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| Quarter | Site | Title | Description | |
|---|---|---|---|---|
| 05000250/FIN-2005010-01 | 2005Q4 | Turkey Point | Unprotected Post-Fire Safe Shutdown Cables and Related Non-feasible Local Manual Operator Actions | An apparent violation (AV) of 10 CFR 50, Appendix R requirements was identified for failure to: 1) protect the control circuit of motor operated valve (MOV) MOV-4-626, Reactor Coolant Pump (RCP) Thermal Barrier Component Cooling Water (CCW) Return Isolation Valve and to prevent its spurious operation during a fire in fire zone (FZ) 67; 2) ensure that local manual operator actions used to verify correct alignment of MOV-3-716A and MOV-4-716A, RCP Thermal Barrier CCW Supply Isolation Valves and MOV-3-626 were completed in a timely manner for fires in either FZ 63 or FZ 67; and 3) ensure local manual operator actions to verify correct alignment of valves MOV-3-716A and MOV-4-716A were completed in a timely manner for a fire in FZ 106. These conditions could result in an RCP seal loss of coolant accident (LOCA). Pursuant the safe shutdown analysis report (SSAR), thermal barrier cooling is the assured method for protecting the RCP seals during a severe fire in FZ 67 because charging pump seal injection flow may be terminated by operator action or lost due to the fire. Valve MOV-4-626 is a motor operated valve in the thermal barrier CCW header returning from all three Unit 4 RCPs. The valve can be controlled from either the main control room (MCR) (FZ 106) or the alternate safe shutdown panel (ASP) (which is located in the 4B 4160V switchgear room (FZ 67)). Because the control cable for this valve terminates at the ASP and the cable is unprotected, thermal insult to the control circuit for the valve could cause it to spuriously close. Closure of the valve would stop thermal barrier cooling return flow from all three Unit 4 RCPs. Guidance in 0-ONOP- 016.10, Pre-fire Plan Fire Zone 67, directs local manual operator actions to prevent, or recover from, spurious closure of MOVs that could interrupt thermal barrier cooling. For FZ 67, thermal barrier cooling valves MOV-4-716B and MOV-4-626 could be subject to spurious operation but the inspectors found that MOV-4-626 was not included in the procedure. On September 9, 2003, the licensee identified an error in the safe shutdown analysis (SSA) Essential Equipment List. They found that valve MOV-4-626 was not properly classified as being required to assure safe shutdown (SSD). As a result, the fire response procedure failed to include MOV-4-626 as part of the mitigation strategy against spurious valve operation. The issue was entered into the licensees corrective action program (CAP) as condition report (CR) 03-1330-1. The need to review and update 0-ONOP-016.10 was entered into the CAP as CR 04-0292; but this deficiency was not resolved prior to the inspection. During the inspection, the licensee resolved this concern by issuing an on-the-spot-change to 0-ONOP-016.10 which specified manual actions to de-energize and verify open MOV-4-626. The licensee documented this action in its CAP as CR 04-0610. Thermal barrier cooling is also the assured method for protecting the RCP seals during a severe fire in FZ 63 because charging pump seal injection flow may be terminated by operator action or lost due to the fire. In lieu of protecting the control circuits and cables for the RCP thermal barrier cooling valves (MOV-3-716B and MOV-3-626 in FZ 63; and MOV-4-716B in FZ 67), guidance in 0-ONOP-016.10 directed local manual operator actions to prevent, or recover from, spurious closure of the MOVs. When evaluating the feasibility of the manual actions using the guidance in NRC inspection procedure (IP) 71111.05T, Fire Protection (Triennial), the inspectors identified that procedure 0-ONOP- 016.10 allowed 20 minutes to complete the operator actions for verification of thermal barrier cooling valve alignment. However, industry analyses (Westinghouse Direct Work No. DW-94-011; Westinghouse WCAP-10541, Revision 2; and Westinghouse WCAP- 15603, Revision 1-A) have determined that seal package damage could occur within 13 minutes of loss of all seal package cooling. Thus, the operator guidance provided in procedure 0-ONOP-016.10 does not provide timely action and could result in an RCP seal LOCA. Loss of reactor coolant system (RCS) inventory due to an RCP seal LOCA could be beyond the capacity of equipment dedicated to achieve and maintain post-fire safe shutdown. The licensee entered the finding into its CAP as CR 04-0688 and resolved this concern by revising procedure 0-ONOP-016.10. Fire Area (FA) MM includes the MCR, the MCR roof, and the Unit 3 and 4 mechanical equipment room. Per the SSAR, thermal barrier cooling is the assured method for protecting the RCP seals during a severe fire in FA MM because charging pump seal injection flow may be terminated by operator action or lost due to the fire. Guidance in procedure 0-ONOP-105 directs local manual operator actions to prevent, or recover from, spurious closure of MOVs that could interrupt thermal barrier cooling. The inspectors identified that 0-ONOP-105, Attachment 7 (Unit 3) and Attachment 8 (Unit 4) allowed 20 minutes to complete the operator actions for verifying that MOV-3-716A and MOV-4-716A were open. However, industry analyses (Westinghouse Direct Work No. DW-94-011; Westinghouse WCAP-10541, Revision 2; and Westinghouse WCAP- 15603, Revision 1-A) have determined that seal package damage could occur within 13 minutes of loss of all seal package cooling. Thus, the operator guidance provided in procedure 0-ONOP-105 does not provide timely action and could result in an RCP seal LOCA. Loss of RCS inventory due to an RCP seal LOCA could be beyond the capacity of equipment dedicated to achieve and maintain post-fire safe shutdown. The licensee entered the finding into its CAP as CR 04-0688 and resolved this concern by revising procedure 0-ONOP-105. |
| 05000259/FIN-2007003-01 | 2007Q2 | Browns Ferry | Reactor Core Isolation Cooling System Loss of Configuration Control | The inspectors identified an unresolved item (URI) involving a mispositioned and faulted switch on the 1C 250 VDC Reactor Motor-operated Valve (RMOV) Board used for Unit 1 RCIC operation from outside the main control room. Description: On June 15, while conducting a system alignment walkdown, inspectors found two out-of-position RCIC barometric condenser pump emergency handswitches on the 1C 250 VDC RMOV Board with respect to the 1-OI-71, Reactor Core Isolation Cooling System, Attachment 2, Panel Lineup Checklist. Both handswitches were found in the STOP position versus the required START position per the checklist. To address this problem, the licensee initiated PER 126345. The specific handswitches in question were: 1-HS-71-31C, RCIC Vacuum Pump 1-HS-71-29C, RCIC Vacuum Tank Condensate Pump Upon notification of the mispositioned switches, Operations commenced an independent performance of 1-OI-71, Attachment 2, RCIC Panel Lineup Checklist which would reposition the above handswitches in addition to verifying all other RCIC panel components. While performing this checklist, operators discovered that the RCIC Barometric Condenser Vacuum Pump Backup Control Switch, 1-HS-71-31C, on the 1C 250 V RMOV Board, was mechanically bound in the STOP position. The licensee initiated Work Order (WO) 07-719158-000 to repair the switch and PER 126352 to document an unplanned 30-day LCO entry into Technical Specification 3.3.3.2.A.1 for an inoperable backup control system function of the RCIC Barometric Condenser Vacuum Pump. After further review, Operations also discovered a difference between the 1-OI-71, Attachment 2 checklist and the Monthly Emergency Control Switch Verification 0-GOI- 300-1, Operator Round Log, Attachment 15.12, Monthly Emergency Control Switch Verification - Unit 1, which had placed the aforementioned handswitches in the STOP position. The inspectors verified that the correct switch positions were START, as required by 1-OI-71, Attachment 2. The licensee initiated Procedure Change Request (PCR) 07002587 to correct the GOI-300-1 attachment. In evaluating the implications of past operability of the Unit 1 RCIC system given the mispositioned switches (one of which was faulted), the inspectors first reviewed drawings and wiring schematics to verify that the emergency control handswitches in question would not have adversely impacted the RCIC pump automatic and manual control circuit when other emergency control handswitches in the circuit, separate switches from those in question, were in the NORMAL position. Based on this review, the inspectors concluded that the mispositioned switches would not have adversely affected RCIC pump automatic operation, or manual operation from the main control room (MCR). However, with the emergency control handswitches in EMERGENCY, the Start/Stop handswitches in question would be in the control circuits. Therefore, the inspectors examined whether the RCIC system would be capable of performing its safety function during an event necessitating MCR abandonment (requiring th emergency control handswitches in EMERGENCY) with a loss of the RCIC Vacuum Pump due to the faulted switch. In particular, the inspectors needed additional information from the licensee in order to determine whether a sufficiently high temperature environment (turbine gland seals and valve packing exhausting to the RCIC room) could be created that would cause an automatic isolation of the RCIC System steam supply thereby rendering RCIC inoperable. In order to fully assess the enforcement implications and safety significance of this issue, additional information from the licensee will be needed. Consequently, pending the receipt of additional information and further review by the NRC (e.g., determination of the safety significance), this issue will be identified as URI 05000259/2007003-01, Reactor Core Isolation Cooling System Loss of Configuration Control. |
| 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. |
| 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). |
| 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-2016011-03 | 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-2016011-04 | 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-2016011-05 | 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-2016011-06 | 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. |
| 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-2016011-08 | 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-2016011-09 | 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-2016011-10 | 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-2016011-11 | 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-2016011-12 | 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-2016011-13 | 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. |
| 05000302/FIN-2008006-01 | 2008Q1 | Crystal River | Failure to Control Transient Combustibles | The team identified a non-cited violation of Crystal River Unit 3 Operating License Condition 2.C.(9), for the licensees failure to properly implement fire protection program procedures for control of transient combustible materials. Specifically, transient combustible materials were left unattended for four days in the 3B 480V ES Switchgear Room after work had been completed, which was a violation of the licensees administrative procedures for control of transient combustibles. Once identified, the licensee removed the combustible materials and initiated a nuclear condition report to address the issue. The finding is more than minor because the transient combustible materials presented a credible fire scenario involving equipment important to safety, which degraded the reactor safety Initiating Events cornerstone objective to limit the likelihood of those events that may upset plant stability and challenge critical safety functions. The amount of unattended transient combustible materials did not violate the licensees transient combustible control limits for the fire area. Therefore, the finding was assigned a low degradation rating against the combustible controls program. The finding was of very low safety significance (Green) based on the low degradation rating. This finding has a cross-cutting aspect in the Work Practices component of the Human Performance area because the licensee failed to effectively communicate expectations regarding procedural compliance and personnel following procedures (NRC Inspection Manual Chapter 0305, H.4(b)) |
| 05000302/FIN-2008006-02 | 2008Q1 | Crystal River | Failure to Adequately Protect Cables for Valve DHV-42 | The team identified a non-cited violation of 10 CFR 50, Appendix R, Section III.G.2., for failure to protect cables from fire damage for components required for safe shutdown. Specifically, the Mecatiss MTS-3 fire wrap installed around the cables for valve DHV-42 (suction from the reactor building sump to the Train A decay heat pump) was not installed in accordance with the vendors tested configuration. The licensee initiated a nuclear condition report and implemented an hourly roving fire watch to address this issue. Additionally, the licensee implemented repairs during the March 2008 forced outage to upgrade the Mecatiss MTS-3 fire wrap to comply with the vendor tested configuration. This finding is more than minor because it is associated with the external factors attribute, i.e., fire, and it degraded the reactor safety Mitigating Systems cornerstone objective. The inspectors completed a Phase 1 screening of the finding in accordance with IMC 0609, Appendix F, Attachment 1, Step 1.3, Qualitative Screening Approach, and concluded that the finding, when given credit for the fixed automatic suppression system in the area, was of very low safety significance (Green) |
| 05000302/FIN-2008006-03 | 2008Q1 | Crystal River | Evaluate Opening Access Hatch to Cable Spread Room | The team identified an unresolved item (URI) related to the licensees compliance with the CR-3 operating license condition 2.C.(9) and the approved FPP when the access hatch from the MCR floor to the CSR was opened on more than one occasion for maintenance troubleshooting activities. The team reviewed NCR 264494 which the licensee initiated in response to questions from the NRC resident inspectors who observed the access hatch from the MCR floor to the CSR was open and there did not appear to be any compensatory measures in place. The NCR stated that the licensee opened the access hatch between the MCR floor and the CSR to perform battery ground troubleshooting activities. The team questioned if this activity potentially degraded the CSR Halon suppression system. With the hatch open, the team questioned the capability of the Halon suppression system to meet the licensing basis requirement to maintain a 5% Halon concentration for 10 minutes in the event of an Appendix R fire in the CSR. The team also questioned if the licensee performed an evaluation to determine the impact of the hatch being open on the CSR Halon suppression system and to determine if compensatory measures were needed. As a result of questions raised by the team during the inspection, the licensee initiated NCR 266356 to evaluate the impact on the operability of the CSR Halon suppression system with the MCR access door hatch open. The team requested additional information from the licensee regarding the amount of thermoplastic cables in the CSR, how many times and the duration each time the hatch was opened for maintenance troubleshooting in the past year. The licensee provided the requested information to the team and the information is currently being reviewed. The team informed the licensee that this issue will be identified as an URI pending further NRC review of the requested information. This item will be tracked as URI 05000302/2008006-03, Evaluate Opening Access Hatch to Cable Spread Room |
| 05000302/FIN-2008006-04 | 2008Q1 | Crystal River | Reactor Coolant Pump 1B Lube Oil Collection System Leakage | A self-revealing non-cited violation of 10 CFR 50, Appendix R, Section III.O, was identified for failure of the reactor coolant pump (RCP) oil collection system to collect and drain RCP oil leakage to a vented closed container. Specifically, the licensee found an estimated one to two gallons of oil on the reactor building floor beneath RCP-1B. The licensee initiated a nuclear condition report for this issue. This finding is more than minor because it is associated with the external factors attribute, i.e., fire, and it degraded the reactor safety Initiating Events cornerstone objective. The team completed a Phase 1 screening of the finding in accordance with IMC 0609, Appendix F, Attachment 1, Step 1.3, Qualitative Screening Approach, and concluded that the finding was of very low safety significance (Green) because the amount of oil identified in 2008 was bounded by the licensees 2004 analysis (which assumed a 21 gallon oil leak). This finding has a cross-cutting aspect in the Corrective Action Program component of the Problem Identification and Resolution area because the licensee did not take appropriate corrective actions in a timely manner to address the adverse trend related to oil leakage for RCP-1B (NRC Inspection Manual Chapter 0305, P.1(d)) |
| 05000302/FIN-2008006-05 | 2008Q1 | Crystal River | Design Oversight Results in 10 CFR 50, Appendix R, Cable Separation Criteria Not Met | The problem described in the LER is a performance deficiency because the licensee failed to protect cables important to safe shutdown as required. The problem is more than minor because it was associated with the external factors attribute, i.e. fire, of the Mitigating Systems cornerstone and it affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. When the probability of fire starting in the penetration area or inside containment is multiplied by the probability of the multiple cable damage states described above the result indicates the postulated event is lower than high safety significance (Red) and indicative of having very low safety significance. |
| 05000321/FIN-2003006-02 | 2003Q3 | Hatch | Untimely and Unapproved Manual Operator Action for Post-Fire SSD | The team found that a local manual operator action to prevent spurious opening of all eleven SRVs would not be performed in sufficient time to be effective. Licensee reliance on this manual action for hot shutdown during a fire, instead of physically protecting cables from fire damage, had not been approved by the NRC. The team noted that Step 9.3.2.1 of AOP 34AB-X43-001-2, Fire Procedure, Version 10.8, dated May 28, 2003, stated: To prevent all eleven SRVs from opening simultaneously, open links BB-10 in Panel 2H11-P927 and BB-10 in Panel 2H11-P928. The team noted that spurious opening of all eleven SRVs should be considered a large loss of coolant accident (LOCA), and that a LOCA should be prevented from occurring during a fire event to comply with 10 CFR 50, Appendix R, Section III.L. Section III.L requires that, during a post-fire shutdown, the reactor coolant system process variables (e.g., reactor vessel pressure and water level) shall be maintained within those predicted for a loss of normal alternating current power. Having all eleven SRVs opened during a fire would challenge this. Additionally, the team observed that this step was sufficiently far back in the procedure that it may not be completed in time to prevent potential fire damage to cables from causing all eleven SRVs to spuriously open. The licensee had no preplanned estimate of how long it would take operators to complete this step during a fire event. There was no event time line or operator training JPM on this step. The team noted that, during a fire, operators could be using many other procedures concurrent with the Fire Procedure. For example, they could be using other procedures to communicate with the fire brigade about the fire, respond to a reactor trip, deal with a loss of offsite power, and provide emergency classifications and offsite notifications of the fire event. During the inspection, licensee operators estimated that, during a fire event, it could take about 30 minutes before operators would accomplish Step 9.3.2.1. The team concurred with that time estimate which the team had previously determined independently. However, NRC fire models indicated that fires could potentially cause damage to cables in as short a period as five to ten minutes. Consequently, the team concluded that during a fire event, the licensees procedures would not ensure that Step 9.3.2.1 would be accomplished in time to prevent potential spurious opening of all eleven SRVs. The team also identified other issues with Step 9.3.2.1. There was no emergency lighting inside the panels, hence, if the fire caused a loss of normal lighting (e.g., by causing a loss of offsite power), operators would need to use flashlights to perform the actions inside the panels. Consequently, the team considered the emergency lighting for Step 9.3.2.1 to be inadequate (see Section 1R05.07.b). In addition, labeling of the links inside the panels was so poor that operators stated that they would not fully rely on the labeling. Also, the tool that operators would use to loosen and slide the links inside the energized panels was made of steel and was not professionally, electrically insulated. Further, licensee reliance on this operator action, instead of physically protecting the cables as required by 10 CFR 50, Appendix R, Section III.G.2, had not been approved by the NRC. The licensee stated that cable damage to two reactor pressure instrument cables would be needed to spuriously open all eleven SRVs. Because the licensee stated that the two cables were in the same cable tray in Fire Area 2104, the team considered that a fire in that area could potentially cause all eleven SRVs to spuriously open (see Section 1R21.01.b). In response to this issue, the licensee initiated CR 2003008203 and promptly revised the Fire Procedure before the end of the inspection, moving the actions of Step 9.3.2.1 to the beginning of the procedure. The procedure change enabled the actions to be accomplished much sooner during a fire in the Unit 2 east cableway or in other fire areas that were vulnerable to the potential for spuriously opening all eleven SRVs. The team determined that this issue is related to associated circuits. As described in NRC IP 71111.05, Fire Protection, inspection of associated circuits is temporarily limited. Consequently, the team did not pursue the cable routing or circuit analysis that would be necessary to evaluate the possibility, risk, or potential safety significance of Group B and C SRVs spuriously opening due to fire damage to the instrument cables. The team did, however, perform a circuit analysis of Group A SRVs for which the licensee takes credit during a fire in Fire Area 2104. |
| 05000321/FIN-2005009-01 | 2005Q2 | Hatch | Failure to Follow and Maintain in Effect ITS Emergency Plan When the TSC Was Removed from Service During This Period to Allow for Modification Activities | During an NRC inspection completed on June 30, 2005, a violation of NRC requirements was identified. In accordance with the NRC Enforcement Policy, the violation is listed below: 10 CFR 50.54(q) requires, in part, that a licensee authorized to operate a nuclear power reactor shall follow and maintain in effect emergency plans which meet the standards in Section 50.47(b). 10 CFR 50.54(q) also states that a licensee may make changes to these plans without Commission approval only if the changes do not decrease the effectiveness of the plans and the plans, if changed, continue to meet the standards of Section 50.47(b). 10 CFR 50.47(b)(8) requires that adequate emergency facilities and equipment to support the emergency response be provided and maintained. Section H of Revision 18 of the Edwin I. Hatch Nuclear Plant Emergency Plan, which implements the requirements of 10 CFR 50.47(b)(8), states that in the event that the Technical Support Center (TSC) becomes uninhabitable during an emergency, the control room will serve as an alternate TSC location. Contrary to the above, between April 25 and May 4, 2005, the licensee failed to maintain in effect a provision of its emergency plan in that adequate emergency facilities and equipment to support the emergency response were not provided. In this case, the licensee failed to follow and maintain in effect its emergency plan when the TSC was removed from service during this period to allow for modification activities. The removal of the TSC for the modification did not represent a condition in which the TSC was uninhabitable during an emergency. This violation is associated with a White Significance Determination Process finding for Units 1 and 2 in the emergency preparedness cornerstone. |
| 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. |
| 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. |
| 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. |
| 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. |
| 05000327/FIN-2005011-03 | 2005Q4 | Sequoyah | Sprinklers Apparently Too Far Below Ceiling in Cable Spreading Room | The team identified an URI related to the design of the sprinkler system in the cable spreading room, in that, the sprinklers were apparently installed too far below the ceiling. This issue is unresolved pending further NRC review of the licensing basis and the suppression capability of the installed sprinkler system. The team observed that all of the installed sprinklers in the cable spreading room were 30 inches or more below the ceiling. However, the NFPA code requires that sprinklers be installed within 18 inches of the ceiling. Positioning the sprinklers farther below the ceiling results in a delayed sprinkler response and allows a fire to grow larger in size. The Sequoyah FPP stated that sprinkler systems comply with the NFPA Code for installation of sprinkler systems. The SQN Fire Protection Report, Part VII - Deviations and Evaluations, paragraph 5.1.1, stated that sprinkler systems comply with NFPA 13- 1975, with certain exceptions. The list of exceptions did not include any sprinklers being installed farther below the ceiling than allowed by the NFPA code. NFPA 13-1975, Section 4-3.1, requires that for smooth ceiling construction, deflectors of sprinklers in bays shall be located 1 inch to 12 inches below noncombustible ceilings. For panel construction, the code allows sprinklers to be as much as 18 inches below the ceiling; however, in no case does the code allow sprinklers to be 30 inches below the ceiling. In a Safety Evaluation Report (SER), (NUREG-011, Supplement 1), the NRC approved the licensees sprinkler system design for the cable spreading room, including the use of an upper level near the ceiling and an intermediate level approximately halfway between the floor and the ceiling. However, the NRC SER did not specifically recognize that the upper level of sprinklers was more than 18 inches below the ceiling. The team concluded that the SER did not appear to approve a deviation from the NFPA code. In Generic Letter (GL) 86-10, the NRC stated a staff position that licensees may deviate from NFPA code requirements with an evaluation approved by a fire protection engineer. GL 86-10 stated that such deviations from the NFPA code should be identified in the FSAR or FHA. However, GL 86-10 also stated an NRC staff position that sprinkler heads should be located at the ceiling. The team observed that the cable spreading room contained cables for both units and was very large in volume (approximately 219 feet long by 42 feet wide and 25 feet high). Rows of intermediate sprinklers were located between rows of upper sprinklers such that most fires that could start near the floor would generate a wide heat plume that would impact at least one upper or intermediate level sprinkler. The sprinklers had metal heat collectors installed above them; however, NRC Information Notice 2002-024 describes potential problems with such heat collectors. Also, sprinklers that were not directly in the heat plume of a fire could potentially have a significantly delayed response to the fire. This issue remains open for further NRC review of the licensing basis and the suppression capability of the installed sprinkler system. The issue is identified as URI 05000327,328/2005011-03, Sprinklers Apparently Too Far Below Ceiling in Cable Spreading Room. |
| 05000327/FIN-2005011-07 | 2005Q4 | Sequoyah | Potential for Fire Damage to Spuriously Close the Charging Header Flow Control Valve | The team identified an URI associated with potential fire-induced electrical circuit failures in the charging header flow control valve control circuit. A postulated fire in fire area FAA-070 could result in fire-induced electrical circuit faults in the control cables and control logic of the charging flow control valve causing the valve to close and shut off cooling flow to the reactor coolant pump (RCP) seals. This issue is unresolved pending further NRC review of whether the licensee is required to design against such a failure mode. The team reviewed cable routing information for charging header flow control valve 1-FCV-62-093 and determined that two cables in the control logic for the valve were routed in fire area FAA-070 without appropriate separation or protection. These cables were identified as 1PM108 and 1PM110. Both cables provided a 10-50 milliamp signal for control of the charging pump discharge air operated valve (AOV). A cable-to-cable hot short of 50 milliamps in either cable could spuriously close the AOV and stop all RCP seal injection flow. The team determined that both cables were routed in trays with other signal cables of 10-50 milliamps so that a cable-to-cable hot short of this type could potentially occur. However, because the cables were shielded twisted pairs with drain wires, it is not likely a failure of this type could occur without the cables shorting to each other or to ground. This item is unresolved pending further NRC review to determine whether the licensee is required to design against such a failure mode. This issue is identified as URI 05000327,328/2005011-07, Potential for Fire Damage to Spuriously Close the Charging Header Flow Control Valve. |
| 05000327/FIN-2008006-01 | 2008Q2 | Sequoyah | Fire Detectors in 480 V Shutdown Board Room 2B2 Not Installed According to NFPA Code | A Green NCV of Unit 2 License Condition 13, Fire Protection, was identified since fire detectors in the Unit 2 480 Volt shutdown board room 2B2 were not installed according to the applicable National Fire Protection Association code. Specifically, two detectors were located near forced ventilation fresh air inlets. The licensee entered this issue into their corrective action program and promptly posted a continuous fire watch in the fire area. This finding is a performance deficiency because the licensee did not properly locate the smoke detector or the heating, ventilating and air conditioning (HVAC) system supply air inlet registers to adequately comply with the applicable industry code of record for the facility. As a result two of the four smoke detectors would not be effective in detecting fires. 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 substantially affects the objective of ensuring reliability and capability of systems that respond to initiating events. Considering the degree of system degradation, the length of time the problem existed, the calculated fire frequency for the fire area and shutdown systems independent of the fire area the finding was of very low safety significance |
| 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 |
| 05000327/FIN-2008006-03 | 2008Q2 | Sequoyah | Sprinklers too far below Ceiling in Cable Spreading Room | A green NCV of Unit 1 License Condition 16 and Unit 2 License Condition 13, Fire Protection, was identified for failure to install the automatic suppression system (sprinkler system) in the cable spreading room according to the applicable National Fire Protection Association standard with regard to the ceiling to sprinkler head dimension. As a result, the fusible link type sprinkler heads may be significantly slower than originally intended after fire ignition. The licensee entered this problem into their corrective action program. This finding is a performance deficiency because the licensee did not locate the sprinkler heads according to the applicable industry code of record for the facility. 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 substantially affects the objective of ensuring reliability and capability of systems that respond to initiating events. The finding was determined to be of very low safety significance when the likelihood of fires, the transients that could be initiated by fires and the probability of failure of mitigating systems for those transients were evaluated |
| 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). |
| 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). |
| 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. |
| 05000335/FIN-2006010-01 | 2006Q4 | Saint Lucie | Cable Spreading Room Automatic Halon Suppression System Out of Service | The team identified an unresolved item related to the licensees failure to comply with the approved Unit 1 FPP for the out of service Halon 1301 fire suppression system in the Unit 1 CSR (FA B/FZ 57). Specifically, the system has been out of service since inadvertently discharging in December, 2005. The team did not find evidence in the licensees corrective action program to demonstrate the planned return of this system to operable status in a timely manner. The Unit 1 CSR is equipped with an automatic Halon 1301 fire suppression system that could be released both automatically and manually. During a maintenance activity in December, 2005, there was an accidental manual actuation and discharge of the Halon system. The licensee initiated CR 2005-33539 to document this incident, but the CR only addressed the accidental discharge of the system. The CR did not address the return of the Halon system to its intended design function nor did the CR evaluate the safety significance (from a fire protection standpoint) of the lack of an automatic fire suppression system in the room. During 2006, activities were undertaken to attempt to obtain the necessary parts and components needed to replace and/or restore the Halon system to an operable status. There was also an effort to evaluate alternative automatic suppression systems for the Unit 1 CSR in lieu of the existing Halon system due to Halons general decreased use for environmental considerations. Although these efforts were presented to the team by the licensee, there was no mechanism in place to formally track a systematic resolution of this issue. Additionally, there had been no engineering evaluation performed to determine the safety significance of the Halon fire suppression system being out of service for an extended period of time. Section 7.0 in Appendix 9.5A of the Unit 1 UFSAR addresses the FPP administrative controls. Section 7.5 addresses the inspection and testing requirements of the fire protection program and specifically lists the RAB Cable Spreading Room Halon System as a plant fire protection feature that is subject to periodic tests and inspections. Section 7.5 further stated that remedial actions be taken for equipment out of service, including fire suppression equipment, and remedial actions would include compensatory measures to ensure equivalent level of fire protection in addition to timely efforts to effect repairs and restore equipment to service. As part of its immediate compensatory measures, the licensee had posted a continuous fire watch in the Unit 1 CSR in accordance with provisions of its FPP. Communication that the Halon system was out of service was made to operations personnel and the station fire brigade through daily operations and shift turnover briefings. The Unit 1 CSR was also equipped with an automatic fire detection system. However, there was no evidence of actions or measures to evaluate the CSR to ensure an equivalent level of fire protection due to the automatic Halon suppression system being out of service for an extended period of time. Additionally, there was no evidence of timely efforts to effect repairs to this system and restore it to service, given the stated risk significance of a postulated Unit 1 CSR fire (PSL Individual Plant Examination of External Events). The fire fighting strategy procedure for the Unit 1 CSR had not been changed or annotated to reflect the Halon system being out of service. None of the plant hardware components associated with the Halon system were tagged or labeled to state that the system was out of service. During the inspection, the licensee generated CRs 2006-25892 and 2006-30034 to track the resolution of this issue in its corrective action program. Also, labels were applied to the Halon manual actuation release stations to inform plant personnel that actuation of those devices would not result in a release of Halon into the room. |
| 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 |
| 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. |
| 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). |
| 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. |
| 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. |
| 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-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. |
| 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). |
| 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. |
| 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. |