in contact, or close proximity, with the drywell liner and had caused damage. Entergy initiated CRs and performed an operability evaluation for the identified issues. However, following a review of these CRs, the NRC team determined that Entergy failed to take corrective actions to address the condition adverse to quality. Entergy entered this issue into the corrective action program as CR-PNP-2016-09346 and CR-PNP-2016-09377 to perform an extent of condition review, secure the loose grating that had caused damage to the liner, and evaluate the need for a clearance criteria between components such as floor grating and support structures and the containment liner. The performance deficiency was more than minor because it was associated with the configuration control attribute of the Barrier Integrity cornerstone and 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. Using IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, Exhibit 3, Barrier Integrity Screening Questions, the NRC team determined that this finding was of very low safety significance (Green) because the finding did not represent an actual open pathway in the physical integrity of reactor containment (valves, airlocks, etc.), containment isolation system (logic and instrumentation), and heat removal components. This finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Evaluation, because the engineering evaluation of the degraded condition identified by the inspectors did not thoroughly evaluate the containment liner issues to ensure that resolutions address causes and extents of condition commensurate with their safety significance (P.2). |
| 05000293/FIN-2016011-08 | 2017Q1 | Pilgrim | Failure to Adequately Monitor the Performance of Maintenance Rule Scoped Components | The NRC team identified a Green non-cited violation of 10 CFR 50.65(a)(2), Requirements for monitoring the effectiveness of maintenance at nuclear power plants. Specifically, Entergy did not demonstrate that the performance of 18 maintenance rule scoped components was effectively controlled through the performance of appropriate preventive maintenance, and did not establish goals and monitoring in accordance with 10 CFR 50.65(a)(1). Entergys immediate corrective action was to initiate a CR to evaluate moving the affected systems to 10 CFR 50.65(a)(1) monitoring requirements. Entergy entered this issue in the corrective action program as CR-PNP-2017-00401. The performance deficiency was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and affected the cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, Entergy failed to demonstrate that the performance of the 18 maintenance rule scoped components was being effectively controlled through the performance of appropriate preventive maintenance which adversely impacts the reliability of those systems. The NRC team evaluated the finding using Exhibit 2, Mitigating Systems Screening Questions, of IMC 0609, Appendix A, Significance Determination Process for Findings At-Power, and determined this finding did not affect the design or qualification of a mitigating structure, system, or component; represent a loss of system and/or function; involve an actual loss of function of at least a single train or two separate safety systems for greater than its technical specificationallowed outage time; or represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant. Therefore, the NRC team determined the finding was of very low safety significance (Green). The finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Evaluation, in that Entergy failed to thoroughly evaluate and ensure that resolution of the identified issue, maintenance not being performed on maintenance rule scoped components, included reclassifying the components as necessary. Specifically, Entergy failed to demonstrate that the performance of Maintenance rule scoped components was effectively controlled through the performance of appropriate preventive maintenance, or through performance goals and monitoring. (P.2). |
| 05000293/FIN-2016011-04 | 2017Q1 | Pilgrim | Programmatic Issue with Implementation of the Operability Determination Process | The NRC team identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings. Specifically, the NRC team identified a programmatic issue because in some cases, Entergy did not enter the operability determination process when appropriate, and, when the process was entered, did not adequately document the basis for operability, in accordance with Procedure ENOP-104, Operability Determination Process, Revision 11. In each of the examples discussed, though the basis for operability was not adequate, all components were determined to be operable upon further evaluation. Entergy entered this issue into their corrective action program as CR-PNP-2017-00626. The performance deficiency was more than minor because if left uncorrected, could lead to a more significant safety issue. Specifically, the failure to enter and document a basis for operability could lead to not recognizing inoperable safety-related equipment, and place the reactor at a higher risk of core damage in a design basis accident. The NRC team evaluated the finding using Exhibit 2, Mitigating Systems Screening Questions, of IMC 0609, Appendix A, Significance Determination Process for Findings At-Power, and determined this finding did not affect the design or qualification of a mitigating structure, system, or component; represent a loss of system and/or function; involve an actual loss of function of at least a single train or two separate safety systems for greater than its technical specification-allowed outage time; or represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant. Therefore, the NRC team determined the finding was of very low safety significance (Green). This finding had a cross-cutting aspect in the area of Human Performance, Teamwork. Specifically, the operations and engineering departments did not demonstrate a strong sense of collaboration and cooperation with respect to holding each other accountable when performing operability determinations to ensure nuclear safety is maintained (H.4). |
| 05000293/FIN-2016011-03 | 2017Q1 | Pilgrim | Failure to Issue Appropriate Corrective Actions to Preclude Repetition for the Causes of the September 2016 Scram | The NRC team identified a Green finding because Entergy did not issue appropriate CAPRs in accordance with Entergy procedure EN-LI-102, Corrective Action Process, Revision 28. Specifically, Entergy did not issue adequate CAPRs associated with Root Cause 1 of the feedwater regulating valve failure in September 2016 that resulted in a manual scram. As a result of the NRC teams questions, Entergy issued procedure 1.13.2, Vendor and Technical Information Reviews, Revision 0, as continuous use to ensure that planners will always have the checklist in-hand when planning work to ensure that appropriate vendor technical information is always included in applicable work instructions. Entergy entered the NRC teams concerns in the corrective action program as CR-PNP-2017-00687 and CR-PNP-2017-00936. The performance deficiency was more than minor because it is associated with the equipment performance attribute of the Initiating Events cornerstone and if left uncorrected, the performance deficiency would have the potential to lead to a more significant safety concern. Specifically, if left uncorrected, the performance deficiency could have the potential to result in repetition of a significant condition adverse to quality, loss of control of feedwater regulating valve 642A and a manual scram. The NRC team evaluated the finding using Exhibit 1, Initiating Events Screening Questions, of IMC 0609, Appendix A, Significance Determination Process for Findings At-Power, and determined this finding did not cause a reactor trip or the loss of mitigation equipment relied upon to transition the plant from the onset of a trip to a stable shutdown condition. Therefore, the NRC team determined the finding was of very low safety significance (Green). The NRC team determined that the finding had a cross-cutting aspect in the area of Human Performance, Procedure Adherence, because individuals did not follow processes, procedures, and work instructions. Specifically, Entergy did not follow procedure EN-LI-102, which provides the station standards for crafting a corrective action and states, in part, that the corrective action descriptions must be worded to ensure that the adverse condition or cause/factor is addressed (H.8). |
| 05000293/FIN-2016011-02 | 2017Q1 | Pilgrim | Failure to Establish Corrective Actions to Preclude Repetition of a Significant Condition Adverse to Quality | The NRC team identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, because Entergy did not implement CAPRs for a significant condition adverse to quality identified in root cause evaluation CR-PNP-2016-00716, Implementation of the Corrective Action Program, Revision 2. Specifically, the team identified that CAPRs for Entergys continued weaknesses in the implementation of the corrective action program were inadequate. Entergy entered this issue into their corrective action program for further evaluation as CR-PNP-2017-00053, CR-PNP-2017-00410, and CR-PNP-2017-01134. The performance deficiency was more than minor because if left uncorrected, it had the potential to lead to a more significant safety concern. Specifically, the failure to preclude repetition of this significant condition adverse to quality could result in continuing weaknesses in implementation of the corrective action program, which was designated as a fundamental problem, and thus a contributing factor for PNPS Column 4 performance. Additionally, weaknesses with corrective action program implementation could result in equipment issues where operability is not maintained. The NRC team evaluated the finding using Exhibit 2, Mitigating Systems Screening Questions, of IMC 0609, Appendix A, Significance Determination Process for Findings At-Power, and determined this finding did not affect the design or qualification of a mitigating structure, system, or component; represent a loss of system and/or function; involve an actual loss of function of at least a single train or two separate safety systems for greater than its technical specificationallowed outage time; or represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant. Therefore, the NRC team determined the finding was of very low safety significance (Green). The NRC team determined that the finding had a cross-cutting aspect in the area of Human Performance, Procedure Adherence, because individuals did not follow processes, procedures, and work instructions. Specifically, Entergy did not follow procedure EN-LI-102, which provides the station standards for crafting a corrective action and states, in part, that the corrective action descriptions must be worded to ensure that the adverse condition or cause/factor is addressed (H.8). |
| 05000293/FIN-2016011-06 | 2017Q1 | Pilgrim | Design Change Not Appropriately Reviewed by Entergy | The NRC team identified a preliminary greater than Green finding and apparent violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, associated with Entergys failure to ensure that design changes were subject to design control measures commensurate with those applied to the original design and were approved by the designated responsible organization. Specifically, Entergy received a new style right angle drive for the A emergency diesel generator radiator blower fan from a vendor but failed to adequately review the differences in the design of the drives to identify potential new failure mechanisms for the part or the need for related preventive measures. Entergy entered this issue into the corrective action program as CR-PNP-2016-07443. The performance deficiency was more than minor because it was associated with the design control attribute of the Mitigating Systems cornerstone, and affected the associated cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. 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 team screened the finding for safety significance and determined that a detailed risk evaluation was required based on the A emergency diesel generator being inoperable for greater than the technical specification allowed outage time. Region I senior reactor analysts performed a detailed risk evaluation. The finding was preliminarily determined to be of greater than very low safety significance (greater than Green). The risk important sequences were dominated by external fire risk. Specifically, a postulated fire in the B 4 kilovolt (KV) switchgear room with a consequential loss of the unit auxiliary generator power supply, non-recoverable loss of off-site power (LOOP) to both safety buses A5 and A6, loss of the B emergency diesel generator with the conditional failure of the A emergency diesel generator, along with the loss of bus A8 feed (from the shutdown transformer or station blackout (SBO) diesel generator) to safety buses A5 and A6. The internal event risk was dominated by weather related LOOPs, failure of the A emergency diesel generator, with failure of the B emergency diesel generator and SBO diesel generator to run, along with failure to recover offsite power or the emergency diesel generators. See Attachment 1, A Emergency Diesel Generator Cooling Water System Degradation Detailed Risk Evaluation, for a detailed review of the quantitative criteria considered in the preliminary risk determination. The NRC team did not assign a cross-cutting aspect to this finding because the performance deficiency occurred in May 2000. Entergys program has undergone changes since May 2000, and the NRC team did not identify any recent examples of this performance deficiency. Other aspects of Entergys performance related to this issue are further discussed in Sections 5.10.3 and 6.3.4. |
| 05000424/FIN-2017007-01 | 2017Q1 | Vogtle | Failure to identify a Degraded Atmospheric Relief Valve | The NRC identified a Green finding for the licensees failure to identify the reduced reliability of Unit 1 loop 3 atmospheric relief valve (ARV) 1PV-3020 as a degraded/nonconforming condition, as required by NMP-AD-012, Operability Determinations and Functionality Assessments, Version 12.5. As a result, corrective maintenance was not prioritized nor conducted at the next available opportunity and led to an additional valve failure in March 12, 2016. The failure to identify aging of 1PV-3020 #285 pilot-to-check valve as a degraded/non conforming condition, as required by NMP-AD-012, was a performance deficiency. The performance deficiency was more than minor because it was associated with the equipment performance attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability o systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the performance deficiency prevented the license from prioritizing and conducting corrective maintenance of 1PV-3020 at the next available opportunity, and led to an additional valve failure in March 2016. Using Exhibit 2 of IMC 0609, Appendix A, the inspectors determined that this finding is of very low safety significance (Green) because, although the performance deficiency (PD) affected the design/qualification of the 1PV3020 operability, it did not result in an actual loss of safety system function, and it did not represent a loss of function of one or more than one train for more than its technical specification (TS) allowed outage time or greater than 24 hours. The finding was assigned a cross cutting aspect of Resolution in the Problem Identification and Resolution area, because the licensee failed to take effective corrective actions to address aging of the #285 pilot-to-check valve in a timely manner. |
| 05000293/FIN-2016011-01 | 2017Q1 | Pilgrim | Failure to Identify All Root Causes of a Significant Condition Adverse to Quality | The NRC team identified a Green non-cited violation of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion XVI, Corrective Action, because Entergy did not adequately determine all root causes associated with a significant condition adverse to quality related to the failure to identify, evaluate, and correct the A SRVs failure to open upon manual actuation during a plant cooldown on February 9, 2013. Specifically, Entergy did not establish adequate measures to assure that the cause of a significant condition adverse to quality, inadequate shift manager operability determination rigor and its associated causes, were adequately determined and corrective action taken to preclude repetition. Entergys immediate corrective actions included planning to conduct operations management face-to-face conversations with shift manager qualified individuals to reinforce the shift managers responsibility for operability and functionality determination accuracy and rigor. Entergy entered this issue into the corrective action program as CRPNP-2017-00363 and CR-PNP-2017-00828. The performance deficiency was more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone and if left uncorrected, the performance deficiency would have the potential to lead to a more significant safety concern. Specifically, if left uncorrected, the performance deficiency could have the potential to result in repetition of a failure to identify, evaluate, and correct an SRVs failure to open or a similar significant condition adverse to quality. The NRC team evaluated the finding using Exhibit 2, Mitigating Systems Screening Questions, of IMC 0609, Appendix A, Significance Determination Process for Findings At-Power, and determined this finding did not affect the design or qualification of a mitigating structure, system, or component; represent a loss of system and/or function; involve an actual loss of function of at least a single train or two separate safety systems for greater than its technical specification-allowed outage time; or represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant. Therefore, the NRC team determined the finding was of very low safety significance (Green). The NRC team determined that the finding had a cross-cutting aspect in the area of Human Performance, Avoid Complacency, because individuals did not recognize and plan for the possibility of mistakes, latent issues, and inherent risk, even while expecting successful outcomes. Specifically, Entergy incorrectly assumed that CR-PNP-2013-00825 contained inadequate information to determine that the A SRV had not opened, and this assumption ultimately impacted the root cause results documented in CR-PNP-2016-01621 (H.12). |
| 05000395/FIN-2016007-02 | 2016Q4 | Summer | Failure to Correct a Condition Adverse to Quality Associated with a Previously Issued NCV | The inspectors identified a non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, for the failure to correct a condition adverse to quality associated with a previously issued NCV, 05000395/2012004-02, Inadequate Installation of Unit 1 Service Water Piping and Related Pipe Support. The licensee entered the issue in the correction action program as condition report (CR)-16-04621. The PD is more than minor because if left uncorrected, the reduction in design margin of the pipe support could affect the Unit 1 SW systems ability to mitigate a seismic event. Specifically, Unit 1 service water (SW) piping and support had been impacted by the reduction in design margin and without formally updating the associated drawings and calculations or restoring to the original design, future modifications to the system could impact the systems ability to mitigate a seismic event. Using Manual Chapter 0609 Attachment 04, Initial Characterization of Findings, Table 2, dated October 07, 2016, the finding was determined to adversely affect the External Event Mitigating Systems. The inspectors screened the finding using Inspection Manual Chapter (IMC) 0609, Appendix A, Significance Determination Process (SDP) for Findings at-Power, dated June 19, 2012, and determined that it screened as Green (very low safety significance) because the service water system maintained its functionality to mitigate a seismic event. The inspectors determined that the finding had a cross-cutting aspect in the area of PI&R because the licensee did not take effective corrective actions to address this issue in a timely manner (P.3). |
| 05000395/FIN-2016007-01 | 2016Q4 | Summer | Failure to Implement Corrective Actions and Restore Compliance for Previous NRCIdentified SLIV NCV | The inspectors identified a cited Severity Level (SL) IV violation of Operating Licensee Condition 2.C.(18) for failure to ensure that conditions adverse to fire protection as noted in a previous NRC-identified SLIV NCV, 05000395/2016001-01, Failure to Implement Adequate Administrative Controls Following a Departure from National Fire Protection Association (NFPA) 80-1973 and Provide NRC Staff Complete and Accurate Information, were promptly corrected. Specifically, the licensee failed to implement corrective actions and restore compliance in a timely manner for (1) the noncompliance with 10 CFR 50.9 to provide staff complete and accurate information and (2) fire doors DRIB/105A&B currently do not meet self-closing requirements in accordance with the current NFPA 805 licensing basis and no actions were specified in licensees corrective action program to restore compliance. The licensee entered the issue in their corrective action program as condition report (CR)-16-04701. The inspectors determined that the performance deficiency was more than minor because it impacted the ability of the NRC to perform its regulatory oversight function and was dispositioned using traditional enforcement. Because the licensee failed to implement corrective actions and restore compliance in a timely manner, this violation is being treated as a cited violation, consistent with Section 2.3.2. a of the NRC Enforcement Policy. This violation involved traditional enforcement and a cross-cutting aspect was not assigned to this violation. |
| 05000327/FIN-2016003-02 | 2016Q3 | Sequoyah | Isolation of Fire Suppression System to a Significant Portion of the Plant Site | A self-revealing non-cited violation (NCV) of the facility operating licenses DPR-77 and DPR-79 conditions 2.C.(16) and 2.C.(13), respectively, was identified for the licensees failure to properly implement the clearance process such that the fire suppression system was rendered non-functional for approximately 41 hours. The licensee inappropriately expanded an existing clearance on March 29, 2016 in order to attempt to reduce boundary valve leakage affecting existing maintenance on the fire suppression system within a valve pit. Subsequently on March 30, 2016 during fire system testing, technicians noted a lack of system pressure and it was ultimately concluded the clearance expansion had inadvertently isolated fire suppression water to a significant portion of the site. Upon discovery of the clearance error, the system was restored to a functional status. The licensee entered the issue into their corrective action program (CAP) as CR 1155763. The licensees failure to properly assess the system impact of a clearance revision for the High Pressure Fire Protection (HPFP) suppression header and enter the required FPR Operating Requirement (FOR) Action was a performance deficiency. The performance deficiency was more than minor because it was associated with the protection against external events (fire) 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. The inability to pressurize the HPFP system from either the electric or diesel-driven fire pumps rendered the fire suppression system inoperable. Based on the complexities of this particular event, the inspectors concluded that Appendix M, Significance Determination Process Using Qualitative Criteria, of IMC 0609 should be performed in lieu of a Phase 3 analysis. Under appendix M, the Senior Reactor Analyst (SRA) performed an initial bounding evaluation using qualitative methods. The licensee submitted a detailed analysis that estimated an upper bound for the risk of the finding which was less than 1E-6. The SRA performed a review of this screening analysis as part of this SDP evaluation. In addition to the SRA review, the resident inspectors performed an independent review of the licensees estimation of the success of actions used to recover the isolated fire header. To the extent reviewed, the methodology and results were determined to be acceptable for use in this SDP review of this Performance Deficiency. The SRA concurred with the submitted results of the licensees screening analysis, and has determined the finding to be GREEN. The inspectors determined that the finding had a cross cutting aspect of Procedural Adherence within the Human Performance area, because the licensee failed to consider the affect that changing a clearance order could have on the operability of the fire suppression system. |
| 05000327/FIN-2016003-01 | 2016Q3 | Sequoyah | Hydrogen Mitigation System Inoperable Longer than Allowed by Technical Specifications | A self-revealing NCV of Technical Specification 3.6.8, Hydrogen Mitigation System (HMS), was identified for the licensees failure to restore an inoperable train of HMS within the 7 day completion time or place the unit in Mode 3 within the action time of 6 hours. Each train of HMS has 34 hydrogen igniters and SR 3.6.8.1 defines an operable train as one that has at least 33 igniters operable. A review of the operating history revealed the A train HMS had only 31 operable igniters for a period of 91 days due to a mispositioned circuit breaker. Upon discovery of the unexpected condition, the circuit breaker was closed to restore operability to the HMS train. The licensee entered the issue into their CAP as CR 1179126. The licensees failure to preclude an inoperable HMS train for more than 7 days without a subsequent plant shutdown was a performance deficiency. The performance deficiency was more than minor because it was associated with the Configuration Control attribute of Barrier Integrity cornerstone and adversely affected the cornerstones objective to ensure the structural integrity of the containment boundary. Specifically, the finding challenged containment integrity as hydrogen igniters have a high risk significance in ice condenser style containments. The finding was screened to Green based on the fact that the loss of igniters did not affect multiple igniters in adjacent compartments. The inspectors determined that the finding had a cross cutting aspect of Avoid Complacency within the Human Performance area because the licensee failed to implement appropriate error reduction tools while working near the HMS circuit breakers (H.12). |
| 05000335/FIN-2016007-01 | 2016Q2 | Saint Lucie | Intake Cooling Water Pump House Transient Combustible Fire Loading Calculation | The inspectors identified an unresolved item (URI) associated with the transient combustible heat load calculation for both Units ICW pump houses and the basis for exclusion of treated or fire retardant wood. The URI is being opened to review the licensees evaluation and determine if a performance deficiency exist. Three ICW pumps and motors are located in each house. Each pump motor is 600 horsepower. During a walkdown of both units ICW pump houses, inspectors noted that the scaffolding around the ICW pumps consisted of metal and wood planks. The inspectors determined that the wood was not included in heat load calculation for the respective pump houses. The licensee stated that the wood was treated or fire retardant and did not need to be included in the sites transient combustible heat load calculations. The inspectors questioned the licensee on the basis for not including the treated wood in the transient combustible heat load calculation. The licensee entered this issue into the CAP as 2133079 and 2134308, and initiated corrective actions to evaluate the basis for not performing a combustible heat loading calculation for fire retardant wood. The licensee also took corrective actions to replace the wood with a non-combustible material. Additional inspection time is required to review the licensees evaluation and determine if a performance deficiency exist. This issue will be tracked as URI 05000335,389 / 2016007-01, Intake Cooling Water Pump House Transient Combustible Fire Loading Calculation. |
| 05000327/FIN-2016002-01 | 2016Q2 | Sequoyah | Isolation of Fire Suppression System to a Significant Portion of the Plant Site | A self-revealing apparent violation (AV) of the facility operating licenses DPR-77 and DPR-79 conditions 2.C.(16) and 2.C.(13) was identified for the licensees failure to properly implement the clearance process such that the fire suppression system was rendered non-functional for approximately 48 hours. The licensee inappropriately expanded an existing clearance on March 29 in order to attempt to reduce boundary valve leakage affecting existing maintenance on the fire suppression system within a valve pit. Subsequently, on March 30, during fire system testing, technicians noted a lack of system pressure and it was ultimately concluded the clearance expansion had inadvertently isolated fire suppression water to a significant portion of the site. Upon discovery of the clearance error, the system was restored to a functional status after being isolated for approximately 48 hours. The licensee entered the issue into their corrective action program as condition report (CR) 1155763. The performance deficiency was determined to be more than minor because it was associated with the protection against external events (fire) 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. The inability to pressurize the high pressure fire protection (HPFP) system from either the electric or diesel-driven fire pumps rendered the fire suppression system inoperable. The finding could not be screened to Green and is pending a significance determination. The inspectors determined that the finding had a cross-cutting aspect of Procedural Adherence within the Human Performance area, because the licensee failed to consider the effect that changing a clearance order could have on the operability of the fire suppression system. (H.8). |
| 05000400/FIN-2015008-02 | 2015Q4 | Harris | Failure to Follow EPM-410 Procedure | An NRC-identified Green NCV of 10 CFR 50.54(q)(2) was identified, for the licensees failure to follow and maintain, in effect, the Emergency Plan when performing monthly testing of the Technical Support Center (TSC). Specifically, the licensee failed to follow procedural steps when recorded values did not meet acceptance criteria as specified in EPM-410, Communication and Facility Performance Tests. The issue was placed in the licensees corrective action program as CRs 01942073, 01940053. The finding was more than minor because it was associated with the Emergency Response Organization (ERO) Performance attribute and it adversely affected the Emergency Preparedness Cornerstone objective of ensuring that the licensee was capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. Specifically, the failure to follow procedural steps when recorded values did not meet acceptance criteria resulted in a failure to comply with emergency plan. The finding was assessed for significance in accordance with NRC Manual Chapter 0609, Appendix B Emergency Preparedness Significance Determination Process. Attachment 2 of Appendix B, Failure to Comply Significance Logic is as follows: Failure to comply; Loss of Risk Significant Planning Standard Function (RSPS), NO; RSPS Degraded Function, NO; Loss of Planning Standard Function, No; results in a Green finding. The inspectors identified a cross-cutting aspect in the Problem Identification and Resolution area because the licensee did not take effective corrective actions to address issues in a timely manner commensurate with their safety significance (P.3). |
| 05000400/FIN-2015008-01 | 2015Q4 | Harris | Untimely 10 CFR 50.73 Notification of an Inoperable CIV | An NRC-identified Severity Level IV violation of 10 CFR 50.73 was identified for the licensees failure to provide a written report to the NRC within 60 days after discovery of a condition prohibited by Technical Specification (TS) Limited Condition for Operation (LCO) 3.6.3, "Containment Isolation Valves."The issue was placed in the licensees corrective action program as CR 01958628.The inspectors determined that the failure to provide a written report to the NRC within the time limits specified in regulations was a violation 10 CFR 50.73. The violation was evaluated using Section 6.9 of the NRC Enforcement Policy, because the failure to submit a required licensee event report may impact the ability of the NRC to perform its regulatory oversight function. As a result, this violation was evaluated using traditional enforcement. In accordance with Section 6.9.d.9of the NRC Enforcement Policy, this violation was determined to be a Severity Level IV, non-cited violation. The inspectors determined that a cross-cutting aspect was not applicable because the issue involving untimely reports to the NRC was strictly associated with a traditional enforcement violation. |
| 05000324/FIN-2015007-02 | 2015Q2 | Brunswick | Insufficient Material Evaluation of Commercially Dedicated Allen Bradley Relays | An NRC-identified Green NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control was identified for the licensees inadequate commercial grade dedication technical evaluation that resulted in non-conforming relays being installed in the control circuits for emergency diesel generator output breakers. This led to specification of a relay that was unsuitable for the application being installed in the control circuit for two emergency diesel generator output breakers and failure of one of those breakers to close. The licensee documented this issue in their corrective action program and performed corrective actions to mitigate the effects of the undetected changes on the relay. The inspectors determined that the finding was more than minor in accordance with Manual Chapter 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, dated September 7, 2012, because, if the process for detecting commercial grade item changes using material evaluations was left uncorrected, additional undetected design or process changes would likely occur. Using Manual Chapter 0609, Appendix A, issued June 19, 2012, The Significance Determination Process (SDP) for Findings At-Power, the inspectors determined the finding required a detailed risk evaluation because the effect on two emergency diesel generators was considered a loss of function. For Unit 1, the regional Senior Reactor Analyst used demand data to adjust the probability that an emergency diesel generator would fail to start and ran a condition assessment on SAPHIRE. Because of limited exposure time, the finding was determined to be Green for Unit 1. For Unit 2, the conditions for exposure occurred during an outage with the reactor cavity filled, and both EDGs would be available. The SRA determined the significance to be bounded by the at power risk analysis performed for Unit 1. Because of the low exposure time, and the high likelihood of operators recovering the failure to start of the EDGs, this issue was Green for Unit 2. The inspectors did not identify a crosscutting aspect associated with this finding because the original relay evaluation was done in 1999 and was not indicative of current licensee performance. |
| 05000324/FIN-2015007-01 | 2015Q2 | Brunswick | Failure to Identify Conditions Adverse to Quality | An NRC-identified Green non-cited violation (NCV) of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion XVI, Corrective Action, was identified for licensee failure to identify conditions adverse to quality during the evaluation of an emergency diesel generator (EDG) output breaker failure on March 16, 2015. Specifically, the licensee missed that an internal change made to a relay was a condition adverse to quality. Further, the licensee failed to reclassify a corrective action document to higher significance when information arose indicating that the event in question was a loss of safety function. The licensee documented these issues in their corrective action program, completed the necessary reviews for a condition adverse to quality, and reclassified the original event to Significance Level 1. The inspectors determined that the finding was more than minor in accordance with Manual Chapter 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, dated September 7, 2012, because, if left uncorrected, additional unqualified relays would likely have been installed in the plant. Using Manual Chapter 0609, Appendix A, Exhibit 1, effective July 1, 2012, the finding screened as Green for each unit by answering no to the questions related to an actual loss of function of a system, a single train, non-technical specification equipment designated as high safety-significant in accordance with the licensees maintenance rule program for >24 hrs. The finding had a cross-cutting aspect for Evaluation in the area of Problem Identification & Resolution because the most likely cause of the missed conditions adverse to quality was a lack of thorough investigation during the evaluations (for cause and reportability) of the relay issue. |
| 05000390/FIN-2014007-01 | 2014Q4 | Watts Bar | Security | |
| 05000390/FIN-2015405-01 | 2014Q4 | Watts Bar | Security | |
| 05000261/FIN-2014008-01 | 2014Q2 | Robinson | Failure to Take Adequate Corrective Action to Preclude Repetition of a Significant Condition Adverse to Quality Associated with the Steam Generator Tube Leak | The team identified a Green NCV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Actions, for the licensees failure to take adequate corrective action to prevent repetition of a significant condition adverse to quality regarding steam generator tube leakage due to poor maintenance practices. Specifically, on February 27, 2014, the C steam generator showed indications of a primary to secondary tube leak due to foreign material that was introduced during the fall 2013 refueling outage. As immediate corrective actions, on March 7, 2014, the licensee shutdown the plant and repaired the leak. This violation was entered into the licensees CAP as nuclear condition reports (NCRs) 683695, 683593, and 683591. The licensees failure to implement appropriate corrective actions to address poor worker practices to prevent recurrence of a steam generator tube leak was a performance deficiency. The finding was more than minor because it was associated with the initiating events cornerstone equipment performance attribute 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, foreign material entered the steam generator and damaged a steam generator tube, which increased the likelihood of a steam generator tube rupture. The inspectors screened this finding using IMC 0609, Appendix A, The Significant Determination Process (SDP) For Findings At-Power, dated June 19, 2012. The finding screened as Green per Section D of Exhibit 1, Initiating Events Screening Questions, because testing showed that the affected steam generator tube could sustain three times the differential pressure across the tube during normal full power and that the steam generator did not violate the accident leakage performance criterion. The performance deficiency does not have a cross cutting aspect because the last revision of the root cause evaluation was completed in 2011 and it is not indicative of current licensee performance. |
| 05000389/FIN-2014007-03 | 2014Q1 | Saint Lucie | Failure to Follow Refueling Operations Procedure Resulting in a Fuel Mishandling Event | A self-revealing, Non-Cited Violation (NCV) of Technical Specification (TS) 6.8.1, Procedures and Programs, was identified which requires that written procedures be established, implemented, and maintained covering activities referenced in NRC Regulatory Guide 1.33, Revision 2, dated February 1978, including safety related activities carried out during operation of the reactor plant. The licensees failure to comply with refueling procedure 0-NOP-67.05, Refueling Operations, was a performance deficiency. Specifically, the licensees procedure for refueling operation, 0- NOP-67.05, Refueling Operations, was not implemented as written for conducting refueling operations resulting in a fuel mishandling event. This issue was documented in the licensees corrective action program as condition report 1911660. This performance deficiency was more than minor because it was associated with the human performance attribute of the Barrier Integrity Cornerstone and it adversely affected the associated cornerstone objective to provide reasonable assurance that physical design barriers (fuel cladding) protect the public from radionuclide releases caused by accidents or events. Specifically, failure to prevent fuel assemblies from contacting one another during refuel operations could fail to provide reasonable assurance that physical design barriers (fuel cladding) protect the public from radionuclide releases caused by accidents or events. The inspectors evaluated the risk of this finding using Manual Chapter 0609, Appendix G, Significance Determination Process for Shutdown Operations. The inspectors determined that the finding was of very low safety significance Green using IMC 0609, Appendix G, Figure 1, because it did not require a quantitative assessment as determined in IMC 0609, Appendix G, Attachment 1, Checklist 4. The finding involved a cross-cutting aspect of Human Performance, in the component of Teamwork. Specifically, individuals and work groups failed to communicate and coordinate their activities within and across organizational boundaries to ensure nuclear safety is maintained. |
| 05000389/FIN-2014007-01 | 2014Q1 | Saint Lucie | Inadequate Corrective Actions to Address Water Intrusion in the HCV-09-2A Relay Box | A self-revealing, Non-Cited Violation (NCV) of 10 CFR Part 50 Appendix B, Criterion XVI, Corrective Action, was identified for the licensees failure to correct an identified condition adverse to quality associated with the water intrusion into the HCV- 09-2A relay box. The licensees failure to implement corrective actions to address previous water intrusion events was a performance deficiency. Specifically, the licensee failed to implement corrective actions to address previous water intrusion events, which resulted in the failure of HCV-09-2A, and a plant trip. This issue was documented in the licensees corrective action program as CR 1920696. Immediate corrective actions included the restoration of HCV-09-2A to operable status and the inspection of other Main Feedwater Isolation Valve (MFIV) relay boxes. This performance deficiency was more than minor because it was associated with the equipment performance attribute of the Initiating Events Cornerstone and it adversely affected the associated cornerstone objective of limiting the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. In accordance with the NRC inspection Manual Chapter 0609, Attachment 4, Initial Characterization of Findings, the finding was determined to be of very low safety significance (Green) because the finding did not result in a loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. The finding had a cross-cutting aspect in the area of Problem Identification and Resolution, in the component of Evaluation, because the licensee failed to thoroughly evaluate issues to ensure that resolutions address causes and extent of conditions commensurate with their safety significance (P2). |
| 05000335/FIN-2014007-02 | 2014Q1 | Saint Lucie | Failure to Follow Seismic Restraining Procedures on Ladders Located Near Safety-Related Equipment | An NRC identified non-cited violation (NCV) of Technical Specification 6.8.1, Procedures and Programs, was identified which requires that written procedures be established, implemented, and maintained covering activities referenced in NRC Regulatory Guide 1.33, Revision 2, dated February 1978. The licensees failure to comply with procedures to seismically restrain ladders was a performance deficiency. Specifically, the licensees procedures for seismic restraint of ladders: MA-AA-100- 1008, Station Housekeeping and Material Control; QI-13-PSL, Housekeeping and Cleanliness Controls Methods St. Lucie Plant; ADM-04.02, Industrial Safety Program; and ADM-27.11, Scaffold Control, were not implemented as written with regard to ladders that were installed near safety-related equipment. The inspectors identified three examples of ladders not seismically restrained in accordance with the licensees procedures. Immediate corrective actions included completing a site-wide walkdown of the safety-related systems to identify and bring into procedural compliance any ladders that were not seismically restrained. This issue is documented in the licensees corrective action program as Action Request (AR) 1935979 and 1933112. The performance deficiency was determined to be more than minor because if left uncorrected the failure to comply with station procedures to ensure adequate restraining of seismically controlled ladders could lead to a more significant safety concern. Specifically, seismically unrestrained ladders could impact safety-related equipment during a design basis seismic event. Using Manual Chapter 0609.04, Significance Determination Process Initial Characterization of Findings Table 2 dated June 19, 2012, the finding was determined to affect the Mitigating Systems Cornerstone. The inspectors evaluated the risk of this finding using Manual Chapter 0609 Appendix A, Significance Determination Process for Findings At-Power, Exhibit 2- Mitigating Systems Screening questions. The inspectors determined that the finding was of very low safety significance because it did not represent an actual loss of safety function. The finding involved the cross-cutting area Problem Identification and Resolution, in the component of Resolution. Specifically licensee failed to take effective corrective actions to address issues in a timely manner commensurate with their safety significance (P3). |
| 05000324/FIN-2013004-01 | 2013Q3 | Brunswick | Failure to Identify and Correct Nuclear Service Water Pump Shaft Degradation | An NRC identified Green non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, was identified for the failure of the licensee to identify and correct a condition adverse to quality (CAQ) on the 1B nuclear service water pump (NSWP). Specifically, between June 26, 2012, and January 12, 2013, the licensee failed to identify or correct the pump shaft degradation on the 1B Nuclear Service Water Pump (NSWP) pump. This resulted in the shaft bearing delaminating and bearing material becoming dislodged and trapped in the pump strainer which caused the 1B NSWP to become inoperable. The licensee replaced the pump shaft and returned the pump to operable. The licensee entered this issue into the corrective action program (CAP) as nuclear condition report (NCR) 582584. The inspectors determined that the failure of the licensee to identify and correct the 1B NSWP shaft degradation before the pump failed was a performance deficiency. The finding was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone and affects the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the shaft degradation resulted in the 1B NSWP being inoperable. Using IMC 0609, Appendix A, issued June 19, 2012, the SDP for Findings At-Power, the inspectors determined the finding was of very low safety significance (Green) because the finding did not affect the design or qualification of a mitigating structure, system and component (SSC), the finding did not represent a loss of system and/or function, the finding did not represent an actual loss of a function of a single train for greater than the technical specifications (TS) allowed outage time, the finding did not represent an actual loss of a function of one or more non-TS trains of equipment, and did not screen as potentially risk-significant due to a seismic, flooding, or severe weather initiating event. The finding has a cross-cutting aspect in the area of problem identification and resolution associated with the CAP attribute because the licensee failed to implement a CAP with a low threshold for identifying issues, specifically the licensee did not enter this issue into the CAP in June 2012. |
| 05000324/FIN-2013004-02 | 2013Q3 | Brunswick | Inadequate Preventative Maintenance Procedure for the Service Water Pump Breakers | A self-revealing Green NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified for the failure of the licensee to have an adequate preventative maintenance procedure for the service water pump breakers. Specifically, from December 1, 2004, through the end of this inspection period (September 30, 2013), the licensee failed to have an adequate preventative maintenance procedure to ensure the 52S mechanism was securely bolted to the breaker for the 2C conventional service water pump (CSWP). This resulted in both discharge valves failing to open when the 2C CSWP was started, and the inoperability of the 2C CSWP. The licensee securely bolted and tightened the 52S mechanism to the breaker. The licensee entered this issue into the CAP as NCR 604452. The inspectors determined the failure to have an adequate preventative maintenance procedure for the service water pump breakers was a performance deficiency. The finding was more than minor because it was associated with the configuration control attribute of the Mitigating Systems Cornerstone and affects the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to ensure the 52S mechanism was securely bolted to the 2C CSWP breaker resulted in the failure of both 2C CSWP discharge valves to open. Using IMC 0609, Appendix A, issued June 19, 2012, the SDP for Findings At-Power, the inspectors determined the finding was of very low safety significance (Green) because the finding did not affect the design or qualification of a mitigating SSC, the finding did not represent a loss of system and/or function, the finding did not represent an actual loss of a function of a single train for greater than the TS allowed outage time, the finding did not represent an actual loss of a function of one or more non-TS trains of equipment, and did not screen as potentially risk-significant due to a seismic, flooding, or severe weather initiating event. The finding does not have a cross-cutting aspect since the performance deficiency is not indicative of current plant performance. The 2C CSWP breaker was refurbished in December 2004 and installed in the plant in January 2005. |
| 05000390/FIN-2013007-01 | 2013Q1 | Watts Bar | Failure to Follow Procedure BP-529, Oversight of Supplemental Personnel | Inspectors identified a finding of very low safety significance for failure to follow procedure BP-259, Oversight of Supplemental Personnel, Rev. 9. Specifically, during the licensees review of the vendor instructions for performing maintenance on turbine intercept valve 1-FCV-1-102, the licensee failed to recognize that the vendor instructions were not wholly applicable due to site-specific modifications made on the Electro Hydraulic Control (EHC) system. Consequently, an EHC system leak was identified on valve 1-FCV-1-102 during power ascension at 61% power that led to a manual turbine trip. The issue was entered into the licensees CAP program as Problem Evaluation Report (PER) 686688. The finding was determined to be more than minor because it affected the design control attribute of the initiating events 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. Using the Inspection Manual Chapter 0609, Significance Determination Process, Phase 1 worksheet, the finding was determined to have very low safety significance because the condition only affected the initiating events cornerstone and did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions will not be available. The finding was determined to have a cross-cutting aspect in Human Performance, Work Practices, in that the licensee did not ensure supervisory and management oversight of work activities, including contractors, such that nuclear safety is supported. |
| 05000395/FIN-2012008-01 | 2012Q3 | Summer | Inadequate Procedures and Procedure Compliance for Preventative Maintenance Deferrals | The inspectors identified a non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings. The licensee failed to ensure that the procedure for performing Preventative Maintenance (PM) deferrals included provisions to ensure that when a Work Order (WO) high value Preventative Maintenance Task Sheet (PMTS) is deferred past its end date that the new end date for the PMTS is updated in the Computerized Maintenance Management System (CMMS). Additionally, the licensee failed to ensure personnel performed PM deferrals when a WO high value PMTS could not be performed by its required end date as directed by the PM program procedure. The licensee entered the issue into the corrective action program as CRs 12-03940, 12-3930, 12-03931, 12-04122, and 12-04152. The licensees failure to have an adequate procedure for PM deferrals and failure to perform PM deferrals as required by procedure SAP 143 was a performance deficiency. The performance deficiency was determined to be more than minor because if left uncorrected, the performance deficiency had the potential to lead to a more significant safety concern. Specifically, the failure to perform PMs at the required intervals could result in degradation or failure of safety significant equipment. The inspectors used IMC 0609, Att. 4, Initial Characterization of Findings, issued 6/19/12, and IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, issued 6/19/12, and determined the finding to be of very low safety significance (Green) because the finding was not a design or qualification deficiency, did not represent a loss of system and/or function, did not result in exceeding a TS allowed outage time and did not represent an actual loss of function of one or more non-Tech Spec Trains. The team identified a crosscutting aspect in the resources component of the human performance area because the licensee failed to ensure that the procedure was complete accurate and up to date. |
| 05000413/FIN-2011005-01 | 2011Q4 | Catawba | Follow-up for NOED 11-2-004 | The inspectors reviewed NOED 11-2-004 and related documents to determine the accuracy and consistency with the licensees assertions and implementation of the licensees compensatory measures and commitments which included deferring non-essential surveillances and other maintenance activities on the emergency diesel generators, the turbine-driven AFW pumps, the Standby Shutdown System, fire protection systems and switchyard. The inspectors also verified that the licensee briefed the oncoming operations shift on AP/0/A/5500/039, Control Room High Temperature. Additional inspection is required to conduct a review of the LER, root cause, and planned corrective actions. This URI is identified as URI 05000413, 414/2011005-01, Follow-up for NOED 11-2-004 |
| 05000390/FIN-2010007-01 | 2010Q4 | Watts Bar | Use of Omas Potentially Not Consistent with the Fire Protection Licensing Basis | The inspectors opened an unresolved issue (URI) pending NRC review of recently-received requested information related to questions regarding the licensee compliance with all provisions of their approved FPP. Specifically, the inspectors requested information regarding the licensees reliance and use of post-fire OMAs that may have not been approved by the NRC in SSERs 18 or 19. In SSER 18, the NRC approved certain post-fire OMAs used to compensate for fire-induced equipment failures. The licensee calculation WBN-OSG- 165, Rev. 5, Manual Actions Required for Safe Shutdown Following a Fire, which was referenced in SSER 18, section 3.5, identified OMAs credited for achieving and maintaining safe shutdown conditions for certain fire events. In this calculation, the licensee identified the OMAs which needed to be accomplished to achieve safe shutdown, established time requirements to accomplish these OMAs, and quantified expected completion times for performance of these OMAs. The licensee credited the use of Abnormal Operating Instruction (AOI 30.2) as its post-fire safe-shutdown procedure per SSER 18, section 3.5.1, Safe-Shutdown Procedures and Manpower. The inspectors identified at least two instances, one onsite and one in-office, where OMAs were not listed in the calculation WBN-OSG-165, Rev. 5. In the first instance, inspectors reviewed credited post-fire operator actions implemented in AOI 30.1, Plant Fires, Rev. 9, Step 5, and AOI 30.2, Fire Safe Shutdown, Rev. 27, Step 10. The inspectors found that these actions did not appear to have been analyzed in Rev. 5 of calculation WBN-OSG-165. Therefore, these OMAs may not have been reviewed and approved by the NRC. These actions were brought to the licensees attention October 6, 2010. The licensee provided an initial response to NRC questions related to these actions on October 7, 2010. Based upon NRC comments, the licensee provided additional information to the inspectors related to these OMAs on December 6, 2010. On December 22, 2010, based upon these responses and review of information, the NRC inspectors requested the licensee to provide a list of all OMAs implemented in lieu of meeting 10 CFR Part 50, Section III.G.2, after SSER 18 was issued, as well as the supporting analyses. After several conference calls, on April 5, 2011, the licensee provided a spreadsheet titled, Watts Bar Nuclear Plant Manual Operator Actions (MOAs) Developed For and After Revision 6 of Calculation WBN-OSG4-165 (06/30/1995). The licensee stated that information provided included the list of all OMAs implemented after issuance of SSER 18. The inspectors reviewed the information and found that the OMAs identified during the onsite portion of the inspection were not included, nor did the list include the associated evaluations. On April 15, 2011, as a result of NRC review and additional questions, the licensee stated that some of the OMAs they listed in their April 5, 2011, response were added June 6, 1995, before Rev. 5 of calculation WBN-OSG-165 and SSER 18 was issued. On a follow-up call to the license conducted June 13, 2011, licensee personnel stated the OMAs identified in AOI 30.1, Plant Fires, Rev. 9, Step 5, and AOI 30.2, Fire Safe Shutdown, Rev. 27, Step 10 were done so in response to NRC Information Notice (IN) 89-52, Potential Fire Damper Operational Problems. In the second instance, the inspectors identified seven OMAs which appeared to be added after WBN-OSG-165, Rev. 5. This was based upon the review of information provided to inspectors on April 5, 2011. The inspectors determined that Rev. 5 of calculation WBN-OSG-165 became effective May 3, 1995, and the seven OMAs were added June 30, 1995. On June 13, 2011, the inspectors conducted a follow-up call with the licensee and were provided additional information. Specifically, licensee personnel stated that the seven OMAs were added via a design change before SSER 18 was issued to the licensee in October 1995; however, were not included in calculation WBNOSG- 165. The licensee personnel stated these additional OMAs were added to the FPR in revisions 3 & 4. Pending review of this additional information, this issue will remain open as unresolved item (URI) 05000390/2010007-001, Use of OMAs Potentially Not Consistent with the Fire Protection Licensing Basis. |
| 05000390/FIN-2010007-02 | 2010Q4 | Watts Bar | INSTALLED INSULATING FLUID IN INTERIOR TRANSFORMERS POTENTIALLY DEVIATES FROM LICENSE/DESIGN CRITERION IN SSER 10 AND POSITION D.1.g OF APPENDIX A TO BTP (APCSB) 9.5-1 | The inspectors opened an URI related to questions regarding the licensees compliance with all provisions of their NRC-approved FPP. Specifically, the inspectors raised questions regarding the dielectric insulating liquid used for indoor power transformers as specified Appendix FF, Section 5.10.2 of SSER 18 and NRC Position D.1.g of Appendix A to BTP APCSB 9.5-l, Guidelines for Fire Protection for Nuclear Power Plants, dated August 23, 1976. Fire Area FA 37 (AV-064) contained four liquid-insulated 6.9kV to 480V shutdown board transformers, in groups of two inside containment curbs. These medium voltage transformers were insulated with a silicone-type dielectric insulating fluid. Three of the four transformers (1-OXF-212-A2-A, 1-OXF-212-A1-A, and 1-OXF- 212-A-A) contained an estimated 317 gallons of insulating fluid and the other transformer (0-OXF-206-A) contained approximately 205 gallons. Near these transformers were combinations of redundant safety-related cable trays or conduits or both. While performing the review of FA 37 (AV-064), the inspectors identified the indoor power transformers dielectric insulating liquid was not consistent with that described in SSER 18, section 5.10.2, Askarel-Insulated Transformers and NRC Position D.1.g of Appendix A to (BTP) APCSB 9.5-l, Guidelines for Fire Protection for Nuclear Power Plants. Section 5.10.2 of SSER 18 specified that indoor transformers would be either a dry type or insulated with non-combustible liquid. Section 5.10.2 of SSER 18 further stated that Askarel was used as the noncombustible liquid for indoor transformers. The inspectors determined that the SSER reference was based on transformer insulating liquid being noncombustible material (negligible combustible loading) which did not represent an ignition source. However, during the inspection the inspectors found that the transformers in FA 37 did not contain the specified dry type or non-combustible dielectric insulating material, but were insulated with a silicon-based combustible dielectric liquid. Furthermore, Position D.1.g. (ii) of Appendix A to (BTP) APCSB 9.5-l specified that safety related systems that are exposed to flammable oil-filled transformers should be protected from the effects of a fire by enclosing the transformer with a three-hour fire barrier and installing an automatic water spray protection. The transformers had not been enclosed with such a barrier. The inspectors reviewed Part VI of the WBN FPR (Revision 39) and found that the fire rating of the regulatory barriers for the floor and walls in FA 37 was two-hours. The inspectors also reviewed WBN FPR, Part 1, Table 1-1, Summary of Fire Protection Conformance, (Revision 27) which specified that safe shutdown equipment cables were located in FA 37 and were protected with a credited one-hour rated fire resistive wrap. Table 1-1 of the FPR also identified that the area total fixed combustible load fire severity for a 3-hour rated barrier was classified as Moderately Severe, e.g., less-than 240,000 Btu/ft2. The inspectors reviewed the combustible loading summary calculationEPM-DOM-012990, (Revision 41) for FA 37 and found that the fuel load in the area was 164,549 Btu/ft2, which exceeded the 2-hour rated barrier criteria of 160,000 Btu/ft2. Additionally, the review of WBN FPR, Part VII, Deviations and Evaluations, (Revision 10) noted that the licensees evaluation for deviation 2.4 concerning intervening combustibles did not specifically consider the transformers in the area (insulated with a combustible dielectric liquid) as a potential intervening combustible located between redundant components. The licensee was not able to provide a documented technical evaluation which justified the use of the combustible dielectric insulating liquid and its associated contribution to the area combustible load fire severity or intervening combustible evaluation. In response to the inspectors questions, the licensee stated that, although SSER 18 did address Askarel oil, no additional evaluations of the type of oil used in indoor transformers was required since the SSER did not reflect the latest information provided by TVA in Revisions 4 and 5 of their FPR submitted to NRC on September 28, 1995, and November 1, 1995, respectively. The licensee stated that these submittals identified that transformers installed within safetyrelated buildings are either dry-type or insulated and cooled with high fire point (650F) liquid. Based upon the review of the WBN FPR and EPM-DOM-012990, the inspectors concluded that the transformers in the area (insulated with a combustible dielectric liquid) contributed to a total fixed fuel load fire severity that exceeded the credited fire resistive rating of the room fire barriers and could potentially challenge either the credited one-hour barrier for the safety related cables, the walls separating the adjacent FAs or both. The inspectors discussed this issue further with licensee personnel on June 13, 2011 during a teleconference. The licensee personnel stated they would provide additional information related to questions raised by inspectors regarding when the change to the combustible dielectric was made. Based upon questions raised by the inspectors, 40 additional indoor transformers were identified in Unit 1 and areas of Unit 2 (under construction) to have the same combustible dielectric liquid and located within ten (10) additional AVs (AV-1, AV-51, AV-63, AV-64, AV-68, AV-69, AV-89, AV-94, AV-95, and AV-96) at WBN. The licensee initiated service request (SR) 263312 and problem evaluation report (PER) 265331 to address the issues described in this section. Further review and consultation with NRC experts in the Office of Nuclear Reactor Regulation will be needed to determine the regulatory impacts of this issue. As a result, this issue is identified as URI 05000390/2010007-002, Installed Insulating Fluid in Interior Transformers Potentially Deviates from License/Design Criterion in SSER 18 and Position D.1.g of Appendix A to BTP (APCSB) 9.5-1. |
| 05000390/FIN-2010007-03 | 2010Q4 | Watts Bar | Questions Related to OMA to Establish RCP Seal Cooling in the Event of a Fire in AV-076, Computer Room | The inspectors opened an URI involving an OMA credited for establishing (RCP) seal cooling. Specifically, a hand-wheel on a valve required by procedure to be closed in the event of a fire in the control building, FA 48 (AV-076), was missing. The licensee maintained that the action, if not performed, would not have an effect on their ability to achieve and maintain safe shutdown. This item is pending further inspector review. In the event of a fire in AV-076, procedure AOI-30.2 C69, Fire Safe Shutdown Control Building, directed operators to establish RCP seal injection via air-operated valve 1-FCV-62-93. While performing a field walk-down of procedure AOI-30.2 C69, the inspectors identified that Step 4 of Auxiliary Unit Operator Checklist 1 could not be completed as directed, because the hand wheel for valve 1-ISV-32-2934 was missing. Valve 1-ISV-32-2934 is a manual air isolation valve on a 34 inch airline to air-operated valve 1-FCV-62-93. The procedure directed the operator to close valve 1-ISV- 32-2934 to isolate air to valve 1-FCV-62-93, and open the petcock on the regulator for valve 1-FCV-62-93 to bleed off the air, which forced valve 1-FCV-62-93 to fail open. This would allow charging flow to the RCP seals to be controlled by the seal water injection filter via a series of manually-operated valves. This would also provide makeup to the RCS since the primary injection path would be isolated. The inspectors identified that the last time valve 1-ISV-32-2934 was operated was on February 23, 2008, per Work Order WO 07-816218-000. The licensee staff initially told the NRC inspectors that this manual action was not required for SSD. Inspectors requested an evaluation of the impact of the failure to perform this manual action on the ability to achieve and maintain SSD. Upon identification of the missing hand-wheel on October 8, 2010, the licensee initiated Service Request SR-262219 to replace the missing hand-wheel. On October 20, 2010, the inspectors requested a copy of the corrective action documents for the missing hand-wheel, and were told that the service request had been closed to a work order which was still open. As a result, the hand-wheel had not been replaced. The licensee informed the inspectors that in accordance with their corrective action program, a PER should have been initiated for this issue. The licensee then initiated SR 269706 to address the failure to write a PER and untimely replacement of the hand-wheel. The hand-wheel was replaced by licensee staff on October 30, 2010, per WO 11524638. The licensee had not established compensatory measures for the time period the hand wheel was missing, because tools were available in an Operations personnel cabinet for individuals to use. However, the need to obtain the necessary tools to manually close valve 1-ISV-32-2934 was not discussed in procedure AOI-30.2 C69 or evaluated to determine if extra time was available to obtain the tools. On October 22, 2010, inspectors requested information on the effect on SSD if the action was not completed successfully, the fire areas where the action was credited, and the design basis impact if the RCP seal cooling flow criteria was not met. The licensee staff provided a response to the inspectors on November 8, 2010, in which they indicated that RCP seal injection flow rates would be adequate without closing valve 1-ISV-32-2934. As a result of reviewing this information the inspectors requested additional information regarding seal injection flow rates and the effect on the pressurizer. The licensee provided additional information to NRC on December 1, 2010. A conference call with the licensee was conducted on February 24, 2011, to discuss a discrepancy between the licensees November 8, 2010, response and calculation WBNOSG4- 031. On March 24, 2011, the licensee provided clarifying information to the inspectors related to this issue. Pending NRC review of all information this issue is identified as URI 05000390/2010007-003, Questions Related to OMA to Establish RCP Seal Cooling in the Event of a Fire in AV-076, Computer Room. |
| 05000335/FIN-2009007-01 | 2009Q1 | Saint Lucie | Failure to Correct Conditions Adverse to Quality | The team identified two examples of a non-cited violation of St. Lucies Unit 1 and Unit 2 Renewed Operating License Conditions 3.E for the licensees failure to promptly correct conditions adverse to quality. The first example involved failure to take prompt corrective action for a noncompliance that was identified during the 2006 triennial fire protection inspection (Inspection Report 05000335, 389/2006010). Specifically, the licensee did not implement corrective actions to perform surveillance tests on the Unit 1 eight-hour battery powered portable emergency lights. The second example identified by the team during the 2009 inspection, involved four eight-hour battery powered fixed emergency lights that failed an annual surveillance test and were not repaired or replaced. The licensee initiated Condition Reports 2009-4010, -4056 and -4220 to implement corrective actions to address these issues. The licensees failure to correct the above conditions adverse to quality involving fire protection, as required, was a performance deficiency. The finding is more than minor because it is associated with the reactor safety, mitigating systems, cornerstone attribute of protection against external factors (i.e., fire) and it affects the objective of ensuring reliability and capability of systems that respond to initiating events. The team determined that this finding was of very low safety significance (Green) because the operators had a high likelihood of completing the task using flashlights. This performance deficiency is associated with the cross-cutting area: Human Performance, Work Control: H.3(b). The finding was directly related to the licensee not planning and coordinating work activities to support long-term equipment reliability and their maintenance scheduling was more reactive than preventive. |
| 05000335/FIN-2009007-02 | 2009Q1 | Saint Lucie | Passive Fire Protection | St. Lucie Unit 1 and 2 License Conditions 3.E states, in part, that the licensee shall implement and maintain in effect all provisions of the approved FPP as described in the UFSAR, and supplemented by licensee submittals dated through February 21, 1985 for the facility; and as approved in the various NRC SERs and supplements. The approved FPP is maintained and documented in the St. Lucie UFSAR, Appendix 9.5A, FPP Report. PSL FSAR Appendix 9.5A, subsection 3.12.2, Design Basis, specifies that fire doors are designed and constructed in accordance with the requirements of NFPA 80. Per the code of record, NFPA-80 1973 Edition, Paragraph 2-1.7.2.1, specifies that only labeled locks and latches or labeled fire exit hardware (panic devices) meeting both life safety requirements and fire protection requirements shall be used. Paragraph 2-1.7.2.4 specifies that where the inactive leaf pairs of doors are not required for exit purposes, it shall be provided with labeled selflatching top and bottom bolts or labeled two-point latches. Paragraph 2-1.7.2.5 specifies that the throw of single point latch bolts shall not be less than the minimum shown on the fire door label. If the minimum throw is not shown or the door does not bear a label the minimum throw shall be as required in Table 2-1B. Table 2-1B, for hollow metal (flush) doors (doors in pairs), requires an active leaf minimum latch throw of 34 with top and bottom bolts on the inactive leaf. Paragraph 2-1.7.7.1, specifies that self-closing doors are those which, when opened, return to the closed position. The door shall swing freely and shall be equipped with a closing device to cause the door to close and latch each time it is opened. The closing mechanism shall not have a hold-open feature. Contrary to the above, on February 12, 2009, the team identified that the licensee failed to implement and maintain in effect all provisions of the approved fire protection program. Specifically, the inspectors determined that the licensee had failed to install Fire Doors RA48, RA93, and RA110 in accordance with the applicable requirements of NFPA-80, Fire Doors & Windows 1973 Edition, Paragraphs 2-1.7.2.1, 2-1.7.2.4, 2- 1.7.2.5, and 2-1.7.7.1. Pursuant to the Commissions Enforcement Policy and NRC Manual Chapter 0305, under certain conditions fire protection findings at nuclear power plants that transition their licensing bases to 10 CFR 50.48(c) are eligible for enforcement and ROP discretion. The Enforcement Policy and ROP also state that the finding must not be evaluated as Red. On December 22, 2005, the licensee submitted a letter to the NRC stating its intent to transition to 10 CFR 50.48(c). Because the licensee committed, prior to December 31, 2005, to adopt NFPA 805 and change their fire protection licensing bases to comply with 10 CFR 50.48(c), the NRC is exercising enforcement discretion for this issue in accordance with the NRC Enforcement Policy, Interim Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48). Specifically, this issue would have been expected to be identified and addressed during the licensees transition to NFPA 805, was entered into the licensees corrective action program and will be corrected, was not likely to have been previously identified by routine licensee efforts, was not willful, and was not associated with a finding of high safety significance (Red). |
| 05000335/FIN-2009007-03 | 2009Q1 | Saint Lucie | Post-Fire Safe Shutdown From Outside the Main Control Room (Alternative Shutdown) | Technical Specification 6.8.1.a. requires that written procedures shall be established, implemented, and maintained covering the activities in Appendix A of Regulatory Guide 1.33, Revision 2, dated February 1978. Regulatory Guide 1.33, Appendix A, Section 6.v., requires procedures for combating emergencies such as plant fires. Procedure 2-ONP-100.02, Control Room Inaccessibility, Rev. 22, provided instructions for placing St. Lucie Unit 2 in a safe condition if operations could not be performed from the MCR due to a fire in the MCR. Contrary to the above, on February 12, 2009, the team identified that procedure 2-ONP- 100.02, Control Room Inaccessibility, provided inadequate guidance. Specifically, the procedure did not identify that personnel fall protection safety equipment and additional keys were required for performance of certain operator manual actions to support operation from the HSCP during post-fire SSD conditions. The licensee initiated CRs 2009-2590 and 2009-2592 to address this issue. Pursuant to the Commissions Enforcement Policy and NRC Manual Chapter 0305, under certain conditions fire protection findings at nuclear power plants that transition their licensing bases to 10 CFR 50.48(c) are eligible for enforcement and ROP discretion. The Enforcement Policy and ROP also state that the finding must not be evaluated as Red. On December 22, 2005, the licensee submitted a letter to the NRC stating its intent to transition to 10 CFR 50.48(c). Because the licensee committed, prior to December 31, 2005, to adopt NFPA 805 and change their fire protection licensing bases to comply with 10 CFR 50.48(c), the NRC is exercising enforcement discretion for this issue in accordance with the NRC Enforcement Policy, Interim Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48). Specifically, it was likely this issue would have been identified and addressed during the licensees transition to NFPA 805, it was entered into the licensees corrective action program and will be corrected, was not likely to have been previously identified by routine licensee efforts, was not willful, and was not associated with a finding of high safety significance. |
| 05000400/FIN-2008008-02 | 2008Q4 | Harris | Post-Fire Safe Shutdown From Outside the Main Control Room (Alternative Shutdown) | The team identified a noncompliance of very low safety significance with Shearon Harris Technical Specification 6.8.1.a, for inadequate procedural guidance which directed usage of instruments that were not protected from fire damage in FZ 12- A-6-PICR1. Specifically, procedure AOP-004, Remote Shutdown, directed the operators to verify emergency service water (ESW) header flows were above the minimum flow requirement of 7500 gpm using flow indicators (FI) FI-9101A2 and FI-9101B2. These instruments would be unreliable during operation from the ACP because their cables were routed through the FZ of concern and the cables were not protected from fire damage. The violation meets the criteria of NRC Enforcement Policy, Interim Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48) for enforcement discretion. The team noted that procedure AOP-004, Remote Shutdown, would be used to safely shut down the plant from the ACP (utilizing Train B equipment) for a fire in FZ 12-A-6-PICR1. The procedure directed operators to verify ESW header (HDR) flows using FI-9101A2, A HDR Flow and FI-9101B2, B HDR Flow. The team reviewed cable routing data and noted that FI-9101A2 and FI-9101B2 may not provide reliable ESW flow indication for the operators at the ACP because the cables were routed through FZ 12-A-6-PICR1 and were not protected from fire damaged. This may potentially delay operator actions required to bring the plant to SSD conditions. Based on discussions with operations personnel and review of service water system simplified flow diagrams, the team determined that the ESW system was flow balanced to ensure that the 7500 gpm minimum flow would be provided to ESW HDR A and ESW HDR B. During walkdowns of the ACP, the team noted that valve position indication (i.e., open/close) was provided at the ACP for various ESW valves, including 1SW-270, HDR A to Auxiliary Reservoir and 1SW-271, HDR B to Auxiliary Reservoir. These valves were required to be opened (from the ACP) to ensure adequate ESW header flow. Review of cable routing data for valve 1SW-271 showed that this valve was not routed through FZ 12-A-6-PICR1 and would not be affected by a postulated fire in this FZ. The team determined that, based on operator experience, training, and indication of the position of ESW valve 1SW-271 at the ACP, it was likely plant operators would be able to determine that sufficient ESW flow was available and they would take the appropriate actions required to ensure post-fire SSD conditions. The licensee initiated NCR 298072 to address this issue in the CAP. |
| 05000400/FIN-2008008-01 | 2008Q4 | Harris | Sprinkler System in Cable Spreading Room A Does Not Meet Licensee\'s Fire Protection Program Requirements | The team identified a non-cited violation of Shearon Harris Unit 1 operating license condition 2.F, for the licensees failure to install the sprinkler system in Cable Spreading Room A (CSRA) in accordance with the approved fire protection program (FPP). Specifically, the installed system would not have been able to deliver the sprinkler system design density of 0.3 gallons per minute/square foot in CSRA, as stated in the FPP in Updated Final Safety Analysis Report Section 9.5.1.2.3. The licensee entered this issue in the corrective action program and established a continuous fire watch in CSRA as a compensatory measure in accordance with the Shearon Harris FPP. The licensees failure to install the sprinkler system in CSRA in accordance with the approved FPP is a performance deficiency. This finding is more than minor because the installed sprinkler system degraded one of the fire protection defense in depth elements and it affected the reactor safety Mitigating Systems cornerstone objective. The team completed a Phase 2 screening of the finding in accordance with IMC 0609, Appendix F, Attachment 1, Part 2, Fire Protection SDP Phase 2 Worksheet, and concluded that the finding was of very low safety significance (Green), in accordance with Step 2.5, Task 2.5.5 of the Worksheet, because there was a safe shutdown path available which was independent of CSRA. The cause of this finding was not associated with a cross-cutting area because it is not reflective of current licensee performance. (Section 1R05.04 |
| 05000335/FIN-2008006-01 | 2008Q3 | Saint Lucie | Licensee-Identified Violation | 10 CFR Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, and drawings. On December, 27, 2007, operations Component Cooling Water (CCW) system valve, TCV-14-4B failed its quarterly stroke time surveillance. The cause of this failure was attributed to the installation of an o-ring not designed for the application. This installation of an unapproved o-ring was a deviation from the requirements of site procedure QI-8-PR/PSL-1. This violation is of very low safety significance because it did not result in actual loss safety function for the B Train ICW for greater than its Technical Specification allowed outage time. |
| 05000335/FIN-2008008-01 | 2008Q3 | Saint Lucie | Licensee-Identified Violation | 10 CFR Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, and drawings. On December, 27, 2007, operations Component Cooling Water (CCW) system valve, TCV-14-4B failed its quarterly stroke time surveillance. The cause of this failure was attributed to the installation of an o-ring not designed for the application. This installation of an unapproved o-ring was a deviation from the requirements of site procedure QI-8-PR/PSL-1. This violation is of very low safety significance because it did not result in actual loss safety function for the B Train ICW for greater than its Technical Specification allowed outage time |
| 05000327/FIN-2008006-02 | 2008Q2 | Sequoyah | Sprinkler System in Room 690.0-A1 of the Auxiliary Building has NFPA Code Deviation | The team observed a number of water suppression sprinkler heads in the eastern portion of the Auxiliary Building Elev. 690 (Room 690.0-A1, Fire Area FAA-029) that were located approximately six feet below the ceiling. These sprinkler heads are part of an NFPA 13 preaction sprinkler system which requires that the sprinkler heads in this area be no more than 12 inches below the ceiling. The sprinkler system in this area would not be effective in a response to a fire since the time delay to fuse any particular sprinkler head could be significant due to the location of the sprinkler heads. This portion of the sprinkler system does not meet the requirements of NFPA 13 and the licensee could not produce an evaluation or analysis that demonstrated the capability of this system to adequately control a potential fire in this area. However, the licensee claimed that the installation had been previously approved by the NRC; therefore, considered the system non-degraded. They did, however, initiate a Problem Evaluation Report (PER) to evaluate the condition. In order to determine all the facts concerning the licensing basis of the system and to review the potential acceptability of the as-built system with its code deviation an URI was established: URI 05000327, 328/2008006-02, Sprinkler System in Room 690.0-A1 of the Auxiliary Building has NFPA Code Deviation |