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05000369/FIN-2018011-012018Q2Mcguire
McGuire		Question about treatment of well-sealed, robustly secured cabinets in the Fire PRAInspectors identified an unresolved item (URI) associated with how the site calculated fire frequencies of electrical cabinets in the fire PRA. The site retained floor-mounted electrical cabinets characterized as well-sealed and robustly-secured as ignition sources in the fire PRA. The guidance of NUREG-6850, which the site is committed to, instructs that electrical cabinets housing voltages less than 400V, and that are characterized as well-sealed and robustly secured not be counted as ignition sources. This is because the fire PRA should only consider fires that can propagate to other combustibles and targets, and by including ignition sources that cannot propagate to other combustibles and targets, the frequency of fires in other electrical cabinets that can actually propagate could be erroneously lowered. Inspectors noted that retaining floor-mounted cabinets characterized as well-sealed and robustly-secured appeared to not be in alignment with the sites NFPA 805 submittal, and associated SE, which each contain information specific to the question about how well-sealed robustly secured cabinets were treated in the fire PRA. The SE states, Regarding the counting of well-sealed, robustly-secured electrical cabinets having circuits less than 440V, the licensee stated in its response to PRA RAI 03.b.01 that it updated the FPRA to remove cabinets meeting this definition. The site has asserted that this statement in the SE is incorrect, and does not align with what the site submitted on the docket as a part of their NFPA 805 submittal. Planned Closure Action(s): This issue is being characterized as a URI, pending a decision from NRR as to the interpretation of the sites submittal regarding treatment of floor-mounted well-sealed and robustly-secured cabinets, and the accuracy of the associated SER
05000424/FIN-2017008-012017Q2VogtleFire Protection Program Change did not meet VEGP License Condition Requirement 2.G for Units 1 and 2The inspectors identified a Severity Level IV (SL IV) non-cited violation (NCV) and associated Green finding of Vogtle Units 1 and 2 Operating License Conditions 2.G, for the licensees failure to perform an evaluation of the impact of a change to the approved fire protection program (FPP). The failure to adequately evaluate the impact of the change resulted in the implementation of a change to the FPP that could have adversely affected the ability to achieve and maintain safe shutdown. The licensee initiated condition report (CR) 10382461 to evaluate the issue and make necessary correction to the program. The inspectors determined that the licensees failure to adequately evaluate the impact of the change to the FPP was a performance deficiency (PD). The PD was determined to be more than minor because if left uncorrected, the PD could have the potential to lead to a more significant safety concern. Specifically, if degraded fire doors are not evaluated for functionality, the doors could potentially be left in a condition where it would not perform its design function in the case of a fire. The licensees failure to submit the FPP change to the NRC was determined to impede the regulatory process because the FPP change required NRC review and approval prior to implementation. The finding was screened as Green because, based upon inspection of the affected barriers, the inspectors determined that, either, the combustible loading on both sides of the barrier represented a fire duration of less than 1.5 hours, there was a fully functional automatic suppression system on either side of the barrier, or the barrier separated rooms that utilized the same SSD strategy. This violation was determined to be a Severity Level IV violation because the associated finding was evaluated by the SDP as having very low safety significance (i.e., Green finding). No cross cutting aspect was assigned because the finding was not indicative of current licensee performance.
05000321/FIN-2017002-012017Q2HatchHardened grease prevents 1RHRSW pump breaker operationGreen. A self-revealing, Green, non-cited violation (NCV) of Hatch Unit 1 Technical Specification 5.4 Procedures, was identified when procedures to rejuvenate grease in the 1C' residual heat removal service water (RHRSW) Pump breaker were not implemented resulting in failure of the pump to start. The violation was entered into the licensees corrective action program as condition report (CR) 10263236 and the breaker was replaced to restore compliance. Failure to rejuvenate the lubricating grease on 4kv DHPVR breakers in accordance with vendor guidance was a performance deficiency. Specifically, the hardened grease prevented the 1C RHRSW pump breaker from closing resulting in the inoperability of the 1C RHRSW pump. The performance deficiency was associated with the Mitigating Systems cornerstone and was more than minor because it adversely affected the cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors screened this finding using IMC 0609, Appendix A, The Significant Determination Process (SDP) For Findings At-Power, dated June 19, 2012. Because all four questions in Section A of Exhibit 2, Mitigating Systems Screening Questions, were answered no, the finding screened as Green. The inspectors determined that this finding did not have an associated cross cutting aspect because this finding is not reflective of current licensee performance.
05000321/FIN-2017002-042017Q2HatchLicensee-Identified ViolationTS 3.6.4.1 requires secondary containment be operable in Mode 1 and during movements of irradiated fuel assemblies in the secondary containment. Contrary to the above, on February 8 at 1035, with Unit 1 operating at 100 percent RTP and Unit 2 conducting refueling operations, secondary containment was made inoperable when Unit 2 reactor building containment was breached for a scheduled refueling outage and a configuration control error on the Unit 2 standby gas treatment system provided a uncontrolled opening into the secondary containment for the Unit 1 reactor building and the common refueling floor. A temporary blind flange had been incorrectly installed on the upstream side vice downstream side of the Unit 2 standby gas treatment inlet isolation valve when the valve had been removed from the system for testing. This configuration rendered secondary containment for the Unit 1 reactor building and the common refueling floor inoperable. A senior reactor operator performing a plant tour noted the incorrect flange configuration and at 2017 on February 17, the blind flange was moved to the downstream side of the Unit 2 standby gas treatment inlet isolation valve to restore compliance. Inspectors screened the finding in accordance with IMC 609 Appendix A The Significance Determination Process (SDP) for Findings at-Power. The finding screened as very low safety significance (Green) because the questions in Appendix A Exhibit 3 for Control Room, Auxiliary, Reactor, or Spent Fuel Pool Building, were answered no. This issue was documented in the licensees corrective action program as CR 10332592.
05000321/FIN-2017002-032017Q2HatchNoncompliance for Providing Inadequate Procedural Guidance for Post-Fire Safe ShutdownIntroduction: The inspectors identified a noncompliance with Hatch Technical Specification 5.4.1.a for the licensees failure to provide adequate procedural guidance in post-fire safe shutdown abnormal operating procedure of Abnormal Operating Procedure (AOP) 34AB-X43-001-1, Fire Procedure. Specifically AOP 34AB-X43-001-1 directs operators to perform manual actions that may not be adequate to reopen a credited valve that has spuriously closed. Description: During the transition to NFPA 805, the licensee identified multiple instances of cables for equipment required to achieve SSD not meeting the separation requirements of the current licensing basis. The licensee determined that this condition existed for FA 1105, East Cableway Foyer. It was discovered that cables were identified in the current Safe Shutdown Analysis Report (SSAR) for HPCI Steam Supply Isolation motor operated valve 1E41-F002 . These cables were dispositioned by taking an Operator Manual Action (OMA) to open links BB-49 and BB-57 in panel 1H11-P622. Further evaluation showed that the OMA would prevent the valve from spuriously clos ing, but it would not re-open the valve after a spurious closure, due to the power supply for this valve being unavailable due to fire impacts. The licensee determined that these conditions were caused by methodology weaknesses in the sites fire safe shutdown analysis. Upon discovery, the licensee implemented compensatory measures in the form of posting a roving fire watch in fire areas of concern, and revised the affected procedure. 19 Analysis of the Problem Failure to adequately implement the requirements contained in 10 CFR Part 50.48(b)(1), and Hatch Renewed Operating License Condition 2.C.(3) and 2.C.(3)(a), for Units 1 and 2 was a performance deficiency. This finding was more than minor because it was associated with the reactor safety mitigating system cornerstone attribute of protection against external events (i.e., fire). Because this issue relates to fire protection and this non-compliance was identified as a part of the sites transition to NFPA 805, this issue is being dispositioned in accordance with Section 9.1, Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48) of the NRC Enforcement Policy. In order to verify that this non-compliance was not associated with a finding of high safety significance (Red), inspectors revi ewed qualitative and quantitative risk analyses performed by the licensee. These risk evaluations took ignition source and target information from the ongoing Hatch fire PRA to demonstrate that the significance of the non-compliances were less-than-Red (i.e. core damage frequency (CDF) less than 1E-4/year). Inspectors determined that cables associated with some of the VFDRs were not located in the zone of influence (ZOI) of any credible ignition source. For cables that were located in the ZOI of a credible ignition source, inspectors were able to perform a calculation to determine the change in conditional core damage probability (CCDP), based on the postulated fire-affected equipment not being available. Based on these screenings, inspectors determined that the significance of this non-compliance was less- than-Red. A bounding risk assessment was performed by a regional SRA which included the review of the licensee and inspectors risk evaluations and confirmed the CDF risk increase due to this condition was less than 1E-4, and therefore less than RED. The inspectors determined that no cross-cutting aspect was applicable to this performance deficiency because this finding was not indicative of current licensee performance. Enforcement of the Problem 10 CFR Part 50.48(b)(1) requires that all nuclear power plants licensed to operate prior to January 1, 1979, must satisfy the applicable requirements of 10 CFR Part 50, Appendix R, Sections III.G, III.J, and III.O. Section III.G.2 requires, in part, that where cables and equipment of redundant trains of systems necessary to achieve and maintain hot shutdown conditions are located in the same fire area outside of primary containment, one of the following means of ensuring that one of the redundant trains is free of fire damage shall be provided: o separation of cables and equipment by a fire barrier having a 3-hour rating; or o separation of cables and equipment by a horizontal distance of more than 20 feet with no intervening combustibles or fire hazards. Fire detection and automatic fire suppression shall be installed in the fire area; or o enclosure of cables and equipment of one redundant train in a fire barrier having a 1-hour fire rating. Fire detection and automatic suppression shall be installed in the fire area. 20 Section III.G.3 requires, in part, that alternative shutdown capability be provided where the protection of systems whose function is required for how shutdown does not satisfy the requirement of Section III.G.2. Additionally, Hatch Technical Specifications 5.4.1.a, Procedures for Unit 1 states that written procedures shall be established, implemented, and maintained covering activities listed in NRC Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Item 6.v of Appendix A lists Plant Fires as an activity that requires written procedures. Contrary to the above, the licensee failed to meet the requirements of its documented fire protection program since initial plant licensing, in that: The licensee did not meet the requirements of 10 CFR Part 50, Appendix R, Section III.G.2 in that the licensee did not ensure that one of the redundant trains was free of fire damage by providing one of the following means stated in Section III.G.2. The licensee did not ensure alternative shutdown capability be available for 2 fire areas where the guidelines for ensuring one redundant train for safe shutdown be free of fire damage, as required by 10 CFR Part 50, Appendix R, Section III.G.3. The licensee failed to provide adequate procedural guidance to ensure fire safe shutdown due to a fire in FA 1105. CRs generated for these issues are listed in the Documents Reviewed section. Because the licensee committed to adopt NFPA 805 and change their fire protection licensing bases to comply with 10 CFR 50.48(c), t he NRC is exercising enforcement and reactor oversight process (ROP) discretion (EA-17-120) for this issue in accordance with the NRC Enforcement Policy, Section 9.1, Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48) and Inspection Manual Chapter 0305. Specifically, this issue was identified and will be addressed during the licensees transition to NFPA 805, it was entered into the licensees corrective action program, immediate corrective action and compensatory measures were taken, it was not likely to have been previously identified by routine licensee efforts, it was not willful, and it was not associated with a finding of high safety significance (Red)
05000366/FIN-2017002-022017Q2HatchPerformance of Operations with Potential to Drain the Reactor Vessel (OPDRV) Without Secondary ContainmentThe inspectors reviewed this LER for potential performance deficiencies and/or violations of regulatory requirements. In February 2017, during the Unit 2 refueling outage, operations with the potential to drain the reactor vessel (OPDRV) activities were performed while in Mode 5 (Refueling Mode) contrary to Technical Specification (TS) 3.6.4.1. Enforcement Guidance Memorandum (EGM) 11-003, Revision 3, provided required interim actions which were incorporated into procedure 31GO-OPS-025-0 Operations with the Potential to Drain the Reactor Vessel. This procedure was used during the OPDRV activities for the Unit 2 refueling outage. LER 05000366/2017-001- 00 is closed. Description: The inspectors reviewed the plants implementation of Enforcement Guidance Memorandum 11-003 during maintenance activities which had the potential to drain the reactor vessel during the Unit 2 refueling outage. The activities were: Local power range monitors removal and replacement February 10, 2017; Control rod drive insert / recouple activity February 11, 2017; and Hydraulic Control Unit Venting February 12-13, 2017. 15 These activities took place without secondary containment being operable. Inspectors verified compliance with the guidelines of Enforcement Guidance Memorandum 11-003 prior to and during these activities. This condition was documented in the licensees corrective action program as CR 10329405, 10329857, 10330152, and 10330153. Enforcement: Unit 2 TS 3.6.4.1 required, in part, that activities that had the potential to drain the reactor vessel be conducted only with secondary containment operable. Contrary to that requirement, the licensee conducted activities that could cause the reactor vessel to drain while secondary containment was inoperable. The NRC is exercising enforcement discretion (Enforcement Action (EA)-17-124) in accordance with Section 3.5, Violations Involving Special Circumstances, of the NRC Enforcement Policy because the violation was identified during the discretion period described in Enforcement Guidance Memorandum 11-003. Therefore, the NRC will not issue enforcement action for this violation, subject to the license amendment request which was submitted on April 20, 2017.
05000324/FIN-2017007-012017Q1BrunswickFailure to Correct a Nonfunctional Fire DoorGreen. The NRC identified a Green non-cited violation (NCV) of Brunswick Operating License Condition (OLC) 2.B(6) for Units 1 and 2, for the licensees failure to correct a nonfunctional fire door in the diesel generator (DG) building. Specifically, on three occasions, NRC inspectors identified door 2-DGB-DR-E L023-118 in the DG building as having a stuck open latch, which prevented the door from closing and latching securely. U pon the third discovery of the nonfunctional fire door, the licensee initiated AR 02100405, entered the appropriate action statement in accordance with site procedure 0PLP-01.2, Fire Protection System Operability, Action, and Surveillance Requirements, and took actions to install a new thumb latch, and to install a new door closure mechanism. The inspectors determined that the licensees failure correct nonfunctional fire door was a performance deficiency (PD). The PD was determined to be more than minor because if left uncorrected, the PD could have the potential to lead to a more significant safety concern. Specifically, if the door was not repaired adequately, it could have the potential to not be able to perform its design function in the case of a fire in diesel generator cell nos. 1 or 2 (FA DG-4 or DG-5). Using IMC 0609, Appendix F, Attachment 1, Fire Protection Significance Determination Process Worksheet, the finding was screened as Green at task 1.4.3-C because there was a fully functional automatic suppression system on at least one side of the fire barrier. The finding has a cross-cutting aspect in the area of problem identification & resolution associated with the Evaluation attribute because the organization did not thoroughly evaluate the condition of the door to ensure that the resolution addressed the underlying cause of the nonfunctional fire door (PI.2)
05000250/FIN-2016008-012016Q4Turkey PointLicensee-Identified ViolationTurkey Point Nuclear Generating Station, Unit 4, Renewed Facility Operating License 3.D, Fire Protection, stated that Florida Power and Light (FPL) shall implement and maintain in effect all provisions of the approved fire protection program that comply with 10 CFR 50.48 (c), National Fire Protection Association (NFPA) 805. NFPA 805, Section 2.4.2.2.2 (b), Common Enclosure Circuits, required circuits that share a common enclosure with circuits required to achieve nuclear safety performance criteria shall be identified for their impact on the ability to achieve nuclear safety performance criteria. Contrary to the above, since 2014, the licensee failed to identify circuits that impact the ability to achieve nuclear safety performance criteria as a result of the effects of fire on circuits that share a common enclosure with the Unit 4 4kV switchgear. The violation was determined to be of very low safety significance based on risk evaluation provided by the licensee and reviewed by NRC senior reactor analyst. The licensee entered this issue into their corrective action program as action request 2134673.
05000413/FIN-2016003-012016Q3CatawbaLicensee-Identified ViolationThe licensee identified a non-compliance with Operating License Condition 2.C.(5), for Units 1 and 2, for the failure to protect one of the redundant trains of equipment needed to achieve post-fire SSD from fire damage. Specifically, the licensee failed to use one of the means described in Branch Technical Position (BTP) Chemical Engineering Branch (CMEB) 9.5-1, Item C.5.b.2 to ensure that one of the redundant trains of equipment necessary to achieve and maintain hot shutdown conditions was protected from fire damage. Description: On June 2, 2014, the licensee submitted LER 413/2014-002-00 with Revision 01 submitted on December 1, 2014, which documented discovery of cable routing issues and postulated fire-induced circuit failures that could prevent operation or cause maloperation of equipment required to achieve SSD in the event of a fire. This condition was identified during the licensees transition to National Fire Protection Association Standard 805 (NFPA 805). During the transition to NFPA 805, the licensee identified multiple instances of cables for equipment required to achieve SSD not meeting the separation requirements of the current licensing basis. The licensee determined that this condition existed for 22 fire areas (FAs) across both units. The licensee characterized these issues as variance(s) from deterministic requirements (VFDRs). The conditions identified in the LER are related to VFDRs that met the following criteria: 1) VFDRs that required a plant modification to meet the fire risk criteria of NFPA 805, or 2) VFDRs where a potential concern existed with respect to NRC Information Notice (IN) 92-18, Potential for Loss of Remote Shutdown Capability During a Control Room Fire, dated February 28, 1992. The licensee determined that the deficiencies existed because of latent design deficiencies in the cable routing and circuit design. This LER was applicable to Units 1 and 2. Upon discovery, the licensee entered this issue into their corrective action program as PIP C-1401427, and implemented compensatory actions in the form of fire watches and/or control of transient combustible material for the affected FAs. Analysis. Failure to protect one redundant train of cables and equipment necessary to achieve post-fire SSD from fire damage was a performance deficiency. This finding was more than minor because it was associated with the reactor safety mitigating system cornerstone attribute of protection against external events (i.e., fire). Specifically, failure to protect safe shutdown cables and equipment from fire damage negatively affected the reactor safety mitigating systems cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Because this issue relates to fire protection and this noncompliance was identified as a part of the sites transition to NFPA 805, this issue is being dispositioned in accordance with Section 9.1, Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48) of the NRC Enforcement Policy. In order to verify that this non-compliance was not associated with a finding of high safety significance (Red), inspectors reviewed qualitative and quantitative risk analyses performed by the licensee. These risk evaluations took ignition source and target information from the licensees fire probabilistic risk assessment to demonstrate that the significance of the non-compliances were less-than-Red (i.e. CDF less than 1E-4/year). Inspectors determined that cables associated with some of the VFDRs were not located in the zone of influence (ZOI) of any credible ignition source. For cables that were located in the ZOI of a credible ignition source, inspectors were able to perform a calculation to determine the change in conditional core damage probability (CCDP), based on the postulated fire-affected equipment not being available. Based on these screenings, inspectors determined that the significance of this non-compliance was lessthan-Red. A bounding risk assessment performed by a regional Senior Risk Analyst (SRA) reviewed the licensee and inspector risk evaluations and confirmed the CDF risk increase due to this condition was less than 1E-4, and therefore less than RED. The inspectors determined that no cross cutting aspect was applicable to this performance deficiency because this finding was not indicative of current licensee performance. Enforcement. Operating License Condition 2.C.(5), for Units 1 and 2, requires that the licensee implement and maintain in effect all provisions of the approved FPP as described in the UFSAR, as amended, for the facility and as approved in the SER through Supplement 5. BTP CMEB 9.5-1, which incorporated the guidance of Appendix A to BTP ASB 9.5-1 and the technical requirements of Appendix R to 10 CFR 50, established the regulatory and licensing requirements for the FPP at Catawba Nuclear Station (CNS). The CNS FPP was reviewed against and approved for conformance with BTP CMEB 9.5-1 in the SER through Supplement 5. BTP CMEB 9.5-1, Item C.5.b.1, requires that fire protection features be provided that are capable of limiting fire damage so that one train of systems necessary to achieve and maintain hot standby conditions from either the control room or emergency control station(s) is free from fire damage. BTP CMEB 9.5- 1, Item C.5.b.2 requires one redundant train to be protected from fire damage by one of the following specified methods: (a) separation of cables and equipment by a fire barrier having a 3-hour rating, (b) separation of cables and equipment by a horizontal distance of more than 20 feet with no intervening combustibles or fire hazards and with fire detectors and an automatic fire suppression system in the fire area, or (c) enclosure of cables and equipment in a fire barrier having a 1-hour rating and with fire detectors and an automatic fire suppression system in the fire area. Contrary to the above, the licensee failed to use one of the means described in BTP CMEB 9.5-1, Item C.5.b.2 to ensure that one of the redundant trains of equipment necessary to achieve and maintain hot shutdown conditions was protected from fire damage. Specifically, on April 2, 2014, the licensee identified the failure to protect equipment in accordance with the current licensing basis. The licensee determined that fire damage could prevent operation of, or cause maloperation of, components that were required to achieve and maintain SSD. This condition has existed since initial plant startup for Units 1 and 2. The licensee entered this issue into the corrective action program (PIP C-14-1427) and implemented compensatory measures in the form of fire watches and/or control of transient combustible material for the affected FAs. Because the licensee committed to adopt NFPA 805 and change their fire protection licensing bases to comply with 10 CFR 50.48(c), the NRC is exercising enforcement and reactor oversight process (ROP) discretion for this issue in accordance with the NRC Enforcement Policy, Section 9.1, Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48) and Inspection Manual Chapter 0305. Specifically, this issue was identified and will be addressed during the licensees transition to NFPA 805, it was entered into the licensees corrective action program, immediate corrective action and compensatory measures were taken, it was not likely to have been previously identified by routine licensee efforts, it was not willful, and it was not associated with a finding of high safety significance (Red).
05000259/FIN-2016011-012016Q3Browns FerryFailure to Identify and Evaluate All Targets Within the Zone of Influence of Ignition SourcesThe NRC identified a violation of 10 CFR 50.48(c) for the licensees failure to address in the Fire Probabilistic Risk Assessment (Fire PRA) the risk contribution associated with all potentially risk significant fire scenarios for a given fire compartment/fire area. The licensee did not identify and evaluate all targets that were within the zone of influence (ZOI) of ignition sources for selected fire scenarios that could potentially contribute to the risk for the fire scenarios. The licensee entered the issue in the corrective action program (CAP) as Condition Reports (CRs) 1195603 and 1197392. The affected area was already covered by an hourly roving fire watch as a compensatory measure. The licensees failure to address the risk contribution associated with all potentially risksignificant fire scenarios, as required by section 2.4.3.2 of NFPA 805, was a performance deficiency. For each example, the performance deficiency was determined to be more than minor because it was associated with the reactor safety mitigating systems cornerstone attribute of protection against external factors (i.e., fire) and it adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensee failed to analyze the full risk impact of the selected fire scenarios, and the missed targets in the ZOI for the selected fire scenarios had the potential to impact the ability to achieve safe and stable conditions. Using IMC 0609, Appendix F, Attachment 1, Fire Protection Significance Determination Process Worksheet, the finding was screened as Green in step 1.6.1 Screen by Licensee PRA-Based Safety Evaluation. There was no cross cutting aspect assigned to this finding because it was not indicative of current licensee performance since the original ignition source and target walkdowns were performed more than 3 years ago. (Section 1R05.06)
05000259/FIN-2016011-022016Q3Browns FerryFailure to Adequately Identify and Evaluate All Circuit Failures for NSCA Credited EquipmentThe NRC identified a violation of 10 CFR 50.48(c) for the licensees failure to properly identify circuits required for the nuclear safety function. Specifically, the licensees Nuclear Safety Capability Assessment (NSCA) failed to identify that fire-induced failure of cables associated with the undervoltage trip function of the 4KV Shutdown Board could cause the shutdown board to not shed loads upon an undervoltage condition. This could lead to overloading the emergency diesel generator (EDG) credited for powering the shutdown board. This item was entered into the CAP as CR 1199002. The affected area was already covered by an hourly roving fire watch as a compensatory measure. Additionally, the licensee submitted EN 52150 to the NRC, documenting this as an unanalyzed condition. The licensees failure to identify circuits required for the nuclear safety function, as required by Section 2.4.2.2.1 of NFPA 805 was a PD. The PD was determined to be more than minor because it was associated with the reactor safety mitigating systems cornerstone attribute of protection against external factors (i.e., fire) and it adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensees failure to analyze the effects of fire damage on the 4kV shutdown bus undervoltage circuitry could result in overloading the emergency diesel generator (EDG) credited for powering the shutdown board. Using the guidance of IMC 0609, App. F, the finding was screened as Green because the risk increase associated with the finding was an increase of core damage frequency of <1E-6/year. There was no cross cutting aspect assigned to this finding because it was not indicative of current licensee performance since the original ignition source and target walkdowns were performed more than 3 years ago. (Section 1R05.06)
05000269/FIN-2016002-022016Q2OconeeFailure to Properly Control Transient Combustible Materials in the Oconee Main Control RoomsAn NRC-identified Green non-cited violation (NCV) of Oconee Nuclear Station Units 1, 2, and 3 Renewed Facility Operating License Condition 3.D, Fire Protection, was identified for the licensees failure to adequately implement the requirements of the transient combustible material program. Specifically, the licensee failed to control the storage of transient combustible material in the Oconee main control rooms with the proper evaluation in accordance with procedure AD-EG-ALL-1520, Transient Combustible Control, Attachment 3, Allowed Combustible Materials in Level B and Level C Areas. The licensee removed the stored items from each of the main control rooms and entered this issue into their corrective program as nuclear condition reports (NCRs) 02012091, 02012290, and 02013990. The licensees failure to control the storage of transient combustible material in the Oconee main control rooms with the proper evaluation in accordance with procedure AD-EG-ALL-1520 was a performance deficiency. The performance deficiency was more than minor because it was associated with the protection against external factors 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 (i.e., core damage). Specifically, uncontrolled transient combustibles challenge the habitability requirements of the main control room in the event of a fire and the ability of licensed operators to respond to events using the systems designed to prevent undesirable consequences. The finding was screened in accordance with IMC 0609, Significance Determination Process, Attachment 4, Initial Characterization of Findings and IMC 0609 Appendix F, Fire Protection Significance Determination Process Task 1.3.1, and determined to be of very low safety significance (Green) because the finding did not prevent the reactor from reaching and maintaining a safe shutdown condition. The finding was determined to have a cross-cutting aspect of procedure adherence in the human performance cross-cutting area because the licensee failed to implement the requirements of station procedure AD-EG-ALL-1520, Transient Combustible Control.
05000287/FIN-2016002-042016Q2OconeeFailure to Make a Non-Emergency Eight Hour Notification of a Loss of Safety FunctionAn NRC-identified Severity Level IV NCV of 10 CFR 50.72(b)(3)(v) was identified for the licensees failure to make a required non-emergency eight hour notification for a loss of the emergency AC power path function. On December 7, 2015 Oconee Nuclear Station Unit 3 experienced a loss of the emergency AC power path function for approximately 21 minutes. The licensee entered this issue into their corrective action program as NCR 01981762 and will evaluate their internal reportability procedures regarding the time of discovery. The failure to make an eight hour non-emergency report for a loss of the emergency AC power path function per 10 CFR 50.72(b)(3)(v) was a performance deficiency. This performance deficiency impacted the ability of the NRC to perform its regulatory oversight function and was dispositioned using traditional enforcement. This violation was assessed using Section 2.2.4 of the NRCs Enforcement Policy, revised February 4, 2015. Using the example listed in Section 6.9.d.9, A licensee fails to make a report required by 10 CFR 50.72, the issue was determined to be a Severity Level IV violation. In accordance with IMC 0612, because this violation involved traditional enforcement and does not have an underlying technical violation that would be considered more than minor, a cross-cutting aspect was not assigned to this violation.
05000287/FIN-2016002-032016Q2OconeeDegraded power cables result in inoperable startup transformer and loss of Unit 3 safety functionA self-revealing Green violation of Oconee Technical Specification 5.4, Procedures, was identified for the licensees failure to establish adequate procedures to detect degradation of the startup transformer power cables. Station procedure IP/0/A/2400/002, Substation Insulators, Lighting Arrestors, CCVT, Transformer Drop Down Line, Bus Inspection and Maintenance, lacked sufficient detail for maintenance personnel to properly inspect power cables for cracks and fraying. This allowed undetected degradation of the Oconee startup transformer power cables to develop causing the Unit 3 startup transformer to become inoperable. The licensee performed repair activities on the degraded power cables to remove areas where strands of the power cables were severed and re-established proper connections. Also, the licensee created work orders in their work management process to replace the drop down lines on the Unit 1 and Unit 3 startup transformers. The licensee entered this issue into their corrective program as NCR 01733811. The licensees failure to establish an adequate procedure to detect degradation of startup transformer power cables during periodic maintenance was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the equipment performance attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage). Specifically, the power cable failure caused inoperability of the Unit 3 startup transformer. The finding was screened in accordance with IMC 0609, Significance Determination Process, Attachment 4 and Appendix A and determined to require a detailed risk evaluation. A senior reactor analyst performed a detailed risk evaluation of this condition and determined delta CDF was 3E-7 (Green). The finding was determined to have a cross-cutting aspect of evaluation in the problem identification and resolution cross-cutting area because the licensees corrective actions resulting from a degraded power cable in 2002 failed to incorporate sufficient detail into their procedures necessary to detect frayed cables.
05000287/FIN-2016002-012016Q2OconeeFailure to Perform ISI General Visual Examinations of Containment Moisture BarrierAn NRC-identified Green NCV of 10 CFR Part 50.55a, Codes and Standards, was identified for the licensees failure to conduct 100 percent general visual examinations of the moisture barriers to the containment liner in accordance with Subsection IWE of American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code, Section XI. Specifically, the licensee failed to conduct visual examinations of the sealant applied to interior expansion joint locations in containment. In response, the licensee repaired the identified moisture barriers and confirmed the operability of the containment liner with the satisfactory results of the containment integrated leak rate test. The licensee entered this issue into their corrective action program as NCR 02027086. The failure to conduct a general visual examination of 100 percent of the moisture barriers intended to prevent intrusion of moisture against inaccessible areas of the containment liner was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the design control attribute of the barrier integrity cornerstone and adversely affected the cornerstone objective of providing reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, the inspectors determined that this finding was of more than minor significance because the failure to conduct required visual examinations and identify the degraded moisture barriers, which could allow the intrusion of water, if left uncorrected, had the potential to lead to a more significant concern. The inspectors used IMC-0609, Appendix A, The Significance Determination Process (SDP) For Findings At-Power, Exhibit 3 Barrier Integrity Screening Questions, and determined that the finding was of very low safety significance (Green) because it did not represent an actual open pathway in the physical integrity of the reactor containment and did not involve an actual reduction in function of hydrogen igniters in the reactor containment. The inspectors determined no cross-cutting aspect was associated with this finding because the finding was not reflective of present licensee performance.
05000390/FIN-2016001-012016Q1Watts BarFailure to Use a Procedure Appropriate to the Circumstances for the Auxiliary Control Air System Train AA self-revealing non-cited violation (NCV) of 10 Code of Federal Regulations (CFR) 50, Appendix B, Criterion V, Procedures was identified for the licensees failure to use a procedure appropriate to the circumstances for work associated with the A-A auxiliary control air system (ACAS) compressor. Specifically, the licensee used a section of procedure 0-SOI-32.02, Auxiliary Air System, Revision 2, that placed the air compressor in OFF when it was intended to place it in A-Auto. The licensee restored the compressor to A-Auto and entered this issue into their corrective action program as condition report (CR) 1131261. The performance deficiency was more than minor because it affected the equipment performance attribute of the mitigating system cornerstone to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the ACAS train A was nonfunctional for approximately 19.5 hours on January 29, 2016 and as a supported system, the auxiliary feedwater system was inoperable during this time. The inspectors determined that this finding was of very low safety significance (Green) because the finding did not represent an actual loss of function of a single train for greater than its TS allowed outage time. The finding has a cross cutting aspect in the Work Management component of the Human Performance area because the licensee failed to implement a process of planning, controlling, and executing work activities such that nuclear safety is the overriding priority. Specifically, the planning and execution of work on the A-A ACAS compressor on January 29, 2016 lacked sufficient rigor to ensure the activity was performed as intended.
05000390/FIN-2016001-022016Q1Watts BarInadequate Immediate Determination of Operability for the Auxiliary Control Air System Train AThe NRC identified an NCV of 10 CFR 50, Appendix B, Criterion V, Procedures, for the licensees failure to follow TVA procedure OPDP-8, Operability Determination Process and Limiting Conditions for Operation Tracking, Revision 21. Specifically, the licensee failed to base an immediate determination of operability (IDO) for the auxiliary control air system on information sufficient to conclude that a reasonable expectation of operability/functionality existed. The licensee subsequently implemented compensatory measures and entered this issue into their corrective action program as CR 1129322. The performance deficiency was more than minor because it affected the equipment performance attribute of the mitigating system cornerstone to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, reasonable assurance of operability/functionality did not exist for the A train of auxiliary control air from January 13, 2016, until January 14, 2016, and it therefore should have been declared inoperable/nonfunctional. The inspectors determined that this finding was of very low safety significance (Green) because the finding did not represent an actual loss of function of a single train for greater than its TS allowed outage time. This finding had a cross-cutting aspect in the area of Human Performance, conservative bias, because the licensee failed to make the conservative decisions. Specifically, the licensee reinstalled a degraded valve in the auxiliary control air system without fully understanding the failure mechanism or its impact on system operability/functionality.
05000390/FIN-2016001-032016Q1Watts BarFailure to Adequately Implement the Administration of Site Technical Procedures for TDAFW Pump Governor CalibrationThe NRC identified an NCV of TS 5.7.1.1.a, Procedures, for the licensees inadequate implementation of procedure NPG-SPP-01.2, Administration of Site Technical Procedures, Revision 8. Specifically, the licensee determined applicable acceptance criteria steps in technical procedures were not applicable (N/A) in lieu of performing a procedure change. This resulted in challenging the operability of safety-related plant equipment. The licensee entered this issue into their corrective action program as CR 1125256. The performance deficiency was more than minor because, if left uncorrected, it could lead to a more significant safety concern with the use of N/A and implementation of site technical procedures. Specifically, if further adjustments outside of the acceptance criteria or additional acceptance criteria were not met, it could have resulted in the turbine-driven auxiliary feedwater pump becoming inoperable. The inspectors determined this finding to be of very low safety significance (Green) because it was a deficiency affecting the design or qualification of equipment and operability was maintained. The finding had a cross-cutting aspect of Procedure Adherence, as described in the Human Performance cross-cutting area because the licensee failed to comply with NPG-SPP-01.2.
05000390/FIN-2016001-042016Q1Watts BarFailure to Place the RHR System in ECCSStandby Mode Prior to Exceeding an RCS Temperature of 212 oFThe NRC identified an NCV of TS 5.7.1.1.a, Procedures, for the licensees failure to place the residual heat removal (RHR) system into ECCS-Standby Mode prior to the reactor coolant system (RCS) temperature exceeding 212 oF as required by procedure 1-GO-1, Unit Startup from Cold Shutdown to Hot Standby, Revision 4. The licensee entered this issue into their corrective action program as CR 1127691. The performance deficiency was determined to be more than minor because, if left uncorrected, a failure to align a safety system under the proper plant conditions could lead to that system being inoperable or degraded. The inspectors determined that this finding was of very low safety significance (Green) because the system temperatures never rose high enough to allow the RHR pump suction header to form steam voids. The performance deficiency had a cross-cutting aspect of Avoid Complacency in the area of Human Performance because licensee personnel were complacent and failed to question the long held idea that the particular step just needed to be started prior to exceeding an RCS temperature of 212 oF.
05000390/FIN-2016001-052016Q1Watts BarFailure to Use Approved Procedures to Place RHR Letdown In ServiceThe NRC identified an NCV of TS 5.7.1.1.a, Procedures, for the licensees failure to use any approved procedures to place RHR Letdown in service. The licensee entered this issue into their corrective action program as CR 1127691. The performance deficiency was determined to be more than minor because if left uncorrected a failure to use procedures to place systems or portions of systems in service could result in equipment being operated incorrectly and that system could then become inoperable or degraded. The inspectors determined that this finding was of very low safety significance (Green) because the way that the system was placed in service did not cause any safety-related components to become inoperable nor did it represent an actual loss of function of one or more non-TS trains of equipment designated as high safety-significant in accordance with the licensees maintenance rule program for greater than 24 hours. The performance deficiency had a cross-cutting aspect of safety conscious work environment (SCWE) policy in the area of Safety Conscious Work Environment because the licensee organization failed to effectively implement a policy that supports individuals rights and responsibilities to raise safety concerns, and does not tolerate harassment, intimidation, retaliation, or discrimination for doing so.
05000390/FIN-2016001-062016Q1Watts BarFailure to Track Applicable Technical Specification Action Statement for Charging Pump InoperabilityThe NRC identified an NCV of TS 5.7.1.1.a, Procedures, for the licensees failure to implement OPDP-8, Operability Determinations and LCO tracking. Specifically, the licensee failed to track the applicability of action statement B of TS LCO 3.5.3, ECCS- Shutdown, during planned testing. The licensee entered this issue into their corrective action program as CR 1134949. The licensees failure to track applicable TS LCOs, as required by Section 3.5.1 of OPDP-8 was a performance deficiency. The performance deficiency was more than minor because, if left uncorrected, it would have had the potential to lead to a more significant safety concern in that, the failure to track an applicable TS action statement could lead to plant operations outside of TS analyzed conditions. The inspectors determined that this finding was of very low safety significance (Green) because the finding did not represent an actual loss of function of a single train for greater than its TS allowed outage time nor did it represent an actual loss of function of one or more non-TS equipment for greater than 24 hours. The performance deficiency had a cross-cutting aspect of Challenge the Unknown in the area of Human Performance because licensee personnel did not appropriately stop, question, and evaluate the risks before proceeding when the 1A-A CCP oil cooler low flow alarm came in during flow testing.
05000390/FIN-2016001-102016Q1Watts BarFailure to Maintain an Adequate Surveillance Procedure for Emergency Core Cooling System VentingThe inspectors identified an apparent violation of TS 5.7.1.1.a, Procedures, for the licensees failure to maintain procedure 1-SI-63-10.1-A, ECCS Discharge Pipes Venting Train A Inside Containment, Revisions 11-16, in accordance with the requirements of Regulatory Guide 1.33. Specifically, the procedure did not have provisions for quantifying accumulated gases during venting which allowed emergency core cooling system (ECCS) piping to be vented without being evaluated for potential adverse impacts on system operability. The licensee implemented manual ultrasonic testing (UT) of gas accumulation and entered this issue into their corrective action program as CR 1136359. The performance deficiency was more than minor because, if left uncorrected, it had the potential to lead to a more significant safety concern. Specifically, if left uncorrected, the potential existed for an unacceptable void affecting ECCS operability to develop prior to the next scheduled surveillance. The inspectors determined the finding could not be screened to GREEN and may require a detailed risk evaluation following a determination of whether the finding represents a loss of system and/or function. Because the safety characterization of this finding is not yet finalized, it is being documented with a significance of To Be Determined (TBD). The inspectors determined that the finding had a cross-cutting aspect of Change Management in the area of Human Performance because the licensee failed to use a systematic process to implement changes to the ECCS venting procedure to ensure that Generic Letter 2008-01 commitments would continue to be met.
05000390/FIN-2016001-112016Q1Watts BarLicensee-Identified ViolationWatts Bar Operating License Condition 2.F requires that the licensee shall implement and maintain in effect all provisions of the approved fire protection program, as described in the Fire Protection Report for Watts Bar Unit 1, as approved in Supplements 18 and 19 of the SER (NUREG-0847). Fire Protection Report, Part V, Section 2.1, Safe Shutdown Procedures states, in part, the fire safe shutdown procedures contained in AOI-30.2 were developed based on calculations WBN-OSG4-031, Equipment Required for Safe Shutdown per 10 CFR 50 Appendix R, and WBN-OSG4-165, Manual Actions Required for Safe Shutdown Following a Fire. Calculation WBN-OSG4-165 is contained within drawing 1-45A897-1, Manual Actions Required for Safe Shutdown Following a Fire to 10 CFR 50 Appendix R. Contrary to the above, since initial plant licensing, the licensee failed to perform an adequate calculation to support fire safe shutdown procedure AOI-30.2. Specifically, for certain fire scenarios, the licensee failed to identify all equipment required to ensure availability of the TDAFW pump; and, for certain fire scenarios, the licensee established a non-conservative time requirement to mitigate spurious opening of a pressurizer PORV to prevent an undesired safety injection. This violation is of very low safety significance (Green). This issue was determined to be of very low safety significance based on the results of the IMC 0609, Appendix F, Fire Protection Significance Determination Process, Phase II Quantitative Screening Approach. A bounding risk assessment performed by a regional SRA reviewed the licensee and inspector risk evaluations and confirmed the CDF risk increase due to this condition was less than 1E-6, and therefore Green. This violation was documented in the licensees corrective action program as CRs 946764 and 999926.
05000390/FIN-2016001-122016Q1Watts BarLicensee-Identified ViolationTechnical Specification 5.7.1, Procedures, requires, in part, that written procedures shall be established, implemented, and maintained covering activities described in Regulatory Guide (RG) 1.33, Revision 2, Appendix A, February 1978; Appendix A, Section 6.v, requires procedures for Combating Emergencies and other Significant Events such as Plant Fires. Contrary to the above, the licensee provided operators inadequate procedural instructions to support fire safe shutdown. Specifically, since 2012, for certain fire scenarios, fire SSD procedures did not contain necessary steps to secure all reactor coolant pumps to prevent inadvertent RCS depressurization due to spurious opening of a pressurizer spray valve. Additionally, since initial plant licensing, for certain fire scenarios, fire SSD procedures did not contain necessary steps to isolate the normal charging line to prevent inadvertent RCS depressurization due to spurious opening of an auxiliary pressurizer spray valve. This violation is of very low safety significance (Green). This issue was determined to be of very low safety significance based on the results of the IMC 0609, Appendix F, Fire Protection Significance Determination Process, Phase II Quantitative Screening Approach. A bounding risk assessment performed by a regional SRA reviewed the licensee and inspector risk evaluations and confirmed the CDF risk increase due to this condition was less than 1E-6, and therefore Green. This violation was documented in the licensees corrective action program as CRs 954895 and 954957.
05000269/FIN-2016007-022016Q1OconeePostulated Fire Affecting High Pressure Injection Pump Did Not Receive a VFDR EvaluationThe NRC identified a Green NCV of 10 CFR 50.48(c) and National Fire Protection Association Standard (NFPA) 805, Section 2.4.2.4 for the licensees failure to perform an adequate engineering analysis to determine the effects of fire on the ability to achieve the nuclear safety performance criteria, and consequently, did not add an associated variation from deterministic requirements (VFDR) into the Fire probabilistic risk assessment (PRA). Specifically, the licensees Nuclear Safety Capability Assessment (NSCA) failed to identify cables in the turbine building (TB) that could prevent the operation of the High Pressure Injection (HPI) Pumps. This item was entered into the corrective action program (CAP) as action request (AR) 02011673, and the licensee implemented compensatory measures in the form of hourly fire watches. The performance deficiency (PD) was more than minor because it was associated with the reactor safety Mitigating Systems cornerstone attribute of protection against external factors (i.e. fire), 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, the licensees failure to analyze the effects of fire damage on the HPI cables in the TB could result in fire damage adversely affecting the ability to achieve and maintain safe and stable conditions. Using the guidance of IMC 0609, App. F, the finding was screened as Green because the finding did not affect the ability to reach and maintain a stable plant condition within the first 24 hours of a fire event (Task 1.4.5-B). A cross cutting aspect in the area of Human Performance, Consistent Process because the licensee did not use a consistent, systematic approach to make decisions, and did not incorporate appropriate risk insights (H.13).
05000269/FIN-2016007-012016Q1OconeePressure Boundary of Motor Operated Valves Could be Breached Due to Fire- Induced Hot ShortAn unresolved item was identified regarding the licensees evaluation of certain motor operated valves (MOVs) in the NSCA. Specifically, based on the conclusions in the licensees NSCA, as well as subsequent evaluations, MOVs that are subject to a hot short that bypasses the torque or limit switch could result in damage to the valve that causes an unmitigated loss of reactor coolant system (RCS) inventory due to leakage through the damaged valves pressure boundary or the valves associated sealing components. Information Notice 92-18, Potential for Loss of Remote Shutdown Capability During a Control Room Fire, stated that fire damage could cause an electrical hot short that bypasses thermal overload protection for MOVs, and that this hot short could result in damage to the valve. As a part of the licensees transition to NFPA 805, the licensee identified a number of MOVs that could be susceptible to IN 92-18 type damage. These valves were classified as non-compliant components or variances from deterministic requirements (VFDRs). The subsequent evaluation of these valves by the licensees Fire PRA group determined that these VFDRs met the acceptance criteria of the Fire Risk Evaluation, as documented in OSC-9314, as being acceptable "as-is" and that no further action was required. These VFDRs and their FPRA dispositions were communicated to the NRC in the April 2010 Oconee NFPA 805 license amendment request (LAR). Subsequent to NRCs issuance of the SER, Oconee Valve Engineering determined that, due to the size of the installed motor/gearbox, 10 MOVs could potentially suffer IN 92-18 damage to the extent that the integrity of the valve body or bonnet could be compromised. Loss of valve integrity of the valve pressure boundary was not an assumption used in the FPRA evaluation. The licensee documented this condition in AR 01906086. After further evaluation, the licensee documented in AR 01999309 that 9 of the original 10 valves identified could potentially suffer IN 92-18 damage to the extent that the integrity of the valve body or bonnet could be compromised. For the 9 affected valves, the licensee has undertaken additional evaluations to determine whether some portion of the valve would fail before the valves pressure boundary is compromised, or that any possible leakage that may result can be bounded by the credited RCS make-up sourcein this case, the reactor coolant make-up pump. Inspectors determined that no immediate safety concern existed with this item because the licensee had implemented compensatory measures in accordance with the sites approved FPP. This item is unresolved pending inspector receipt and review of the licensees evaluation.
05000390/FIN-2016001-072016Q1Watts BarFailure to Maintain Operating LogsThe NRC identified a NCV of 10 CFR 50, Appendix B, Criterion XVII, Quality Assurance Records, for the licensees failure to maintain sufficient records to furnish evidence of activities affecting quality. The licensee entered this issue into their corrective action program as CR 1127691. The inspectors determined that the licensees failure to document plant operations in the operating logs in accordance with OPDP-1 was a violation of 10 CFR 50, Appendix B, Criterion XVII, Quality Assurance Records. This violation constitutes a traditional enforcement violation because it impacts the NRC's ability to carry out its regulatory function. The failure to maintain accurate logs was more than minor because it would have likely caused the NRC to undertake further inquiry and was consistent with Enforcement Policy section 6.9.d.1 for a SL-IV violation. Crosscutting aspects are not assigned to traditional enforcement violations.
05000390/FIN-2016001-082016Q1Watts BarCharging Pump 1B-B Room Cooler Fan Bearing FailureInspectors identified an unresolved item (URI) associated with the failure of the 1B-B charging pump room cooler. This item is unresolved pending review of an equipment apparent cause evaluation that was performed after deficiencies were identified by inspectors in the past operability evaluation. On September 27, 2015, the licensee installed a new bearings on the 1B-B CCP room cooler fan shaft as part of planned maintenance (PM) under WO 115790759. The WO noted the room cooler had a broken lubrication line close to the point where it is attached to the outboard fan shaft bearing, but the new bearing on the fan shaft, including the outboard shaft bearing, were installed without an immediate repair of the lubrication line. The bearing replacements for WO 115790759 were accomplished in accordance with maintenance procedure 0-MI-0.16, Maintenance Guidelines for Belt Driven Equipment, Rev. 7. Appendix D, Bearing Installation, Step 14 requires, All remote lubrication lines, remote vibration attachments, etc. shall be verified as attached prior to return to service. The work order noted at this step that the lubrication line to the outboard fan shaft bearing was broken in half and will need to be replaced prior to return to service and the step was left blank. The licensee did not initiate a CR for this degraded condition. Due to the broken lubrication line, the outboard fan shaft bearing was the only fan shaft bearing that was not greased during installation. October 15, 2015, the licensee completed the PMT for the room cooler and noted it to be satisfactory. The broken lubrication line documented in the PM WO was identified and CR 1093983 was initiated to document the condition. This CR stated that the broken lubrication line did not affect the functionality of the fan and could be repaired at the next scheduled PM. This assessment was not questioned during the review of the CR for operability. The fan was returned to service and declared operable. On December 4, 2015, the room cooler failed in service. The licensee declared the 1BB charging pump inoperable and entered the applicable TS LCO. Investigation revealed that the outboard fan shaft bearing had failed. At this point, the inappropriate treatment of the degraded lubrication line under 0-MI-0.16 and the associated PMT was identified. This issue was documented in the licensees CAP in CR 1111791. The licensee performed a past operability evaluation (POE) for CR 1111791 which concluded the fan was operable until several hours before the time of the failure. The POE was based largely on statements from the bearing vendor indicating that the new bearing was pre-lubricated at the factory and should have performed under load for a long period of time without needing to be pre-greased at installation. The POE was hampered by the fact that the licensee did not retain the damaged bearing for failure analysis. The inspectors reviewed the POE and determined that it failed to adequately document sufficient information to either discount the broken lubrication line as a cause of the bearing failure or to identify another cause. In response, the licensee opened an investigation of the cause of the bearing failure under an equipment apparent cause evaluation. Because more information is necessary to evaluate the cause of the 1B-B CCP room cooler fan shaft bearing failure, future inspection is required to determine if a more than minor performance deficiency or violation exists associated with this issue. Specifically, the inspectors need to review the equipment apparent cause evaluation, which was not completed by the end of the inspection period. This is identified as URI 05000390/2016001-08, Charging Pump 1B-B Room Cooler Fan Bearing Failure.
05000390/FIN-2016001-092016Q1Watts BarAppropriateness of Corrective Actions Associated with Safety Related Pump Mechanical Seal Issues and the Effect on Plant ResponseThe inspectors identified an URI associated with the timely and effective corrective action associated with an adverse trend in safety related pump performance, including mechanical seal degradation and failure. This item is unresolved pending review and evaluation of the licensees response to the CRs generated to determine if a performance deficiency exists. During Unit 1, 2015 fall outage, the 1A Safety Injection (SI) pump mechanical seal was replaced. The mechanical seal had degraded to a point at which the leakage was greater than the Technical Specification limit for ECCS leakage outside of containment. The inspectors identified several issues during a review of the Prompt Determination of Operability for CR 1125623 and WO 116050574 to replace the seal. Specifically, inspectors found that non-QA1 parts were being used for seal replacement, the seal was the original equipment manufacturer part from startup, the failure mechanism was not clearly understood, and an extent of condition review was not performed. The inspectors reviewed other safety related pump mechanical seal performance and corrective action program entries. The inspectors are awaiting the completion of the licensees evaluation to determine the licensees compliance with applicable procedures and TS relative to pump operability and ECCS leakage limits outside containment. Additional inspection activities are needed to determine the extent of condition and compliance with the procedures and TS. Pending the results of this additional inspection, an URI will be opened and designated as URI 05000390/2016001-09, Appropriateness of Corrective Actions Associated with Safety Related Pump Mechanical Seal Issues and the Effect on Plant Response.
05000269/FIN-2016008-012015Q4OconeePotential lack of adequacy of the licensees maintenance program to detect substantial degradation of cables and their connections used on Oconee large oil filled stationary transformersAn URI was identified to determine if a performance deficiency exists regarding the adequacy of the licensees maintenance program to detect substantial degradation of cables and their connections used on the stations large oil filled stationary transformers. Description The inspectors developed an issue of concern related to the adequacy of the licensees maintenance program to detect substantial degradation of cables and their connections used on the stations large oil filled stationary transformers. The inspectors noted that all inspections required by the licensees surveillance and preventative maintenance programs used unaided visual inspections of bushings, surge arrestors, cable connections, T-connections, and cables on the stations large oil filled stationary transformers. The inspectors noted that the licensees metallurgical report associated with the failed power cable from the Unit 3 startup transformer identified degradation which likely occurred over a lengthy period of time. The inspectors determined that the following inspection activities should be pursued to determine if a performance deficiency exists: Review of the licensees completed cause determination Review of any additional testing and metallurgical reports Review of any license event report submitted by the licensee Review of requirements associated with emergency AC power paths and associated transformers This issue is identified as URI 05000269, 287/2016008-01, Potential lack of adequacy of the licensees maintenance program to detect substantial degradation of cables and their connections used on Oconee large oil filled stationary transformers.
05000369/FIN-2015008-012015Q4Mcguire
McGuire		Failure to Completely and Accurately Translate the Safe Shutdown Analysis to ProceduresThe NRC identified a Green non-cited violation (NCV) of McGuire Technical Specification 5.4.1.a, for Unit 1, for having an inadequate procedure to support safe shutdown for a fire in fire area (FA) 15/17. Specifically, the licensees deterministic safe shutdown analysis identified the need for a procedural action to de-energize PORV 1NC- 34A at power supply 1EVDA, breaker 8. This action was not translated to Enclosure 15 of McGuire fire safe shutdown procedure AP-45. This item was entered into the corrective action program (CAP) as action requests (ARs) 1979875 and 1983360, and the licensee initiated a procedure change to incorporate the missing action. The performance deficiency (PD) was more than minor because it was associated with the reactor safety Mitigating Systems cornerstone attribute of protection against external factors (i.e. fire), and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using the guidance of IMC 0609, App. F, the finding was screened as Green because the finding did not affect the ability to reach and maintain a stable plant condition within the first 24 hours of a fire event (Task 1.4.5-B). No cross cutting aspect was assigned because the finding did not represent current licensee performance.
05000413/FIN-2015004-012015Q4CatawbaFailure to Adequately Implement In-service Test Procedure for the Unit 1 Standby Makeup PumpA Green self-revealing non-cited violation of Technical Specification (TS) 5.4.1, Procedures, was identified for the licensees failure to adequately implement their inservice test procedure for the Unit 1 standby makeup pump (SMP). Operators performed procedure steps out of sequence which resulted in the pumps discharge relief valve lifting, requiring valve replacement. The licensee entered this issue into their corrective action program as nuclear condition report (NCR) 1954266. The performance deficiency was considered to be more than minor because it was associated with the equipment performance attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the SMP was unavailable to perform its safety function during unplanned testing and maintenance. The internal events risk contribution was determined by the inspectors to be 3E-7 and thus required a senior reactor analyst to review for external events and large early release frequency (LERF) to ensure the finding was below the Green/White threshold. The external events contribution was determined to be 5E-7 and thus the total risk was 8E-7 and core damage frequency (CDF) was determined to be the limiting metric. Consequently the finding was determined to be of very low safety significance (Green). This finding had a cross-cutting aspect of avoid complacency, as described in the human performance cross-cutting area, because the operators failed to implement appropriate error reduction tools such as formal three-way communications while performing the SMP surveillance procedure. (H.12)
05000390/FIN-2015004-042015Q4Watts BarShield Building Operability RequirementsThe inspectors identified an unresolved item (URI) associated with the requirements of Watts Bar Unit 1 technical specification (TS) 3.6.15, Shield Building. Additional inspection is required to determine if the requirements of 3.6.15.B applied during a specific testing alignment. On September 10, 2015, the licensee conducted 0-SI-65-6-A, Emergency Gas Treatment System (EGTS) Train A 10-Hour Operation. During the 10-hour time period of the test when the EGTS was in service, the auxiliary gas building treatment system was also in service for a Unit 2 construction test. This unique ventilation combination is not normally experienced during the 0-SI-65-6-A surveillance. As a result, shield building annulus differential pressure fell below the limit established by TS surveillance requirement (TSSR) 3.6.15.1 limits for the entire duration of the 10-hr EGTS surveillance. TS limiting condition for operation (LCO) 3.6.15.B requires annulus pressure be restored when it is outside of limits with a required completion time of 8-hrs. The licensee considered the note associated with TS LCO 3.6.15.B, which states that the annulus pressure requirement is not applicable during ventilating operations, required annulus entries, or auxiliary building isolations not exceeding one hour in duration. The licensee considered the alignment they were in at the time to be ventilating operations and thus the requirements of TS LCO 3.6.15.B did not apply. The licensee further considered that the note, as written, allowed grace from the annulus pressure requirement for ventilating operations for an unlimited amount of time. The inspectors were concerned about a possible allowance in the TS to have grace from annulus pressure requirements for longer than the allowed LCO required action completion time. Furthermore, a basis for the note and what can be considered ventilating operations was not immediately apparent. Because more information is necessary to evaluate the proper applicability of TS LCO 3.6.15.B and the associated note, future inspection is required to determine if a more than minor performance deficiency or violation exists associated with this issue. Specifically, the inspectors need to determine if a TS compliance issue exists. This is identified as URI 0500390/2015004-04, Shield Building Operability Requirements.
05000390/FIN-2015004-022015Q4Watts BarAFWST Permanent Plant ModificationThe inspectors identified an unresolved item (URI) associated with the 50.59 screening performed for the installation of the auxiliary feedwater storage tank (AFWST). Additional inspection is required to determine if the plant modification which installed the tank would have required NRC permission in the form of a license amendment prior to the change. The AFWST is a 500,000 gallon source of clean water for the auxiliary feedwater (AFW) pumps. It was installed as part of the licensees post-Fukushima (FLEX) modifications to meet the mitigating strategies order (EA-12-049). The new tank was needed because the licensee determined they could not credit their existing condensate storage tanks (CSTs) for FLEX strategies due to seismic requirements necessary to survive the extended loss of AC power (ELAP) event. The AFWST was connected to the existing condensate system in the AFW supply piping upstream from the AFW pumps and downstream from the CSTs. The modification was evaluated in two separate DCNs, each with its own 50.59 applicability screening. DCN 60060 evaluated the installation of the tank and DCN 61422 evaluated the piping connections to the condensate system. The piping connections included new check valves in the CST piping to prevent AFWST inventory loss in the event the CSTs are damaged in the ELAP event. There were also two air-operated supply valves on AFWST outlet piping which automatically open on low pressure in the downstream condensate piping and also fail open on a loss of power or air. Inspectors noted a number of deficiencies in the 50.59 screening for DCN 61422. Inspectors determined that several potentially adverse impacts were introduced by the modification and were not adequately considered in the 50.59 screening. The licensee re-performed the screening and concluded that the modification would require a 50.59 evaluation due to adverse impacts brought up by the inspectors. Because more information is necessary to properly evaluate the 50.59 evaluation that was completed late in the quarter, future inspection is required to determine if a more than minor performance deficiency or violation exists associated with this issue. Specifically, the inspectors need to determine if prior NRC approval was required for the installation of the AFWST. This is identified as URI 05000390/2015004-02, AFWST Permanent Plant Modification.
05000424/FIN-2015007-012015Q3VogtleFailure to Fully Close and Latch Plant Fire DoorsAn NRC-identified Green non-cited violation of Vogtle Units 1 and 2 Operating License Conditions 2.G, was identified for the licensees failure to ensure that fire doors V22108L1A67, V12111L1238, and V12111L1A41 in 3-hour rated fire barriers were fully closed and latched, as required by the approved fire protection program (FPP) and National Fire Protection Association (NFPA) Code 80-1983, Fire Doors and Windows (Vogtle NFPA Code of Record). The licensee took corrective actions and declared fire door V22108L1A67 inoperable and established a roving fire watch. The inoperable door was entered into the licensees corrective action program as condition report (CR) 10067247 and was repaired the next day. For doors V12111L1238 and V12111L1A41, the licensee immediately removed materials that were interfering with the latching of the doors and entered these into their corrective action program as CR 10096004 and CR10096008 respectively. Because these two conditions were corrected as soon as they were brought to the licensees attention by the inspectors, no fire watch was required to be established. The licensees failure to ensure the three fire doors were fully closed and latched as required by the approved FPP and NFPA Code 80-1983 was determined to be a performance deficiency. This performance deficiency was more than minor because it affected the reactor safety mitigating systems cornerstone attribute of protection against external events (i.e., fire) and adversely affected the fire protection defense-in-depth element involving fire confinement and control of fires that do occur to protect systems important to safety. The finding was screened in accordance with NRC Inspection Manual Chapter (IMC) 0609, Significance Determination Process, Attachment 4, Initial Characterization of Findings, which determined that an IMC 0609, Appendix F, Fire Protection Significance Determination Process, review was required as the finding involved the ability to confine a fire. The finding category of Fire Confinement was assigned, based upon that element of the FPP being impacted. Using IMC 0609, Appendix F, Attachment 1, Fire Protection Significance Determination Process Worksheet, the inspectors determined that the finding was of very low safety significance (Green) at Task 1.4.3, Question C, based upon observation that a fully functioning, automatically actuated, fire suppression system was installed on both sides of fire doors V12111L1238 and V12111L1A41 and on one side of fire door V22108L1A67. The inspectors determined that the finding had a cross-cutting aspect of Procedure Adherence in the Human Performance area because individuals did not follow processes and procedures for ensuring that fire doors were properly closed and latched after passing through the doors.
05000424/FIN-2015007-022015Q3VogtleFailure to Identify and Repair a Degraded Fire Penetration SealAn NRC-identified Green non-cited violation of Vogtle Unit 1 Operating License Condition 2.G was identified for the licensees failure to identify and repair degraded fire penetration seal 1-11-759A, as required by the approved fire protection program (FPP). The licensee took corrective actions to declare the penetration seal inoperable, entered the issue in their corrective action program as condition report 10102010 and established a roving fire watch. The licensees failure to identify and repair the degraded fire penetration seal 1-11-759A was a performance deficiency. This performance deficiency was more than minor because it affected the reactor safety mitigating systems cornerstone attribute of protection against external events (i.e., fire) and adversely affected the fire protection defense-in-depth element involving fire confinement and control of fires that do occur to protect systems important to safety. The finding was screened in accordance with NRC Inspection Manual Chapter (IMC) 0609, Significance Determination Process, Attachment 4, Initial Characterization of Findings, which determined that an IMC 0609, Appendix F, Fire Protection Significance Determination Process, review was required as the finding involved the ability to confine a fire. The finding category of Fire Confinement was assigned, based upon that element of the FPP being impacted. Using the criteria contained in IMC 0609 Appendix F, Attachment 2, Table A2.2, the inspectors concluded that the seal degradation level was low because the silicone foam seal depth and a fully intact damming board on one side of the barrier would have been sufficient to provide at least two hours of fire resistance. In addition, it was noted that the fire zones on each side of the degraded fire penetration seal were protected with an automatic fire suppression system. Using IMC 0609, Appendix F, Attachment 1, Fire Protection Significance Determination Process Worksheet, the inspectors determined that the finding was of very low safety significance (Green) at Task 1.4.3, Question C. The inspectors determined that the finding had a cross-cutting aspect of Avoid Complacency in the Human Performance area because individuals inspecting the seals failed to recognize and plan for the possibility of the penetration seal being damaged.
05000321/FIN-2015003-012015Q3HatchFailure to Perform Adequate Surveillance on Fire Barriers and Penetration SealsThe NRC identified a non-cited violation (NCV) of Hatch Operating License Conditions (OLCs) 2.C.(3) and 2.C.(3)(a), for Units 1 and 2 respectively, for the licensee s failure to perform fire barrier penetration seal inspections in accordance with the requirements of Surveillance Requirement 2.1.1.c of Appendix B of the Fire Hazard Analysis (FHA). Specifically, the licensee failed to ensure that fire-rated penetrations and fire-rated barriers separating redundant safe-shutdown trains were adequate to keep a fire from spreading from one fire area to another. To restore compliance the licensee performed a 100 percent inspection of fire-rated penetrations to verify the material condition of the site s rated fire barrier penetrations. The licensee s failure to perform fire barrier penetration seal inspections was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the reactor safety Mitigating Systems cornerstone attribute of protection against external factors (i.e. fire), and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Based on the finding being of very low probability, the finding was determined to be of very-low safety significance (Green). The cause of the finding had a cross-cutting aspect in the area of Human Performance, field presence, because plant leadership did not reinforce standards and expectations, and did not ensure that deviations from standards and expectations were corrected promptly (H.2). Specifically, licensee oversight was not properly engaged to ensure that surveillances were performed adequately, and that deviations were addressed appropriately.
05000321/FIN-2015003-022015Q3Hatch1A PSW Pump High Vibration FailureA self-revealing, NCV of 10 CFR 50, Appendix B, Criterion V, Procedures, Instructions, and Drawings, was identified when the licensee failed to provide instructions to ensure alignment of the 1A plant service water (PSW) pump column in the true vertical position. The failure to align the 1A PSW pump column resulted high stresses which caused the failure of the 1A PSW pump. To restore compliance, the licensee replaced the 1A PSW pump and revised the pump installation procedure to ensure the pump column is aligned in the true vertical position. Failure to provide instructions to ensure appropriate vertical alignment of the 1A PSW pump column was a performance deficiency. This performance deficiency was more than minor because it affected the Mitigating Systems cornerstone attribute of Equipment Performance and adversely affected the cornerstone objective in that the misalignment of the pump column resulted in inoperability of the 1A PSW pump. A regional Senior Reactor Analyst (SRA) performed a detailed risk review of the finding. The SRA calculated the difference between the risk associated with loss of offsite power (LOOP) events with extended recovery times with the 1A pump available, and without the pump. Because of the low frequency of the seismic event, the finding was determined to be Green. The inspectors determined that this finding did not have an associated cross cutting aspect because this finding was not reflective of current licensee performance.
05000321/FIN-2015003-032015Q3HatchLicensee-Identified ViolationTechnical Specification 3.4.3 requires 10 of 11 safety relief valves (SRVs) to be operable during Mode 1, 2, and 3. Contrary to the above, the licensee identified during bench testing that two safety relief valves failed to lift at the required technical specification setpoint, and therefore were inoperable in Mode 1, 2, and 3. Analysis showed that with the SRVs lifting at the as-found bench test setpoints, the SRVs still would have maintained reactor coolant system pressure below the TS safety limit requirements. The inspectors determined the violation was of very low safety significance (Green) because the SRVs maintained their functionality. This condition was documented in the licensees corrective action program as CR 10067922
05000259/FIN-2015002-022015Q2Browns FerryLicensee-Identified ViolationBrowns Ferry Technical Specification (TS) 5.7.1, High Radiation Area, requires, in part, that each individual or group entering HRAs shall possess: 1) A radiation monitoring device that continuously displays radiation dose rates in the area; or 2) A radiation monitoring device that continuously integrates the radiation dose rates in the area and alarms when the device's dose alarm setpoint is reached, with an appropriate alarm setpoint, or 3) A radiation monitoring device that continuously transmits dose rate and cumulative dose information to a remote receiver monitored by radiation protection personnel responsible for controlling personnel radiation exposure within the area. Contrary to the above, on April 3, 2015, the licensee did not ensure the use of a radiation monitoring device that continuously transmits dose rate and cumulative dose information by an individual who entered the refueling cavity, a high radiation area with a radiation dose rate of approximately 260 mrem in one hour at 30 centimeters from the reactor vessel. Upon identification, the licensee immediately implemented RCA access restrictions for the individual and relocated the smart turnstile at the HRA entrance. This violation was determined to be not greater than very low safety significance (Green) because it was not related to As Low As Reasonably Achievable planning, it did not involve an overexposure or substantial potential for overexposure, and the ability to assess dose was not compromised because the individual was wearing passive dosimetry (OSLD). Subsequent comparison of the workers OSLD with the OSLD and electronic dosimeter of coworkers on the same crew resulted in the worker being assigned 19 mrem for the time he was in the area without an electronic dosimeter. This violation was violation was entered into the licensees Corrective Action Program as SR1008704.
05000296/FIN-2015002-012015Q2Browns FerryUnit 3 HPCI Turbine Exhaust Drain High LevelThe inspectors identified an unresolved item (URI) associated with repeat observations of HPCI Turbine Exhaust Drain Pot High Level Alarms upon shutdown of the Unit 3 HPCI turbine. Information associated with the licensees cause determination, previous corrective actions, and design change documentation required for review of the HPCI Turbines final operability determination and disposition the issue was not available at the conclusion of the inspection period. The inspectors conducted a review of the implementation of corrective actions from related PERs 885945, 933630, and 999196 which were written due to repeat observations of HPCI Turbine Exhaust Drain Pot High Level Alarms upon shutdown of the Unit 3 HPCI turbine. The review revealed that the HPCI system was unknowingly in a degraded state and because the licensee did not effectively document all aspects of the problem, appropriate corrective actions and operability determinations were not completed in a timely manner. Specifically, the amount of water drained from the turbine casing was not recorded until the third occurrence, but even then, the amount was an estimation. Following questioning by the NRC inspectors, the licensee discovered that the severity of the problem had been underestimated and that the turbine exhaust vacuum breakers may not be adequately designed to prevent siphoning of suppression pool water back to the turbine casing. Ultimately, with engineering support from the system vendor, the licensee determined that the HPCI system remained operable despite the presence of approximately 190 gallons of water in the turbine casing. Because more information is necessary to properly evaluate the final operability determination, licensee actions, and system design, future inspection is required to determine if a more than minor performance deficiency or violation exists associated with this issue. Initial reviews have not identified any immediate safety concerns associated with the determination. This is identified as URI 05000296/2015002-01, HPCI Turbine Exhaust Drain High Level.
05000321/FIN-2015001-012015Q1HatchFailure to perform adequate surveys of air samples for alpha activityAn NRC-Identified non-cited violation (NCV) of 10 CFR 20.1501(a) was identified for failure to perform an adequate survey. Air samples obtained in the reactor cavity and on the refuel floor during a contamination event indicating greater than 0.3 beta-gamma Derived Air Concentration (DAC) fraction level were not analyzed for alpha activity as required by the licensees procedures. Previous characterization of the area had determined the area to be an Alpha Level II area requiring additional assessment and evaluation of air samples. This violation was entered into the licensees CAP as CR 10033022. This finding is greater than minor because it was associated with the Occupational Radiation Safety Cornerstone attribute of Program and Process (Monitoring and RP Controls) and adversely affected the cornerstone objective in that failure to identify potentially significant contributors to internal dose could lead to unmonitored occupational exposures. The finding was determined to be of very low safety significance (Green) because it was not related to As Low As Reasonably Achievable (ALARA) Planning and the ability to assess dose was not compromised during these instances. The cause of this finding was directly related to the cross-cutting aspect of leaders ensuing equipment, procedures, and other resources are available and adequate in the Resources component of the Human Performance area.
05000321/FIN-2015001-052015Q1HatchLicensee-Identified ViolationTechnical Specification 5.7.2 requires areas with radiation levels greater than or equal to 1000 mrem/hr, measured at 30 cm from the radiation source or from any surface the radiation penetrates, but less than 500 Rads in 1 hour measured at 1 meter from the radiation source or from any surface the radiation penetrates shall be provided with a locked or continuously guarded doors to prevent unauthorized entry. Contrary to this on 12/18/14, a RPT found the Unit 1 Recombiner Preheater B room door propped open and not posted as a LHRA. Follow-up surveys of the area identified maximum radiation levels of 1600 mR/hr at 12 inches from surface of the preheater. This finding was of very low safety significance (Green) because there was no substantial potential for overexposure and the licensees ability to assess dose was not compromised. This violation was documented in the licensees CAP as CAR 249078.
05000321/FIN-2015001-042015Q1HatchLicensee-Identified Violation10 CFR Part 50.48(b)(1) required that all nuclear power plants licensed to operate prior to January 1, 1979, must satisfy the applicable requirements of 10 CFR Part 50, Appendix R, Sections III.G.2 or III.G.3. Contrary to the above, since November 1985, the licensee has not met the requirements of 10 CFR Part 50, Appendix R, Sections III.G.2 or III.G.3, in that the licensee failed to provided adequate protection of cables and equipment of redundant trains of systems necessary to achieve and maintain hot shutdown conditions located in the same fire area by either (a) a 3-hour rated fire barrier; (b) 20 feet of spatial separation with detection and suppression installed in the fire area; or (c) a 1-hour rated fire barrier with detection and suppression installed in the fire area; or by providing alternative shutdown capability for the areas where adequate cable protection was not provided. This violation was determined to be of very low safety significance (Green) based on the results of the IMC 0609, Appendix F, Fire Protection Significance Determination Process, Phase III Quantitative Screening Approach. This violation was documented in the licensees CAP as CRs 687178, 688543, 687173, and 692904
05000321/FIN-2015001-032015Q1HatchFailure to Identify Embedded Conduit prior to Core Drill OperationsA self-revealing non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion V, Procedures, Instructions, and Drawings, was identified for failure to identify existing embedded conduit in the vicinity of prescribed core drills location. The violation was entered into the licensees corrective action program (CAP) as condition report (CR) 902506. Failure to provide adequate instructions in Design Change Package (DCP) SNC467474 to perform core drills in the Unit 2 control building to support conduit installations was a performance deficiency. This performance deficiency is more than minor because it affected the Equipment Performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective in that 2P41F316A was rendered incapable of performing its safety related function of closing in the event of an accident condition. The finding was screened as Green because the inoperability did not last longer than the technical specification (TS) allowed outage time. The inspectors determined the performance deficiency has a cross-cutting aspect of work management in the human performance area, because the licensees work process did not identify and manage the risk commensurate to the core drill work.
05000366/FIN-2015001-022015Q1HatchFailure to perform complete analysis of air samplesAn NRC-Identified non-cited violation (NCV) of TS 5.4.1 was identified for the failure of the licensee to perform complete quantitative analysis of air samples using approved counting equipment as required by the licensees procedures. NMP-HP-301, Step 5.6, provides guidance for quantitative evaluation of air samples. On February 16, and 25, 2015, air samples for work activities in the Reactor Pressure Vessel head (RPV) and the Reactor Water Cleanup (RWCU) System heat exchanger were not quantitatively analyzed or evaluated for alpha activity even though the areas had been identified as having elevated alpha contamination levels. The licensee entered the issue into their corrective action program (CAP) as CR 10034556. The finding was more than minor because it was associated with the Occupational Radiation Safety Program attribute of exposure control and affected the cornerstone objective of ensuring adequate protection of worker health and safety from exposure to radiation from airborne radioactive material during routine civilian nuclear reactor operation. Failure to identify potentially significant contributors to internal dose could lead to unmonitored occupational exposures. The finding was determined to be of very low safety significance (Green) because it did not involve: (1) an as low as is reasonably achievable finding, (2) an overexposure, (3) a substantial potential for overexposure, or (4) an impaired ability to assess dose related to As Low As Reasonably Achievable (ALARA) Planning and the ability to assess dose was not compromised during this instance. The cause of this finding was directly related to the cross-cutting aspect of following processes, procedures, and work instructions in the Procedure Adherence component of the Human Performance area.
05000321/FIN-2015001-062015Q1HatchUnfused DC Ammeter Circuits Result in an Unanalyzed ConditionOn April 28, 2014, the licensee submitted an LER documenting the discovery of a condition of non-compliance with the sites fire protection program (FPP). This condition could prevent operators from achieving and maintaining safe shutdown (SSD) of the plant, in the case of a postulated fire. The inspectors reviewed documents related to the LER and discussed the event with plant personnel to assess if the licensees compensatory measures and corrective actions were adequate. The licensee identified a non-compliance with Hatch Renewed License Conditions 2.C.(3) and 2.C.(3)(a), for Units 1 and 2. The licensee failed to provide short circuit protection for non-safety-related associated circuits which could result in a secondary fire in another fire area and adversely affect SSD capability. Description: During a review of industry operating experience (OE) related to unfused DC ammeter circuits the licensee determined that certain DC ammeter circuits lacked short circuit protection. A postulated fire in a fire area containing affected DC ammeter circuit cabling could result in concurrent shorts in the circuit. Due to the lack of short circuit protection, the resultant excessive current flow in the DC ammeter cable could result in a secondary fire in another fire area and adversely affect SSD equipment or cables for SSD equipment. Multiple fire areas in the Control Building were potentially affected. Section 9.6.2.4 of Appendix E of the licensees Fire Hazards Analysis (FHA) categorizes associated circuits of concern into 3 types. Type C associated circuits were defined as nonsafe shutdown circuits which shared a common enclosure with safe shutdown circuits and were not electrically protected by an automatic fault protection device or were not inherently self-protected because the circuit lacks sufficient energy to cause circuit damage. A subsequent paragraph in Section 9.2.6.4 stated that Type C associated circuits are electrically protected by automatic fault interrupting devices, do not carry sufficient energy to cause cable damage, and will not propagate fire into a common enclosure in another fire area. The licensees OE review determined that certain DC ammeter circuits were not provided with automatic fault interrupting devices, and thus, invalidates the SSD evaluation bases stated in Section 9.6.2.4 of the FHA. Upon discovery, the licensee implemented roving fire watches for the affected areas. Analysis: The licensees failure to provide short circuit protection for DC ammeter circuits is a performance deficiency. This finding is more than minor because it is associated with reactor safety mitigating system cornerstone attribute of Protection Against External Events (i.e., fire) and adversely affected the cornerstone objective in that not providing circuit protection could have affected the licensees SSD capability. Because this issue relates to fire protection, and this noncompliance was identified by the licensee as a part of the sites transition to NFPA 805, this issue is being dispositioned in accordance with Section 9.1, Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48) of the NRC Enforcement Policy. In order to verify that this non-compliance was not associated with a finding of high safety significance (Red), a bounding phase 3 SDP risk analysis was performed by a regional SRA using the guidance from NRC Inspection Manual Chapter 0609 Appendix F and NUREG/CR 6850 revision 0 and Supplement 1. The analysis used inputs from the licensees NFPA 805 project for ignition frequency and cable routing data. The major analysis assumptions were: a one year exposure period, two proper DC polarity hot shorts required to achieve the high current conditions for secondary fires, and all ignition sources for each affected fire zone assumed to damage the ammeter cables. Based on this bounding risk analysis, the regional SRA determined that this performance deficiency resulted in a CDF increase for each Hatch Unit 1 and 2 of less than 1E-4/year (i.e., less than Red). The licensee also performed a risk assessment using their Hatch fire probabilistic risk assessment model which also produced a result
05000348/FIN-2014005-042014Q4FarleyUnfused DC Ammeter Circuits Result in an Unanalyzed ConditionOn February 14, 2014, the licensee submitted an LER documenting the discovery of a condition of non-compliance with the sites fire protection program (FPP). This condition could prevent operators from achieving and maintaining safe shutdown (SSD) of the plant, in the case of a postulated fire. The inspectors performed a detailed review of the information related to the LER. Inspectors reviewed documents, and discussed the event with plant personnel to gain an understanding of the event. The inspectors assessed the licensees compensatory measures and corrective actions to determine if they were adequate. The licensee identified a non-compliance with Farley Operating License Condition 2.C(4) for Unit 1, and 2.C(6) for Unit 2, for the failure to meet requirements for protection of associated circuits. Specifically, the licensee failed to provide short circuit protection for safety-related and nonsafety-related associated circuits. As a result, a postulated fire could result in a secondary fire in another fire area. The secondary fire could adversely affect SSD capability. On December 13, 2013, the licensee conducted a review of industry operating experience (OE) related to unfused DC ammeter circuits. The review determined that certain DC ammeter circuits at Farley lacked short circuit protection. Because these circuits lack short circuit protection, a postulated fire in a fire area containing DC ammeter circuit cabling could result in concurrent shorts in the circuit. Due to the lack of short circuit protection, the resultant excessive current flow in the DC ammeter cable could result in a secondary fire in another fire area. The secondary fire could adversely affect SSD equipment or cables for SSD equipment, and thus, adversely affect SSD capability. Multiple fire areas in the Turbine Building, Service Water Structure, and Auxiliary Building are potentially affected. Section 9B.1.2 of Appendix 9B of the licensees FSAR defines associated circuits of concern as those cables that have a physical separation less than that required by 10 CFR 50 Appendix R, Section III.G.2, and have a common enclosure (e.g., raceway, panel, junction) with the shutdown cables (redundant and alternative) and are not electrically protected by circuit breakers, fuses or similar devices. Section 9B.3 provides the basis for the review that a fire would not negate the safe shutdown of the plant. For associated circuits that share common enclosures with safe shutdown circuits, Section 9B.3.J.4.b(2) states, in part, Nonsafe shutdown circuits as well as safe shutdown circuits are provided with short circuit protection. Nonsafe shutdown circuits which share raceway or other enclosures with safe shutdown circuits are not considered as a potential fire source because short circuit protection is provided. The licensees OE review determined that certain DC ammeter circuits were not provided with short circuit protection, and thus, invalidates the SSD evaluation bases stated in Section 9B.3 of the FSAR. Upon discovery, the licensee entered the condition into the corrective action program (CRs 723304 and 746046), and implemented appropriate compensatory measures in the form of roving fire watches for the affected areas. Plant modifications are currently being developed to provide short circuit protection for the affected DC ammeter circuitry. The licensees failure to provide short circuit protection for DC ammeter circuits is a PD. This PD is more than minor because it is associated with reactor safety Mitigating System cornerstone attribute of Protection Against External Events (i.e., fire). Specifically, not providing circuit protection for associated circuits affects the reactor safety mitigating systems cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Because this issue relates to fire protection, and this noncompliance was identified as a part of the sites transition to NFPA 805, this issue is being dispositioned in accordance with Section 9.1, Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48) of the NRC Enforcement Policy. In order to verify that this non-compliance was not associated with a finding of high safety significance (Red), a bounding phase 3 SDP risk analysis was performed by a regional SRA using the guidance from NRC Inspection Manual Chapter 0609 Appendix F and NUREG/CR 6850 revision 0 and Supplement 1. The analysis used inputs from the licensees NFPA 805 project for ignition frequency and cable routing data. The major analysis assumptions were: a one year exposure period, two proper DC polarity hot shorts required to achieve the high current conditions for secondary fires, and all ignition sources for each affected fire zone assumed to damage the ammeter cables. Based on this bounding risk analysis, the regional SRA determined that this performance deficiency resulted in a CDF increase for each Farley Unit 1 and 2 of less than 1E-4/year (i.e., less than Red). The licensee also performed a risk assessment using their Farley fire probabilistic risk assessment model which also produced a result <1E-4 for each Farley unit. No cross-cutting aspect was applicable to this performance deficiency because this finding was not indicative of current licensee performance. Enforcement. Farley Operating License Condition 2.C(4) for Unit 1, and 2.C(6) for Unit 2 states, in part, Southern Nuclear shall implement and maintain in effect all provisions of the approved fire protection program as described in the Final Safety Analysis Report for the facility, which implements the fire protection requirements of 10 CFR 50.48 and 10 CFR 50 Appendix R. Farleys Fire Protection Program is detailed in Appendix 9B of the FSAR. For associated circuits that share common enclosures with safe shutdown circuits Section 9B.3.J.4.b(2) of Appendix 9B of the FSAR states, in part, Nonsafe shutdown circuits as well as safe shutdown circuits are provided with short circuit protection. Non-safety shutdown circuits, which share raceway or other enclosures with safe shutdown circuits, were not considered as a potential fire source because short circuit protection was provided. Contrary to the above, for associated circuits that share common enclosures with safe shutdown circuits, the licensee failed to provide short circuit protection for associated circuits, in accordance with the FSAR. Specifically, on December 16, 2013, the licensee discovered that circuits for certain DC ammeters did not contain any form of short circuit protection. This condition has existed since original plant design and construction. Upon discovery, the licensee entered the condition into the corrective action program (CRs 723304 and 746046), and implemented appropriate compensatory measures in the form of roving fire watches for the affected areas. This finding affected 10 CFR 50.48, was identified by the licensee, and is a violation of NRC requirements. The licensee has committed to adopt NFPA 805 and change their fire protection licensing bases to comply with 10 CFR 50.48(c), the licensees license amendment request to transition to NFPA 805 is still under NRC review, and the noncompliance is not associated with a finding of high safety significance. Therefore, the NRC is exercising enforcement discretion in accordance with the NRC Enforcement Policy, Section 9.1, Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48) and Inspection Manual Chapter 0305. This condition was entered into the licensees corrective action program and immediate corrective actions and compensatory measures were taken.
05000348/FIN-2014005-032014Q4FarleyLicensee-Identified Violation10 CFR 50.55a(g)(4), In-service Inspection Standards Requirements for Operating Plants, requires, in part, that throughout the service life of a boiling or pressurized water-cooled nuclear power facility, components (including supports) that are classified as Class MC or Class CC pressure retaining components and their integral attachments must meet the requirements, except design and access provisions and pre-service examination requirements, set forth in Section XI of the ASME BPV Cod and addenda that are incorporated by reference in paragraph (a)(1)(ii) of this section. Section XI of the ASME BPVC, 2001 Edition with 2003 Addenda, Table IWE-2500-1, Examination Category E-A Containment Surfaces, required a general visual examination of 100 percent of the containment moisture barriers during each inspection period. Contrary to the above, the licensee failed to perform 100 percen inspection of the moisture barrier during each inspection period as stated in Section XI of the ASME BPVC, 2001 Edition with 2003 Addenda, Table IWE-2500-1. During the most recent Unit 2 refueling outage, the licensee examined the segments of moisture barrier inside containment that were not previously inspected and identified portions to be deteriorated. This violation was determined to be not greater tha very low safety significance (Green) because it could not result in a breach of containment and could not have likely introduced radioactive materials to the ground and atmosphere. This violation was documented in the licensees CAP as CR 886644.
05000364/FIN-2014005-022014Q4FarleyFailure to perform an adequate risk assessment led to a manual reactor trip of Unit 2A self-revealing non-cited violation of 10 CFR 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, was identified for the licensees failure to properly assess the increase in risk that resulted from a planned maintenance outage of the 2B emergency diesel generator (EDG). As a result, a Unit 2 manual reactor trip was required when the 2B startup auxiliary transformer (SAT) deenergized. This finding was entered into the licensees CAP as CR 10019361. The failure to properly assess and manage the increase in risk was a performance deficiency. The performance deficiency was more than minor because it adversely affected the Configuration Control attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective in that the risk associated with the component cooling water (CCW) system configuration in tandem with the 2B EDG maintenance outage was no considered which contributed to a manual reactor trip. A detailed risk assessment determined that the incremental core damage probability risk deficit was < 1E-6/year and the incremental large early release probability risk deficit was < 1E-7/year. Therefore, the finding was determined to be of very low safety significance (Green). The inspectors determined the finding had a cross-cutting aspect of work management in the human performance area, because the risk associated with operating the B train of CCW as the on service train while the 2B DG was out of service for planned maintenance was not considered. (H.5)
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