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05000338/FIN-2018003-012018Q3North AnnaLicensee-Identified ViolationThis violation of very low safety significance was identified by the licensee and has been entered into the licensee corrective action program and is being treated as a Non-Cited Violation, consistent with Section 2.3.2.a of the Enforcement Policy. Violation: TS 5.4.1.a, requires in part, that written procedures shall be established per Revision 2 of Regulatory Guide 1.33, Appendix A, of which part 9.a requires written procedures and documented instructions appropriate to the circumstances for performing maintenance that can affect the performance of safety related equipment. Contrary to the above, on June 12, 2018, the licensee failed to adequately establish a procedure appropriate to the circumstances during maintenance on the safety-related main control chillers. Specifically, licensee mechanical preventative maintenance procedure, 0-MPM-0806-02, Inspection of Control Room Chillers, Revision 0, did not provide a proper method to adequately monitor the Freon level in main control room chillers. Consequently, the licensee discovered a low Freon level condition on main control room chiller 1-HV-3-4B, which rendered the chiller inoperable. Significance: The inspectors reviewed Exhibit 2 Mitigating Systems Screening Questions of IMC 0609 Appendix A, The Significance Determination Process (SDP) for findings at Power and determined this finding was of very low safety significance, Green, because there was no design deficiency, it did not represent a loss of system or function, and did not represent an actual loss of function for greater than its TS allowed outage time. Corrective Action Reference: CR109958
05000327/FIN-2018003-012018Q3SequoyahLicensee-Identified ViolationThis violation of very low safety significance was identified by the licensee and has been entered into the licensee corrective action program and is being treated as a Non-Cited Violation, consistent with Section 2.3.2 of the Enforcement Policy. Sequoyah Unit 1 Operating License Condition 2.C(16) and Sequoyah Unit 2 Operating License Condition 2.C(13) require in part that TVA shall implement and maintain in effect all provisions of the approved fire protection program. The Sequoyah fire protection report describes how the licensee complies with applicable sections of 10 CFR 50, Appendix R, including Section III.L.1 which states in part that alternative or dedicated shutdown capability provided for a specific fire area shall be able to achieve cold shutdown conditions within 72 hours and maintain cold shutdown conditions thereafter. Contrary to the above, since implementation of the Sequoyah Fire Protection Program, the licensee failed to maintain all aspects of the approved program. Specifically, in August 2018, the licensee discovered that the sites ability to achieve cold shutdown conditions within 72 hours would be challenged due to an inadequate evaluation of the RHR pumps functionality during certain Appendix R fire scenarios.
05000400/FIN-2018003-012018Q3HarrisFailure to Implement Adequate Periodic Exercising of Turbine Trip Solenoid Operated ValvesA self-revealing Green finding was identified for the licensees failure to establish and implement adequate preventive maintenance (PM) for exercising the turbine electro-hydraulic auto-stop trip (AST) solenoid operated valves (SOVs) in accordance with procedure AD-EG-ALL-1202, Preventive Maintenance and Surveillance Testing Administration. As a result of the failure to exercise the SOVs at the weekly vendor recommended frequency, three of the four SOVs experienced mechanical binding (sticking) which rendered the turbine emergency trip system incapable of tripping the main turbine within the time response requirements of Technical Specifications.
05000327/FIN-2018001-032018Q1SequoyahLicensee-Identified ViolationThis violation of very low safety significant was identified by the licensee and has been entered into the licensee corrective action program and is being treated as a Non-Cited Violation, consistent with Section 2.3.2 of the Enforcement Policy.Violation: Sequoyah Unit 1 and Unit 2 Technical Specification 3.7.12, Auxiliary Building Gas Treatment System (ABGTS), requires two ABGTS trains be operable in modes 1, 2, 3, and 4. Contrary to the above, from March 3-7, 2017, the licensee blocked open door A212 resulting in the inoperability of the auxiliary building secondary containment enclosure boundary and thus inoperability of both trains of the ABGTS. Significance/Severity Level: Green. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, the inspectors determined that this finding was of very low safety significance (Green) because the finding only represents a degradation of the radiological barrier function provided for the auxiliary building.Corrective Action Reference: CR1269767
05000327/FIN-2018001-012018Q1SequoyahEssential Raw Cooling Water Pumps Inoperable due to Frozen Motor Bearing Cooling LinesA self-revealing Green NCV of Technical Specification 5.4.1, Procedures, was identified when Sequoyah/TVA did not establish, implement and maintain applicable procedures recommended in Regulatory Guide 1.33, Appendix A, Section 9, Procedures for Performing Maintenance. Specifically, the essential raw cooling water (ERCW) pump motor maintenance procedure, 0-MI-MRR-067-002.0, Removal/Disassembly/Reassembly Instruction for ERCW Pumps does not contain specific direction for the slope of the motor bearing cooling supply and return lines for the motor reassembly.
05000327/FIN-2018001-022018Q1SequoyahImproper Calibration of Reactor Trip Instrumentation Results in a Condition Prohibited by Technical SpecificationsA self-revealing Green finding and associated NCV of Sequoyah Unit 1 Technical Specification 5.4, Procedures, was identified on June 25, 2016, when the licensee did not implement procedures to calibrate Delta-T/Tavg Channel IV with the correct test equipment input impedance settings, which resulted in Delta-T/Tavg Channel IV being out of technical specifications allowed tolerances.
05000321/FIN-2017003-012017Q3HatchInstallation of Non-Conforming RPS EquipmentAn NRC-identified non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion III, Design Control was identified for failure to translate regulatory requirements and the design basis of the scram discharge volume (SDV) thermal probes into the System Evaluation Document, which resulted in the installation of a nonsafety-related terminal board in the reactor protection system (RPS). As an immediate corrective action the licensee installed fully qualified equipment. The failure to classify reactor protection system components as safety-related in accordance with design documents was a performance deficiency. The violation was entered into the licensee's corrective action program as CR 10344772.The performance deficiency was more than minor because it affected the design control attribute of the Mitigating Systems Cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the ensured reliability of the RPS system wasadversely affected because the installed components were not qualified for the application. The team used IMC 0609, Attachment 4, Initial Characterization of Findings, issued June 19, 2012, for Mitigating Systems, and IMC 0612, Appendix A, The Significance Determination Process for Findings At-Power, issued June 19, 2012, and determined the finding to be of very low safety significance (Green), because the finding was a deficiency affecting the design or qualification of a mitigating SSC, and the SSC maintained its operability. The inspectors determined that this finding did not have an associated cross-cutting aspect because this finding did not occur within the previous three years and is not reflective of current licensee performance.
05000250/FIN-2017003-032017Q3Turkey PointInadequate Maintenance Rule (a)(4) Risk Assessment for the High Head Safety Injection PumpsAn NRC-identified NCV of 10 CFR 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, paragraph (a)(4), was identified for the licensees failure to adequately assess and manage the Unit 3 and Unit 4 online risk associated with taking both Unit 4 high head safety injection (HHSI) pumps out of service. This issue was entered in the licensees corrective action program as AR 2193584. Corrective actions completed included providing additional training to senior reactor operators (SROs) on the maintenance rule (a)(4) implementation procedure and the definition of unavailability as used in maintenance rule (a)(4) risk assessments. The licensees failure to adequately assess and manage the Unit 3 and Unit 4 online risk associated with taking both Unit 4 HHSI pumps out of service, as required by 0-ADM-225, On Line Risk Assessment and Management, was a performance deficiency. The performance deficiency was more than minor because it adversely affected the equipment performance attribute of the Mitigating Systems Cornerstone. The significance of the finding was determined using IMC 0609, Appendix K, Maintenance Risk Assessment and Risk Management Significant Determination Process. The finding was determined to be of very low safety significance (Green) because the incremental core damage probability deficit for the timeframe the HHSI pumps were unavailable was less than 1E-6 for each unit, prior to, and after, the failure of the Unit 3A 4kV switchgear bus. The finding had a cross-cutting aspect in the area of Human Performance, Training, because the control room SROs did not have an adequate understanding regarding crediting operator actions and the definition of unavailability. The SROs incorrectly considered the Unit 4 HHSI pumps as available to perform their safety functions under the maintenance rule (a)(4) risk assessments (H.9).
05000250/FIN-2017003-022017Q3Turkey PointInadequate Operator Fundamentals during Diesel Driven Fire Pump Surveillance TestingAn NRC-identified finding was identified for the failure to adequately implement OP-AA-100-1000, Conduct of Operations procedure. Specifically, non-licensed operators (NLOs) failed to identify that the diesel driven fire pump (DDFP) was operating in a degraded condition. The outboard shaft gland was at elevated temperature because there was no packing leakoff established. Plant operators initiated an action request (AR) 2220785 to repair the stuffing box packing and the DDFP was declared non-functional. The electric driven fire pump (EDFP) remained functional and available to supply 100% of the fire water capacity while the DDFP was non-functional. This issue has been entered into the licensees corrective action program as ARs 2220785 and 2226305.The failure to identify that the DDFP was operating in a degraded condition was a performance deficiency. The performance deficiency was more than minor because it was associated with the protection against external hazards (fire) attribute of the initiating events cornerstone and adversely affected the cornerstones objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown, as well as power operations. Specifically, NLOs did not identify a degrading and unreliable DDFP condition. The inspectors determined that the issue had very low safety significance (Green) because the EDFP remained available to provide 100 percent of the required fire water capacity. The finding had a cross-cutting aspect in the area of Human Performance, Avoid Complacency, because NLOs did not recognize and consider that the DDFP was operating without adequate packing gland leakoff after a significant idle period (H.12)
05000250/FIN-2017003-012017Q3Turkey PointFailure to Identify and Correct CCW Pipe CorrosionAn NRC-identified NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, was identified for the licensees failure to promptly identify and correct component cooling water (CCW) external pipe corrosion that led to a through-wall flaw and leak on the Unit 3 CCW surge tank makeup line. FPL performed an immediate operability screening and determined the condition was operable but degraded considering previous prompt operability determinations for more significant CCW system leaks that bounded the leak rate and with similarly characterized structural flaws. Plant operators later isolated the through wall leak and established an alternate makeup path. This issue has been entered into the licensees corrective action program as AR 2223132.The failure to identify and correct the significant external corrosion that occurred on the Unit 3 CCW surge tank makeup line was a performance deficiency. The performance deficiency was more than minor because it was associated with the equipment performance attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective of ensuring the reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, through wall corrosion affects the reliability of the CCW system. The inspectors determined the finding to be of very low safety significance because it did not represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant in accordance with the licensees maintenance rule program for greater than 24 hours. The finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Identification, because the licensee failed to identify the significant external corrosion and apparent metal pipe wastage. Prior opportunities for FPL to identify the significant external corrosion and pipe wastage occurred through maintenance activities on the same pipe section and system engineer quarterly systems walkdowns (P.1).
05000352/FIN-2017002-032017Q2LimerickLicensee-Identified ViolationLER 05000352/2017-003-00 Condition Prohibited by Technical Specifications Due to an Inoperable Rod Position Indication System. TS 3.1.3.7 requires, in part, with one or more control rod position indicators inoperable, within 1 hour, determine the position of the control rod by using an alternate method, or otherwise, be in at least hot shutdown within the next 12 hours. Contrary to the above, on March 16, 2017, a power supply for the Unit 1 rod position indication system rendered position indication for 83 control rods inoperable for approximately 19.5 hours until the power supply was replaced. Exelon incorrectly used the full core display to verify control rod position for 81 of the 83 rods. The power supply failure rendered the full core display incapable of updating in response to a rod position change and was, therefore, not a valid means to determine rod position. Exelon initiated condition report IR 3988302 to document the TS violation. The inspectors evaluated the significance of this finding using IMC 0609 Appendix A, Significance Determination Process for Findings at Power, Exhibit 2, Mitigating Systems Screening Questions. The inspectors determined that this finding was of very low safety significance (Green) because the issue did not affect a single reactor protection system trip signal or the function of the other redundant trips or diverse methods of reactor shutdown, did not involve addition of positive reactivity, and did not result in mismanagement of reactivity by operators. Because this issue was of very low safety significance (Green) and Exelon entered the issue into the corrective action program (IR 3988302), this finding is being treated as a non-cited violation, consistent with Section 2.3.2.a of the NRC Enforcement Policy.
05000352/FIN-2017002-022017Q2LimerickFollow -Up of Events and Notices of Enforcement DiscretionInspection Scope On March 20, 2016, Limerick Unit 1 was performing a planned shutdown to support a refueling outage. The drywell leak inspection team identified a 0.5 gallons per minute reactor coolant system (RCS) pressure boundary leak on the shutdown cooling equalizing line. The apparent cause evaluation determined that the 34 inch A RHR shutdown cooling return check valve equalizing line developed a crack at the toe of the weld due to high cyclic fatigue induced by vibration from the reactor recirculation system. This check valve was previously replaced in 2006, and the equalizing line came pre - fabricated to the valve body. The affected section of the piping was replaced with a new socket weld with a 2x1 overlay to improve the pipe stability and minimize stresses. The Unit 1 B RHR shutdown cooling return check valve equalizing line weld was also reworked using the 2x1 weld method during the Unit 1 refueling out age in April 2016. The similar Unit 2 welds on the equalizing lines were examined and reinforced during the May 2017 refueling outage. The LER and associated evaluations and follow -up actions were reviewed for accuracy, the appropriateness of corrective actions, violations of requirements, and potential generic issues. This LER is closed. b. Findings Description. On March 20, 2016, Limerick Unit 1 was performing a planned shutdown to support a refueling outage. The drywell leak inspection team identified a 0.5 gallons per minute RCS pressure boundary leak on the shutdown cooling equalizing line. Additionally, Exelon determined that this leakage constituted a violation of the Unit 1, TS 3.4.3.2. Operational Leakage that requires the RCS leakage to be limited to no pressure boundary leakage. The condition was reported in event notification 51809 as required by 10 CFR 50.72(b)(3)(ii)(A ) because it represented a degradation of a principal safety barrier. Exelon evaluated the flaw and determined the cause of the RCS pressure boundary leakage was that the 34 inch A RHR shutdown cooling return check valve equalizing line developed a crack at the toe of the weld due to high cyclic fatigue induced by vibration from the reactor recirculation system. The inspectors reviewed the LER and Exelons apparent cause evaluation of the event. The inspectors reviewed the event information and leakage data over the previous cycle and concluded that reactor pressure boundary leakage reasonably began on an unknown date that was more than 36 hours before March 20, 2016. However, the inspectors determined that the existence of R CS pressure boundary leakage was not within Exelons ability to foresee and correct and therefore was not a performance deficiency. In particular, the RHR shutdown cooling return check valve was replaced on the recommended periodicity, and the equalizing line that developed the crack came pre- fabricated to the valve body when replaced in 2006. For information, the inspectors screened the significance of the condition using IMC 0609, Appendix A, The Significance Determination Process For Findings At -Power , and determined that the condition represented very low safety significance (Green) because it would not result in exceeding the RCS leak rate for a small LOCA and would not have likely affected other systems used to mitigate a LOCA. 19 Enforcement. TS 3.4.3.2 requires, in part, that RCS operational leakage shall be limited to no pressure boundary leakage. If pressure boundary leakage exists, the TS 3.4.3.2 limiting condition for operation action statement requires Unit 1 to be in at least hot shutdown within 12 hours and in cold shutdown within the next 24 hours. Contrary to the above, for a period that began on an unknown date that was very likely more than 36 hours before March 20, 2016, and ending on March 20, 2016, RCS pressure boundary leakage existed, and Exelon did not place Unit 1 in at least hot shutdown within 12 hours and in cold shutdown within the next 24 hours. This issue is considered within the traditional enforcement process because there was no performance deficiency associated with the violation of NRC requirements. Inspection Manual Chapter 0612, Power Reactor Inspection Reports, Section 03.22 states, in part, that traditional enforcement is used to disposition violations receiving enforcement discretion or violations without a performance deficiency. The NRC Enforcement Policy, Section 2.2.1 states, in part, that, whenever possible, the NRC uses risk information in assessing the safety significance of violations. Accordingly, after considering that the condition represented very low safety significance, the inspectors concluded that the violation would be best characterized as Severity Level IV under the traditional enforcement process. However, the NRC is exercising enforcement discretion (EA- 17- 076) in accordance with Section 3.10 of the NRC Enforcement Policy which states that the NRC may exercise discretion for violations of NRC requirements by reactor licensees for which there are no associated performance deficiencies. In reaching this decision, the NRC determined that the issue was not within the licensees ability to foresee and correct; the licensees actions did not contribute to the degraded condition; and the actions taken were reasonable to identify and address the condition. Furthermore, because the licensees actions did not contribute to this violation, it will not be considered in the assessment process or the NRCs Action Matrix.
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.
05000353/FIN-2017002-012017Q2LimerickInadequate Design Control of the Drywell Unit Cooler Condensate Flow Rate Monitoring SystemGreen . A self -revealing Green NCV of 10 Code of Federal Regulations (CFR) Part 50, Appendix B, Criterion III, Design Control, occurred when Exelon failed to verify or check the adequacy of design of a new Unit 2 drywell unit cooler condensate flow rate monitoring system. Specifically, the design did not identify that the low conductivity of the drain fluid affected the ability of the flow elements to accurately detect drain flow. In addition to this, LGS staff did not assure adequate post modification acceptance test ing in accordance with CC- AA- 107- 1001, Post Modification A cceptance Testing. This inadequately designed and tested modification also resulted in a violation of technical specification (TS) 3.4.3.1, Leakage Detection Systems , because the system was inoperable and unavailable to perform its function following t he Unit 2 April 2015 refueling outage, and the TS 3.4.3.1 action statement was not met until the system was decl ared inoperable on December10, 2015. In response to this issue, Exelon initiated a condition report, IR 2598308, performed an apparent cause investigation, and replaced the Rosemount drywell unit cooler condensate flow rate monitoring system with a modified ver sion of the previously used system. The inspectors determined that the failure to verify the adequacy of the newly installed Rosemount dr ywell unit cooler condensate flow rate monitoring was within Exelons ability to foresee and correct and should have been prevented and therefore w as a performance deficiency . This issue is more than minor because it adversely affected the design control attribute of the barrier integrity cornerstone to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, the Unit 2 drywell unit cooler condensate flow rate monitoring system was inoperable and unavailable to perform its function as part of the reactor coolant leakage detection system following the Unit 2 April 2015 refueling outage . This issue was evaluated in accordance with IMC 0609, Appendix A, "Significance Determination Process for Findings At-Power, using Exhibit 3, Barrier Integrity Screening Questions, Section B, Reactor Containment . The finding was determined to be of very low safety significance (Green) because the finding 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 ig niters in the reactor containment. The inspectors determined that this finding has a cross -cutting aspect in the area of Human Performance, Conservative Bias , because LGS staff ma de inappropriate decisions based on informal vendor input and a successful implementation of the modification at another facility . (H.1 4)
05000352/FIN-2017003-002017Q2LimerickLicensee-Identified ViolationLER 05000352/2017- 003 -00 Condition Prohibited by Technical Specifications Due to an Inoperable Rod Position Indication System . TS 3.1.3.7 requires, in part, with one or more control rod position indicators inoperable, within 1 hour, determine the position of the control rod by using an alternate method, or otherwise, be in at least hot shutdown within the next 12 hours. Contrary to the above, on March 16, 2017, a power supply for the Unit 1 rod position indication system rendered position indication for 83 control rods inoperable for approximately 19.5 hours until the power supply was replaced. Exelon incorrectly used the full core display to verify control rod position for 81 of the 83 rods. The power supply failure rendered the full core display incapable of updating in response to a rod position change and was, therefore, not a valid means to determine rod position. Exelon initiated condition report IR 3988302 to document the TS violation. The inspectors evaluated the significance of this findi ng using IMC 0609 Appendix A , Significance Determination Process for Findings at Power, Exhibit 2, Mitigating Systems Screening Questions. The inspectors determined that this finding was of very low safety significance (Green) because the issue did not affect a single reactor protection system trip signal or the function of the ot her redundant trips or diverse methods of reactor shutdown, did not involve addition of positive reactivity, and did not result in mismanagement of reactivity by operators. Because this issue was of very low safety significance (Green) and Exelon entered the issue into the corrective action program (IR 3988302), this finding is being treated as a non- cited violation, consistent with Section 2.3.2 .a of the NRC Enforcement Policy.
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-2017002-012017Q2HatchHardened 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.
05000366/FIN-2017001-012017Q1HatchFailure to Identify Abnormal Condition on 2C EDG Cross Drive AssemblyGreen . A self -revealing non- cited violation (NCV) of Hatch Unit 2 Technical Specification 5.4.1 was identified when technicians performing maintenance on the 2C emergency diesel generator observed pitting on the lower crank component gears and did not initiate a condition report as required by procedure 52SV -R43 -001- 0, Diesel, Alternator, and Accessories Inspection. The licensees failure to initiate a condition report, as required by 52SV -R43 -001- 0 Diesel, Alternator, and Accessories Inspection, for the pitting observed on the lower crank component gears was a performance deficiency. The violation of regulatory requirement occurred on or about November 2015 until the licensee replaced the 2C EDG cross drive assembly and restored compliance on August 25, 2016. The violation was entered into the licensees corrective action program as CR 10263236. The performance deficiency was more than minor because if left uncorrected, the failure to evaluate gear pitting would allow progression of a degradation mechanism to the point of EDG inoperability. 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 had a cross -cutting aspect in the Resources aspect of the human performance area, because the licensee did not ensure adequate procedural guidance to recognize the difference between normal and destructive pitting. (H .1)
05000321/FIN-2017001-022017Q1HatchLicensee-Identified ViolationUnit 2 Technical Specification 3.6.1.3 requires each PCIV be operable in Mode 1. With one PCIV inoperable, the affected penetration flow path must be isolated by use of at least one closed and de -activated automatic valve, closed manual valve, blind flange, or check valve with flow through the valve secured. Contrary to the above, on November 6, 2016 at 21:51 operators tagged valve 2E41F111, a PCIV, open with the breaker off. Subsequently, a licensed operator performing a main control room board walk down noted the PCIV was inoperable and, on November 8 at 0151, operators closed and de -activated an automatic valve in the line to rest ore 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 E xhibit 3 for reactor containment were answered no. This issue was documented in the licensees corrective action program as CR 10295889. (Section 4OA3.2)
05000321/FIN-2017001-032017Q1HatchLicensee-Identified ViolationTechnical Specification 5.7.1 requires, in part, entrances into areas in which the intensity of r adiation is > 100 mrem/hr but < 1000 mrem/hr, measured at 30 cm from the radiation source or from any surface the radiation penetrates, to be controlled by requiring issuance of a Radiation Work Permit (RWP). Contrary to this, On September 9, 2016, two in dividuals entered a High Radiation Area in the Unit 2 SE Diagonal 87' elevation to calibrate an RHR Service water transmitter without the proper briefing or RWP. The individuals were briefed and permitted to enter the HPCI Room area instead of this area. 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. The immediate corrective actions were documented in CR 10271667. The long term corrective actions include continuing training suc h that all craft personnel are exposed to the remediation scenario. (Section 2RS1 )
05000321/FIN-2016004-012016Q4HatchFailure to Establish Icing Controls on CAD SubsystemAn NRC-identified non-cited violation (NCV) of Hatch Unit 1 Technical Specification 5.4, Procedures, was identified when procedures did not include inspection criteria for ice buildup of the Unit 1 nitrogen storage tank piping. The licensees failure to establish controls to ensure that ice buildup on the Unit 1 Containment Atmospheric Dilution (CAD) subsystem piping did not exceed ten inches was a performance deficiency. The licensee entered the condition into their corrective action plan as CR10296584, and performed de-icing activities to remove the ice buildup. This performance deficiency was more than minor, because ice buildup on the CAD system may lead to CAD subsystem inoperability if left uncorrected. The finding screened as Green because the CAD subsystem remained operable. The inspectors determined that this finding had a cross-cutting aspect in the Initiation aspect of the problem identification and resolution area, because the licensee did not initiate a condition report upon initially identifying the issue. (P.1)
05000321/FIN-2016003-012016Q3HatchUnit Downpower Caused by RFP Vent Line FailureA self-revealing finding was identified when the licensee failed to install a reactor feed pump (RFP) vent line weld in accordance with plant procedures resulting in a failure that required an unplanned Unit 1 power reduction greater than 20%. Failure to install the correct weld thickness on the unit 1 B RFP vent line, as required by procedures, was a performance deficiency. This performance deficiency was more than minor because it was associated with the Equipment Performance attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective in that an unplanned reactor power reduction was required from 100 percent to 60 percent RTP. The inspectors determined this finding was of very low safety significance (Green) because there was not a reactor trip or loss of mitigation equipment. The inspectors determined that this finding had a cross-cutting aspect in the Resolution aspect of the problem identification and resolution area, because the organization did not take effective corrective actions to address the previous weld configuration issue. (P.3)
05000321/FIN-2016003-022016Q3HatchFailure to Ensure Work Hours are Within Work Hour LimitsAn NRC-identified non-cited violation (NCV) of 10 CFR Part 26, Fitness for Duty Programs, was identified when the licensee failed to ensure that personnel subject to work hour controls did not exceed 72 hours in a work week. The licensee entered this condition into their corrective action program as Condition Report 10214872 and restored compliance when the affected individuals received an adequate rest period. The failure to ensure that work hours for personnel subject to work hour controls were tracked in accordance with licensee procedures was a performance deficiency. The finding was more than minor because, if left uncorrected, the failure to appropriately implement work hour limitations for covered workers could adversely impact the conduct and oversight of work on safety significant components. The inspectors determined that the finding was of very low safety significance (Green) because the finding did not result in an adverse impact to plant safety due to worker fatigue. The inspectors determined this performance deficiency had a cross-cutting aspect of Consistent Process in the Human Performance area because the licensee failed to assess which workers were subject to work hour limits. (H.13)
05000321/FIN-2016002-012016Q2HatchFailure to Implement Maintenance Procedure for Control Room Air Conditioning SystemA self-revealing Green non-cited violation (NCV) of Hatch Unit 1 and Unit 2 Technical Specification 5.4, Procedures, was identified when the B main control room air conditioning condenser tripped on high discharge pressure due to an improperly adjusted water regulating valve. The licensee entered the condition into their corrective action program as CR 10217777 and adjusted the water regulating valve to the appropriate setpoint. Failure to adjust the water regulating valve in accordance with preventive maintenance procedure 52PM-Z41-002-1, Control Room Air Conditioning Maintenance, was a performance deficiency. The performance deficiency was more than minor because it associated with the Equipment Performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective in that the failure resulted in the inoperability of the B main control room air conditioner. The finding screened as Green because the loss of component function did not significantly affect the function of the train or system. The inspectors determined that this finding had a cross-cutting aspect in the Resources aspect of the Human Performance area, because the licensee did not ensure that procedures were available and adequate to support nuclear safety (H.1).
05000321/FIN-2016002-032016Q2HatchPerformance of Operations with Potential to Drain the Reactor Vessel (OPDRV) Without Secondary ContainmentIn February 2016, during the Unit 1 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. These OPDRV activities were also performed during the Unit 2 Refueling Outage. 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 1 refueling outage. Enforcement: Unit 1 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 was inoperable. The inspectors determined this was a Severity Level IV violation. The NRC is exercising enforcement discretion (Enforcement Action (EA)-16-158) 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 a timely license amendment request.
05000321/FIN-2016002-022016Q2HatchLicensee-Identified ViolationTS 3.9.4 requires control rod full-in position indication for each control rod be operable in Mode 5. With one or more control rod position indications inoperable, in vessel fuel movement must be suspended. Contrary to the above, on February 11, 2016, at 1156 the licensee initiated fuel move in the vessel with 20 control rod full-in position indications inoperable. On February 11, 2016, at 1320 the shift manager suspended moving fuel to restore compliance. Inspector screened the finding in accordance with IMC 609 Appendix G Shutdown Operations Significance Determination Process. The finding screened as very low safety significance (Green) because all the questions in Appendix G Attachment 1 were answered no. This issue was documented in the licensees corrective action program as CR 10181628.
05000321/FIN-2016001-012016Q1HatchReactor Coolant System N2E Weld FlawThe inspectors identified an unresolved item associated with a flaw identified in the safe end-to-nozzle weld of the Reactor Coolant System N2E Nozzle. In July 2015, the licensee submitted a proposed alternative to ASME Code, HNP-ISI-ALT-15-01 (ML15183A354), to install a full-structural weld overlay on reactor coolant nozzle N2E (1B31-1RC-12-BR-E). This proposed alternative was approved by the NRC in December 2015 (ML15349A973). The licensee implemented this proposed alternative during the February 2016 refueling outage (1R27). After removing all but 1/16 of the existing overlay, the licensee performed a liquid penetrant examination and noted a pair of linear indications. Subsequently, the licensee determined that these indications were actually a single indication, and that it exceeded allowable size limitations according to ASME Code. Upon further review, the licensee realized that these indications were potentially the result of growth of an inner-diameter, surface-connected intergranular stress corrosion cracking (IGSCC) flaw found in 1988. The licensee has repaired the flaw, installed the full-structural weld overlay, and completed all required post-installation examinations. This is an unresolved item pending review of whether the licensee performed all required examinations of the N2E nozzle between 1988 and 2016, and whether the flaw exceeded minimum wall limitations at some point during prior operation. The issue will be tracked as URI 05000321/2016001-01, Reactor Coolant System N2E Weld Flaw.
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
05000366/FIN-2015002-022015Q2HatchLicensee-Identified ViolationOn February 9, 2015, a violation of Unit 2 Technical Specification (TS) 3.6.1.3 was identified by the licensee. TS 3.6.1.3 requires primary containment isolation valves to be operable during Modes 1, 2, and 3. Contrary to this requirement, the A and C inboard main steam isolation valves (MSIVs) failed to close within the required isolation time during a technical specification surveillance test. Therefore, the A and C inboard MSIVs were inoperable when Unit 2 was in Modes 1, 2, and 3. The cause of the failure of the MSIVs to close within the required isolation time was excessive lubrication of the pistons and springs in the 2-way and 4-way valves within the pneumatic manifold assembly of the MSIV actuator. The excessive lubrication became tacky, causing a delay in the opening of the air supply and exhaust paths. Because the A and C outboard MSIVs closed within the required technical specification isolation time, the primary containment isolation safety function of the main steam lines was maintained. Therefore, this finding was determined to be of very low safety significance (Green). This condition was entered into the licensees corrective action program as CR 10036361.
05000321/FIN-2015002-012015Q2HatchFailure to Maintain HELB PenetrationAn NRC identified non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion III, Design Control, was identified for failure to maintain reactor building residual heat removal (RHR) diagonal room penetrations in the designed configuration. The violation was entered into the licensees corrective action program as CR 10055943. The licensee issued work orders to seal the affected penetrations in accordance with design documents. The licensees failure to maintain the penetration seals in accordance with design drawings was a performance deficiency. The performance deficiency was more than minor because it was associated with the Design Control attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective in that the failure to maintain the design basis configuration compromised the capability of the RHR diagonal room wall to restrict a high pressure coolant injection (HPCI) high energy line break to the torus area. The finding was of very low safety significance (Green) because the loss of component function did not significantly affect the function of the train or system. The inspectors determined that the finding had a cross-cutting aspect of work management in the human performance area (H.5), because the licensees work process did not control work activities such that nuclear safety was the overriding priority.
05000321/FIN-2015002-032015Q2HatchPerformance of Operations with Potential to Drain the Reactor Vessel (OPDRV) in Mode 5 Without Secondary ContainmentA violation of Unit 2 Technical Specification (TS) 3.6.4.1 was identified. Because the violation was identified during the discretion period described in Enforcement Guidance Memorandum 11-003, the NRC is exercising enforcement discretion in accordance with Section 3.5, Violations Involving Special Circumstances, of the NRC Enforcement Policy and, therefore, will not issue enforcement action for this violation, subject to a timely license amendment request being submitted.
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-2015001-062015Q1HatchUnfused 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
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
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-2015001-032015Q1HatchFailure 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.
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-2014005-022014Q4HatchFailure to report degraded fire penetration seals per 50.72 and 50.73The NRC identified a Severity Level IV NCV of 10 CFR Part 50.72(b)(3)(ii)(B), Immediate Notification Requirements for Operating Nuclear Power Reactors, and 10 CFR Part 50.73(a)(2)(ii)(B) Licensee Event Report System for failure to report unanalyzed conditions that significantly degraded plant safety. Specifically, the licensee failed to notify the NRC upon discovery of reportable degraded conditions in the control building that could have resulted in the loss of both Unit 1 safe shutdown paths in the event of a postulated fire. The violation was entered into the licensees corrective action program as CR 870626. Failure to report an unanalyzed condition that significantly degraded plant safety as required by 10 CFR Part 50.72(b)(3)(ii)(B) and 10 CFR Part 50.73(a)(2)(ii)(B) was a performance deficiency (PD). The PD potentially impeded or impacted the regulatory process and was evaluated using traditional enforcement in accordance with Section 6 of the NRC Enforcement Policy. Failure to make a report required by 10 CFR Part 50.72 or 10 CF Part 50.73 is identified in example 9 of Section 6.9.d as a Severity Level IV violation. Crosscuttin aspects are not assigned to traditional enforcement violations.
05000321/FIN-2014005-042014Q4HatchLicensee-Identified ViolationTitle 10 CFR Part 50.54(q)(2) requires, in part, that a licensee shall follow and maintain the effectiveness of an emergency plan which meets the planning standards of 10 CFR Part 50.47(b). 10 CFR Part 50.47(b)(4) requires that a standard emergency action level (EAL) scheme, the bases of which include facility system and effluent parameters, is in use by nuclear facility licensee, and state and local response plans call for reliance on information provided by facility licensees fo determinations of minimum initial offsite response measures. Contrary to the above, from May 2011 to November 2013, the licensee failed to maintain the effectiveness of its emergency plan. The System Malfunction EAL for Fuel Clad Degradation (SU4) listed incorrect reactor coolant sample activity threshold values and the Fission Product Barrier EAL contained an incorrect drywel radiation monitor threshold value for reactor coolant system leakage (FA1). These incorrect EAL values were associated with changes to the license technical specifications when incorporating an alternate source term. The licensee implemented immediate compensatory actions by issuing a standing order to include the correct threshold values and informed appropriate operators and decisionmakers These corrected values were then incorporated into Revision 3 of procedure NMP-EP-110-GL02, HNP EALs ICs, Threshold Values and Basis. The issue was placed in their corrective action program as CR732879. This violation was determined not to be greater than Green as these incorrect EAL threshold values only affected Unusual Event and Alert declarations using Inspection Manual Chapte 0609, Appendix B, Emergency Preparedness Significance Determination Process, Revision dated September 26, 2014.
05000321/FIN-2014005-012014Q4HatchFailure to evaluate fire penetration 1T43-H528JThe NRC identified a Green Non-Cited Violation (NCV) of Unit 1 License Condition 2.C.(3) Fire Protection when a fire penetration that deviated from three-hour rating requirements was not evaluated in accordance with Unit 1 Fire Hazards Analysis (FHA) Appendix I, Evaluation of non-rated penetration seals in rated fire barriers. The licensee initiated roving fire watches and initiated corrective actions to restore compliance with Appendix I of the Unit 1 FHA. The violation was entered into the licensees corrective action program as CR 865615. Failure to implement the Unit 1 Fire Hazards Analysis (FHA) Appendix I, Evaluation of nonrated penetration seals in rated fire barriers was a performance deficiency. This performance deficiency was more than minor because it was associated with the Mitigating Systems cornerstone of the Protection Against External Factors (Fire) attribute and adversely affected the cornerstone objective in that the licensee failed to evaluate the asfound configuration of the penetration which resulted in a nonfunctional fire barrier. The inspectors determined the finding was Green because there was a fully functional automatic suppression system on either side of the fire barrier. The inspectors determined that thi finding did not have an associated cross-cutting aspect because this finding is not reflectiv of current licensee performance.
05000321/FIN-2014005-032014Q4HatchLicensee-Identified ViolationTitle 10 of the Code of Federal Regulations (10 CFR Part 50.54(q)(2)) requires, in part, that a holder of a license under this part shall follow and maintain the effectiveness of an emergency plan that meets the requirements in 10 CFR Part 50, Appendix E and the planning standards of 10 CFR Part 50.47(b). 10 CFR Part 50, Appendix E, Section IV.A.9 states, By December 24, 2012, for nuclear powe reactor licensees, a detailed analysis demonstrating that on-shift personnel assigned emergency plan implementation functions are not assigned responsibilities that would prevent the timely performance of their assigned functions as specified in the emergency plan, shall be included. Contrary to the above, on December 24, 2012, the licensees detailed analysis of onshift staffing was deficient in that the specific scenario involving a fire in the Main Control Room with dual unit remote shutdown panel operations was evaluated assuming a typical complement of 17 operations personnel vice the 14 specified in the licensees Emergency Plan and fire response plan. The licensee subsequently performed a detailed time-motion study and determined that all required functions could have been performed, but individual workload capacity would have been challenged. The NRC determined that with no identified loss or degradation of a planning standard function, the failure to complete the detailed analysis in accordance with 10 CFR Part 50, Appendix E, Section IV.A.9, was a very low safety significance issue (Green) as indicated in Inspection Manual Chapter 0609, Appendix B, Emergency Preparedness Significance Determination Process, Revision dated September 26, 2014. This violation was documented in CAR 11209. Immediate corrective actions included interim augmentation for on-shift positions and the on-shift staffing analysis was re-performed. Final incorporation into the licensees emergency plan is in progress.
05000321/FIN-2014004-022014Q3HatchFailure to Implement Fire Surveillance Procedure Resulted in Isolation of All Fire Water to the StationThe inspectors identified a Green non-cited violation (NCV) of Technical Specification 5.4, Procedures, for the licensees failure to properly implement a valve lineup in a surveillance procedure for the fire protection system. On July 17, 2014 Hatch personnel isolated all fire suppression water during the performance of a valve lineup in accordance with surveillance procedure 42SV-FPX-015-0, System Flush Fire Protection Water. The licensee restored the fire protection system by implementing the correct valve lineup and suspended the use of the procedure until revisions can be made to enhance the procedures usability. The violation was entered into the licensees corrective action program as condition report 841493. The licensees failure to implement the correct valve lineup in accordance with procedure 42SV-FPX-015-0, System Flush Fire Protection Water, was a performance deficiency. This performance deficiency was more than minor because the performance deficiency was associated with the Protection Against External Factors (Fire) attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective in that the failure to implement the correct valve lineup of 42SV-FPX-015-0 resulted in total fire suppression water isolation. The inspectors screened this finding using IMC 0609, Appendix F, Attachment 1, dated September 20, 2013. In Part 1: Fire Protection SDP Phase 1 Worksheet, this finding screened as requiring a Phase 3 analysis. The regional Senior Reactor Analyst performed a Phase 3 analysis using licensee input from their fire PRA. Because of the short exposure time of approximately one hour, the change in risk was below 1E-6. Therefore, this finding is Green. The finding had a cross-cutting aspect of resources in the human performance area, because the licensee did not ensure that procedure 42SV-FPX-015-0 was adequate to support nuclear safety.
05000321/FIN-2014004-042014Q3HatchLicensee-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 five safety relief valves failed to lift at the required technical specification setpoint, and therefore were inoperable when Unit 1 was 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 809721.
05000321/FIN-2014004-052014Q3HatchLicensee-Identified Violation10 CFR Part 50 Appendix B, Criterion V, requires in part that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions. Contrary to the above, on June 6, 2014, the licensee failed to accomplish installation of thermal overload (TOL) heaters for 1X41-C002B using actual fan running current in accordance with procedure 52PM-R24-001-0, Allis Chalmers Low Voltage MCC Inspection. The design group based the TOL heaters on motor name plate data and did not consider actual motor running amps. This violation was determined to require a detailed risk (Phase 3) analysis because there was an actual loss of function for greater than the TS AOT. A Senior Reactor Analyst performed a Phase 3 analysis using the NRCs Hatch PRA model modified to include the EDG room ventilation fan breakers including common cause failure terms. Since the EDG 1B fan breakers were not included in the licensee breaker upgrade program, they were not included in the common cause assumptions. The licensee had performed an analysis that showed the EDGs would remain functional with any one of the three fans operating. The screening analysis conservatively assumed complete failure of one of the large room fans, an increase in the common cause failure rate, and no recovery of the tripped breakers. The dominant sequences involved a Loss of Offsite Power initiator, independent failure of the EDG 1B fans, common cause failure of the EDG 1A and 1C fans, and no recovery of the EDGs or offsite power for 7 hours. The second EDG 1A room fan breaker was found tripped due to a cause not part of the performance deficiency, and was assumed to fail at its normal rate. Because of the short exposure time and the lack of a common cause failure of fan breakers for the 1B EDG, the finding screened well below the 1E- 6 threshold. Therefore, this finding was determined to be of very low safety significance (Green). This condition was documented in the licensees corrective action program as CR 835377.
05000321/FIN-2014004-062014Q3HatchLicensee-Identified Violation10 CFR Part 50 Appendix B, Criterion III, Design Control, requires in part that design changes shall be subject to design control measures commensurate with those applied to the original design. Contrary to the above, during design activities to replace safety related low voltage breaker pan assemblies, the licensee incorrectly classified Cutler Hammer thermal overload blocks as like-for-like replacements of the previous Westinghouse design. The new Cutler Hammer thermal overload blocks had different operating characteristics which resulted in newly installed pan assemblies having incorrectly sized thermal overload heaters. The nonconforming thermal overload heaters tripped the fan motors under normal operating conditions which resulted in the 2A emergency diesel generator being declared inoperable. The inspectors determined that the violation required a detailed risk (Phase 3) assessment because there was an actual loss of function for greater than the TS AOT. A Senior Reactor Analyst performed a Phase 3 analysis for the finding using 20 the NRCs Hatch PRA model modified to include the EDG room ventilation fan breakers including common cause failure terms. Since the EDG 1B fan breakers were not included in the licensee breaker upgrade program, they were not included in the breaker common cause assumptions. The screening analysis assumed an increase in failure rate of the fan breakers based on actual run data that was applied to the 6 breakers that control the EDG 2A and EDG 2C fans, and also conservatively assumed no recovery of the tripped breakers. The exposure time was assumed to be one year for SDP purposes, in accordance with the program assumptions, since the exposure time exceeded one year. The dominant sequences involved a Loss of Offsite Power initiator, independent failure of the EDG 1B fans, common cause failure of the EDG 2A and 2C fans, and no recovery of the EDGs or offsite power for 7 hours. Because of the multiple successful operations of the EDG fans prior to failure, and the lack of a common cause failure tie for the fan breakers for the 1B swing EDG, the finding screened well below the 1E-6 threshold. Therefore, this finding was determined to be of very low safety significance (Green). This condition was documented in the licensees corrective action program as CR 822819.
05000321/FIN-2014004-032014Q3HatchFailure to Promptly Identify Malfunction of HPCI Exhaust Drain Pot Level InstrumentationA self-revealing Green NCV of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion XVI, Corrective Actions, was identified on May 1, 2014 when a control room annunciator and subsequent investigation of the high pressure coolant injection (HPCI) system led to the discovery that on March 4, 2014 the licensee failed to identify that a blown fuse was preventing the HPCI turbine exhaust drain pot from performing its automatic level control function. The licensee restored HPCI operability by replacing the fuse and draining the accumulated condensation from the HPCI turbine. The violation was entered into the licensees corrective action program as condition report 807394. The failure to promptly identify and correct the failure of the exhaust drain pot level instrumentation, as required by 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Actions, was a performance deficiency. This performance deficiency was determined to be more than minor because it was associated with the Equipment Performance - Reliability attribute of the Mitigating Systems cornerstone and it adversely affected the cornerstone objective in that the failure to promptly identify and replace the blown fuse resulted in the HPCI system inoperability from April 24 to May 1, 2014. The inspectors assessed this finding using IMC 0609, Appendix A, The Significance Determination Process For Findings At-Power, dated July 1, 2012. The inspectors determined in accordance with Exhibit 2 that the finding was of very low safety significance (Green) because there was no loss of function. The inspectors determined the finding had a cross cutting aspect of avoid complacency in the human performance area because the licensee did not recognize the possibility of latent issues and inherent risk when evaluating CR 782581.
05000321/FIN-2014004-012014Q3HatchUnit Downpower Caused by Relief Valve FailureA self-revealing finding was identified when the opening of the 8th stage feedwater heater relief valves due to improper set point adjustment necessitated a Unit 1 downpower. Failure to verify the 8th stage feedwater heater shell side relief valve set point was greater than normal system operating pressure as required by 52IT-MME-006-0 was a performance deficiency. This performance deficiency was more than minor because it was associated with the Equipment Performance attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective in that a manual reactor power reduction was required from 93 percent to 25 percent. The inspectors screened this finding as Green because the finding did not cause a reactor trip and the loss of mitigation equipment, a high energy linebreak, internal flood, or a fire. The finding had a cross cutting aspect of training in the human performance area because the engineer performing the work order review and approval was newly qualified and did not know how to determine system operating pressures.
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