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05000277/FIN-2018010-02Peach Bottom2018Q2Failure to Develop and Maintain Mitigating StrategyThe inspectors identified a Green non-cited violation of 10 CFR 50.54(hh)(2), Conditions of Licenses, and Peach Bottom Unit 2 and Unit 3 Renewed Facility Operating License Condition 2.C.(11), Mitigation Strategy License Condition, because Exelon did not develop and maintain strategies for addressing large fires and explosions that include operations to mitigate fuel damage. Specifically, Exelon did not adequately develop and maintain procedures to manually depressurize the reactor using the automatic depressurization system safety relief valves in the event of a challenge to the reactor due to a postulated large fire and/or explosion.
05000298/FIN-2017001-06Cooper2017Q1Failure to Install Correct Mechanical Stop and Verify Proper OperationThe inspectors reviewed a self-revealed, non-cited violation of Technical Specification 3.0.4 for the licensees failure to install the correct reactor core isolation cooling pressure control valve, RCIC-AOV-PCV23, mechanical stop and verify proper operation of the system prior to entering a mode of applicability for Technical Specification 3.5.3. This condition resulted in RCIC-AOV-PCV23 going fully open during surveillance testing following Refueling Outage 29, causing a pressure transient. This transient caused a failure of the reactor core isolation cooling turbine lube oil cooler gasket, lifting of a pressure relief valve, and a water leak. The licensee immediately shut down the reactor core isolation cooling system and declared it inoperable. The immediate corrective actions were to restore RCIC-AOV-PCV23 from the closed mechanical stop to the required open mechanical stop and to replace the turbine lube oil cooler gasket to restore operability of the system. The licensee entered this deficiency into the corrective action program as Condition Report CR-CNS-2016-08122 and initiated a root cause evaluation to investigate this condition. The licensees failure to install the correct reactor core isolation cooling pressure control valve, RCIC-AOV-PCV23, mechanical stop and verify proper operation of the system prior to entering a mode of applicability for Technical Specification 3.5.3, in violation of Technical Specification 3.0.4, was a performance deficiency. The performance deficiency was determined to be more than minor, and therefore a finding, because it was associated with the design control attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events. Specifically, the licensee installed RCIC-AOV-PCV23 with the incorrect mechanical stop, and proper valve operation was not verified after installation during Refueling Outage 29, which caused the reactor core isolation cooling system to lose function during surveillance testing. This transient caused a failure of the reactor core isolation cooling turbine lube oil cooler gasket and an associated water leak. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, the inspectors determined that the finding required a detailed risk evaluation because it represented a loss of system and/or function. In the detailed risk evaluation, the analyst assumed the reactor core isolation cooling system was unavailable for 50 hours. The analyst used the Test/Limited Use Version COOPER-DEESE-HCI03 of the Cooper SPAR model run on SAPHIRE, Version 8.1.5. The analyst updated the initiating event frequencies for transients, losses of condenser heat sink, losses of main feed water, grid related losses of offsite power, and switchyard centered losses of offsite power to the more recent values from the 2014 update to the industry data found in INL/EXT-14-31428, Initiating Event Rates at U.S. Nuclear Power Plants, 1998-2013, Revision 1. From this, the finding was determined to have an increase in core damage frequency of 8.4E-8/year and to be of very low safety significance (Green). Transients, losses of condenser heat sink, and losses of main feed water were the dominant core damage sequences. The automatic depressurization system and the reactor protection system remained to mitigate these sequences. The finding had a cross-cutting aspect in the area of human performance associated with documentation because the licensee failed to create and maintain complete, accurate, and up-to-date documentation associated with RCIC-AOV-PCV23 design drawings and the maintenance procedure for setting and testing the mechanical stop (H.7).
05000219/FIN-2016004-01Oyster Creek2016Q4E EMRV Failureto Stroke Due to Incorrect ReassemblyThe NRC identified a preliminary White finding and associated apparent violation of Technical Specification 6.8.1, Procedures and Programs, and Technical Specification 3.4.B, Automatic Depressurization System, because Exelon failed to implement a procedure related to the maintenance of safety related equipment. Specifically, Exelon personnel did not follow electromatic relief valve (EMRV) reassembly instructions that required personnel to reinstall previously removed lock washers from the E EMRV cut-out switch lever. The incorrect reassembly caused excessive friction between the solenoid frame and the cut-out switch lever, which led to the E EMRVs failure to perform its safety function. This resulted in one inoperable EMRV for greater than the Technical Specification allowed outage time. The issue was entered into the corrective action program as issue report 2722109, and Exelons immediate corrective actions include installing new cut-out switch lever plates with increased clearances, replacing star lock washers with split ring lock washers for additional clearance, and verifying the five EMRV solenoid actuators being installed into the drywell following the most recent refueling outage were correctly assembled. The finding is more than minor because it adversely affects the human performance quality attribute of the Mitigating Systems cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the missing lock washers due to the incorrect EMRV lever plate reassembly caused excessive friction between the solenoid frame and the cut-out switch lever, causing the cut-out switch lever to become bound in the energized position. This led to the E EMRVs failure to perform its safety function. The inspectors screened this issue for safety significance in accordance with Inspection Manual Chapter 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, and determined a detailed risk evaluation was required because the E EMRV had potentially failed or was unreliable for greater than the Technical Specification allowed outage time. A detailed risk evaluation concluded that the increase in core damage frequency (CDF) related to the failure of the E EMRV is 5.4E-6/year; therefore, this finding was preliminary determined to have a low to moderate safety significance (White). Due to the nature of the failure, no recovery credit was assigned. The dominant core damage sequences involve loss of main feedwater events with operator errors resulting in failure to make-up to the 4 isolation condensers or otherwise maintain reactor vessel level and the loss of reactor pressure vessel depressurization capability (due to common cause failure of the remaining four EMRVs). The finding has a cross-cutting aspect in the area of Human Performance, Procedure Adherence, because Exelon personnel did not follow station processes. Specifically, Exelon did not follow written instructions when reassembling the E EMRV. The missing lock washers resulted in excessive friction between the solenoid frame and cut-out switch lever, causing the cut-out switch lever to become bound in the energized position, which led to the E EMRVs failure to perform its safety function. (H.8)
05000296/FIN-2016003-05Browns Ferry2016Q3Alternate Depressurization Valve Inoperable Longer than the Allowed Outage TimeA self-revealing NCV of TS 3.5.1, Emergency Core Cooling Systems, Condition E in that an inoperable Automatic Depressurization System (ADS) valve function existed longer than the allowed technical specification time. The licensee implemented corrective actions by declaring the affected component inoperable per technical specifications, identified preventative maintenance procedures as the cause, repaired the breaker stabs to restore the circuit, and re-performed the surveillance to establish operability. This issue was entered into the licensee's corrective action program as CR 1161991. The performance deficiency was more than minor because it adversely affected the Mitigating Systems cornerstone attribute of equipment performance. Specifically, one of the TS required ADS valves opening capability was not fully qualified. Using NRC IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, dated June 19, 2012, the inspectors determined the finding was of very low safety significance (Green) because the finding did not represent a loss of system safety function as the other five Main Steam Relief Valve (MSRV) ADS functions were still available. The inspectors assigned a cross cutting aspect of Identification since the licensee had not taken sufficient post maintenance actions to verify function of the alternate breaker for the ADS valve 3-PCV-001-0022. (P.1)
05000254/FIN-2015003-03Quad Cities2015Q3Failure to Adequately Inspect Relay Contacts for Oxidation Results in Relay FailureA finding of very low safety significance and an associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was self-revealed for the licensees failure to establish a preventive maintenance procedure for HFA relays that was appropriate to the circumstances. Immediate corrective actions included burnishing of the associated relay contacts and testing the associated relays. In addition, the licensee revised their relay inspection procedure and planned future relay replacements during the next refueling outage. The licensee entered the issue into their CAP as IR 2485051. The finding was determined to be more than minor because the finding was associated with the Mitigating Systems Cornerstone attribute of Procedure Quality and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage). Specifically, the failure to perform adequate preventive maintenance on the automatic depressurization system (ADS) logic HFA relay in 2013 resulted in the build-up of oxidation on the relay contacts. This build-up caused the relay to fail its next scheduled test in 2015. A senior reactor analyst performed a detailed risk evaluation and determined the finding was of very low safety significance. This finding had a cross-cutting aspect of operating experience in the area of problem identification and resolution, because the licensee did not systematically collect, evaluate, and implement relevant internal and external operating experience in a timely manner. Specifically, the licensee identified several internal and external operating experience events related to relay contact oxidation and failed to implement changes to their relay inspection procedures to ensure that effective corrective actions were implemented (P.5).
05000293/FIN-2015002-05Pilgrim2015Q2Failure to Submit an LERThe inspectors identified a Severity Level IV NCV because Entergy personnel did not provide a written report to the NRC within 60 days after discovery of the event as required by 10 CFR 50.73(a)(2)(i)(B) for a condition which was prohibited by TS 3.5.E, Automatic Depressurization System (ADS). Specifically, on January 27, 2015, Pilgrim experienced a loss of offsite power and reactor scram during a winter storm. While operators performed a reactor cooldown with manual operation of safety relief valves (SRVs), the 3C SRV twice failed to open upon demand by the operations crew. Entergy staff initiated CR-PNP-2015-0561 to document SRV 3Cs failure to open, and the valve was immediately declared inoperable. The inspectors determined that the improper operation of SRV 3C was reportable in accordance with 10 CFR 50.73(a)(2)(i)(B). Entergy has captured this issue in CR-2015-6191. The inspectors determined that Entergys failure to submit an event notification in accordance with 10 CFR 50.73 within the required time was a performance deficiency that was reasonably within Entergys ability to forsee and correct, and should have been prevented. Because the issue had the potential to affect the NRCs ability to perform its regulatory function, the inspectors evaluated this performance deficiency in accordance with the traditional enforcement process. Using example 6.9.d.9 from the Enforcement Policy, the inspectors determined that the violation was a Severity Level IV (a failure of a licensee to make a report required by 10 CFR 50.72 or 10 CFR 50.73) violation. Because this violation involves the traditional enforcement process and does not have an underlying technical violation, inspectors did not assign a cross-cutting aspect to this violation in accordance with IMC 0612, Appendix B.
05000374/FIN-2015001-03LaSalle2015Q1COLR Revision Potentially Created Non-Conservative Technical SpecificatAs part of the overall review of the Unit 2 Jet Pump Plug issue (described in greater detail in Section 4OA2.4 of this report), the inspectors reviewed the changes made to the Unit 2 COLR, Cycle 16, Revisions 1 and 2. The inspectors assessed the changes with respect to their potential impact on the current licensing basis, i.e., TSs and regulations such as 10 CFR 50.36. In Revision 1 of LaSalles Unit 2 Cycle 16 COLR, the licensee introduced a new section in the form of an Appendix, entitled Operating Limits for Lost Jet Pump Plug Seals Mitigation Strategy. This appendix states The following limits apply while the jet pump plug peripheral bundle blocked orifice condition exists. Specifically, item 4 entitled Other Requirements, states in part that All equipment must be in-service. This includes the EOOS (equipment out-of-service) assumed in the Base Case mentioned in Footnote 1 of COLR Section 10 EXCEPT LPRMs (local power range monitors) and TIPOOS (traversing in-core probe out-of-service) (...) In the event of an EOOS, take action in accordance with TS 3.2.2 ACTION statements. Those TS actions were to Reduce THERMAL POWER to < 25% RTP (rated thermal power) within a 4-hour completion time. The equipment referenced in the COLR Section 10 Base Case that have associated TS LCOs are safety relief valves (SRVs) (LCOs 3.4.4 and 3.5.1) and turbine bypass valves (TBVs) (LCO 3.7.7). LCO 3.4.4 states The safety function of 12 SRVs shall be OPERABLE. Unit 2 has a total of 13 SRVs, so this LCO essentially allows one SRV to be OOS indefinitely with no further action required; however, since the COLR created a new operational restriction to prohibit any SRVs from being OOS in order to maintain the unit in an analyzed condition, the inspectors questioned the apparent non-conservatism that the COLR created for LCO 3.4.4. Specifically, under an identical condition of 1 SRV OOS, the COLR would have required the unit to downpower to less than 25 percent power, while the TSs would have allowed continuous operation at full power. LCO 3.5.1 states (...) the Automatic Depressurization System (ADS) function of six safety/relief valves shall be OPERABLE. Unit 2 has a total of 7 ADS SRVs, so this LCO essentially allows one ADS SRV to be OOS indefinitely with no further action required; however, since the COLR created a new operational restriction to prohibit any SRVs from being OOS in order to maintain the unit in an analyzed condition, the inspectors questioned the apparent non-conservatism that the COLR created for LCO 3.5.1. Specifically, under an identical condition of 1 ADS SRV OOS, the COLR would have required the unit to downpower to less than 25 percent power, while the TSs would have allowed continuous operation at full power. LCO 3.7.7 states The Main Turbine Bypass System shall be OPERABLE. OR LCO 3.2.2, MINIMUM CRITICAL POWER RATIO (MCPR), limits for an inoperable Main Turbine Bypass System, as specified in the COLR, are made applicable. The Cycle 16 COLR Base Case was analyzed to allow 2 TBVs to be OOS without taking any further action or incurring any operational penalty; however, since the COLR created a new operational restriction to prohibit any TBVs from being OOS in order to maintain the unit in an analyzed condition, the inspectors questioned the apparent non-conservatism that the COLR created for LCO 3.7.7. Specifically, under an identical condition of 2 TBVs OOS, the COLR would have required the unit to downpower to less than 25 percent power, while the TSs would have allowed continuous operation at full power. This issue is considered a URI pending additional internal discussion with the NRC Office of Nuclear Reactor Regulation to seek guidance on whether the above examples classify as LCOs and further, how NRC Administrative Letter 9810 may apply.
05000293/FIN-2015007-02Pilgrim2015Q1Failure to Identify, Evaluate, and Correct A SRV Failure to Open Upon Manual ActuationA self-revealing preliminary White finding and AV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, and Technical Specification (TS) 3.5.E, Automatic Depressurization System, was identified for the failure to identify, evaluate, and correct a significant condition adverse to quality associated with the A SRV. Specifically, Entergy failed to identify, evaluate, and correct the A SRVs failure to open upon manual actuation during a plant cooldown on February 9, 2013. In addition, the failure to take actions to preclude repetition resulted in the C SRV failing to open due to a similar cause following the January 27, 2015, LOOP event. Entergy entered this issue in to the CAP as CR-PNP-2015-01983, CR-PNP-2015-00561, and CR-PNP-2015-01520. Immediate corrective actions included replacing the A and C SRVs and completing a detailed operability analysis of the installed SRVs which concluded that a reasonable assurance of operability existed. Entergys failure to identify, evaluate, and correct the condition of the A SRVs failure to open upon manual actuation during a plant cooldown on February 9, 2013, was a performance deficiency. In addition, the failure to take actions to preclude repetition resulted in the C SRV failing to open due to a similar cause following the January 27, 2015 LOOP event. The self-revealing finding was within Entergys ability to foresee and correct because indications were available to determine that the A SRV valve did not open upon manual actuation. This was discovered as a result of an extent of condition review of the C SRV failing to open upon manual actuation following the January 27, 2015 LOOP event. This performance deficiency is more than minor because it could reasonably be viewed as a precursor to a significant event if two of the four SRVs failed to open when demanded to depressurize the reactor, following the failure of high pressure injection systems or torus cooling, to allow low pressure injection systems to maintain reactor coolant system inventory following certain initiating events. In addition, it is associated with the Mitigating Systems cornerstone attribute of equipment performance and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors screened this issue for safety significance in accordance with IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, issued June 19, 2012. The screening determined that a detailed risk evaluation was required because it was assumed that for a year period, two of the four SRVs were in a degraded state such that they potentially would not have functioned to open at some pressure lower than rated pressure and would not fulfill their safety function for greater than the TS allowed outage time. Specifically, the assumptions of failures to open were based on: a failed actual opening demand at 200 psig reactor pressure on January 27, 2015, for the C SRV; examination of the valve internals at the testing vendor (National Technical Systems); and a previous failed actual opening demand at 114 psig reactor pressure on February 9, 2013, for the A SRV. The staff determined that there wasnt an existing SDP risk tool that is suitable to assess the significance of this finding with high confidence, mainly because of the uncertainties associated with: the degradation mechanism and its rate; the range of reactor pressure at which the degraded valves could be assumed to fully function; any potential benefit from an SRV lifting at rated pressure, such that the degradation would be less likely to occur and, therefore, prevent a subsequent failure at low pressure in the near-term; the time based nature of plant transient response relative to when high pressure injection sources fail and the associated impact of reduced decay heat on the SRV depressurization success criteria; and the ability to credit other high pressure sources of water. Based on the considerations above, the risk evaluation was performed using IMC 0609, Appendix M, Significance Determination Process Using Qualitative Criteria, issued April 12, 2012. The NRC made a preliminary determination that the finding was of low to moderate safety significance (White) based on quantitative and qualitative evaluations. The detailed risk evaluation is contained in Attachment 4 to this report. This finding does not present a current safety concern because the A and C SRVs were replaced during the outage following the January 27, 2015 LOOP and reactor trip event. Also, Entergy performed a detailed operability analysis of the installed SRVs which concluded that a reasonable assurance of operability existed. This finding had a cross-cutting aspect in Problem Identification and Resolution, Evaluation, because Entergy did not thoroughly evaluate issues to ensure that resolutions address causes and extent of conditions commensurate with their safety significance. Specifically, Entergy staff did not thoroughly evaluate the operation of the A SRV during the February 9, 2015 plant cooldown and should have reasonably identified that the A SRV did not open upon three manual actuation demands.
05000293/FIN-2015007-01Pilgrim2015Q1Inadequate Past Operability Assessment of C Safety Relief ValveThe team identified a Green NCV of Title 10 of the Code of Federal Regulations (10 CFR) 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, when Entergy staff performed an inadequate past operability determination that assessed performance of the C safety/relief valve (SRV), which did not open as expected when called upon to function. Specifically, following the January 27, 2015 reactor scram, operators placed an open demand for the C SRV twice during post-scram recovery operations, but the valve did not respond as expected and did not perform its pressure reduction function on both occasions. Entergys subsequent past operability assessment for the valves operation incorrectly concluded that the valve was fully capable of performing its required functions during its installed service. In response to the teams past operability concerns, Entergy subsequently re-evaluated the past operability of C SRV and concluded that it was inoperable and placed the issue into the corrective action program (CAP) as CR-PNP-2015- 02051. The team determined the failure to adequately assess past operability of the C SRV was a performance deficiency that was reasonably within Entergys ability to foresee and correct. This NRC-identified performance deficiency is more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone and affects the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent core damage. The team evaluated the finding using IMC 0609, Appendix 0609.04, Initial Characterization of Findings, which directed the use of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power. Using Exhibit 2, Mitigating Systems Screening Questions, of IMC 0609, Appendix A, the team determined this finding was not a design or qualification deficiency and was not a potential or actual loss of system or safety function, and was therefore of very low safety significance (Green). The finding had a cross-cutting aspect in Human Performance, Conservative Bias, because Entergy did not use decision making practices that emphasized prudent choices over those that are simply allowable. Specifically, Entergy did not appropriately evaluate unexpected and unsatisfactory performance of the C SRV in consideration of the entire pressure range that the SRV, including its automatic depressurization system (ADS) function, was required to be operable.
05000219/FIN-2014009-01Oyster Creek2014Q4Inadequate Application of Materials, Parts, Equipment, and Processes Associated with the Electromatic Relief ValvesThe NRC identified a preliminary Yellow finding and associated apparent violation of 10 CFR 50, Appendix B, Criterion III, Design Control, and Technical Specification 3.4.B, Automatic Depressurization System, because the station did not establish adequate measures for selection and review for suitability of application of materials, parts, equipment, and processes that are essential to the safety-related functions of the electromatic relief valves (EMRVs). The violation was also preliminarily determined to meet the IMC 0305, Section 11.05, criteria for treatment as an old design issue. Specifically, on June 20, 2014, during refurbishment of EMRVs that were removed from the plant during the 2012 refueling outage, Exelon personnel identified deficiencies with the B and D EMRVs. As part of the planned EMRV actuator testing and refurbishment activities, Exelon personnel conducted bench testing on June 26, 2014. Both valves did not stroke satisfactorily and resulted in two inoperable EMRVs for greater than the Technical Specification allowed outage time of 24 hours. Exelons immediate corrective actions included placing this issue into the corrective action program as issue report 1679428 and redesigning the EMRV actuators to ensure the spring is on the outside of the guide bushing, therefore removing the possibility of the spring entering the guide bushing area and subsequently jamming the actuator causing valve failure. All of the actuators were replaced with redesigned actuators during the refueling outage in October 2014. In addition, Exelon issued a 10 CFR Part 21 report to inform the industry of the deficient EMRV actuator design. This finding is more than minor because it adversely affected the design control quality 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 design deficiency of the EMRVs and the inadequate maintenance process led to the inability of the B and D EMRVs to perform their safety function. The inspectors screened this issue for safety significance in accordance with IMC 0609, Appendix A, Exhibit 2, and determined a detailed risk evaluation was required because the EMRVs were potentially failed or unreliable for greater than the Technical Specification allowed outage time. As described in Attachment 3 to this report, a detailed risk evaluation concluded that the increase in core damage frequency (CDF) related to failure of the B and D EMRVs is in the mid E-5 range; therefore, this finding was preliminarily determined to have a substantial safety significance (Yellow). Due to the nature of the failures, no recovery credit was assigned. The dominant sequences included loss of main feedwater with failures of the isolation condensers, and failure to depressurize. This finding does not represent an immediate safety concern because Exelon replaced all of the actuators with the redesigned actuators during the refueling outage in October 2014. Further, the NRC is considering treatment of this finding as an old design issue because the condition existed since the original installation of the EMRVs, and is not indicative of current licensee performance. Additional details are discussed in Attachment 1. The inspectors determined that this finding did not have a cross-cutting aspect because the most significant contributor to the performance deficiency was not reflective of current licensee performance. Specifically, the inspectors determined that the performance deficiency existed since original installation of the EMRVs. Although an opportunity to identify this issue following original installation occurred in 2006 when Quad Cities changed the EMRV actuator design due to similar issues, the inspectors could not conclude that the issue would have likely been identified during that period since a Part 21 Report was not issued to inform the industry and NRC of the design change and industry operating experience focused on plants that completed or were scheduled to complete an extended power uprate.
05000259/FIN-2014005-02Browns Ferry2014Q4Failure to Demonstrate Satisfactory Performance of the Automatic Depressurization System Air AccumulatorsA self-revealing non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion XI, Test Control, was identified for the licensees failure to have a test program that assured testing would verify Unit 1 Automatic Depressurization System (ADS) valve 1-PCV-1-19 would perform satisfactorily in service. Specifically, the licensee failed to verify and check the proper configuration and performance of ADS valve 1-PCV-1-19 with a satisfactory post maintenance test as required by NPG-SPP-06.3, Pre/Post-Maintenance Testing. On October 30, 2014 operators discovered that valve 1-PCV-1-19 would no open as required. Troubleshooting revealed that the control air line accumulator to 1-PCV-1-19 was misconfigured and aligned instead to, non-ADS, steam relief valve 1-PCV-1-18. The licensee entered into the licensees corrective action program as PER 952082. The finding was more than minor because it was associated with the mitigating systems cornerstone attribute of Configuration Control, 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 failure t perform an adequate post maintenance test prevented the discovery of the improper installation of ADS valve 1-PCV-1-19 control air line and allowed the inoperability of the valve to exist undetected during plant operation. Using IMC 0609.04, Initial Characterization of Findings and IMC 0609 Appendix A, Exhibit 2 Mitigating Systems screening questions, the finding screened as very low safety significance (Green). The finding did not represent an actual loss of function of a single train for greater than it technical specification allowed outage time and did not represent an actual loss of function of one or more non-technical specification equipment for greater than 24 hours. This finding does not have a cross-cutting aspect because the lack of proper post maintenance testing to verify the configuration of the ADS air line was made in November 2006 and was not reflective of current performance.
05000416/FIN-2014007-01Grand Gulf2014Q2Possible Spurious Actuation of The Safety Relief Valves During Control Room Fire ScenariosThe team reviewed the licensees safe shutdown analyses, thermal hydraulic analysis, and the licensing basis for control room fire scenarios. The team identified three issues of concern that require additional information and inspection for resolution. Concern 1: Required Alternative Shutdown Scenarios The first issue of concern was associated with the identification of the control room fire scenarios that were required by the licensing basis to be considered and mitigated. The NRC promulgated guidance for alternative and dedicated shutdown capability in Generic Letter 86-10, Implementation of Fire Protection Requirements. In Question 5.3.10, Design Basis Plant Transients, the staff addressed the plant transients that should be considered in the design of alternative or dedicated shutdown systems. The staff stated that a loss of offsite power shall be assumed for any alternative shutdown area. In addition, the staff stated that the safe shutdown capability should not be adversely affected by a fire in any plant area which results in the loss of all automatic function (signals, logic) from the circuits located in the area in conjunction with one worst case spurious actuation or signal resulting from the fire. On February 24, 2005, the licensee identified a concern with the transient analysis for a control room fire and documented it in Condition Report CR-GGN-2005-00770. The licensee stated that, it appears that it does not assume the loss of offsite power concurrent with the loss of all automatic functions (signals, logic) in conjunction with the worst case spurious actuation or signal resulting from the fire as required by Section III.L of Appendix R and Generic Letter 86-10. On August 24, 2005, the licensee evaluated this concern and determined that the fire induced spurious actuation of the safety relief valves could occur in any of three ways: 1. A single intra-cable short within the control circuit cable could actuate an individual safety relief valve. The safety relief valve control cables were routed together within the control room with each cable containing multiple control conductors and multiple 125 Vdc conductors. 2. Two intra-cable shorts within two separate instrument cables or two intra-cable shorts within a single instrument cable could actuate all eight of the safety relief valves associated with the automatic depressurization system. 3. Two intra-cable shorts within two separate instrument cables to either Division I or Division II circuits could open all 20 safety relief valves. The licensee concluded in their evaluation that it is expected that the worst case spurious actuation or signal resulting from a fire in the control room would involve opening of 20 safety relief valves. On November 2, 2009, the NRC provided the following additional guidance for alternative and dedicated shutdown capability in Regulatory Guide 1.189, Fire Protection for Nuclear Power Plants, Revision 2: The licensee should consider one spurious actuation or signal to occur before control of the plant is achieved through the alternative or dedicated shutdown system for fires in areas that require alternate or dedicated shutdown. After the operators transfer control from the control room to the alternative or dedicated shutdown system, single or multiple spurious actuations that could occur in the fire-affected area should be considered, in accordance with the plants approved fire protection program. The approach outlined in Appendix D to NEI 00-01 provides an acceptable methodology for evaluating alternative and dedicated shutdown, when applied in conjunction with this regulatory guide. In addition, the second paragraph of Appendix G to NEI 00-01 provides information regarding the analysis of multiple spurious actuations for alternative and dedicated shutdown systems. The licensee continued to evaluate this concern through their corrective action program. On August 17, 2012, the licensee developed Engineering Report GGNS-EE-10-00003, Safe Shutdown Evaluation of Control Room Fire Scenarios, Revision 0. In this report, the licensee relied on guidance contained in Appendix G, Generic List of MSOs, to NEI 00-01, Guidance for Post Fire Safe Shutdown Circuit Analysis, Revision 2, when evaluating the effect of a control room fire spuriously actuating all 20 safety relief valves. Specifically, the licensee stated: In accordance with the second paragraph of Appendix G to NEI 00-01, scenarios that involve spurious operation of multiple safe shutdown components concurrent with failure of automatic functions need not be included in the analysis of impacts for the main control room. However, if plant response to such transients could negate the capability to achieve and maintain post-fire safe shutdown, a voluntary review of the postulated scenarios may be warranted to supplement a previously approved alternative shutdown capability that scenarios that involve the spurious operation of multiple safe shutdown components concurrent with the failure of automatic functions need not be included in the analysis of impacts for the control room. The team reviewed the NRC positions provided in Regulatory Guide 1.189, Revision 2, and discussed these positions with personnel in the Office of Nuclear Reactor Regulation. The team determined that the NRC endorsed the approach outlined in Appendix D, Alternative/Dedicated Shutdown Requirements, to NEI 00-01, Revision 2 (when applied in conjunction with Regulatory Guide 1.189, Revision 2). The team also determined that the NRC neither endorsed nor rejected the approach for analyzing multiple spurious actuations for alternative and dedicated shutdown systems outlined in Appendix G to NEI 00-01, Revision 2. The team was concerned that the licensee may not have adequately followed the guidance for identifying the control room fire scenarios that were required to be considered and mitigated. The NRC staff will need to perform additional review to determine if the plants licensing basis required the licensee to analyze and mitigate the spurious actuation of a single safety relief valve (due to a single intra-cable hot short in a single cable), the spurious actuation of the automatic depressurization system (due to two intra-cable hot shorts in a single cable), or the spurious actuation of all twenty safety relief valves (due to a single intra-cable hot short in two separate cables). Concern 2: Time Available for Operators to Depressurize the Reactor The second issue of concern was associated with the amount of time available for operators to depressurize the reactor during control room fire scenarios. For control room fires, the licensees alternative shutdown strategy required operators to take immediate actions to restore electrical power, align a residual heat removal pump in the low pressure coolant injection mode, and depressurize the reactor using six safety relief valves prior to the reactor vessel level reaching -160 . The licensee described the plant response during an alternative shutdown in Engineering Report GGNS-NE-10-00003, GGNS EPU Appendix R Fire Protection, Revision 2. This thermal hydraulic analysis calculated the amount of time for the reactor vessel level to reach -160 (assuming no high pressure injection sources were available) and the resulting maximum peak clad temperature. Using a nominal scenario with no spurious actuations, the licensee determined the reactor vessel level would reach -160 within 14.3 minutes and the reactor would experience a maximum peak clad temperature of 597 F. The team performed a timed walkdown of the alternative shutdown procedure and determined that it took operators approximately 12 minutes to align the equipment required for depressurizing the reactor and injecting with the residual heat removal pump. The licensee also analyzed the plant response using an alternate scenario with the spurious actuation of all 20 safety relief valves. In this alternate scenario, the licensee determined the residual heat removal pump would initiate in the low pressure coolant injection mode within 118 seconds to restore level, the residual heat removal pump would begin injecting water into the reactor within 153 seconds, and the reactor would experience a maximum peak clad temperature of 597 F. For the evaluation of the alternate scenario, the licensee relied upon guidance contained in NEI 00-01, Appendix G, to credit the automatic initiation of the residual heat removal pump in the low pressure coolant injection mode. The team noted that this assumption could be considered adequate for analyzing control room fire scenarios that were outside of the licensing basis, but would be considered inadequate for demonstrating compliance with control room fire scenarios that were required to be considered and mitigated since it credited the availability of electrical power as well as the automatic initiation of the residual heat removal pump. In either case, the team noted that the evaluation of the alternate scenario failed to account for the steps in the alternative shutdown procedure that directed operators to open the breaker for the residual heat removal pump prior to restoring electrical power and subsequently restarting the pump. The team performed a timed walkdown of the alternative shutdown procedure and determined that it took operators approximately 8 minutes to open the breaker for the residual heat removal pump and approximately 12 minutes to depressurize the reactor and restart the residual heat removal pump. The team was concerned that the licensees determination of the time available for operators to depressurize the reactor may be incorrect. Specifically, the team was concerned that the licensees determination that operators had 14.3 minutes available to take the required immediate actions prior to the reactor vessel level reaching -160 may be incorrect since the evaluation failed to assume any spurious actuations. As described in the previous concern, the licensee may be required to consider and mitigate the spurious actuation of a single safety relief valve, the automatic depressurization system, or all 20 safety relief valves. The team noted that the thermal hydraulic analysis did not evaluate the plant response to the spurious actuation of a single safety relief valve or the automatic depressurization system. The team required additional information in order to resolve this concern. Specifically, the team required a thermal hydraulic analysis that provided the plant response to the control room fire scenarios that were required to be considered and mitigated. This thermal hydraulic analysis will be used to determine the amount of time available for operators to restore electrical power, align the residual heat removal pump in the low pressure coolant injection mode, and prepare to depressurize the reactor prior to reaching a reactor vessel level of -160 . Concern 3: Isolation of the Safety Relief Valve Circuits The third issue of concern was associated with the isolation of the safety relief valve circuits. For control room fires, the licensees alternative shutdown strategy required operators to open two breakers (72-11A23 and 72-11B34) in order to ensure that the 14 non-credited safety relief valves were closed. The six credited safety relief valves were isolated from the control room via the use of transfer switches. The team was concerned that hot shorts in the control room could cause a spurious actuation that threatened the ability to achieve and maintain safe shutdown conditions. The team noted that the control room cabinets containing the safety relief valve circuits also contained other 125 Vdc circuits that may remain energized during an alternative shutdown. The team was concerned that hot shorts from one of these circuits could prevent the closure of safety relief valves (if spuriously open) or could spuriously open the safety relief valves after the control room was isolated and control transferred from the control room to the remote shutdown panel. The team required additional information in order to resolve this concern. Specifically, the team required an evaluation of the remaining circuits in the control room panels that contain the safety relief valve circuits in order to determine if any of these other circuits remain energized during an alternative shutdown. The licensee entered these issues of concern into the corrective action program as Condition Report CR-GG-2014-03690. These issues of concern are being treated as an Unresolved Item 05000416/2014007-01, Possible Spurious Actuation of the Safety Relief Valves During Control Room Fire Scenarios.
05000458/FIN-2013007-04River Bend2013Q4Unresolved Item Associated with the Isolation of the Alternative Shutdown SystemThe team identified an unresolved item associated with the isolation of post-fire safe shutdown circuitry for control room fire scenarios. Specifically, the team identified that the licensee may not adequately isolate circuitry for the safety relief valves and the main steam isolation valves from the effects of a control room fire. In the event of a fire in the control room, the licensee must ensure control circuitry for equipment credited for post-fire safe shutdown is electrically isolated from the control room so that fire damage could not prevent the ability to achieve and maintain safe shutdown conditions. For valves that are required to close or remain closed for post-fire safe shutdown, the licensee must ensure that control room fires do not prevent the closure of the valves and do not spuriously open the valves once the control room has been isolated and control transferred from the control room to the remote shutdown panel. Example 1: Spurious Opening of the Safety Relief Valves The alternative shutdown procedure provided steps for operators to mitigate the effects of any single spurious actuation or signal resulting from a control room fire that occurred prior to transferring control from the control room to the remote shutdown panel. For the safety relief valves, the procedure directed operators to de-energize two 125 Vdc panels (ENB-PNL02A and ENB-PNL02B) in order to ensure that the 13 non-credited safety relief valves were closed. The three credited safety relief valves were isolated from the control room via the use of transfer switches. The team identified a concern that hot shorts in the control room could cause a spurious actuation that threatened the ability to achieve and maintain safe shutdown conditions. The team noted that the control room cabinets containing the safety relief valves also contained other 125 Vdc circuits that remained energized during an alternative shutdown. The team was concerned that hot shorts from one of these circuits could prevent the closure of a safety relief valve (if spuriously open) or could spuriously open the safety relief valve once the control room was isolated and control transferred from the control room to the remote shutdown panel. The team was also concerned that the safe shutdown analysis did not analyze for one or more safety relief valves remaining open during the plant shutdown. This concern applied to the 13 safety relief valves that did not have control transferred to the remote shutdown panel. In addition, the team noted that circuit failures could spuriously open multiple safety relief valves through the spurious actuation of the automatic depressurization system. The team was concerned that the spurious actuation of the automatic depressurization system could be considered a single spurious actuation or signal that fell within the bounds of the safe shutdown analysis. A similar concern was first identified during the 1997 fire protection functional inspection and documented in Inspection Reports 97-201 and 98-16. Example 2: Spurious Opening of the Main Steam Isolation Valves As noted in the previous example, the alternative shutdown procedure provided steps for operators to mitigate the effects of any single spurious actuation or signal resulting from a control room fire that occurred prior to transferring control from the control room to the remote shutdown panel. For the main steam isolation valves, the procedure directed operators to attempt to close the main steam isolation valves inside the control room and then de-energize the reactor protection system motor generator sets outside the control room. The reactor protection system provides power to the circuitry for the main steam isolation valve solenoids. When the solenoids are de-energized, the main steam isolation valves fail closed. The team identified a concern that hot shorts in the control room could cause spurious actuations that threatened the ability to achieve and maintain safe shutdown conditions. Specifically, the team identified that a portion of the trip logic circuitry was connected in the control room to the portion of the circuitry that energizes the solenoid valve for each main steam isolation valve. The trip logic circuitry was located downstream of where the reactor protection system bus was de-energized, and it did not contain a protective circuit device such as fusing or open contacts that would isolate the trip logic portion of the circuitry from the solenoid valve. The control room cabinet containing the trip logic circuitry also contained other 125 Vdc circuits that remained energized during an alternative shutdown. The team was concerned that hot shorts from these circuits could prevent the closure of the main steam isolation valves or could spuriously open the main steam isolation valves after the reactor protection system motor generator sets were de-energized. The team noted that one main steam isolation valve, either inboard or outboard, must close and remain closed in order to maintain inventory. The licensee entered these issues into the corrective action program as Condition Report CR-RBS-2013-03473. The team determined that additional inspection is required to determine if a performance deficiency exists. This issue of concern is being treated as an Unresolved Item URI 05000458/2013007-04, Unresolved Item Associated with the Isolation of the Alternative Shutdown System.
05000324/FIN-2011004-04Brunswick2011Q3Licensee-Identified ViolationTechnical Specification 5.4.1, Procedures, requires that written procedures shall be implemented covering applicable procedures recommended in Regulatory Guide 1.33, Appendix A, November 1972 (Safety Guide 33, November 1972). Regulatory Guide 1.33, section I (Safety Guide 33, November 1972) requires written procedures for performing maintenance. Contrary to the above, the licensee identified that maintenance procedure 0CM-VFC500, Instructions for Repair, Reassembly, and Adjustment of the RCIC Terry Turbine Governor Valve, did not contain adequate guidance for assembling the unit 2 RCIC turbine governor valve. As a result, inadequate maintenance was performed on the unit 2 RCIC governor valve in 2009 in that proper spacing of the valve stem packing spacers was not maintained. This inadequate maintenance on the RCIC governor valve led to failure of the valve during quarterly surveillance testing on April 15, 2011. This finding was evaluated by the Regional Senior Reactor Analyst performing a Phase 3 significance analysis. The finding was determined to have a risk lower than 1E-6, and is GREEN. The short exposure time, and the availability of the severe accident mitigation alternative (SAMA) diesels for battery charging contributed to the low impact of the finding. The results were dominated by loss of the DC bus that powers HPCI, combined with automatic depressurization system (ADS) failures that could lead to high pressure core melt. External Events and Large Early Release Probability were found not to be major contributors to the risk of the finding. As corrective actions, the licensee revised the maintenance procedure and repaired the valve. This issue is in the licensees CAP as NCR #468283.
05000259/FIN-2011003-02Browns Ferry2011Q2Over-Pressurization of High Pressure Coolant Injection System due to Stuck Open HPCI System Testable Check ValveA self-revealing non-cited violation of 10 CFR 50 Appendix B, Criteria XVI, Corrective Action, was identified for the licensees failure to promptly correct a condition adverse to quality related to Unit 1 High Pressure Coolant Injection (HPCI) system testable check valve which resulted in over-pressurization and significant damage to the HPCI system. Specifically, binding of the actuator linkage connected to the valve disc shaft caused the valve disc to physically stick open following a HPCI injection event. Subsequent opening of the inboard HPCI injection valve in preparation for a routine HPCI venting evolution resulted in over-pressurization of the HPCI system. The licensee repaired the damage to the HPCI system and temporarily modified the valve actuator linkage to remove any potential for binding until more permanent repairs could be performed in a unit outage. The licensee entered this issue into their corrective action program as problem evaluation report (PER) 372659. This finding was determined to be more than minor because it was associated with the Mitigating Systems Cornerstone attribute of Equipment Performance, 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 stuck open testable check valve resulted in overpressurization of the HPCI system, significant damage to HPCI components, and loss of the HPCI function. In accordance with Inspection Manual Chapter (IMC) 0609 Attachment 4, Phase I - Initial Screening and Characterization of Findings, this finding was determined to be of very low safety significance because it did not represent a loss of system safety function or screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The Automatic Depressurization System (ADS) was available at all times to support the coolant injection safety function. The cause of this finding was directly related to the cross-cutting aspect of Thorough Evaluation of Identified Problems in the Corrective Action Program component of the Problem Identification and Resolution area, because of the licensees inadequate evaluation of PER 289169 for the abnormal check valve actuator open indication that subsequently resulted in an over-pressurization and loss of function of the Unit 1 HPCI system (P.1.(c)).
05000271/FIN-2011002-03Vermont Yankee2011Q1NoneTechnical Specification 3.5.F, Automatic Depressurization System, allows up to one of. four SRVs in the automatic depressurization system to be inoperable for up to seven days at any time the reactor steam pressure is above 150 psig with irradiated fuel within the vessel, or an orderly shutdown of the reactor shall be initiated and the reactor pressure shall be reduced to less than 150 psig within 24 hours. Contrary to the above, Entergy determined that two (2) of the four (4) SRVs were inoperable for a period of time greater than allowed by Technical Specifications. This determination was based on pneumatic actuator thread seal leakage that was identified during testing of the pneumatic SRV actuators in the 2010 refueling outage. Entergy determined the leakage to be in excess of design requirements. This condition has been entered in the licensee\'s corrective action program (CR-VTY-2010-2187) and corrective actions have been developed. The inspectors determined that this finding was more than minor because it adversely affected the Mitigation Systems cornerstone objective of ensuring the reliability of systems that respond to initiating events to prevent undesirable consequences. The inspectors determined that the function for core decay removal was affected, since the safety function of the ADS valves is to depressurize the reactor to allow for low pressure coolant injection. The inspectors determined that this finding was not greater than Green, because subsequent laboratory analysis and engineering evaluation documented in Entergy Operability Recommendation VTY 2011-0631 concluded that sufficient margin was available in the safety-class backup supply to the pneumatic actuation system. The inspectors reviewed Entergy\'s laboratory results and Operability Recommendation, and concluded that the ADS function would have been met under the worst case leakage for all design basis conditions
05000298/FIN-2007011-06Cooper2007Q4Severity Level Iv for Failure to Comply with the Requirements of 10 CFR 50.71(E) and to Assure the Updated Safety Analysis Report Has the Latest Information DevelopedThe team identified a noncited Severity Level IV violation for the failure to comply with the requirements of 10 CFR 50.71(e). The correct value for the automatic depressurization system accumulator minimum pressure was not used to revise the Updated Safety Analysis Report. Specifically, the licensees technical specifications and Design Calculation NEDC 88-306 require a minimum of 88 psig to assure five actuations of the safety relief valves with the drywell at atmospheric conditions. The Updated Safety Analysis Report lists a minimum pressure of 68.6 psig for this function. The Updated Safety Analysis Report stated pressure of 68.6 psig was incorporated as part of the licensees Updated Safety Analysis Report rebase line project and became effective on March 10, 2000. The licensee was unable to provide a basis for the lower pressure stated in the Updated Safety Analysis Report. This violation was subject to traditional enforcement because it had the potential to impact the regulatory process. This finding is considered more than minor because use of this lower pressure value could render the automatic depressurization feature incapable of performing its design function. In accordance with NRC Enforcement Policy, the NRC has concluded that this is a Severity Level IV violation. Because this violation was of very low safety significance, was not repetitive or willful, and it was entered into the licensees corrective action program as Condition Report CNS-2007-07468, this violation is being treated as an noncited violation, consistent with Section VI.A.1 of the NRC Enforcement Policy.
05000254/FIN-2000016-04Quad Cities2000Q4Associated Circuits Issue. Single spurious operation, including effect of automatic depressurization system failures on the time line.Single spurious operation, including effects of automatic depressurization system failures on the time line for achieving safe shutdown. This issue pertains to associated circuits and is described in Section E1.4 of Inspection Report 50-254/98011; 50-265/98011. Pending completion of the NRC/industry review and resolution of associated circuit issues affecting safe shutdown, this is considered an unresolved item. This issue will be tracked under a new unresolved item (URI 50-254/00-16-04; 50-265/00-16-04). This part of the unresolved item is considered closed.
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