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05000387/FIN-2018011-012018Q3SusquehannaFailure to conduct proper testing of 125 VDC molded case circuit breakers to confirm their design adequacy long-termThe inspectors identified a Green non-cited violation (NCV) of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion XI, Test Control. Specifically, Susquehanna has not established a program to adequately exercise and test safety-related 125VDC molded case circuit breakers (MCCBs) since initial plant operation.
05000423/FIN-2018010-052018Q2MillstoneInadequate Test Control of ECCS Valve InterlocksThe team identified a finding of very low safety significance (Green) involving an NCV of 10 CFR Part 50, Appendix B, Criterion XI, Test Control. Specifically, Dominion did not ensure that all testing required to demonstrate that emergency core cooling system (ECCS) valve interlock circuits would perform satisfactorily was being performed. The team determined that certain interlocks associated with ECCS valve 3SIL*MV8804A control circuit were not properly tested to demonstrate that the valve would not open if interlocks had not been met or would open, when required, with minimum interlock requirements met during design basis accidents.
05000336/FIN-2018010-042018Q2MillstoneFlood Seals Not Installed in Unit 2 A EDG and Auxiliary Building PenetrationsThe team identified a finding of very low safety significance (Green) and associated NCV of 10 CFR Part 50, Appendix B, Criterion XIV, Corrective Actions. Dominion identified a condition adverse to quality but did not correct the condition. Specifically, Dominion performed evaluations and walk downs in 2012 and 2016 to validate that all necessary flood seals for design basis and beyond design basis flood events had been properly installed. Dominion determined that they could not verify 50 wall penetrations had seals installed and entered the deficiency into the corrective action program. The team noted that an electrical conduit that passed through a Unit 2 A emergency diesel generator (EDG) building exterior wall, located below the design basis flood height, was one of the penetrations in question. During the inspection, following NRC questions, Dominion removed the electrical conduit cover plate and confirmed that a seal was not installed.
05000423/FIN-2018010-022018Q2MillstoneOver-Duty Breakers on Safety-Related Bus 34C on Unit 3The team identified a finding of very low safety significance (Green) and an associated NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control. Specifically, Dominion did not adequately evaluate the results of the Unit 3 short circuit calculations for the 4.16 kV breakers. Dominions evaluation of the short circuit calculation results did not identify that the breakers were non-conforming to the licensing basis. The teams review of the calculation results found that the momentary and interrupting duty ratings of the 4kV safety-related breakers associated with Bus 34C were not within their short-circuit ratings when evaluated under design fault condition and, therefore, not in accordance with the licensing basis of the plant.
05000336/FIN-2018010-012018Q2MillstoneOver-Duty Breakers on Safety-Related Buses on Unit 2The team identified a finding of very low safety significance (Green) and an associated non-cited violation (NCV) of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion III, Design Control. Specifically, Dominion incorrectly concluded that the 480V safety-related breakers were conforming to the plants licensing basis following their identification that the calculated short circuit fault current exceeded the breaker rating. Dominions evaluation failed to take into consideration that non-class 1E loads fed from safety-related buses must be isolated from the class 1E system by fully qualified safety-related isolation devices (breakers). Dominions design basis requires that a circuit fault on the non-class 1E side of the isolation device shall not cause the loss of the associated safety-related system
05000336/FIN-2018010-032018Q2MillstoneFailure to Correct Part 21 Power Supply DefectsThe team identified a finding of very low safety significance (Green) and associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings. Specifically, Dominion did not accomplish repairs to safety-related power supplies in accordance with instructions and procedures. The team identified that actions taken by Dominion to address Part 21 Report #48863, Foxboro Power Supply Potential Failures due to Defective Tie Wraps and Holder, were performed without procedure or engineering evaluations and the work activities performed were not documented. Specifically, instrumentation and control technicians altered the safety-related power supplies without approved design documents, plant procedures, or work orders, and records of the completed activities were not available
05000334/FIN-2018010-012018Q1Beaver ValleyInadequate Diesel Fuel Oil Temperature ProtectionThe team identified a finding of very low safety significance (Green) for the failure to ensure that diesel powered Diverse and Flexible Coping Strategies (FLEX) equipment would be reliable to mitigate postulated beyond-design basis external events during very low temperature conditions. Specifically, at temperatures below the site fuel cloud point (4 degrees Fahrenheit (F) to -7 degrees F), portable FLEX equipment, such as emergency diesel powered pumps, were susceptible to conditions in which their capability of starting and operating would be impacted due to fuel crystallizing or gelling and subsequent coating of fuel filter elements.
05000220/FIN-2017004-012017Q4Nine Mile PointMain Control Room Annunciators 10 CFR 50.65(a)(2) Demonstration Not MetAn NRC-identified Green non-cited violation (NCV) of Title 10 of the Code of Federal Regulations (10 CFR) 50.65 (a)(2), was identified because Exelon did not adequately demonstrate that the performance of the Unit 1 main control room (MCR) annunciators was effectively controlled through performance of appropriate preventive maintenance. Specifically, Exelon did not identify and properly account for functional failures of the MCR annunciators in June 2017, and therefore did not recognize that the annunciator system exceeded its performance criteria and required a Maintenance Rule (a)(1) evaluation. On December 7, 2017, Exelon entered the issue into their CAP as IR 04081698 and performed a review of the events identified by the inspectors that were applicable to the maintenance rule annunciator system. Corrective actions included Exelon determining that the events were functional failures, and initiated an (a)(1) evaluation based on the MCR annunciator system functional failures exceeding the designated performance criteria of an allowable one functional failure per 24 months.This finding 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 undesirable consequences (i.e. core damage). Specifically, following the two failures of the main control annunciator panel in June 2017, Exelon did not identify the failures as functional failures, and consequently, did not establish goals and monitoring criteria in accordance with 10 CFR 50.65(a)(1). In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 2 of IMC 0609, Appendix A, The SDP for Findings At-Power, issued June 19, 2012, the inspectors determined that the finding was of very low safety significance (Green) because the finding did not affect the design or qualification of a mitigating structure, system, or component (SSC), did not represent a loss of system and/or function, did not involve an actual loss of a function of at least a single train or two separate safety systems for a greater time than allowed by technical specifications (TS), and did not represent an actual loss of function of one or more non-TS trains of equipment designated as high safety-significant in accordance with the licensees maintenance rule program. T his finding has a cross-cutting aspect in the area of Human Performance, Consistent Process, in that Exelon failed to use a consistent, systematic approach to make decisions. Specifically, Exelon did not ensure their review process for issues entered into the CAP was effectively implemented to ensure proper evaluations for all applicable maintenance rule systems affected by a n SSC failure. (H.13)
05000220/FIN-2017004-022017Q4Nine Mile PointInadequate Fill and VentProcedure for Control Room Chiller Results in Unplanned LCO EntryAn NRC-identified Green NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified for Exelons failure to ensure that activities affecting quality were prescribed in a manner appropriate to the circumstances for the Unit 1 control room chiller system. Specifically, Exelon procedure N1-OP-49, Control Room Ventilation System, Revision 03800, Section H.5, Venting of Control Room Chiller Circulating Water Pump 11 and 12 Discharge Piping, led personnel to inadequately fill and vent the 12 control room chiller during system restoration from maintenance, while in a single chiller lineup. As a result, on October 15, 2017, control room chiller 12 tripped on low flow, and due to a prior trip of 11A control room chiller compressor, an unplanned 7-day LCO in accordance with TS 3.4.5.e, Control Room Air Treatment System, was entered due to an insufficient number of available chiller compressors to provide adequate control room cooling. Exelon entered this issue into the CAP as IR 04090200. Corrective actions included generating a procedure change to correct N1-OP-49 Section H.5, which provides instruction for filling and venting when in a single chiller lineup This finding is more than minor because it is associated with the procedure quality attribute of the Barrier Integrity cornerstone and adversely affected the cornerstone objective of providing reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, Exelon failed to prescribe an adequate fill and vent procedure for the Unit 1 control room chillers which led to a trip of the 12 chiller on low flow while troubleshooting of chiller compressor 11A was on-going, resulting in an unplanned TS LCO entry. The inspectors evaluated this finding using IMC 0609.04, Initial Characterization of Findings, and Exhibit 3 of IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power. The performance deficiency did not represent a degradation of the radiological barrier function provided for the control room. Additionally, the performance deficiency did not represent a degradation of the barrier function of the control room against smoke or a toxic atmosphere. Therefore, this finding was determined to be of very low safety significance (Green). This finding has a cross-cutting aspect in the area of Problem Identification and Resolution, Evaluation, because between 2014 and 2017 the inspectors noted over 20 issue reports documenting issues affecting reliability of the control room chiller system. Exelon failed to thoroughly evaluate the issues associated with the chillers to ensure that resolutions address causes and extent of conditions commensurate with their safety significance. Specifically, Exelon failed to effectively evaluate previous chiller trips and to prevent additional trips of the chiller system such as the one that occurred on October 15, 2017. (P.2) (Section 1R12.b.2)
05000410/FIN-2017004-032017Q4Nine Mile PointInadequate Operability Determination forImpairedInternal Flood BarrierAn NRC-identified Green NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified when Exelon failed to perform an adequate operability determination in accordance with OP-AA-108-115, Operability Determinations, Revision 20, upon identification of Unit 2 degraded internal flood barriers that support operability of emergency core cooling system (ECCS) equipment. Specifically, from November 21 until December 10, 2017, Exelon failed to properly evaluate the excavation of internal flood barriers and concluded there was a reasonable expectation for operability of the supported ECCS systems. Exelon entered this issue into the CAP as IR 04082686. Corrective actions included conducting a detailed evaluation of operability for the supported safety-related systems, additional training associated with TS 3.0.9, including a focus on the need for risk assessments when entering TS 3.0.9, and a procedure change to CC-AA-201, Plant Barrier Control Program, and CC-NM-201-1001, Plant Barrier Control Program Implementation, which is the NMPNS specific procedure to address the vulnerabilities associated with impairing multiple required barriers. This finding is more than minor because it is associated with the human performance attribute of the Mitigating Systems cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, from November 21 until December 10, 2017, Exelon failed to adequately evaluate the operability of a degraded internal flooding barrier and the potential impact on operability of the supported ECCS system equipment. The inspectors identified that the internal flood barrier was excavated such that there was not sufficient material to ensure adequate flood protection, and resulted in a reasonable doubt for the operability of the supported ECCS systems. This finding is also similar to example 3.j and 3.k of IMC 0612 Appendix E, Examples of Minor Issues, issued August 11, 2009, because the condition identified by the inspectors resulted in a reasonable doubt for the operability of the ECCS supported systems and additional analysis was necessary to verify operability. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 2 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, issued June 19, 2012, the inspectors determined that the finding was of very low safety significance (Green), because the finding was not a design or qualification deficiency, did not represent a loss of system safety function, and did not screen as potentially risk significant due to vulnerability to external initiating events. This finding has a cross-cutting aspect in the area of Human Performance, Work Management, because Exelon failed to implement a process of planning, controlling, and executing work activities such that nuclear safety is the overriding priority. As a result, Exelon personnel failed to recognize that work activities that impaired internal flood barriers on both Division I and II low pressure ECCS pump rooms were executed simultaneously, which led to an unplanned entry into TS Limiting Condition for Operation (LCO) 3.0.9. (H.5)
05000410/FIN-2017004-042017Q4Nine Mile PointIneffective Correction Action Results in Failure of Instrument Air SystemThe inspectors documented a self-revealing Green finding (FIN) of CNG-CA-1.01-1000, Corrective Action Program, Revision 01100, because Nine Mile Point Nuclear Station (NMPNS) failed to implement corrective actions at NMPNS Unit 2 to remove and replace all un-annealed red brass piping for the instrument air system during the April 2008 refueling outage. Specifically, on July 13, 2017, Unit 2 experienced a rupture of un-annealed red brass instrument air pipe which resulted in a feedwater pump trip and a reactor recirculation pump runback to 49 percent. Exelons corrective actions for the July 13, 2017 failure of un-annealed red brass instrument air piping included wrapping the instrument air piping with a material that both supports the piping and prevents potential stress corrosion cracking. Exelon has developed work orders to replace the piping in the upcoming outage in spring 2018. Exelon also improved staff training for accountability and work checking to verify that generated work orders are completed and closed out. Exelon entered this issue into the corrective action program (CAP) as issue report (IR) 04031685, and performed a corrective action program evaluation (CAPE). This finding is more than minor because it is associated with the design control attribute of the Initiating Events cornerstone and affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during power operations. Specifically, NMPNS staff failed to complete corrective actions to replace Unit 2 un-annealed red brass instrument air piping, which was susceptible to stress corrosion cracking, resulting in a feedwater pump trip and a reactor recirculation runback to 49 percent on July 13, 2017. The inspectors evaluated the finding using IMC 0609, Attachment 4, Initial Characterization of Findings, issued on October 7, 2016, and Exhibit 1 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, issued June 19, 2012. The inspectors determined that the finding was of very low safety significance (Green) because it did not result in the complete or partial loss of a support system that contributes to the likelihood of, or cause, an initiating event and affected mitigation equipment. The inspectors determined that this finding did not have a cross-cutting aspect because the performance deficiency occurred greater than 3 years ago; therefore, it is not considered to be indicative of current plant performance.
05000220/FIN-2017004-052017Q4Nine Mile PointLicensee-Identified ViolationThe following violation of very low safety significance (Green) was identified by Exelon and is a violation of NRC requirements which meets the criteria of the NRC Enforcement Policy for being dispositioned as a NCV. Title 10 CFR 50.65(a)(4) requires, in part, ...the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activities. Exelon procedure WC-AA-101-1006, On-Line Risk Management and Assessment, Revision 001, Section 4.1.3, states to consider work activities that cause equipment to be unavailable (e.g., trains of systems) for assessment of risk under the requirements of 10 CFR 50.65(a)(4). Contrary to the above, on October 17, 2017, Exelon identified a discrepancy in PARAGON (risk software) that resulted in an improper risk assessment for the days planned work. Review and correction of the error resulted in an elevated risk condition of Yellow during Nine Mile Point Unit 1, 11 feedwater pump (FW) maintenance. This performance deficiency was determined to be more than minor because it adversely affected the human performance attribute of the Mitigating Systems cornerstone and affected cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, on October 17, 2017, Exelon identified a planned activity that resulted in an unplanned Yellow risk activity during planned maintenance of the 11 FW pump. In addition, IMC 0612, Appendix E, Examples of Minor Issues, under Section 7, Maintenance Rule, Example E for inadequate risk assessment states in part that a more-than-minor issue would put the plant into a higher licensee-established risk category. The finding was evaluated using IMC 0609, Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process. The finding was determined to affect the overall plant risk with the 11 FW Pump being out of service for maintenance with PARAGON not elevating the overall plant risk from green to yellow. The risk deficit was elevated and determined to not be greater than 1E-6 event per year for Incremental Core Damage Probability Differential and not greater than 1E-7 events per year for Incremental Large Early Release Probability Differential. Therefore, the finding was determined to be of very low safety significance (Green). Exelon entered this issue into its CAP as IR 04064241.
05000352/FIN-2016003-022016Q3LimerickLicensee-Identified ViolationThe following violation of very low safety significance (Green) was identified by Exelon and is a violation of NRC requirements which meets the criteria of the NRC Enforcement Policy for being dispositioned as a non-cited violation. 10 CFR 50.54(q)(2), Emergency Plans, requires, in part, that a holder of a licensee under this part shall follow and maintain the effectiveness of an emergency plan that meets the requirements in Appendix E to this part, and for nuclear power reactor licensees, the planning standards of 50.47(b). 10 CFR 50.47(b)(4) requires that a standard emergency classification and action level scheme, the bases of which include facility system and effluent parameters, is in use by the nuclear facility licensee. Contrary to the above, from April 25, 2016, until August 3, 2016, the spent fuel pool level emergency action level (EAL) RG2/RS2 threshold of Limericks Emergency Plan for a General Emergency and Site Area Emergency did not meet the requirements of Appendix E and the planning standards of 10 CFR 50.47(b). Specifically, Exelon identified that the spent fuel pool level for RG2/RS2 threshold was 0.08 feet, and the correct threshold value was 0.8 feet. The spent fuel pool EAL threshold values for a lowering water level for an Alert and Unusual Event were correct at 10.20 feet and less than 22 feet, respectively. The normal spent fuel pool water level is over 23 feet. The inspectors evaluated this finding using IMC 0609, Appendix B, Emergency Preparedness Significance Determination Process, Table 5.4-1. This Table indicates, in part, that the following should be assessed as low safety significance (White): an EAL has been rendered ineffective such that any General Emergency would not be declared for a particular off-normal event, but because of other EALs, an appropriate declaration could be made in a degraded manner (e.g. delayed), and, an EAL that has been rendered ineffective such that any Site Area Emergency would not be declared for a particular off-normal event. However, the inspectors confirmed that the spent fuel pool level instrumentation at LGS goes off scale at approximately 0.635 feet, and the Limerick Emergency Plan, in Addendum 3, directs any Emergency Director to assume the EAL threshold has been exceeded if the associated parameter goes off scale. In addition, the NEI recommended and NRC endorsed value for this EAL threshold would have been at nominally 0.0 feet, the level at which the fuel remains covered and actions to implement make-up water addition should no longer be deferred. Although the LGS threshold for declaration at 0.8 feet would have been exceeded, the inspectors concluded that the event would have been classified when the SFP level dropped below 0.635 feet, sufficiently above the NEI recommended level. Because the event would have been declared with margin to the actual water level needed for protection of the public, i.e. the spent fuel would still be fully covered by water at the time of the EAL declaration(s), the inspectors concluded that this performance deficiency was most similar to the Table 5.4-1 branches representing very low safety significance (Green). Exelons corrective actions included revising EP-AA-1008, Addendum 3, with the correct spent fuel pool level EAL RG2/RS2 threshold of 0.8 feet. Because this issue was of very low safety significance (Green) and Exelon entered the issue into the corrective action program (IR 2700440), this finding is being treated as a non-cited violation, consistent with Section 2.3.2.a of the Enforcement Policy.
05000353/FIN-2016003-012016Q3LimerickInadequate Design Control of Plant Processing Computer ModificationA self-revealing finding of very low safety significance (Green) was identified when Exelon did not implement their engineering design control procedures during the plant processing computer (PPC) modification. Specifically, Exelon did not fully address effects of the modification on other plant systems and did not establish a testing boundary that encompassed all components whose operation was altered by the modification. As a result, the PPC modification had a wiring design error that resulted in the trip of both reactor recirculation pumps (RRPs) which required a manual reactor trip of Unit 2. In response to this issue, Exelon initiated IR 2676712, investigated the cause of the trip, fixed the wiring design error, performed a root cause evaluation, and performed an extent of condition review. This issue is more than minor because it adversely affected the design control attribute of the initiating events cornerstone to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the PPC modification process had a wiring design error that resulted in the trip of both RRPs which required a manual reactor trip of Unit 2. The issue was evaluated in accordance with IMC 0609, Appendix A, "Significance Determination Process for Findings At-Power, using Exhibit 1, "Initiating Events Screening Questions, Section B, Transient initiators. The finding was determined to be of very low safety significance (Green) because the finding did not cause a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. The inspectors determined that this finding has a cross-cutting aspect in the area of Human Performance, Challenge the Unknown, because LGS staff did not stop when faced with uncertain conditions, and risks were not evaluated and managed before proceeding. Specifically, Exelon did not stop and reevaluate the risks and effects on plant systems when changes were made to the PPC design modification package. (H.11)
05000272/FIN-2016003-012016Q3SalemMisclassification of and Lack of Preventative Maintenance for SWC Valve 2GW75 and Relay S62-C1The inspectors documented a self-revealing, Green finding (FIN) because PSEG did not classify plant equipment in accordance with procedure ER-AA-1001, Component Classification, Revision 0, step 4.5. Specifically, PSEG did not appropriately classify a valve and relay within the stator water cooling (SWC) system, and subsequently did not perform the appropriate periodic maintenance. As a result of the absence of maintenance, the valve developed a packing leak, which dripped onto the trip relay and caused the relay to internally fill with water. On February 14, 2016, the trip relay contacts experienced an electrical short, which led to a turbine trip and a reactor trip from 100 percent power. PSEG entered this issue into the corrective action program (CAP) under notifications 20720566 and 20745264, performed apparent cause evaluation (ACE) 70184453, replaced the failed relay, and repaired the packing leak on the SWC valve. The inspectors determined that a performance deficiency existed because PSEG did not properly classify the SWC relay and valve in accordance with station procedures to ensure the components would receive the appropriate preventive maintenance (PM). The finding was more than minor because it was associated with the equipment performance attribute of the Initiating Events cornerstone and adversely impacted its objective to limit the likelihood of events that upset plant stability (main generator and turbine trip) and challenge critical safety functions. Using IMC 0609, Attachment 4 and Appendix A, Exhibit 1, the inspectors determined that this finding was of very low safety significance, or Green, since mitigating equipment relied up to transition the plant to stable shutdown remained available. The inspectors determined there was no cross-cutting aspect associated with this finding since it was not representative of current PSEG performance.
05000272/FIN-2016003-022016Q3SalemLicensee-Identified Violation10 CFR 72.150 requires that each licensee shall prescribe activities affecting quality by documented instructions, procedures, or drawings of a type appropriate to the circumstances and shall require that these instructions, procedures, and drawings be followed. Holtec HI-STORM Certificate of Compliance 72-1014 Amendment 5, Final Safety Analysis Report for the HI-STORM 100 Cask System, Revision 7, Section 2.1.9.1.2, specifies the required helium backfill pressure range for loaded canisters. Contrary to the above, PSEG selected the incorrect helium backfill pressure range table in Attachment 9 of SC.MD-FR.DCS-0006(Q), Sealing, Drying, and Backfilling of a loaded multi-purpose canister (MPC) for two MPCs, one on June 20, 2016, and the other on June 25, 2016. The NRC inspectors evaluated this violation as having very low safety significance because a thermal analysis performed by Holtec determined the resulting fuel cladding temperatures and the cask/MPC component temperatures would not exceed the applicable design limits for normal long-term storage with the current helium pressure. In accordance with the NRC Enforcement Policy Section 2.2, Part 72, Independent Spent Fuel Storage Installation inspection findings follow the traditional enforcement process and are not dispositioned through the reactor oversight process or the significance determination process. The violation was determined to be a Severity Level IV violation of the NRC requirements. The licensee entered the issue into their CAP as NOTF 20735208. This Severity Level IV violation was treated as a NCV, consistent with Section 2.3.2.a of the NRC Enforcement Policy. CAs for this issue included the Holtec thermal analysis and a revision of the MPC loading procedure SC.MD-FR.DCS-0006, Sealing, Drying, and Backfilling of a Loaded MPC.
05000352/FIN-2015004-012015Q4LimerickSeismic Qualification of Safety Related Block Wall Not MaintainedThe inspectors identified a Green non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion III, Design Control, because Exelon did not properly store circuit breakers and ground trucks in accordance with the established design in order to maintain the seismic qualification of safety-related structures. Specifically, Exelon personnel attached stored circuit breakers and ground trucks to safety-related concrete block walls but did not evaluate the greater weight of circuit breakers, did not maintain the required separation distances, and did not attach all equipment to required attachment points. Exelon initiated issue report (IR) 2592543, removed all stored circuit breakers from the location, rearranged ground trucks to attach them only to designated wall anchors that maintained the required separation distance, and required refresher training of all operators and electrical maintenance personnel on proper spacing and restraint of circuit breakers and ground trucks. This finding is more than minor because it adversely affected the protection against external factors (seismic) attribute of the mitigating systems cornerstone to ensure the availability and reliability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage). Specifically, the improper storage of the circuit breakers and ground trucks affected the seismic qualification of the concrete block walls separating the switchgear of the emergency diesel generators (EDG) which had potential to damage the block walls during a seismic event. Using IMC 0609, Appendix A, Exhibit 4, the inspectors determined that this finding was of very low safety significance (Green). Specifically, the inspectors determined that the performance deficiency only affected the seismic qualification of the concrete block wall, the loss of the concrete wall by itself would not necessarily cause an initiating event or degradation of the EDG system, and the finding did not involve the total loss of any safety function. Furthermore, the inspectors consulted a Senior Risk Analyst regarding the risk screening and determined that a failure of the walls would not necessarily result in the degradation or failure of the EDG systems. Specifically, for screening purposes, assuming total failure of the concrete masonry walls only introduces a potential of degraded performance since the switchgear are anchored to the concrete floor. As such, Exhibit 4 provides a reasonable basis for screening the finding as Green. The inspectors determined that this finding has a cross-cutting aspect in the area of Human Performance, Procedure Adherence, because equipment operators did not follow the established work instructions (posted signs).
05000352/FIN-2015004-022015Q4LimerickLicensee-Identified ViolationTechnical Specification 3.6.5.3, Standby Gas Treatment System Common System, requires with one SGTS subsystem, restore the inoperable subsystem to operable status within 7 days, or be in at least hot shutdown within the next 12 hours and in cold shutdown within the following 24 hours. Contrary to Technical Specification 3.6.5.3, SGTS subsystem B was inoperable for Unit 1 from August 27, 2015, to September 4, 2015, for a time of 8 days 18 hours, and Exelon did not place Unit 1 in hot shutdown or cold shutdown. Exelon entered this issue into the corrective action program as IR 2517538. The inspectors evaluated this finding using IMC 0609.04, Initial Characterization of Findings, and IMC 0609, Appendix A, Exhibit 3, Barrier Integrity Screening Questions. The inspectors determined that the finding was of very low safety significance (Green) because the finding only represented a degradation of the radiological barrier function of the SGTS. In addition, the inoperable condition would have resulted in a flowrate exceeding the analyzed 2500 cfm with a differential pressure greater than the minimum 0.25 inches of vacuum water gauge. However, the condition did not represent a larger pathway through secondary containment and SGTS retained radiological filtering capability.
05000219/FIN-2015002-042015Q2Oyster CreekReset of the Automatic Voltage Regulator Controller Led to an Automatic Reactor ScramA self-revealing finding was identified because Exelon did not properly screen work in accordance with MA-AA-716-010, Maintenance Planning. Specifically, on September 12, 2014, Exelon did not screen the automatic voltage regulators (AVR) human machine interface (HMI) post-maintenance test per the maintenance planning procedure. As a result, on October 12, 2014, Exelon personnel performing the post-maintenance test did not have a work order, which would have included plant configurations and limitations associated with the test. This led to an automatic reactor scram. Exelon entered this issue into the corrective action program. Planned corrective actions include reinforcing with work planners that a work order is required for similar work activities. This finding was determined to be more than minor because it is associated with the human performance attribute of the Initiating Events cornerstone and affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during plant operation. Specifically, resetting the three AVR controllers caused an automatic plant scram. This finding is determined to be of very low safety significance (Green), because it did not cause a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. This finding has a cross-cutting aspect in the area of Human Performance, Challenge the Unknown, because Exelon did not recognize and plan for the possibility of mistakes, or implement appropriate error reduction tools. Specifically, on October 12, 2014, Exelon personnel did not stop when faced with the uncertain situation of the HMI screen that did not respond as expected.
05000219/FIN-2015002-012015Q2Oyster CreekInadequate Assessment of 4k Emergency Switchgear Roll-Up Door Degraded Floor GasketThe inspectors identified a finding associated with Exelon procedure, OP-AA-108-115, Operability Determinations, because Exelon did not adequately assess a degraded floor gasket for the D emergency 4 kilovolt (kV) switchgear roll-up door. Specifically, Exelon did not adequately assess the flood and fire functionality of the degraded gasket, which is credited to provide protection to safety-related D emergency 4kV switchgear during a postulated internal flood event and to contain the carbon dioxide (CO2) gaseous suppression system during a postulated fire within the D switchgear room. Exelon entered this issue into the corrective action program. Planned corrective actions include reinforcing the operability determination procedure and enhancing operator training in fire and flood functionality of gaskets. Additional corrective actions included repairing the gasket and performing a detailed analysis of the ability of degraded gasket to meet its flooding and fire function. This finding is more than minor because it is associated with the protection against external factors attribute of the Mitigating Systems cornerstone, and affected the cornerstone objective of ensuring the reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the degraded floor gasket could have resulted in increased water level in the D emergency 4kV switchgear room during a postulated internal flood due to a fire water pipe rupture, therefore affecting the reliability of the D emergency 4k switchgear to perform its safety function. In addition, the degraded floor gasket could have resulted in CO2 leakage out of the D emergency 4k switchgear room during a postulated fire in that room, therefore affecting the reliability of the D emergency 4k switchgear gaseous suppression system to perform its safety function. The inspectors determined that this finding is of very low safety significance (Green) because it is a deficiency that affected the design or qualification of a mitigating structure, system, or component (SSC), where the SSC maintained its operability or functionality. This finding has a cross-cutting aspect in the area of Problem Identification and Resolution, Evaluation, because Exelon did not thoroughly evaluate issues to ensure that resolutions address the causes and extent of conditions commensurate with their safety significance. Specifically, Exelon staff did not thoroughly evaluate the issue associated with the degraded floor gasket for fire and flood functionality.
05000219/FIN-2015002-022015Q2Oyster CreekFailure Rates Exceed Twenty Percent for Annual Requalification ExamA self-revealing finding was identified associated with inadequate licensed operator performance during licensed operator requalification exams in accordance with TQ-AA-150, Operator Training Program. Specifically, two of seven crews failed the simulator scenario portion of the requalification examinations. As an immediate corrective action, the crews that failed were restricted from licensed duties. Exelon entered this issue into the corrective action program, and facility training staff remediated the crews (the crews were retrained and successfully retested), and those crews were returned to licensed duties. This finding is more than minor because it is associated with the human performance attribute of the Mitigating Systems cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, two of seven crews failed to demonstrate a satisfactory understanding of the knowledge and abilities required to safely operate the facility under normal, abnormal, and emergency conditions. The inspectors determined the finding to be of very low safety significance (Green) because it is related to requalification exam results, did not result in a failure rate of greater than forty percent, and the two crews were remediated (i.e., the crews were retrained and successfully retested) prior to returning to shift. This finding has a cross-cutting aspect in the area of Human Performance, Training, because Exelon staff did not provide adequate operator requalification training to maintain a knowledgeable, technically competent workforce.
05000219/FIN-2015002-032015Q2Oyster CreekReactor Water Cleanup Procedure Not Followed Resulting in a Level TransientA self-revealing NCV of Technical Specification 6.8.1(a), Procedures and Programs, was identified because Exelon did not follow procedure 303, Reactor Cleanup Demineralizer System, during the system restoration on March 26, 2015. Specifically, during startup from a forced outage (1F36), Exelon did not follow procedure 303, which required correct valve lineups for system restoration of reactor water cleanup (RWCU) after system isolation. This resulted in decreasing reactor water level, which was automatically terminated by a second RWCU isolation. Exelon entered this issue into the corrective action program. Planned corrective actions include enhancing operator training in system knowledge and procedure compliance and revising startup procedures. This finding is determined to be more than minor because it is associated with the human performance attribute of the Initiating Events cornerstone and affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, Exelon did not properly lineup the RWCU system after isolation, which resulted in a water level transient and challenging the critical safety function of inventory control. This finding is determined to be of very low safety significance (Green), because it did not cause a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. This finding has a cross-cutting aspect in the area of Human Performance, Challenge the Unknown, because Exelon did not recognize and plan for the possibility of mistakes, or implement appropriate error reduction tools. Specifically, the operators did not stop and fully communicate plant condition after the initial RWCU isolation. Consequently, operators opened the RWCU system inlet valve due to the increasing water level without following procedure guidance.
05000387/FIN-2014005-012014Q4SusquehannaRisk Management Actions Not ImplementedThe inspectors identified a Green NCV of Title 10 Code of Federal Regulations (CFR) 50.65(a)(4) due to multiple examples of not assessing and managing the increase in risk from online maintenance activities. Specifically, on November 12, 2014, a risk assessment did not identify a Yellow online risk condition during a residual heat removal system (RHR) outage. Additionally, the inspectors identified multiple examples where PPL did not implement the procedural requirements of OI-013-002, Fire Risk Management, NDAP-QA-1902, Integrated Risk Management, and NDAP-QA-0340, Protected Equipment Program such that adequate risk mitigation actions were performed. Immediate corrective actions were taken and PPL documented the issues in condition report (CR) 2014-35235 and 2014-35270. The inspectors determined the performance deficiency (PD) was more than minor because it adversely impacted the protection against external factors attribute of the Mitigating Systems cornerstone objective to ensure the capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). The inspectors evaluated the finding using IMC 0612 Appendix K, Maintenance Risk Assessment and Risk Management SDP. The inspectors and the Region I Senior Risk Analyst (SRA) used Appendix K, Flowchart 2, Assessment of Risk Management Actions (RMAs), and determined that not implementing the appropriate RMAs was of very low safety significance (Green). The basis for this determination was that the short duration of the actual planned maintenance activities (62 hours and 40.5 hours) associated with the RHR Train B unavailability results in a mid E-9 calculated incremental core damage probability (ICDP), using the Susquehanna Unit 2 standardized plant analysis risk (SPAR) Model, Revision 8.21, and Systems Analysis Programs for Hands-on Integrated Reliability Evaluations (SAPHIRE) 8. In accordance with Appendix K guidance, doubling the estimated ICDP value to reflect not implementing RMAs is a reasonable approximation of the increased risk. The resultant low E-8 ICDP deficit remains below the ICDP E-6 deficit Green-White threshold and screens this PD to Green. The finding was determined to have a cross-cutting aspect in the area of Human Performance, Work Management, in that, PPL did not control and execute activities, consistent with nuclear safety, by managing risk commensurate to the work and the need for coordination with different groups or job activities. Specifically, PPL did not recognize an elevated risk category and incorporate all RMAs into its work activities (H.5).
05000387/FIN-2014005-042014Q4SusquehannaEPA Breaker Under Frequency Setpoint DriftThe inspectors identified a Green NCV of 10 CFR 50, Appendix B, Criterion III, Design Control, for PPL not establishing design control measures that provide for verifying or checking the adequacy of design and translating the design basis requirements into allowable values and trip set points. Specifically, PPL did not establish measures to assure the under frequency trip set point on the electrical protection assemblies (EPA) for the reactor protection system (RPS) were correctly translated into design specifications. PPL took immediate corrective actions to perform calibration of all EPA under frequency setpoints and document the condition under CR 2014-28492 and 2014-37665. The PD was determined to be greater than minor because it was associated with the Design Control attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the capability of the system that respond to initiating events to prevent undesirable consequences (i.e., core damage). The item is similar to example 3.j in NRC IMC 0612, Appendix E, Examples of Minor Issues. This example states, in part, that it is not minor if the engineering calculation error results in a condition where there is now reasonable doubt on the operability of a system or component. The inspectors evaluated the finding in accordance with NRC IMC 0609, Attachment 4, "Initial Characterization of Findings," Table 2, Cornerstones Affected by Degraded Condition or Programmatic Weakness, and determined it affected the Reactivity Control Systems Degraded subsection of the Mitigating Systems cornerstone. Per IMC 0609, Appendix A, SDP for Findings at Power, Exhibit 2, Mitigating Systems Screening Questions, sub-paragraph C, the inspectors and a Region 1 SRA determined that a detailed risk evaluation was needed to assess the safety significance of this finding. Based upon the detailed risk evaluation, this finding was determined to be Green. The finding was determined to have a cross-cutting aspect in the area of Problem Identification and Resolution, Evaluation, in that PPL did not thoroughly evaluate issues to ensure resolutions address causes commensurate with their safety significance. Specifically, PPL did not thoroughly investigate and evaluate the causes of EPA under frequency set point drift outside the technical specification (TS) allowable values after three EPAs under frequency trip set points drifted below the TS allowable value in 2013 (P.2).
05000387/FIN-2014005-052014Q4SusquehannaLicensee-Identified ViolationMultiple Inoperable Main Steam Safety Relief Valves On May 6, 2013, PPL determined that three main steam SRVs did not meet the setpoint criteria of +3%/-5% set forth in TS 3.4.3. PPL reported this condition under LER 05000388/2013-002. PPL determined that this had resulted in a condition prohibited by TS. Specifically, the LCO 3.4.3 states the safety function of 14 SRVs shall be operable while in Mode 1, 2, and 3. If LCO 3.4.3 is not met, action A.1 requires the reactor to be placed in mode 3 within 12 hours and mode 4 in 36 hours. With three of the sixteen main steam SRVs inoperable due to setpoints less than the -5% criteria, LCO 3.4.3 was not met. Contrary to the above, PPL had not recognized the failure of the main steam SRV setpoint criteria until removed and tested during the Unit 2 Refueling and Inspection Outage in May 2013 and, therefore had not taken the required action. Traditional enforcement applies in accordance with IMC 0612, sections 0612-09 and 0612-13 and Enforcement Policy section 2.2.4.d, because the inspectors did not identify an associated PD. Specifically, the inspectors determined that the failure of main steam SRV setpoint criteria would not have been readily apparent. This issue was considered to be an SL IV violation of TS 3.4.3 in accordance with Enforcement Policy section 6.1.d. In addition, IMC 0612, Appendix B, Figures 1 and 2, Issue Screening, were referenced in documenting this SL IV licensee-identified NCV. There was no actual safety consequence and although not considered operable for design conditions the three SRVs would have relieved pressure before exceeding +3 percent. The SRV safety function, described in UFSAR 5.2.2.1.1, to prevent over-pressurization of the reactor coolant pressure boundary, was not adversely impacted. This Severity Level IV licensee-identified NCV was entered into PPLs CAP as CR-1700379.
05000387/FIN-2014005-062014Q4SusquehannaLicensee-Identified ViolationSecondary Containment Door Found Ajar On February 12, 2014, PPL identified a secondary containment door (Door 612) between the HVAC room and central railroad bay wedged open by a door sign. In order for secondary containment to be operable in the as-found mode of operation, Door 612 had to be secured. PPL immediately secured the door, entered the condition into their CAP (2014-04709), and reported the condition under LER 50-387; 388/2014-002. Contrary to TS 5.4.1a, PPL did not secure the secondary containment door and maintain system operability in accordance with OP-134-002, RB HVAC Zones 1 and 3 after realignment of the secondary containment. The finding was more than minor because it adversely impacted the barrier performance attribute of barrier integrity and was determined to be of very low safety significance (Green) in accordance with IMC 0609, Appendix A, since the finding only represented a degradation of the radiological barrier function provided by standby gas treatment system.
05000387/FIN-2014005-022014Q4SusquehannaEmergency Preparedness Drill Critique Did Not Identify a Risk-Significant Planning Standard WeaknessThe inspectors identified a Green non-cited violation (NCV) of 10 CFR 50.54(q)(2) for failing to follow and maintain an emergency plan that meets the requirements of appendix E and the planning standards of 10 CFR 50.47(b). Specifically, PPL did not identify and critique a weakness related to a risk significant planning standard during their critique following the July 24, 2014, emergency preparedness drill, as required by 10 CFR 50.47(b)(14) and Appendix E, Section IV(F)(2)(g). The inspectors determined that PPL did not identify and critique an emergency preparedness drill performance weakness in the formal critique was a performance deficiency that was within PPLs ability to foresee and correct and should have been prevented. Specifically, PPL did not identify that a periodic update notification provided to the offsite response organizations (OROs) was inaccurate in that it stated an airborne radiological release was in progress when one was not occurring. The inspectors determined the performance deficiency was more than minor because it was associated with the emergency response organization performance attribute of the Emergency Preparedness cornerstone and affected the cornerstone objective (Training, Drills, Exercises) to ensure that the licensee is capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. Specifically, PPLs did not effectively identify and critique an emergency preparedness drill performance weakness caused a missed opportunity to identify and correct a drill-related performance deficiency. The inspectors evaluated the finding using IMC 0609, Attachment 4, Initial Characterization of Findings, issued June 19, 2012. The attachment instructs the inspectors to utilize IMC 0609, Appendix B, Emergency Preparedness Significance Determination Process, issued September 26, 2014, when the finding is in the licensees Emergency Preparedness cornerstone. The inspectors determined this finding was a critique finding, the drill scope was full scale, the planning standard was a risk-significant planning standard, and the performance indicator opportunity was a success because periodic update notifications to the OROs are not credited as performance indicator (PI) opportunities using the guidance provided in Nuclear Energy Institute (NEI) 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7. Therefore, using Figure 5.14-1, Significance Determination for Critique Findings, the inspectors determined the finding was of very low safety significance (Green). The cause of the finding has a cross-cutting aspect in the area of Human Performance, Consistent Process, because PPL did not use a consistent, systematic approach when making decisions. Specifically, PPL personnel did not use a consistent approach when evaluating and critiquing the accuracy of all notifications provided to the OROs (H.13).
05000387/FIN-2014005-032014Q4SusquehannaFailure to Submit an LERInspectors identified a Severity Level IV NCV of 10 CFR 50.73 (a)(2)(v) for PPL staff not submitting an Licensee Event Report (LER) within 60 days of discovery of a condition that could have prevented the fulfilment of the safety function of the RPS Electrical Power Monitoring System. PPL submitted an LER for the subject condition and entered the issue into their CAP under CR-2014-17112. The finding was evaluated using the traditional enforcement process because not accurately reporting events has the potential to impact or impede the regulatory process. The finding was determined to be a Severity Level IV violation of 10 CFR 50.73 (a)(2)(v) based on example 6.9.d.9 of the NRC Enforcement Policy. This example states that a licensee failing to make a report required by 10 CFR 50.73 is an example of a Severity Level IV violation. Because this violation involves the traditional enforcement process and does not have an underlying technical violation that would be considered more-than-minor, inspectors did not assign a cross-cutting aspect to this violation in accordance with IMC 0612, Appendix B.
05000412/FIN-2014004-012014Q3Beaver ValleyInadequate Plant Startup Procedure Led to Manual Reactor TripA self-revealing NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings was identified for FENOCs failure to have an adequate plant startup procedure. Specifically, 2OM-52.4A, Raising Power from 5% to Full Load Operation, did not adequately address plant startup with one condensate pump in operation. This led to an inability to adequately control steam generator (SG) level when the second condensate pump was started which required the operators to trip the reactor. FENOC is in the process of implementing corrective actions to revise procedure 2OM-52.4A and to address the human performance errors associated with this event. Additionally, FENOC entered the issue into their corrective action program as condition report (CR) 2014-09256. The finding is more than minor because it is associated with the procedure quality and human performance attributes of the Initiating Events cornerstone and affected the cornerstone objective of limiting the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the inadequate procedure led to SG level fluctuations that could not be adequately controlled when the second condensate pump was started, and required the operators to trip the reactor. The inspectors determined that this finding is of very low safety significance (Green), because while it did result in a reactor trip, it did not cause a loss of mitigation equipment relied upon to transition the plant from the onset of a trip to a stable shutdown condition. The finding has a cross-cutting aspect in Human Performance, Challenge the Unknown, because FENOC operators did not stop when faced with uncertain conditions. Specifically, the adequacy of the procedure was not sufficiently questioned when the plant was not in the normal start up configuration of two running condensate pumps nor later when the condensate pump discharge header pressure low alarm occurred.
05000387/FIN-2014004-012014Q3SusquehannaAdequacy of Guidance to an Emergency Plan Procedure ChangeAn Unresolved Item (URI) was identified because additional information is needed to determine whether a performance deficiency exists and if a violation of 10 CFR 50.54(q)(2) occurred. The inspectors identified an issue of concern when multiple instances were noted during emergency plan (EP) drills and exercises where emergency response organization (ERO) members reached different conclusions about the status of a release when presented with the same set of plant conditions and indications. On July 24, 2014, inspectors observed a full-scale emergency preparedness (EP) drill at PPLs Susquehanna Steam Electric Station (SSES). During the drill, the inspectors observed that the staff in the Susquehanna control room (CR), the Technical Support Center (TSC), and the Emergency Operating Facility (EOF) utilized Attachment QQ of EP-PS-001, Radiological Release in Progress Guidance, Revision 3 to determine whether or not a radioactive release was occurring due to the event. The inspectors identified that, when presented with the same set of plant conditions and indications, different emergency facilities made different notifications to the offsite response organization (ORO). Specifically, the notifications pertaining to the declaration of an Unusual Event by the CR, an Alert by the TSC, the CR and TSC Emergency Directors (EDs) communicated their determinations that there was no release in progress. Conversely, in a periodic update at the Alert level by the EOF staff, the EOF Recovery Manager (RM) communicated a determination that a release was occurring. The plant conditions for all three of these notifications involved a fuel failure with an unmonitored release path to the environment because the Turbine Building ventilation was inoperable due to a loss of offsite power. However, all main steam isolation valves (MSIVs) were closed in response to the event and the only unmonitored path for radioactive material was through MSIV seat leakage assumed in the design bases. As the drill progressed, plant conditions changed and a site area emergency (SAE) was declared due to a steam leak on the RCIC system in the reactor building. A fourth notification was made, by the EOF, and the RM again stated that there was a release in progress. On July 25, 2014, the inspectors observed the post-drill critique, and noted that PPL determined that all four of these notifications were accurate thereby raising questions for the inspectors. Subsequently, in response to questions by the inspectors, PPL determined that there was initially no release in progress due to the event and that the EOF RM had communicated incorrect information during the periodic (third) update notification. The inspectors then questioned whether the subsequent (fourth) notification pertaining to the SAE was accurate. The inspectors also questioned PPL on the potential inconsistent outcomes that can arise from using the flowchart in Attachment QQ, Radiological Release in Progress Guidance, Revision 3 of EP-PS-001). The inspectors also noted that, since 2005, two changes had been made to the release progress flowchart. These two changes appeared to have the potential to change the outcome of the release in progress determinations. While reviewing the inspectors concerns, PPL identified that, in recent licensed operator requalification training cycles, crews using the Attachment QQ flowchart had reached different conclusions on whether there was a release in progress for the same set of conditions and indications as provided for the SAE declaration in the July 24th full-scale drill. PPL found that, despite this disparity, the EP organization evaluated each opportunity as having appropriately assessed the status of the release, and reported them all as drill and exercise performance (DEP) performance indicator (PI) successes to the NRC. Inspectors noted that at the time of drill performance, the EP organization did not review and did not critique whether judgment was appropriately applied, nor did they retain sufficient documentation to allow inspectors to independently inspect and assess the outcome. Therefore, the inspectors determined that additional inspection and information regarding these questions are required. The inspectors could not conclude whether each of the release determinations were accurate or whether the guidance provided to implement EPIP changes regarding release in progress determinations allowed PPLs ERO to come to disparate conclusions when presented with the same plant conditions and indications. Therefore, an Unresolved Item (URI) was identified because additional information is needed for the inspectors to determine whether a performance deficiency existed and if a violation of 10 CFR 50.54(q)(2) occurred when changes were implemented to the emergency plan implementing procedure (EPIP) for determining whether an event-based release is in progress.
05000387/FIN-2014009-042014Q2SusquehannaFailure to Take Action to Restore Degraded Emergency Action Level SchemeThe inspectors identified a Green cited violation of 10 CFR 50.54(q)(2) for PPLs failure to follow and maintain an emergency plan that meets the requirements of the planning standards in 10 CFR 50.47(b), in that, since October 2003, PPL did not follow and maintain a standard emergency classification and action level scheme. Specifically, PPL did not take timely corrective actions to provide an adequate means to measure temperature in nine out of 21 areas, where reactor building temperatures are considered for the fission product barrier degradation emergency action levels (EALs). As a result, this deficiency adversely affected PPLs ability to classify an emergency such that a Site Area Emergency would be declared in a degraded manner. The violation is being cited because PPL has failed to restore compliance or demonstrate objective evidence of plans to restore compliance at the first opportunity in a reasonable period of time following discussion in a formal exit meeting on January 24, 2014 and documented in NRC Inspection Report 05000387;388/2013005 on February 14, 2014. The finding is more than minor because it is associated with the Facilities and Equipment attribute of the emergency preparedness cornerstone, and adversely affected the cornerstone objective of ensuring that a licensee is capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. Specifically, the continuing lack of installed temperature instrumentation or any other compensatory measures and the reliance on personnel dispatched to take temperature readings were insufficient to ensure a timely and accurate EAL classification could be made. Using IMC 0609, Appendix B, Emergency Preparedness Significance Determination Process, section 5.4, the finding is of very low safety significance (Green) because the finding was determined to be an example of an ineffective EAL initiating condition, such that a Site Area Emergency would be declared in a degraded manner. The inspectors determined that this finding had a problem identification and resolution cross-cutting aspect related to Resolution because PPL did not take corrective actions in a timely manner nor did they take appropriate interim corrective actions to mitigate the issues while more fundamental causes are being assessed. Specifically, PPL had no corrective actions planned or taken to address the degraded EALs until NRC approval of their new EAL scheme, currently scheduled to be implemented no earlier than December 2015. (P.3)
05000354/FIN-2013005-062013Q4Hope CreekOperations with a Potential to Drain the Reactor Vessel (OPDRV) Without Secondary ContainmentTS 3.6.5.1 is applicable in Operational Conditions 1, 2, 3 and * requires that secondary containment integrity shall be maintained. Operational Condition* is defined, in part, as being during OPDRV. TS 3.6.5.1, action b, states, in part, in operational condition, * suspend operations with a potential for draining the reactor vessel. Contrary to the above, between 1700 on October 15, 2013, and 1143 on October 30, 2013, Hope Creek Generating Station did not maintain secondary containment integrity while conducting OPDRV activities. Because the violation was identified during the discretion period described in EGM 11-003 Revision 1, 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.
05000244/FIN-2013005-012013Q4GinnaFailure to Identify and Correct Non-Hydrostatically Sealed Penetrations into Battery Room ?BThe inspectors identified a finding associated with an apparent violation of Title 10 of the Code of Federal Regulations (10 CFR) 50, Appendix B, Criterion XVI, Corrective Action, for Constellation Energy Nuclear Group, LLC (CENG) staffs failure to assure that conditions adverse to quality were promptly identified and corrected. Specifically, CENG failed to identify the need to hydrostatically seal two cable penetrations between manhole 1 and battery room B after the sites design basis flood height was changed during the NRC Systematic Evaluation Program (SEP) in 1983; promptly correct the significant adverse condition in May 2013 when the condition was identified and take timely action in early September 2013 when CENG was presented with evidence challenging its May 2013 evaluation related to manhole 1 and the improperly sealed penetrations. As a result, various Deer Creek flooding scenarios could have resulted in flooding of both battery rooms. Immediate corrective actions included placing this issue in the corrective action program (CAP) as condition report (CR)-2013-003407, CR-2013- 005262, and CR-2013-005643; and hydrostatically sealing the penetrations on October 4, 2013. This finding is more than minor because it is associated with the protection against external factors attribute of the Mitigating Systems cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, propagating flood water could damage mitigating equipment needed to prevent core damage with a flood below the design basis level of 273.8 feet because of the unsealed penetrations in manhole 1. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 2 of IMC 0609, Appendix A, The Significance Determination Process For Findings At-Power, the inspectors utilized Section B, External Event Mitigation Systems (Seismic/Fire/Flood/Severe Weather Protection Degraded), of Appendix A and determined the finding involved the loss or degradation of equipment or function specifically designed to mitigate a flooding initiating event, which requires the inspector to go to Exhibit 4, External Events Screening Questions. The inspectors determined that a detailed risk evaluation (DRE) was needed because the loss of equipment and function would degrade two or more trains of a multi-train system or function, and the loss of equipment and function would degrade one or more trains of a system that supports a risk-significant system or function. The staff determined that, currently, there is not 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 extreme flood frequency extrapolations based on limited available historical data. Therefore, the risk evaluation was performed using IMC 0609, Appendix M, Significance Determination Process Using Qualitative Criteria. The change in core damage frequency (CDF) estimates ranged from Green, a finding of very low safety significance, to Yellow, a finding of substantial safety significance. A significance and enforcement review panel (SERP) held on January 28, 2014, made a preliminary determination that the finding was of low to moderate safety significance (White) based on quantitative and qualitative evaluations. This finding has a cross-cutting aspect in the area of Problem Identification and Resolution, Corrective Action Program, because CENG personnel did not thoroughly evaluate problems such that the resolutions addressed causes. Such evaluations should include properly classifying, prioritizing, and evaluating operability and reportability of conditions adverse to quality. Specifically, CENG personnel had an opportunity to thoroughly evaluate and assess impacts to the plant such that resolutions addressed causes, when two unsealed penetrations into battery room B were identified in May 2013; CENGs evaluation associated with CR-2013-003407 was not thorough and did not consider all flow paths for flooding through manhole 1. Additionally, the condition adverse to quality was not properly evaluated for operability. CENG personnel had an additional opportunity to thoroughly evaluate and assess impacts to the plant such that resolutions addressed causes and properly evaluate for operability when inspectors presented evidence of degraded manhole 1 conditions, e.g., clogged manhole drains, to CENG management on September 5, 2013 (P.1(c)).
05000354/FIN-2013005-012013Q4Hope CreekNCV Failure to Follow Procedure for Configuration Control Activity Adversely Affected Unidentified Leakage in the DrywellA Green self-revealing NCV of TS 6.8.1, Procedures and Programs, was identified regarding PSEGs conduct of maintenance and component configuration control during system restoration from an operation with a potential for draining the reactor vessel (OPDRV) activity. Specifically, PSEG did not close a reactor water cleanup (RWCU) valve in accordance with the maintenance procedure during the refueling outage. This resulted in increased RCS UIL in the reactor drywell area following startup. PSEG restored the mispositioned valves, conducted an extent of condition on other valves in the drywell, completed a prompt investigation concerning the valve mispositioning, and is in the process of conducting an Apparent Cause Evaluation (ACE) on the configuration control event under Order 70161461. PSEG has also placed this issue into CAP as notification 20632003. The performance deficiency was more than minor because it was associated with the configuration control attribute of the Initiating Events Cornerstone, and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. The inspectors evaluated the finding using IMC 0609, Attachment 4, Initial Screening and Characterization of Findings, which required an analysis using Exhibit 1 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, dated June 19, 2012. The finding was determined to be of very low safety significance (Green) because the finding could not result in exceeding the RCS leak rate for a small loss of coolant accident (LOCA) or have likely affected other systems used to mitigate a LOCA resulting in a total loss of their function. This finding had a cross-cutting aspect in the area of Human Performance, Work Practices, because PSEGs communication of human error prevention techniques did not support human performance and proper personnel work practices. Specifically, PSEG did not use adequate human performance tools and valve position verification techniques when controlling valve position for components associated with an OPDRV activity
05000334/FIN-2013005-012013Q4Beaver ValleyMoisture Separator Reheater Valve Misposition Results in Plant TransientA self-revealing, Green NCV of TS 5.4.1 Procedures was identified when an operato did not correctly implement procedure 1OM-52.4.A, Raising Power from 5% to Full Loa Operation, Revision 68, during the warm up the moisture separator reheaters. Specifically, a human performance error resulted in a main steam valve being mispositioned that subsequently caused a plant power transient. FENOC entered this issue into the corrective action program under CR 2013-17848 and reviewed the transient under the Reactivity Management Program. The site performed a limited apparent cause evaluation and plans to update the procedure. The finding is more than minor because it is associated with the Human Performance attribute of the Initiating Events cornerstone and affects the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, a human performance error resulted in a main stea valve being mispositioned that subsequently caused a plant power transient. The finding is also similar to the more than minor example 4.b in IMC 0612, Appendix E, Examples of Minor Issues. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 1 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, issued June 19, 2012, the inspectors determined that this finding is of very low safety significance (Green) because the performance deficiency did not cause both a reactor trip and the loss of mitigation equipment relied upon to transition the plant to a stable shutdown condition. This finding has a cross-cutting aspect in the area of Work Practices, Human Performance because FENOC did not ensure personnel work practices support human performance. Specifically, FENOC operators did not use an appropriate self-check and peer check during an activity with the potential to affect reactivity (H.4(a)).
05000354/FIN-2013005-052013Q4Hope CreekLicensee-Identified ViolationTechnical Specification 3.6.5.1, Secondary Containment Integrity requires, in part, that secondary containment be operable during OPDRV activities in OPCON*. The action statement with secondary containment inoperable in OPCON* is to suspend operations with a potential to drain the reactor vessel. Contrary to the above, from 9:30 a.m. until 5:31 p.m. on October 31, 2013, Hope Creek did not comply with this TS action statement or the EGM 11-003 Revision 1 guidance, and secondary containment should have been operable. The failure to comply with this guidance resulted in a condition prohibited by TSs until the condition was corrected by restoring the automatic isolation function of the drain-down path, complying with both the EGM guidance and TSs at 5:31 p.m. on October 31, 2013. PSEG entered this issue into the CAP as notification 20631218. The inspectors determined that the finding was of very low safety significance (Green) in accordance with NRC IMC 0609, Appendix G, Shutdown Operations Significance Determination Process, because the finding did not represent a finding that required quantitative assessment.
05000244/FIN-2013005-032013Q4GinnaFailure to Modify or Establish a PM for the TDAFW DC Lube Oil Pump SwitchA self-revealing finding was identified for failure to modify or establish a preventive maintenance (PM) schedule for the turbine-driven auxiliary feedwater (TDAFW) direct current (DC) lube oil pump control switch. On November 18, 2013, plant personnel found the main control room switch for the TDAFW DC lube oil pump failed due to switch contact oxidation. This resulted in the DC oil pump failing to automatically start when demanded during a surveillance test and the continued inoperability of the TDAFW pump. As immediate corrective actions for the November 18, 2013, TDAFW DC lube oil switch failure, CENG staff initiated CR-2013-006727, replaced the switch, verified continuity of the other two switches that were not modified in 1980, and established a compensatory action to verify continuity of the other two switches following manipulation of the switch until they are replaced. Additionally, an appropriate PM will be established for the three switches unless they are modified such that the main control board green light indicates continuity of the circuit. This finding is more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, due to the failure of the main control board switch for the TDAFW DC lube oil pump, the pump failed to start during testing resulting in the continued inoperability of the TDAFW pump. The inspectors evaluated the finding using Attachment 0609.4, Initial Characterization of Findings, worksheet to IMC 0609, Significance Determination Process. The attachment instructs the inspectors to utilize IMC 0609, Appendix A, Significance Determination Process for Findings At-Power. The inspectors determined this finding was not a deficiency affecting the design or qualification of a mitigating SSC, did not represent a loss of system and/or function, and did not represent an actual loss of function of at least a single train. Therefore, the inspectors determined this finding to be of very low safety significance (Green). In accordance with IMC 0612, the finding does not have a cross-cutting aspect because the performance deficiency occurred in 1980 and is not reflective of present plant performance.
05000334/FIN-2013005-022013Q4Beaver ValleyInsufficient VHRA Control Under VesselThe inspectors identified a Green non-cited violation involving the failure to properl ensure that a device used to control access to a Very High Radiation Area was adequate to prevent an unauthorized entry into the area. Specifically, the licensee used a pliers-style locking device that did not provide a robust locking mechanism to prevent unauthorized access into a VHRA. In response to the concern, FENOC entered the issue into the corrective action program as CR 2013-18743 and changed the VHRA locking device at the Unit 2 reactor keyway. The finding is more than minor because it is associated with the Program and Process attribute of the Occupational Radiation Safety Cornerstone and affects the cornerstone objective of ensuring the adequate protection of the worker health and safety from exposure to radiation from radioactive material during routine reactor refueling operations. The finding is also similar to the more-than-minor example 6.g in IMC 0612, Appendix E, Examples of Minor Issues issued August 11, 2009. In accordance with IMC 0609.04, Initial Characterization of Findings, issued June 19, 2012 and IMC 0609, Appendix C, Occupational Radiation Safety Significanc Determination Process, issued August 19, 2008, the finding was determined to have very low safety significance (Green), because the finding was identified during a routine test and no unauthorized entry occurred, did not result in an ALARA Planning or work control issue, did not result in an overexposure nor was there a substantial potential for an overexposure, and the ability to assess dose was not compromised. The finding has a cross-cutting aspect in the area of Corrective Action Program, Problem Identification and Resolution, in that FENOC did not identify that the locking device was inadequate for the reactor keyway VHRA, and consequently, did not plan to replace the same type of device in place at Unit 2, even after replacing the failed reactor keyway VHRA locking device at Unit 1 (P.1(c)).
05000354/FIN-2013005-022013Q4Hope CreekFailure to Follow the Primary Containment Closeout Procedure when Declaring the Drywell Ready for Power OperationThe inspectors identified a finding of very low safety significance (Green) and associated NCV of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, for PSEGs failure to conduct primary containment (drywell) close-out activities in accordance with site procedures. Specifically, during the NRCs drywell closeout inspection, the inspectors identified several outage-related items that were not removed from the various elevations of the drywell. As a result, PSEG did not properly inspect the drywell in preparation for power operation. PSEG corrective actions included removing the items identified during the NRC drywell closeout inspection and placing the issue in the corrective action program (CAP). The performance deficiency was determined to be more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone, and affected the cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using NRC IMC 0609, Appendix G, Shutdown Operations Significance Determination Process, dated February 28, 2005, the finding was determined to be of very low safety significance (Green) because the inspectors qualitatively determined that the finding involved adequate mitigation capability and was not an event that could be characterized as a loss of control. This finding had a cross-cutting aspect in the area of Human Performance, Work Practices, because PSEG did not define and effectively communicate expectations regarding procedural compliance and personnel did not follow procedures. Specifically, PSEG personnel did not ensure that the drywell was ready for power operations as required by site procedures.
05000244/FIN-2013005-022013Q4GinnaProgrammatic Failure to Scope SSCs within the Maintenance Rule Monitoring ProgramThe inspectors identified an NCV of 10 CFR 50.65(b), because CENG staff did not include safety-related and non-safety-related structures, systems, and components (SSCs) within the scope of the maintenance rule monitoring program. Specifically, CENG staff failed to appropriately include an estimated 90 safety-related and non-safety-related SSCs within the scope of the maintenance rule monitoring program, which could have resulted in a failure to detect SSC degradation and to provide reasonable assurance that these SSCs are capable of fulfilling their intended functions. Immediate corrective actions included placing these issues into the CAP as CR-2013-002083, CR-2013-004444, CR-2013-004993, CR- 2013-006139, CR-2013-006628, and CR-2013-006674. The finding is more than minor because if left uncorrected, the finding could become a more significant safety concern. Specifically, the failure to monitor SSC performance and condition could have resulted in a failure to detect SSC degradation and to provide reasonable assurance that these SSCs are capable of fulfilling their intended functions. The failure to adequately scope an estimated 90 or more components could have resulted in the failure to detect degradation within multiple systems and to provide reasonable assurance that these SSCs are capable of fulfilling their intended functions. Additionally, this issue is similar to Example 3j described in IMC 0612, Appendix E, Examples of Minor Issues, which states that issues are not minor if significant programmatic deficiencies were identified with the issue that could lead to worse errors if uncorrected. The inspectors evaluated the finding using IMC 0612, Attachment 0609.04, Initial Characterization of Findings. The attachment instructs inspectors to utilize IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power. Using Exhibit 2, Mitigating Systems Screening Questions, of IMC 0609, Appendix A, the inspectors determined that the finding did not represent an actual loss of function of one or more non-technical specification trains of equipment. Therefore, the inspectors determined the finding was of very low safety significance (Green). This finding has a cross-cutting aspect in the area of Problem Identification and Resolution, Corrective Action Program, because CENG personnel did not thoroughly evaluate problems such that the resolutions addressed causes and extent of conditions. Specifically, CENG had multiple opportunities following the inspectors identification of maintenance rule scoping issues on March 27, 2013, and prior to November 7, 2013, to thoroughly evaluate recent maintenance rule scoping problems such that the resolutions addressed causes and extent of conditions (P.1(c)).
05000354/FIN-2013005-042013Q4Hope CreekFailure to Identify Adverse Trend Regarding Bailey Module and Auxiliary Card FailuresA Green self-revealing finding was identified for PSEGs failure to identify and correct an adverse trend regarding 48 Bailey module failures across multiple systems since 2005, including six Bailey module failures in the circulating water (CW) system. As a result of continued problems associated with this previously unidentified adverse trend, on June 12, 2013, the B CW pump tripped resulting in a manual scram of the reactor due to degrading condenser vacuum. PSEG corrective actions include addressing the programmatic weakness identified regarding the performance monitoring and trending program for circuit card failures by amending the Bailey Module Reliability Program to include fuse module and auxiliary card failures. The finding was more than minor because it was associated with the Initiating Events cornerstone and affected the cornerstone objective of limiting the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, PSEGs failure to identify and correct the adverse trend regarding Bailey module failures resulted in a manual scram from 100 percent power due to the trip of the B CW pump concurrent with the B CW discharge valve being gagged in the open position. The finding was determined to be of very low safety significance (Green) in accordance with Appendix A of IMC 0609, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, because the finding did not contribute to both a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. The inspectors determined that this finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Corrective Action Program, because PSEG did not trend and assess information from the CAP and other assessments in the aggregate to identify programmatic and common cause problems. Specifically, PSEG failed to trend or perform an aggregate assessment of Bailey module and auxiliary card failures.
05000354/FIN-2013005-032013Q4Hope CreekInadequate Evaluation of Containment Vent FunctionalityThe inspectors identified a finding of very low safety significance (Green) for PSEGs failure to ensure evaluations addressed identified issues in accordance with PSEG procedure LS-AA-125, Corrective Action Program. Specifically, PSEG failed to adequately assess the functionality of the containment vent following NRC identification of inadequate maintenance practices for an instrument air check valve (1KBV-300) and that design calculation H-1-KB-MDC-1007, Backup Pneumatic Supply for 1GSHV-4964 and 1GSHV-11541 Valves, did not account for leakage through the valve. PSEGs corrective actions included installation of a design change to modify instrument air piping to support leak rate testing of 1KBV-300 and addition of 1KBV-300 to its check valve monitoring and preventive maintenance program. PSEG also completed a revision to design calculation H- 1-KB-MDC-1007 to credit up to 500 standard cubic centimeter per minute (sccm) of leakage through 1KBV-300. This issue was more than minor because it was associated with the design control attribute of the mitigating systems cornerstone, and affected the cornerstones objective to ensure the availability and reliability of systems that respond to initiating events to prevent undesirable consequences. The inspectors determined the finding to be of very low safety significance (Green) in accordance with Exhibit 2 of IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, because: it was not a deficiency affecting the design or qualification of the containment vent; it did not represent a loss of system or function; it did not represent the loss of function for any technical specification (TS) system, train, or component beyond the allowed TS outage time; and it did not represent an actual loss of function of any non TS trains of equipment designated as highly safety-significant in accordance with PSEGs maintenance rule program. The inspectors determined that the finding had a cross cutting aspect in the Human Performance area associated with Resources, because PSEG did not ensure that personnel, equipment, procedures, and other resources are available and adequate to assure nuclear safety, specifically, those necessary for maintaining long term plant safety by maintenance of design margins. Specifically, PSEG did not ensure maintenance of design margin for the containment vent system when concerns were identified regarding its functionality. This included PSEG relying upon operation of the containment vents with hydraulic jacks that have not been operated since 1992 following their installation.
05000333/FIN-2013004-012013Q3FitzPatrickInadequate Reactor Water Recirculation Digital Flow Control Modification Post Maintenance Test Procedure Results in Unexpected Power IncreaseThe inspectors identified a Green self-revealing NCV of Technical Specification (TS) 5.4, Procedures, because Entergy staff did not adequately preplan the implementation of a plant modification to install a digital reactor water recirculation (RWR) flow control system during the 2012 refueling outage. Specifically, post-maintenance testing (PMT) failed to identify that a portion of the runback logic was incorrectly programmed. As a result, the RWR system was restored to operation without identifying the error. On November 8, 2012, during power ascension activities following a subsequent forced outage, the A RWR pump demand signal increased from minimum flow (approximately 30 percent) to approximately 44 percent with no operator action when feedwater flow increased above 20 percent. This resulted in an unexpected power increase of approximately 1.4 percent (37 megawatts thermal (MWth)). As immediate corrective action, control room operators reduced flow in the A RWR loop to restore it to pre-transient conditions, locked the scoop tubes for both RWR motor-generators, and placed the power ascension on hold pending further evaluation of the event. The issue was entered into the corrective action program (CAP) as condition report (CR)-JAF-2012-08042. The issue of inadequate PMT was subsequently entered into the CAP as CR-JAF-2013-05326. The finding was more than minor because it was similar to Example 4.b in IMC 0612, Appendix E, Examples of Minor Issues, in that it resulted in a plant transient. In addition, the finding adversely affected the Initiating Events cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 1 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, issued June 19, 2012, the inspectors determined this finding was of very low significance (Green) because the performance deficiency did not cause a reactor trip or the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. The finding had a cross-cutting aspect in the area of Human Performance, Resources, because FitzPatrick did not ensure that the PMT acceptance criteria specified in the engineering change (EC) package were clearly translated into PMT testing work packages to verify successful implementation of the digital RWR flow control modification.
05000336/FIN-2013004-022013Q3Millstone\"Inadequate Operability Determination for the Turbine Drive Auxiliary Feedwater (TDAFW) Pump\"The inspectors identified a finding (FIN) for Dominions failure to complete an adequate and timely operability determination as required by OP-AA-102, Operability Determination, to assess governor control oscillations following completion of maintenance on the turbine driven auxiliary feedwater (TDAFW) pump 3FWA*P2 on May 17, 2013. The inspectors determined that the failure to adequately evaluate pump operability was a performance deficiency that was within Dominions ability to foresee and correct. Dominion entered this issue into their corrective action program (CAP) as CR528526 and repaired the TDAFW pump governor on August 12, 2013, prior to return to power following the reactor shutdown on August 9, 2013. The inspectors determined the performance deficiency was more than minor because it affected the equipment performance attribute of the Mitigating Systems cornerstone to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Failure to adequately assess operability resulted in a decrease in the reliability of the auxiliary feedwater (AFW) system to mitigate events. In addition, the performance deficiency is similar to examples 1.a and 2.a of IMC 0612, Appendix E, Examples of Minor Issues. The inspectors determined that the finding was of very low safety significance (Green) because the performance deficiency did not represent a loss of system safety function or a loss of safety function of a single train for greater than its Technical Specification allowed outage time. This finding has a cross-cutting aspect in the area of Human Performance, in that Dominion uses conservative assumptions in decision making and adopts a requirement to demonstrate that the proposed action is safe in order to proceed rather than a requirement to demonstrate that it is unsafe in order to disapprove the action.
05000336/FIN-2013004-032013Q3MillstoneLicensee-Identified Violation10 CFR 50 Appendix B, Criterion V, Instructions, Procedures, and Drawings, states, 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 those instructions, procedures, or drawings. Contrary to the above, on March 7, 2013, Dominion failed to maintain a HELB door closed during the TDAFW pump surveillance and rendered both trains of AFW inoperable for approximately 30 minutes. The inspectors determined that the finding was of very low safety significance (Green) in accordance with IMC 0609, Appendix A, The Significance Determination Process for Findings at Power. Dominion entered the issue into their CAP (CR507412).
05000336/FIN-2013004-042013Q3MillstoneLicensee-Identified ViolationTS 3.8.2.1 requires, in part, that when 480V Emergency Load Center 22E is inoperable, it must be restored to operable status within 8 hours or be in COLD SHUTDOWN within the next 36 hours. Contrary to the above, from initial construction until June 8, 2012, the bus 22E was inoperable due to a gap in the HELB barrier. This gap would allow high energy steam to enter the switchgear rooms, causing the electrical equipment inside to potentially fail. The inspectors determined that there was a performance deficiency in that Dominion did not recognize the inoperability of the 22E bus as a result of the historical gap and take the appropriate actions as required by TS. This finding is of very low safety significance as determined by a detailed risk assessment using SAPHIRE 8 and a modified main steam line break outside of containment event tree from the Millstone 2 SPAR model. Specifically, the risk analysis reviewed three possible main steam line break sources in the turbine building near the West 480V Switchgear Room. The assumed one year exposure period was broken down into a period of 66 days when alternate cooling was in effect for the West 480V Switchgear Room and two days when it was in effect for the East 480V Switchgear Room. The frequencies of the associated steam line breaks were determined from a recent EPRI steam line break technical report, given the assumed leak location and the estimated length of associated piping. With the gaps in the HELB barrier and assuming a steam line break, the West 480V switchgear was assumed to fail. When alternate cooling was used for the West 480V Switchgear Room, if the steam line was not isolated, both trains of DC switchgear were also assumed to fail due to high temperature/humidity. When the East Switchgear alternate cooling was used, it was assumed that failure of all safety-related 480V power would have occurred due to high temperature/humidity. Dominion sealed the gap upon discovery in June 2012 and has entered this issue into the CAP (CR478194).
05000336/FIN-2013004-052013Q3MillstoneLicensee-Identified Violation10 CFR 50 Appendix B, Criterion III, Design Control, states, in part, that measures shall be established to assure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions. Contrary to this, from initial construction until November 16, 2012, Dominion failed to ensure that Unit 2 safety related equipment would perform their safety function during a 22 foot MSL design basis flood event concurrent with a 26.5 foot MSL standing wave in the intake structure. Specifically, the unsealed electrical conduits and other openings would have allowed water to bypass Dominions flood protection features and could have affected the functionality of the safety related AFW and HPSI pumps and the PORVs. Dominion entered the issue into their corrective action process as CR491792 and sealed the conduits. Dominion performed an analysis that modeled the postulated effects of the compromised flood barriers. The evaluation postulated the time based impact of the design basis Probable Maximum Hurricane (PMH) tidal surge, using data (including wave runup above the still water heights) from Table 2.5-1 of the UFSAR, with and without the concurrent +26.5 ft MSL water level in the intake structure. The calculation estimated the height of water in the turbine, control, and auxiliary buildings rooms containing equipment necessary to maintain safe hot shutdown using: physical plant layout (floor areas and elevations, internal access doors and postulated water flow paths); water flow estimates; relative height of the identified leakage points; and critical water levels where equipment could be compromised. The engineering calculations demonstrated no impact to equipment needed to perform during the design basis flood without the concurrent intake structure standing wave. However, there was a potential to affect the functionality of the auxiliary feedwater pumps, the PORVs and the high pressure injection system if the standing wave condition occurred, as assumed, for one hour concurrent with the design basis maximum storm surge. The inspectors and a Region I senior risk analyst (SRA) reviewed the associated engineering calculations and technical evaluation. The Region I SRAs conducted and peer reviewed a detailed risk evaluation which they discussed with Office if Nuclear Reactor Regulation, Division of Risk Assessment staff. The SRAs determined that the finding was of very low safety significance with an estimated increase in core damage frequency of less than one in one million reactor years (Green). This was based on available frequency information and on the possibility of some credit for core damage mitigation equipment due to conservative assumptions, as follows: Dominion included significant conservatisms in their calculation and evaluation, which tend to overestimate the chance of damage to mitigation equipment, such as: including wave runup above the assumed still water heights; the one hour duration of intake structure water level at + 26.5 ft MSL due to the postulated standing wave; the height at which equipment damage would occur; and the assumed size of the identified flood barrier breaches. Dominion took no credit for operator actions to protect the important equipment either prior to or during a predicted extreme weather event. Plant procedures for these types of weather conditions discuss pre-staging equipment (sand bags, portable pumps and generators) and personnel to respond to limit the impact of potential flooding on important equipment.
05000336/FIN-2012005-032012Q4MillstoneGaps in West 480V Switchgear HELB Barrier May Impact Safety Related EquipmentOn June 7, 2012, with Unit 2 at 100 percent power, Dominion determined that a series of gaps in a HELB barrier rendered the equipment in the west 480V switchgear room inoperable. Dominion entered TS 3.8.2.1, TS 3.8.2.1(a) action C, and TS 3.3.3.5 action A. The openings were sealed and the switchgear room was returned to operable status at 1605 on June 8, 2012. Dominion determined that this condition may have existed since initial construction. In the past, Unit 2 has implemented compensatory cooling to the west switchgear room when normal ventilation was OOS. Compensatory cooling includes opening one of the doors to the switchgear room. This could allow the steam from the HELB to impact safety related equipment in other areas. The inspectors determined that there was a performance deficiency in that Dominion did not ensure that the gaps in switchgear room HELB barrier were sealed. Additional information is necessary for the inspectors to determine if the issue is more than minor. The information required is the determination of safety related equipment that would be affected by the HELB. This information will be available upon completion of Dominions detailed formal analysis. Upon receipt of the above information, the NRC will assess whether the performance deficiency is more than minor.
05000336/FIN-2012005-042012Q4MillstoneUnsealed Penetrations in Flood Barriers May Impact Safety Related Equipment in a Design Basis FloodOn October 15, 2012, during walkdowns performed in response to the NRCs 10 CFR 50.54(f) letter while Unit 2 was shutdown in Mode 5, Dominion identified several unsealed electrical conduits connecting the SW pump room in the intake structure to the turbine building. During a design basis flood, this condition had the potential to cause flooding of the turbine building such that all auxiliary feedwater pumps could be rendered inoperable. Dominion has also identified other unsealed penetrations in the design basis flood zone. Dominion took prompt corrective actions to seal the identified penetrations. These deficiencies may have existed since initial construction. The inspectors determined that there was a performance deficiency in that Dominion did not ensure that the electrical conduits were sealed to provide adequate flood protection. Additional information is necessary for the inspectors to determine if the issue is more than minor. The information required is as follows: 1. Determine if the conduits that were not sealed at the Unit 2 flood boundary were sealed on the other end; 2 Determine the aggregate impact of potential flooding from all leak paths on the safety function of affected components. Upon receipt of the above information, the NRC will assess whether the performance deficiency is more than minor.
05000293/FIN-2012004-012012Q3PilgrimInadequate Processing of Work Package Results in Reactor ScramA finding of very low safety significance (Green) was identified for personnel not adequately classifying work in regards to processing an emergent work order. Specifically, personnel classified work on a reach rod position indication for valve 1-HO-163, Steam Jet Air Ejector (SJAE) steam supply valve, as minor maintenance, which resulted in the failure to identify and correct the reach rod indicator and position. This resulted in a degraded vacuum during a power maneuver and a subsequent reactor scram. Entergy entered this issue in the corrective action program (CR-PNP-2012-2304). The finding was determined to be more than minor because it was associated with the Configuration Control (i.e., Operating Equipment Lineup) attribute of the Initiating Events cornerstone, and adversely affected the cornerstones objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during power operations. The inspectors screened the issue for significance using IMC 0609.04, Phase 1 Initiating Screening and Characterization of Findings and IMC 0609 Appendix A, Exhibit 1, Initiating Events Screening. The finding was determined to be of very low safety significance (Green) because although the performance deficiency did result in a reactor scram, it did not cause a reactor scram combined with the loss of mitigating equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. This finding has a cross-cutting aspect in the Human Performance cross-cutting area, Work Control component, because Entergy did not appropriately plan and coordinate the repair of the SJAE steam supply valve by incorporating the operational impact of the work activity consistent with nuclear safety.
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