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05000336/FIN-2014011-012014Q3MillstoneFailure to Complete a 10 CFR 50.59 Evaluation for Removal of SLODThe NRC identified a Severity Level III AV of Title 10 of the Code of Federal Regulations (10 CFR) 50.59, Changes, Tests, and Experiments, for Dominions failure to complete a 10 CFR 50.59 evaluation and obtain a license amendment for a change made to the facility as described in the Updated Final Safety Analysis Report (UFSAR). Specifically, Dominion removed a special protection system (SPS), known as severe line outage detection (SLOD), which was described in the UFSAR. Dominion concluded in the 10 CFR 50.59 screening that a full 10 CFR 50.59 evaluation was not required and, therefore, prior NRC approval was not needed to implement this change. The team concluded that prior NRC approval likely was required because the removal of SLOD may have resulted in more than a minimal increase in the likelihood of occurrence of a malfunction of the offsite power system as described in the UFSAR. Dominion has documented condition reports CR 553967 and CR 551068, and participated in a root cause evaluation with Northeast Utilities to determine whether the relay operations that initiated the events of May 25, 2014, were appropriate for the circumstances. Dominion also implemented a compensatory measure by issuing an Operations Standing Order for interim guidance on offsite line outages and plant generation output. The team determined that the failure of Dominion to complete a 10 CFR 50.59 evaluation of the modification for the removal of the SLOD system involved traditional enforcement because it impacted the NRCs ability to perform its regulatory function. This AV was determined to be more than minor because the team determined that the change to the facility required a full 10 CFR 50.59 evaluation and it likely would have required Commission review and approval prior to implementation. The severity level of this AV was determined, in part, using SDP risk significance in accordance with the NRC Enforcement Policy. A Region I Senior Risk Analyst conducted a conditional core damage probability estimate and determined that it was most properly characterized at a Severity Level III. Cross-cutting aspects are not assigned to traditional enforcement violations.
05000219/FIN-2012005-022012Q4Oyster CreekInadequate Application of Strippable Coating to the Refueling Cavity Liner and the Failure to Configure a Valve in the Leakage Collection System Resulting in Increased Potential for Corrosion on the Exterior of the Drywell Liner Surface in the Sand BedsA self-revealing NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified because Exelon procedures and work orders were not effective in preventing refueling cavity leakage from overflowing onto the exterior surface of the drywell liner during the refueling outage (1R24) in November 2012. The performance deficiencies that contributed to the finding were inadequate oversight of the contractors applying a strippable coating to the reactor cavity liner and a valve configuration control error on a temporarily installed leakage collection system. Upon discovery, Exelon took immediate corrective actions to open the leakage collection system filter inlet valve and restore reactor cavity liner leakage flow to the reactor building equipment drain tank. This finding is associated with the barrier integrity cornerstone and is more than minor because, if left uncorrected, this condition would have the potential to lead to a more significant safety concern. Specifically, the continued wetting of the metallic drywell liner surface could provide an environment conducive to corrosion. This finding is not more than very low safety significance because Exelon performs periodic inspections of drywell liner and exterior surface coating to ensure that liner corrosion is monitored and controlled. The inspectors completed the Phase 1 Initial Screening and Characterization of Findings, of Attachment 0609.04 of Inspection Manual Chapter (IMC) 0609, and screened the finding to Green, very low safety significance. Exelon has entered this condition into the corrective action process under IR 1440116. This finding has a crosscutting aspect in the area of Human Performance, Work Practices, for not ensuring supervisory and management oversight of work activities, including contractors and plant personnel, such that nuclear safety is supported regarding the application of the strippable coating on the reactor cavity liner.
05000219/FIN-2012005-012012Q4Oyster CreekFailure to Follow Inspection and Torquing of Bolted Connection ProcedureThe inspectors identified a Green non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, because Exelon did not properly implement procedural controls to ensure adequate thread engagement for standby liquid control (SLC) squib valve spool piece flanges. Specifically, SLC squib valve flanges were installed with inadequate thread engagement (stud was not flush with the nut), as required by Exelons maintenance procedures. Exelons corrective actions included declaring the system inoperable, entering the issue into the corrective action program (IR 1444861 and 1444862) and immediately replacing the existing bolts with bolts of an appropriate length such that projection through the nut was at least flush. The performance deficiency was more than minor because if left uncorrected the inadequate thread engagement would have the potential to lead to a more significant safety concern. Specifically, Exelons evaluation stated that the SLC squib valve spool piece flanges would not have been able to perform their design function under all seismic conditions when the system was required to be operable. In consultation with the Region I senior reactor analyst, the inspectors reviewed this condition using IMC 0609, Attachment G, Shutdown Operations Significance Determination Process. As the condition occurred during the refueling outage and was identified and corrected before Exelon started up the Oyster Creek reactor, and only existed during the outage when SLC was not required to be operable (November 16 27, 2012), the issue screened to very low safety significance (Green). This finding has a cross-cutting aspect in the area of Problem Identification and Resolution, Corrective Action Program, because Exelon did not take appropriate corrective actions to address safety issues and adverse trends in a timely manner, commensurate with their safety significance and complexity. Specifically, Exelon did not take appropriate corrective actions, such as replacing bolts during the refueling outage with longer bolts, after the NRC identified a similar concern on the same SLC squib valve spool piece flanges in September 2012 (IR 1417726).
05000220/FIN-2012004-042012Q3Nine Mile PointFailure to Maintain Radiation Exposure ALARA During Refueling ActivitiesA self-revealing Green finding (FIN) was identified due to NMPNS having unplanned, unintended occupational collective dose resulting from deficiencies in As Low As Reasonably Achievable (ALARA) planning and work control while performing refueling activities at Unit 2. Specifically, inadequate work planning and control of refueling activities resulted in unplanned, unintended collective exposure that was greater than 50 percent above the intended collective exposure, and greater than five person-rem due to conditions that were reasonably within NMPNSs ability to foresee and correct. These factors resulted in the collective exposure for refueling activities increasing from the original estimate of 31 person-rem to an actual dose of 56 person-rem. NMPNS entered this issue into its corrective action program as CR 2012-005939. This finding is more than minor because it was associated with the program and process attribute of the Occupational Radiation Safety cornerstone, and affected the cornerstone objective to ensure the adequate protection of the worker health and safety from exposure to radiation from radioactive material during routine reactor operation. This performance deficiency is similar to example 6.i of IMC 0612, Appendix E Examples of Minor Issues in that the actual collective dose exceeded 5 person-rem and exceeded the planned, intended dose by more than 50 percent. The inspectors evaluated the finding using Attachment 0609.04, Initial Characterization of Findings, of Inspection Manual Chapter (IMC) 0609, Significance Determination Process. The finding was determined to be of very low safety significance (Green) because NMPNS\\\'s current three year rolling average collective dose (143 person-rem/reactor year for 2009 to 2011) is less than the criterion of 240 person-rem per boiling water reactor unit. The finding has a cross-cutting aspect in the area of human performance, work control, in that the job site conditions which impacted human performance were not adequately incorporated into the outage plan. Specifically, the ALARA planning and work controls for refueling activities did not avert a significant unplanned and unintended collective occupational dose.
05000247/FIN-2012004-032012Q3Indian PointInadequate Procedure Guidance to Maintain 22 ABFP Governor Oiler LevelOn July 17, 2012, the inspectors identified that there was no visible oil level in the 22 ABFP governor oiler resevoir, which called into question the adequate lubrication of the governor bearing assembly and operability of the 22 ABFP. Entergy staff immediately added oil to the oiler reservoir and documented the condition in CRIP2- 2012-4631. Subsequently, Entergy determined the pump was operable based on an operability evaluation documented in CR-IP2-2011-5447, on November 2, 2011, for a similar condition. This evaluation determined that the pump remained capable of performing its intended function, since the oiler wick within the reservoir remained saturated. In addition, Entergy determined the pump was operable, because the wick was wet upon discovery, which indicated it had recently flowed oil to the governor bearing assembly. The governor oiler utilizes a wick feed oiler with an internal cotton wick which when saturated in oil, flows oil to the governor bearing assembly. The oiler design results in a flow of 2 to 5 drops per hour, which correlates to approximately 6 to 15 ounces per month. However, when the reservoir is empty, the wick becomes un-saturated and no oil flows. Once the oil passes through the governor bearing, it accumulates in the governor sump, where through periodic (every 6 months) preventive maintenance (PM), it is drained, measured and recorded to prevent excessive oil accumulation in the sump, which could adversely affect the governor or pump operation. On July 19, 2012, inspectors again identified that there was no visible oil level in the governor oiler, and that the oilers wick did not come in contact with the bottom of the reservoir as designed. Entergy immediately added oil to the oiler reservoir, adjusted the wick and documented the conditions in CR-IP2-2012-4756 & 4757. On July 25, 2012, the inspectors again identified no visible oil level in the reservoir. Entergy staff immediately added oil to the reservoir and documented the condition in CR-IP2-2012-4803. The NRCs recurrent identification of empty oiler reservoirs, resulted in Entergys initiation of a special log (2-12-079) to verify twice daily that (1) the reservoir oil level is visible, (2) the wick is saturated in oil, (3) entry of the action into operations logs, and (4) track all oil additions with the CAP. As a result of implementing the special log, the inspectors noted oil addition to the oiler increased from approximately twice a month, to daily. In addition, Entergy drained the governor sump using the PM procedure, on August 31, 2012, to prevent excess accumulation of oil in the sump and to compare the recorded volume of oil with the 10 ounces collected during the most recent PM performed on July 30, 2012. The oil collected was 8.5 ounces, which was determined by Entergy to be a volume within the range expected for a month. The inspectors noted that Entergys operability evaluations for the July 19 and July 25, 2012 conditions also referenced the November 2011 evaluation documented in CR-IP2- 2011-5547. The inspectors noted that the evaluation recommended that during oil replenishment, oil addition be maintained at about half way within the reservoir to preclude a siphon effect on the oiler. However, no corrective actions were assigned to implement this recommendation. Furthermore, the evaluation stated that the oilers oil consumption rate was within the expected range. However, the inspectors identified that this was contrasted by the governor sump draining results obtained on August 31, 2012. Specifically, based on 1999 correspondence between Entergy and the oilers vendor Dresser-Rand, Entergy should have expected adding oil to the oiler more frequently and collecting 36 90 ounces of oil during the periodic PM. During the oil additions that followed each event, the inspectors identified that procedure 2-SOP-AFW-001 was referenced for these oil additions, but only required the operator to verify governor oiler level is visible. Hence, the oil added was not quantified nor was an expected level in relation to the wick, specified in this procedure. The inspectors also identified that Entergy staff controlled the wick adjustment with engineering guidance, instead of an established procedure. Entergy initiated CR-IP2-2012-5711, to evaluate the overall condition of the 22 ABFP governor oiler. The evaluation determined that the monitoring of component and equipment operating parameters was less than adequate. Corrective actions included changing the design of the oiler to a gravity feed style oiler; revising the system monitoring criteria to include tracking governor oil consumption; changing the PM frequency from 6 months to 3 months; and evaluating the past operability of the pump as a result of not having the desired vendor-recommended flow rate to the governor bearing assembly (to be performed under CR-IP3-2012-2400). This issue will be tracked as a URI, because Entergys assessment of the impact of inadequate lubrication of the 22 ABFP governor bearing assembly on the past operability of the 22 ABFP with regard to being able to perform its intended safety function for its specified mission time of 29 hours is needed to determine whether the identified performance deficiency is more-than-minor. This information to be developed is tracked in Entergys CAP under CR-IP3-2012-2400.
05000220/FIN-2012004-032012Q3Nine Mile PointInadequate Installation Instructions for Control Rod Blade Storage RackA self-revealing Green finding (FIN) was identified for NMPNS failure to provide adequate instructions for the installation of a control rod blade storage rack in the Unit 1 spent fuel pool. Specifically, certain critical steps were missing from the installation instructions and as a result, the rack was not properly installed, causing it to shift. The rack could have dropped, potentially resulting in damage to the spent fuel bundles stored beneath the rack. NMPNS immediate CAs were to halt further control rod blade moves and install temporary slings to hold up the rack. The rack was then re-leveled and the jacking pad was welded to the spent fuel pool curb. NMPNS entered this issue into its corrective action program as CR 2012-006547. This finding is more than minor because it would have the potential to lead to a more significant safety concern; e.g. spent fuel bundle damage and a radiological release. The inspectors evaluated the finding using Attachment 0609.04 of Inspection Manual Chapter (IMC) 0609, Significance Determination Process, Exhibit 3, Barrier Integrity Screening Questions, pertaining to spent fuel pools and determined this finding to be of very low safety significance (Green), because the finding did not adversely affect decay heat removal capabilities or pool water inventory, and did not result from fuel handling errors, dropped fuel assembly, dropped storage cask, or crane operations over the spent fuel pool that caused mechanical damage to fuel clad and a detectible release of radionuclides. The finding has a cross-cutting aspect in the area of work practices because NMPNS did not ensure supervisory and management oversight of work activities, including contractors, such that nuclear safety is supported. Specifically, NMPNS supervision did not ensure that critical assumptions contained in the control rod storage rack design analysis concerning the configuration of the Unit 1 spent fuel pool curb were translated into the installation instructions, and differences between Units 1 and 2 curbs noted during the installation were captured or evaluated by engineering, work control, or the CA process.
05000220/FIN-2012004-022012Q3Nine Mile Point\\\"Inadequate Evaluation and Implementation of Design Modifications to the Turbine Gland Seal Supply SystemA self-revealing Green finding (FIN) was identified for NMPNS failure to properly evaluate and implement plant design changes on the Unit 2 turbine gland seal steam supply system. Specifically, incorrect implementation of ECP-11-000977, Turbine Gland Seal and Exhaust System Instrument Changes, in May 2012 caused a reactor scram on July 13, 2012, following a return to full power operations from refueling outage N2RF13. NMPNS immediate corrective actions (CAs) included implementing ECP-12-000629 to revise the initiation setpoints for the emergency seal steam (ESS) system to accommodate higher gland seal operating pressures and properly gagging 2TME-RV135. NMPNS entered this issue into its corrective action program as CR 2012-006615. This finding is more than minor because it is similar to examples 5.a, 5.b and 5.c of IMC 0612 Appendix E, Examples of Minor Issues. In each example, plant modifications were installed and the system was returned to service without identifying and correcting a problem with the design change. This finding also adversely affects the design control attribute 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. The inspectors evaluated the finding using Attachment 0609.04, Initial Characterization of Findings, in Inspection Manual Chapter (IMC) 0609, Significance Determination Process. The finding was determined to be of low safety significance (Green) because while it did cause a reactor scram, it did not result in the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. The finding has a cross-cutting aspect in the area of human performance in that NMPNS did not ensure that personnel and procedures were available and adequate to assure nuclear safety. Specifically, the procedures that were necessary to implement ECP-11-000977, by gagging relief valve 2TME-RV135, were not adequate to ensure proper installation of the gagging device.
05000271/FIN-2012004-022012Q3Vermont YankeeDedicated Operators Required for Operability Under Applied Administrative Controls Left Immediate Vicinity of Open ValvesThe inspectors identified an NCV of technical specification (TS) 6.4, Procedures, for Entergys failure to implement a surveillance activity in accordance with the written procedure. Specifically, the inspectors identified that during a surveillance test, dedicated operators required to maintain operability of primary containment left the immediate vicinity of open manual containment isolation valves. Entergys corrective actions included restoring the administrative controls required to maintain primary containment operability during the subject surveillance test, initiating condition report CR-VTY-2012-03561, sending a memorandum to and discussing the issue with all operating crew shift managers explaining the error and the requirements of a dedicated operator, and issuing a temporary night order further explaining these requirements. Additional corrective actions included implementing and tracking training for all operators on these requirements, and revising licensed operator training on primary containment to specifically describe these requirements. The inspectors determined that the issue was more than minor because it is associated with the Human Performance attribute of the Barrier Integrity cornerstone and affected the cornerstone objective to provide reasonable assurance that physical design barriers (fuel cladding, reactor coolant system, and containment) protect the public from radionuclide releases caused by accidents or events. Specifically, the dedicated operators were required to be stationed in the immediate vicinity of the valve controls to rapidly close the valves when primary containment isolation is required during accident conditions, but the operators were significantly beyond the required immediate vicinity when they left the reactor building. The inspectors determined the significance of the finding using IMC 0609, Appendix H, Containment Integrity Significance Determination Process. The finding was determined to be of very low safety significance (Green) using Appendix H, Table 6.2, Phase 2 Risk Significance Type B Findings at Full Power, because primary containment was inoperable for 37 minutes, i.e. less than 3 days. The inspectors determined that this finding had a cross-cutting aspect in the Human Performance cross-cutting area, Resources component, because the training of personnel did not describe specific requirements of dedicated operators, including the definition of immediate vicinity.
05000271/FIN-2012004-012012Q3Vermont YankeeIncorrect Assessment of Equipment Condition Resulted in Single Recirculating LOOP OperationA self-revealing, Green finding (FIN) was identified because Entergy failed to implement a preventive maintenance procedure. Specifically, Entergy personnel classified the discovery status code for the minor motor inspection on the A recirculation pump motor generator set drive motor incorrectly, as B satisfactory or normal wear, instead of D abnormal wear, which resulted in a missed opportunity to replace degraded components that caused the A recirculation pump to trip and an unplanned entry into single recirculation loop operation. Entergys corrective actions included cleaning the motor and the junction box, replacing components that had been damaged by an arc flash, and testing the circuit to verify no other components were degraded prior to restarting the motor. In addition, Entergy initiated condition report CR-VTY-2012-02811 and issued a corrective action to reinforce the requirements of Entergy Procedure EN-DC-324 among maintenance staff. Entergy also plans to add all large motor and generator junction boxes to the predictive maintenance program and to perform thermography on a six month frequency. The inspectors determined that the issue was more than minor because it resulted in a transient, i.e. an event that upset plant stability (an unplanned entry into single recirculation loop operation). In particular, the issue is associated with the Equipment Performance attribute of the Initiating Events cornerstone and affected the cornerstone objective to limit the likelihood of events that upset plant stability during power operations. The inspectors determined the significance of the finding using IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power. The finding was determined to be of very low safety significance (Green) because the finding was a transient initiator that did not cause a reactor trip. The inspectors determined that the finding had a cross-cutting aspect in the Human Performance cross-cutting area, Work Practices component, because Entergy did not sufficiently define and effectively communicate expectations regarding procedural compliance for the selecting of the discovery status code and personnel did not follow procedures.
05000220/FIN-2012004-012012Q3Nine Mile PointInadequate Implementation of Operational Decision Making Issues Monitoring Plan for EPR Results in Reactor ScramA self-revealing Green finding (FIN) was identified for NMPNS failure to adequately implement the monitoring activities specified in the operation decision making issues (ODMI) plan for the Unit 1 electronic pressure regulator (EPR) in accordance with procedure CNGOP- 1.01-1001, Operational Decision Making . As a result, when the EPR system began to degrade on June 21, 2012, this condition was not identified by station personnel and corrective action (CA) was not implemented. The EPR subsequently malfunctioned while in service, causing a July 17, 2012, reactor scram. NMPNS removed the EPR from service and entered the issue into its corrective action program as CR-2012-006792. This finding is more than minor because it adversely affected the human performance 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. The inspectors evaluated the finding using Attachment 0609.04, Initial Characterization of Findings, in Inspection Manual Chapter (IMC) 0609, Significance Determination Process. The finding was determined to be of low safety significance (Green) because while it caused a reactor scram, it did not result in the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. The finding has a cross-cutting aspect in the area of human performance, work practices, because NMPNS did not ensure proper supervisory and management oversight of the ODMI implementation plan.
05000247/FIN-2012004-042012Q3Indian PointInadequate Operability Evaluation of 22 Static Inverter with a Degraded Frequency MeterThe inspectors identified a Green NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, because Entergy staff did not adequately implement procedure EN-OP-104 Operability Determination Process, section 5.1, to assess the operability of the 22 static inverter due to a degraded frequency meter on September 7, 2012. Specifically, Entergy personnel did not adequately evaluate the impact of the degraded meter on the operability of the static inverter. This condition caused the inverter to be inoperable. As a result of inspector questions, Entergy staff immediately declared the static inverter inoperable and replaced the frequency meter. Entergy staff entered this issue into the CAP as CR-IP2-2012-5620. 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 and reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the degraded frequency meter resulted in the static inverter being declared inoperable on September 10, 2012 to replace the frequency meter. Using IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, the inspectors determined this finding was of very low safety significance (Green) because it 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 a seismic, flooding, or severe weather initiating event. The finding had a cross-cutting aspect in the area of human performance with the Decision Making attribute because Entergy personnel did not make safety-significant decisions using a systematic process, especially when faced with uncertain or unexpected plant conditions, to ensure safety is maintained. Specifically, Entergy did not obtain interdisciplinary input and reviews in resolving degraded 22 static inverter frequency meter.
05000247/FIN-2012004-022012Q3Indian PointInadequate Test Control of Safety Related BatteriesThe inspectors identified a Green NCV of 10 CFR Part 50, Appendix B, Criterion XI, Test Control, because Entergy did not assure that all testing required to demonstrate safety related batteries will perform satisfactorily was identified and performed in accordance with written test procedures. Specifically, temperature compensation for battery discharge testing was performed incorrectly which caused errors in the battery capacity calculations. Entergy staff immediately reviewed historical test results to confirm the batteries remained operable. Entergy entered this issue into the CAP as CR-IP2-2012-5338. This finding is more than minor because it is associated with the procedure quality attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. In addition, it was similar to Example 2c of NRC IMC 0612, Appendix E, Examples of Minor Issues, in that the test control inadequacies affected multiple batteries and the issue was repetitive. Using IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, the inspectors determined the finding screened as very low safety significance (Green) because it 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 a seismic, flooding, or severe weather initiating event. This finding had a cross-cutting aspect in the area of Human Performance, Resources Component, because Entergy did not ensure that complete, accurate, and up-to-date procedures were available and adequate to assure nuclear safety. Specifically, the battery discharge test procedures did not ensure that temperature compensation was correctly applied to provide accurate capacity calculations.
05000247/FIN-2012004-012012Q3Indian PointInadequate Operability Evaluation of Non-conforming Safety Related BatteriesThe inspectors identified a Green NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, because Entergy personnel did not adequately implement procedure EN-OP-104, Operability Determination Process, Section 5.1, to assess the operability of safety related station batteries on June 4, 2012. Specifically, Entergy personnel did not appropriately determine the impact on operability as a result of inadequate surveillance testing of the 21, 22 and 24 station batteries. Entergy staff re-performed the operability determination, identified the issues as nonconforming and implemented compensatory measures. Entergy entered this issue into the CAP as CR-IP2-2012-4009. 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 reliability and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, after inspectors questioned the operability determination, the non-conforming condition was identified and resulted in the station batteries being declared operable with required compensatory measures, revising calculations and implementing a modification to reduce battery load. Using IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, the inspectors determined this finding was of very low safety significance (Green) because it 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 a seismic, flooding, or severe weather initiating event. The finding had a cross-cutting aspect in the area of human performance with the Decision Making attribute because Entergy personnel did not use conservative assumptions in decision making with regards to the non-conservative testing of safety related batteries and adopt a requirement to demonstrate that the proposed action is safe in order to proceed rather than a requirement to demonstrate it is unsafe in order to disapprove the action.
05000443/FIN-2012503-012012Q2SeabrookFailure of Exercise Critique to ldentify an RSPS Weakness as a DEP Pl Opportunity FailureThe NRC identified an apparent violation (AV) for the licensee exercise critique process not properly identifying a weakness associated with a risk significant planning standard (RSPS) that was determined to be a Drill/Exercise Performance (DEP) Performance Indicator (Pl) opportunity failure during a full-scale exercise. The AV is associated with emergency preparedness planning standards 10 CFR 50.47(bX14) and 10 CFR 50.47(bX5) and the requirements of Section lV.F.2.g of Appendix E to 10 CFR Part 50. This finding was entered into the licensee corrective action program. The failure of NextEra to identify the exercise weakness related to an incorrect protective action recommendation (PAR) notification during their exercise critique was a performance deficiency that was reasonably within NextEra ability to foresee and prevent. The finding is more than minor because it is associated with the emergency response organization attribute of the Emergency Preparedness Cornerstone and affected the cornerstone objective 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. This finding was determined to potentially have greater-than- Green safety significance because the licensee exercise critique process did not properly identify a weakness associated with a RSPS that was determined to be a DEP Pl opportunity failure during a biennial full-participation exercise. The finding is related to the cross-cutting area of Problem identification and Resolution, Corrective Action Program; in those NextEra personnel did not identify a RSPS issue completely, accurately, and in a timely manner commensurate with the safety significance. Specifically, during the biennial full-participation exercise evaluation Next Era failed to identify a weakness.
05000333/FIN-2012003-022012Q2FitzPatrickInadequate Procedure for Installation of Reactor Water Recirculation Motor- Generator Scoop Tube PositionersThe inspectors identified a self-revealing NCV of Technical Specification (TS) 5.4, Procedures, because Entergy staff did not provide adequate procedures for installation of a plant modification to replace the reactor water recirculation (RWR) motor-generator (MG) scoop tube positioners during the 2010 refueling outage. Specifically, excessive torque was specified for use on positioner ball joint fasteners, which damaged one of the ball joints and resulted in subsequent binding during attempted operation. As a result, on November 11, 2010, the B RWR MG scoop tube positioner bound when operators attempted to reduce pump speed, and released the following day which resulted in an unexpected power reduction of approximately 1.5 percent (40 megawatts thermal (MWt)). As immediate corrective action, control room operators reduced flow in the A RWR loop to restore compliance with the TS requirement for balanced loop flow, then locked the scoop tubes for both RWR MGs pending further evaluation of the event. The issue was entered into the corrective action program (CAP) as condition report (CR)-JAF-2010-07782. 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. The finding also 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. The inspectors evaluated the finding using the Phase 1, Initial Screening and Characterization, worksheet in Attachment 4 to IMC 0609, Significance Determination Process. The inspectors determined the finding was not a loss of coolant accident or external events initiator, and did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions would not be available. Therefore, the inspectors determined the finding to be of very low safety significance. The finding had a cross-cutting aspect in the area of Human Performance, Resources, because Design Engineering personnel did not ensure that accurate design documentation and procedures were available to assure successful implementation of the RWR MG scoop tube positioner modification.
05000333/FIN-2012003-012012Q2FitzPatrickFailure to Follow Procedure During Removal from Service of Emergency Diesel Generator VentilationThe inspectors identified a self-revealing NCV of TS 5.4, Procedures, because Entergy personnel did not adequately implement procedures when removing the ventilation system for the A emergency diesel generator (EDG) subsystem from service. Specifically, operators did not implement tagout placement instructions, which required that the affected EDGs be declared inoperable once the ventilation system was tagged out. Additionally, control room operators did not respond to the resultant A EDG ventilation system common alarm in accordance with the alarm response procedure, which also would have led to the EDGs being declared inoperable. As a result, TS 3.8.1 was not entered in a timely manner and the TS surveillance requirement was not performed within the specified completion time. As immediate corrective action, the A EDG subsystem was declared inoperable and the specified surveillance requirement was completed. The issue was entered into the CAP as CR-JAF-2012-02591. The finding was more than minor because it affected the equipment performance attribute of the Mitigating Systems cornerstone objective to ensure the availability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the offsite electrical circuits were not verified available by operators for approximately three hours while the A EDG subsystem was inoperable. The inspectors evaluated the finding using the Phase 1, Initial Screening and Characterization of Findings, worksheet in Attachment 4 to IMC 0609, Significance Determination Process. The inspectors determined this finding was not a design qualification deficiency resulting in a loss of functionality or operability, did not represent an actual loss of safety function of a system or train of equipment, and was not potentially risk significant due to external initiating events. Therefore, the inspectors determined the finding to be of very low safety significance. This finding has a cross-cutting aspect in the area of Human Performance, Work Practices, because operators did not follow procedures.
05000454/FIN-2012003-022012Q2ByronFailure to Have Instructions Appropriate to the CircumstancesA self-revealed finding with two examples of very low safety significance and an associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified when licensee personnel failed to properly torque a RCS pressure boundary valve closed and failed to properly re-install a Reactor Containment Fan Cooler (RCFC) interior access panel during the previous Unit 1 refueling outage. The licensee replaced the valve and reinstalled the RCFC internal access panel upon identification and entered the item into the CAP as IR 1339375 and IR 1347450, respectively. Additional corrective actions included modifying the installation procedure to add clarity in the selection of the proper torque value and to add detail and tracking aids for the RCFC interior access panels. In accordance with IMC 0612, Appendix B, Issue Screening, the first example was determined to be more than minor because it was associated with the Procedure Quality attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, this issue increased the risk of a small break loss of coolant accident. The inspectors performed a Phase 1 SDP screening using IMC 0609, Attachment 4, Table 4a, Characterization Worksheet for Initiating Events Cornerstone. The inspectors determined that the finding would not result in exceeding the TS limit for any RCS leakage or could have likely affected other mitigation systems resulting in a total loss of their safety function. . A self-revealed finding with two examples of very low safety significance and an associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified when licensee personnel failed to properly torque a RCS pressure boundary valve closed and failed to properly re-install a Reactor Containment Fan Cooler (RCFC) interior access panel during the previous Unit 1 refueling outage. The licensee replaced the valve and reinstalled the RCFC internal access panel upon identification and entered the item into the CAP as IR 1339375 and IR 1347450, respectively. Additional corrective actions included modifying the installation procedure to add clarity in the selection of the proper torque value and to add detail and tracking aids for the RCFC interior access panels. The second example was determined to be more than minor because it was associated with the Configuration Control attribute of the Barrier Integrity Cornerstone and adversely affected the cornerstone objective of providing reasonable assurance that physical design barriers, including the containment, protect the public from radionuclide releases caused by accidents and events. Specifically, this issue decreased the availability and reliability of the RCFCs for use during a design basis accident. The inspectors determined that the issue was of very low safety significance (Green) because the finding did not represent a degradation of the radiological barrier function, did not represent a degradation of the barrier function of the control room, did not represent an actual open pathway in the physical integrity of reactor containment, and did not involve an actual reduction in function of hydrogen igniters in the reactor containment. Both examples had a cross-cutting aspect in the Work Practices component of the Human Performance cross-cutting area (H.4(a)) because licensee personnel failed to properly utilize human error prevention techniques. These two examples of the finding with a cross-cutting aspect were considered as a single NCV.
05000454/FIN-2012003-012012Q2ByronLeakage Detection Trough with Large Accumulation of Boric Acid IdentifiedA finding of very low safety significance and an associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified by the inspectors when licensee personnel failed to identify boric acid accumulation that would have impeded flow from the containment leakage detection trough to the containment sump. The licensee entered this issue into the Corrective Action Program (CAP) as Issue Report (IR) 1339957. Corrective actions included removing the boric acid accumulation from the leakage detection trough and passing water through the drain to verify associated piping was free of obstruction. The finding was determined to be more than minor because the finding was similar to IMC 0612, Appendix E, Example 4(a). Example 4 focuses on procedural errors. The not minor if section in Example 4(a) discussed that if a later evaluation determines that the safety-related equipment was adversely impacted, it was more than minor. The flow obstruction in the leakage detection trough would have delayed the flow of water to the sump thereby delaying any subsequent alarm. Therefore, this performance deficiency adversely impacted the Equipment Performance aspect of the Initiating Events Cornerstone. The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, Table 4a, Characterization Worksheet for Initiating Events Cornerstone. The inspectors answered No to Question 1: Assuming worst case degradation, would the finding result in exceeding the Technical Specification (TS) limit for any RCS (Reactor Coolant System) leakage or could the finding have likely affected other mitigation systems resulting in a total loss of their safety function? Therefore, this finding was determined to be of very low safety significance (Green). This finding had a cross-cutting aspect in the Corrective Action Program component of the Problem Identification and Resolution cross-cutting area because licensee personnel failed to ensure that an issue potentially impacting nuclear safety was promptly identified and fully evaluated, and that actions were taken to address safety issues in a timely manner, commensurate with their significance.
05000334/FIN-2012003-022012Q2Beaver ValleyInadequate Containment Isolation Valve Leakage Testing Procedure results in RCS piping Water HammerA self-revealing Green NCV of License Condition 2.C.6.(2), Outside Containment Leakage Rate, was identified in FENOCs failure to perform adequate maintenance and restoration of the Unit 1 low head safety injection (LHSI) system. The inspectors determined the failure to adequately perform maintenance and restore the LHSI system to service is a performance deficiency that was within FENOCs ability to foresee and correct which contributed to the inoperability of the LHSI system in November 2010 and exceeding the outside containment leakage rate. FENOC entered this issue into their corrective action program as condition reports (CRs) 2010-85863, 2012-05832, and 2012-06658 This finding is more than minor because it affects the Mitigating Systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences and the Barrier Integrity cornerstone objective to provide reasonable assurance that physical design barriers (fuel cladding, reactor coolant system, and containment) protect the public from radionuclide releases caused by accidents or events. The inspectors and a Region I Senior Reactor Analyst (SRA) evaluated the finding using Phase 1, Initial Screening and Characterization worksheet in Attachment 4 to IMC 0609, Significance Determination Process. Per Table 4a, under the Mitigating Systems Cornerstone, the inspectors determined this finding was not a design or qualification deficiency resulting in a loss of functionality or operability, did not represent an actual loss of safety function of a system or train of equipment, and was not potentially risk-significant due to a seismic, fire, flooding, or severe weather initiating event. Accordingly, under the Mitigating Systems Cornerstone this finding screens as Green. However, under the Barrier Integrity Cornerstone, the inspectors determined this finding represented an actual open pathway in the physical integrity of reactor containment via a heat removal system and warranted a review per Appendix H, Containment Integrity Significance Determination Process. The inspectors and SRA determined that this finding is appropriately categorized as a Type A finding, per Appendix H, because the degraded relief valve adversely affects the operability of the LHSI system, a closed system which extends beyond the containment boundary. Based upon the above Mitigation System Cornerstone determination that this finding screens to Green (no significant increase in core damage frequency) and Table 4.1, that categorizes the faulted relief valve, that is connected to a small line (less than 1 to 2 inches in diameter) and connected to a closed system, as a condition that generally does not contribute to LERF, this finding screens per Appendix H, Figure 4.1, as very low safety significance. This finding has a cross-cutting aspect in the area of Problem Identification and Resolution, Operating Experience, because FENOC failed to implement operating experience through changes to station procedures and equipment.
05000334/FIN-2012003-012012Q2Beaver ValleyInadequate Maintenance results in Low Head Safety Injection System Exceeding Outside Containment Leakage RateA self-revealing Green NCV of TS 5.4.1, Procedures, for FENOCs failure to establish adequate procedural guidance for plant conditions for containment isolation valve leakage testing. Specifically, inadequate procedural guidance in BVT-1.47.11, Safety Injection and Charging System Containment Penetration Valve Integrity Test, established plant conditions that resulted in a water hammer event in reactor coolant system (RCS) safety injection piping. FENOC entered this issue into the corrective action program for resolution as condition report 2012-06841. The inspectors determined the failure to establish adequate procedural guidance for plant conditions for containment isolation valve leakage testing is a performance deficiency that was within FENOCs ability to foresee and correct which contributed to a water hammer event in RCS safety injection piping. The finding is more than minor because it affects the procedure quality attribute of 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. The inspectors evaluated the finding using PWR Refueling Operation: RCS level > 23 or PWR Shutdown Operation with Time to Boil > 2 hours and Inventory in the Pressurizer Checklist 4 of Attachment 1 to Appendix G of IMC 0609. Because no loss of control occurred and all mitigating capabilities were available, a Phase 2 quantitative assessment was not required. Therefore, the inspectors determined the finding to be of very low safety significance. This finding has a cross-cutting aspect in the area of Human Performance, Work Control, because FENOC failed to coordinate work activities impacted by changes to the work scope in the plant.
05000454/FIN-2012003-032012Q2ByronLicensee-Identified ViolationTitle 10 CFR 55.49, Integrity of Examinations and Tests, requires, in part, that the licensee shall not engage in activities that compromises the integrity of any application, test, or examination required by 10 CFR Part 55. Contrary to the above, on March 30, 2012, at the Clinton Power Station, the licensee identified activities that compromised the integrity of the examinations required by 10 CFR Part 55. Specifically, the licensee identified that the control room simulators plant process computer model was saving sequence of events files Title 10 CFR 55.49, Integrity of Examinations and Tests, requires, in part, that the licensee shall not engage in activities that compromises the integrity of any application, test, or examination required by 10 CFR Part 55. Contrary to the above, on March 30, 2012, at the Clinton Power Station, the licensee identified activities that compromised the integrity of the examinations required by 10 CFR Part 55. Specifically, the licensee identified that the control room simulators plant process computer model was saving sequence of events files.
05000454/FIN-2012002-022012Q1ByronPotential Under-Torque of Valve 1RC8042BFollowing the licensees identification of valve 1RC8042B as a source of unidentified leakage in containment in March 2012, the inspectors selected this valve for a maintenance effectiveness review. The inspectors identified that a work package associated with this valve repair was performed during the previous Unit 1 refueling outage in March 2011. The work package for the repair identified an existing boric acid leak and directed the replacement of the valve bonnet. Therefore, the material condition of 1RC8042B was restored and subsequently degraded in less than 1 year. The licensee entered this issue into their CAP as IR 1339922, Perform Rework Evaluation on 1RC8042B. At the end of the inspection period, the licensee was still in the process of evaluating this issue. This URI will remain open pending the licensees completion of the rework evaluation and the inspectors review and follow up of the evaluation
05000289/FIN-2012002-012012Q1Three Mile IslandFailure to Implement Fire Protection Compensatory Actions for Out-of-Service Appendix R Heat ExchangerThe inspectors identified a non-cited violation of license condition DPR-50 section 2.C.(4), Fire Protection, for Exelons failure to implement compensatory actions during planned maintenance on the A nuclear service heat exchanger (NS-C-1A). Specifically, on May 10, 2010, Exelon failed to return Appendix R breakers to their correct position within the seven day allowed outage time and implement compensatory actions in accordance with administrative procedure (AP) 1038, Fire Protection Program. The inspectors determined Exelons failure to implement compensatory actions during planned maintenance on NS-C-1A in accordance with AP 1038 was a performance deficiency that was within Exelons ability to foresee and correct. Exelon performed an extent of condition review and created a requirement to review the fire hazard analysis report for applicability before removing equipment from service. Exelon has entered this issue in the corrective action program for resolution as IR 1347403. This finding is more than minor because it was 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. In accordance with Inspection Manual Chapter 0609.04, Phase 1 Initial Screen and Characterization of Findings, the inspectors conducted a phase 1 SDP screening using Appendix F, Fire Protection Significance Determination Process, and determined that a detailed phase 2 analysis was required due to the elevated calculated delta core damage frequency. The inspectors performed a detailed walkdown of the control cables associated with the nuclear river system valves and identified no fire ignition sources and concluded that the finding was very low safety significance (Green). This finding has a cross-cutting aspect in the area of Human Performance, Resources, because Exelon failed to ensure complete, accurate, and up-to-date procedures were used to determine if compensatory actions were required for planned work activities
05000289/FIN-2012002-022012Q1Three Mile IslandInadequate Inspection of RCP FlangesThe inspectors identified a non-cited violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, because Exelon did not specify, in writing, the exact inspection scope and criteria for boric acid inspections of the reactor coolant pump bolted flanges during plant refueling outages. Lack of specific procedural guidance contributed to the failure to detect reactor coolant system leakage from the thermal barrier flange of the B reactor coolant pump (RC-P-1B) prior to November 2011. Exelons failure to ensure that both the upper and lower RCP thermal barrier flanges were visually inspected for the complete 360 degrees for all RCPs is a performance deficiency within Exelons ability to foresee and prevent. Exelon completed a boric acid evaluation which showed there was reasonable assurance that the flange could safely operate until the next refueling outage. Additionally, Exelon prepared an adverse condition monitoring plan and is performing periodic remote monitoring of the affected flange for changes in leakage from the degraded gasket. Exelon entered this issue into the corrective action program as IR 01344561. The finding is more than minor because it is associated with the Equipment Performance attribute (a degraded RCP flange gasket) of the Initiating Events cornerstone and affected the 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. Also, this finding is similar to the more than minor example 4.a in Inspection Manual Chapter (IMC) 0612, Power Reactor Inspection Reports, Appendix E. The inspectors completed IMC 0609.04, Phase 1- Initial Screening and Characterization of Findings, and screened the finding as very low safety significance (Green). This finding has a cross-cutting aspect in the area of Human Performance, Work Control, because Exelon did not ensure supervisory and management oversight of work activities, including contractors, such that nuclear safety is supported
05000454/FIN-2012002-032012Q1ByronBoric Acid Accumulation Identified in Leakage Detection TroughDuring a Unit 1 containment walkdown the inspectors identified a boric acid leak on sample valve 1PS9365B located on the 426 elevation. The 426 elevation of containment utilized floor grating; therefore the inspectors inspected the lower levels of containment to determine if any other equipment had been impacted by the leak. On the 377 elevation, the inspectors identified a large area of boric acid accumulation. The inspectors subsequently made the licensee staff aware of this additional boric acid accumulation. Photographs were subsequently taken by the licensee and provided to the Outage Control Center. The licensee entered this issue into their CAP as IR 1339957, 1PS9365 Has Leak From Either Packing or Bonnet. In preparation for a Mode 5 to Mode 4 change, the licensee was required to perform an inspection and assessment of containment in accordance with 1BOSR Z.5.b.1-1, Unit 1 Containment Loose Debris Inspection, to ensure that the material condition of containment was adequate to support at-power operations. The inspectors performed an independent inspection following the licensees inspection and assessment. During this independent inspection, the inspectors identified that boric acid associated with boric acid leakage on the 377 elevation documented in IR 1339957 was still present. Specifically, boric acid had accumulated in a trough that was located along the wall of the inner containment structure. The accumulated boric acid completely covered the drain located in the trough. The purpose of this trough was to collect any potential leakage and direct that leakage to a drain that led to a sump. The flow of water into the sump as well as the level of this sump was monitored to facilitate the prompt identification of containment leakage. The leakage detection instrumentation for the RCS was required to be operable in Modes 1-4. Unit 1 was in Mode 4 at the time of this discovery. This issue was entered into the licensees CAP as IR 1341380, NRC Identified Boric Acid Covering Floor. The impact of this issue on the leakage detection instrumentation was still being assessed by the licensee at the end of the inspection period. This URI will remain open pending the licensees completion of their assessment of the issue and the inspectors review of that assessment. This issue is also discussed in Section 71111.20 of this report.
05000289/FIN-2012002-052012Q1Three Mile IslandLicensee-Identified ViolationTMI-1 fire hazard analysis requires two valves to achieve and maintain cold shutdown condition, including remote shutdown via local manual operation, one valve which is the B decay heat cooler shell bypass (DC-V-65B). On March 14, 2012 during valve diagnostic testing, Exelon discovered DC-V-65B manual handwheel drivegear was detached from the valve stem and had been so since identified on April 19, 2006. Contrary to license condition 2.C.(4) compensatory measures were not established for the loss of DC-V-65B to be operated manually and to perform its credited function. The cause of this violation is the failure to correct a degraded condition in a timely manner commensurate with its safety significance. Exelon entered this into the CAP as IR 1341582 and replaced the actuator on April 3, 2012. The inspectors determined that the finding was of very low safety significance (Green) in accordance with IMC 0609, Appendix F, Fire Protection Significance Determination Process, as a cold shutdown category with moderate degradation
05000289/FIN-2012002-032012Q1Three Mile IslandInadequate System Monitoring Results in Multiple IA-P-4 TripsA self-revealing finding was identified for inadequate performance monitoring of instrument air compressor number four (IA-P-4) in accordance with ER-AA-2003, System Performance Monitoring and Analysis. Specifically, performance monitoring action levels established for loaded and unloaded times in procedure 1104-25, Instrument and Control Air System, were not adequate to identify the adverse trend in performance and resulted in recurring drive-motor overload trips and unplanned accrued unavailability of IA-P-4 on September 28, October 8 and November 29, 2011. Maintenance technicians repaired the air leaks and subsequent IA-P-4 air loading decreased. Corrective actions were implemented to trend loaded and unloaded times of IA-P-4 in the system monitoring plan and implement acoustic monitoring for identification of system air leakage (IR 1295235). This finding is more than minor because it was associated with the equipment performance 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 shutdown as well as power operations. In accordance with Inspection Manual Chapter 0609.04, Phase 1 - Initial Screen and Characterization of Findings, the inspectors conducted a phase 1 SDP screening and determined that a detailed phase 2 evaluation was required to assess the safety significance because the finding contributed to both the likelihood of a reactor trip and the likelihood that mitigation equipment would not be available. The inspectors consulted a senior risk analyst (SRA) to perform a detailed phase 2 analysis. The SRA performed a bounding risk analysis using five days of IA-P-4 unavailability. The phase 2 analysis concluded that the significance of 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 Exelon failed to thoroughly evaluate the cause of the IA-P-4 trips such that the resolution addressed the cause
05000289/FIN-2012002-042012Q1Three Mile IslandFailure to Perform an Adequate Maintenance Risk Evaluation for DH-V-3 Planned MaintenanceThe inspectors identified a non-cited violation of 10 CFR 50.65 (a)(4), Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, for Exelons failure to adequately assess and manage the impact to plant risk during a planned maintenance activity. Specifically, Exelon did not recognize an elevated online maintenance risk activity and implement appropriate risk management actions (RMAs) during maintenance on the decay heat removal (DHR) drop line valve (DH-V-3) on January 16, 2012. The inspectors determined that the failure to perform an adequate risk assessment and implement appropriate RMAs for the planned maintenance on DH-V-3 is a performance deficiency that was within Exelons ability to foresee and correct. Immediate corrective actions included operator and work planning training on risk evaluations and an extent of condition review to ensure planned maintenance activities that could impact DHR system operability were identified. Exelon entered this issue into the corrective action program for resolution as IR 1314551. This finding was determined to be more than minor since it is similar to more than minor example 7.e of Inspection Manual Chapter (IMC) 0612, Power Reactor Inspection Reports, Appendix E because the risk assessment, when adequately performed, resulted in an elevated station risk condition and required RMAs. The finding was evaluated in accordance with Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process, of IMC 0609, Significance Determination Process . The inspectors, in consultation with a senior risk analyst, performed a phase 1 analysis and concluded that the incremental core damage probability deficit for DH-V-3 with an out-ofservice time of 8 hours was less than 1E-6. Therefore, the finding was determined to be of very low safety significance (Green). This finding has a cross-cutting aspect in the area of Human Performance, Work Control, because Exelon failed to incorporate appropriate risk insights into the planning and execution of the DH-V-3 maintenance activity
05000289/FIN-2011005-012011Q4Three Mile IslandInspect and Disposition Leakage Event from BRCP Flange from 1R19During a plant shutdown on October 24,2011, Exelon BACC inspectors did not inspect the flanged, gasketed joints of RCP thermal barrier flanges of RC-P-1A, RC-P-18, RC-P-1C and RC-P-1D, while the plant was at hot shutdown conditions. The affected joints use flexitalic gaskets to seal the thermal barrier housing to the RCP motor and to the RCP volute. Exelon inspected the RCP flanges on October 11,2011, after an Exelon NDE inspector observed a significant amount of boric acid on the flange of RCP RC-P-18 and on the pump\\\'s discharge piping inside containment. However, when this inspection was performed on November 1, 2011, the RCS was cold, depressurized and drained. Thus, the inspection conditions did not meet those specified in ER-AP-331-1001, Rev. 5, step 4.1.4.2., to complete A walkdown inspection of borated systems/components inside containment shall be performed to identify evidence of boric acid leakage as soon after plant shutdown . . . as practical, at each refueling. Because this inspection was not completed at operating pressure as specified, Exelon had missed an opportunity to determine the actual leak rate of the component because the RCS was drained and depressurized when the leakage evidence was discovered, i.e. the plant was no longer at hot shutdown conditions. Upon inspection on November 1, 2011, at cold shutdown, Exelon attributed the significant leakage to a damaged flange gasket, an equipment failure. Subsequent examination of the affected carbon steel flange bolts identified degradation of one of the flange bolts. The inspectors reviewed Exelon\\\'s evaluation of the bolt for continued use. Exelon had identified the presence of the boric acid residue coming from the B RCP flange on November 1, 2011, and placed the condition into the corrective action process. However, the inspectors noted that because the B RCP and associated piping had been drained and depressurized, when inspected, Exelon had missed an opportunity to fully characterize, or measure the actual leak rate. Exelon subsequently provided the NRC additional information and an understanding of past Exelon BACC practices at TMl. To completely resolve this issue, the inspectors need additional information from the licensee to evaluate the issue against the current licensing basis and determine if the apparent performance deficiency is more than minor.
05000387/FIN-2011005-092011Q4SusquehannaLicensee-Identified ViolationPPL identified that a reactor operator was removed from the requalification program for a period of six months and returned to licensed duties after three months of makeup training without obtaining NRC review. This issue was determined to be a violation of 10 CFR 55.59, Requalification. Specifically, 10 CFR 55.59 (a) requires that a licensed operator successfully complete an NRC approved requalification program, and that this program be conducted for a continuous period not to exceed 24 months. If this is not done, 55.59 (b) requires the operator to complete additional training and to submit evidence of satisfactory completion of this training to the NRC prior to returning to licensed duties. Contrary to this, PPL did not submit the training evidence to the NRC for review prior to returning the reactor operator to licensed duties. This issue is documented in PPLs CAP as CRs 1486268 and 1516764 and was determined to be of very low safety significance (SL IV) because it did not cause the NRC to reconsider a regulatory position or undertake a substantial further inquiry. Specifically, the operators requalification makeup training and license reactivation process was evaluated as satisfactory during the NRC License Operator Requalification Team Inspection discussed in section 1R11.2 of this report. Therefore, the violation is being treated as an NCV in accordance with the NRC Enforcement Policy.
05000387/FIN-2011005-042011Q4SusquehannaInadequate RCIC PMTAn NRC-identified, Green NCV of 10 CFR 50, Appendix B, Criterion XI, Test Control, occurred when the Unit 2 RCIC ramp generator signal converter (RGSC) failed during maintenance but post maintenance testing (PMT) failed to identify the failure, which went unrecognized until RCIC tripped on overspeed during its normal operating pressure surveillance on June 29, 2011. Consequently, from June 26, 2011, when PPL commenced a reactor startup and transitioned to plant conditions under which RCIC was required to be operable, until June 29, 2011, PPL RCIC was inoperable. After the RGSC was replaced, RCIC was re-tested via SO-250-002 on July 1 and declared operable on July 2. In response to the event, PPL initiated an apparent cause evaluation (ACE), an RCA, and RGSC post mortem investigation. PPL entered this issue into their CAP as CRs 1430270, 1450534, and 1516769. The failure to conduct adequate post-maintenance testing (PMT) that demonstrates RCIC would perform satisfactorily in service via test procedures was a performance deficiency that was reasonable for PPL to foresee and correct. The finding was more than minor since it affected the equipment performance attribute of the Mitigating Systems cornerstone and its objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, reliable operation and the capability of RCIC in automatic were affected by a failure of its RGSC during the refueling outage. The inspectors evaluated the finding in accordance with IMC 0609 Attachment 4, Phase I Initial Screening and Characterization of Findings, and determined it to be Green, since it was not a design or qualification deficiency, was not a loss of system safety function, and was not risk significant due to an external initiating event. This finding had a cross-cutting aspect in the area of Problem Identification and Resolution (PI&R) - Operating Experience (OE), in that licensees are to implement and institutionalize OE through changes to station processes, procedures, equipment, and training programs. Specifically, PPL did not implement and institutionalize various OE pertinent to RCIC in maintenance, PMTs, and system monitoring.
05000387/FIN-2011005-082011Q4SusquehannaLicensee-Identified ViolationOn November 2, 2011, PPL identified that the full scope of a CREOASS system TS SR was not being met due to procedural deficiencies. Specifically, TS SR 3.3.7.1.5 requires a logic system functional test (LSFT) to be performed using procedures SE- 159-200, SE-030-002A, and SE-030-002B. The CREOASS system is a two train system (each with 100 percent capacity), normally with one train in Auto-Lead, and the second train in Auto-Standby. The LSFT verifies that on an actual or simulated initiation signal, each CREOASS train starts and operates. However, between September 2004 and November 2011, the CREOASS system was only tested in the Auto-Lead position per PPL procedures. PPL entered TS SR 3.0.3, performed a risk assessment, and took corrective action to perform a review of all procedures to ensure all aspects of CREOASS testing are being fully met and updated SE-159- 200, SE-030-002A, and SE-030-002B to include testing of the CREOASS system in Auto-Standby. The issue was determined to be a violation of Susquehanna Unit 1 TS 5.4.1, Procedures, which requires that written procedures be established, implemented and maintained as recommended in RG 1.33, Revision 2, Appendix A, February 1978. RG 1.33, Appendix A, requires implementing procedures for each SR listed in TSs. The finding is more than minor because it was determined to be similar to example 3.d of IMC 0612, Appendix E, in that the failure to implement the TS SR as required is not minor if the surveillance had not been conducted. Additionally, the finding affected the procedure quality attribute of not ensuring the control room barrier is maintained and the Barrier Integrity cornerstone and its objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. The finding was evaluated for significance using IMC 0609, Attachment 4, Phase 1 Initial Screening and Characterization of Findings. Since the finding only represented a degradation of the radiological barrier function provided for the control room, the finding was determined to be of very low safety significance (Green). The issue was entered into PPLs CAP as CR 1487546 and 1488400.
05000387/FIN-2011005-072011Q4SusquehannaLicensee-Identified ViolationOn September 17, 2011, a worker in the Unit 1 recombiner room received a dose rate alarm of 683 mR/hr, but the room was not posted and controlled as HRA, contrary to Plant TS 5.7.1. This issue was of very low significance because it was not an ALARA issue, did not involve an actual or substantial potential for an overexposure, and the ability to assess the actual dose received was not compromised. This issue was documented in PPLs CAP as CR 1466609.
05000387/FIN-2011005-032011Q4SusquehannaInadequate Post-Modification Testing Results in Main Turbine Trip and Automatic ScramA self-revealing finding of very low safety significance (Green) was identified when PPL personnel did not have adequate procedures to perform post-modification testing on the unit 2 digital integrated control system (ICS). Specifically, scheme checks and functional testing failed to identify an improper termination in the high reactor water level main turbine trip circuit. This error reduced the channel trip circuitry from a two-out-of-three logic to allowing a main turbine trip from a single channel. As a result, on August 19, 2011, during the first implementation of quarterly surveillance testing for the trip function following ICS and extended power uprate implementation, a main turbine trip and automatic reactor scram occurred. The performance deficiency was determined to be more than minor because the finding was associated with the Initiating Events cornerstone attribute of Equipment Performance, and affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenged critical safety functions during power operation. Specifically, inadequate post-modification testing failed to identify an improperly terminated jumper which ultimately led to a main turbine trip and automatic reactor scram during subsequent surveillance testing. The inspectors evaluated the finding using IMC 0609, Attachment 4, Initial Screening and Characterization of Findings, and determined the finding did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions would not be available. Consequently, the finding is of very low safety significance (Green). This finding is related to the CCA of Human Performance Resources because PPL did not ensure that personnel, equipment, procedures, and other resources were available and adequate to assure nuclear safety. Specifically, PPL did not ensure that complete, accurate and up-to-date maintenance and test procedures were available to perform post-modification testing on the digital ICS.
05000387/FIN-2011005-022011Q4SusquehannaInadequate Operability Assessment of Suppression Pool SprayAn NRC-identified Green NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, occurred when PPL did not perform an adequate operability assessment for a failed suppression pool (SP) spray flow indicator in accordance with Nuclear Department Administrative Procedure (NDAP)-QA-0703, Operability Assessments and Requests for Enforcement Discretion, Revision 15. The issue was entered into PPLs CAP as Condition Report (CR) 1478716. The finding is more than minor because it was similar to example 3.j in IMC 0612, Appendix E, Examples of Minor Issues in that an error in a calculation is not minor if the error results in reasonable doubt on the operability of the system or component. In this case, the error made in evaluating the operability of the SP spray mode of residual heat removal (RHR) operation resulted in the system subsequently being declared inoperable. Additionally, the error affected the structures, systems and components (SSCs) and barrier performance attribute of the Barrier Integrity cornerstone objective to provide reasonable assurance that physical design barriers (fuel cladding, reactor coolant system (RCS), and containment) protect the public from radionuclide releases caused by accidents or events. Specifically, one subsystem of SP spray was declared inoperable, constituting 62.5 hours of subsystem unavailability. The finding was evaluated for significance using IMC 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings. Since the finding was not a degradation of the barrier function of the control room against smoke or toxic gas, did not represent an actual open pathway of the physical integrity of containment, and did not involve an actual reduction in function of hydrogen ignitors in the reactor containment, the finding was determined to be of very low safety significance (Green). This finding is related to the CCA of Problem Identification and Resolution (Pl&R) - CAP because PPL did not thoroughly evaluate problems such that the resolutions address the causes and extent of conditions, to include properly classifying, prioritizing and evaluating for operability. Specifically, PPL failed to appropriately evaluate the effect that an instrumentation failure had on the operability of the SP spray subsystem.
05000387/FIN-2011004-032011Q3SusquehannaRCIC Failure During SurveillanceOn June 29, 2011, Unit 2 RCIC was declared inoperable after it tripped on over speed in automatic flow control when initiated for SR 3.5.3.3 between 920 and 1060 psig reactor pressure. RCIC had previously been operated in manual flow control for SR 3.5.3.4 with reactor pressure less than 165 psig reactor pressure. The failure was attributed to the ramp generator signal converter (RGSC) prior to the end of the refueling outage. The completion of SR 3.5.3.4 did not identify the issue with the RGSC. PPL entered this issue into their CAP as CR 1430270. At the end of this inspection period, PPL was conducting an apparent cause evaluation, a root cause analysis (RCA), and post-mortem investigation of the RGSC. This issue will be tracked as an URI pending inspection and review of PPL\\\'s completed ACE, RCA, and RGSC investigation
05000336/FIN-2011004-012011Q3MillstoneFailure to Electrically Isolate Dissimilar Metal Flanged Joint Leads to Forced Shutdown Due to Service Water LeakA self-revealing NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified for Dominion\\\'s failure to properly electrically isolate service water (SW) flanged joints of dissimilar metals. This caused a more rapid corrosion rate when a defect occurred in the lining of the carbon steel pipe and eventually led to a SW leak. On September 3, 2011, Dominion was forced to shut down Unit 2 when the spool leaked in excess of the limit allowed in authorized relief from American Society of Mechanical Engineers (ASME) code requirements. Dominion repaired the spool and electrically isolated the flanged joint. Dominion entered this issue into their corrective action program (CAP) CR441302. The 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. The finding was of very low safety significance (Green) because the finding was not a design or qualification deficiency that did not result in loss of operability, did not represent an actual loss of system safety function, did not represent an actual loss of safety function of a single train for greater than its technical specification (TS) allowed outage time, did not represent an actual loss of safety function of one or more non-technical specification trains of equipment designated as risk significant per 10 CFR 50.65, and did not screen as risk significant due to a seismic, flooding, or severe weather initiating event. The inspectors determined that this finding had a cross-cutting aspect in the Human Performance cross-cutting area, Work Practices component, because Dominion personnel proceeded in the face of uncertainty andlor unexpected circumstances when they had difficulty installing the isolating sleeves in the flanged joint.
05000334/FIN-2011003-032011Q2Beaver ValleyDefective Fuel Injection Pump Supply Lines Provided by the Diesel Engine Manufacturer Results in an Emergency Diesel Generator Being InoperableOn March 25, while Beaver Valley, Unit 2 was shut down in Mode 6 (refueling), scheduled maintenance was performed on the Train A EDG which included replacing the twelve fuel injection pump supply lines with new fuel injection pump supply lines procured from the EDG vendor. During post maintenance testing of the the Train A EDG, the supply line to the number four injector was replaced with its original supply line due to a small fuel leak (approximately 6 drops per minute). Several additional fuel supply line fittings were tightened to eliminate signs of minor leakage and the required post maintenance testing and endurance run of the Train A EDG was completed satisfactorily. After successful post maintenance testing, the Train A EDG was declared operable by the licensee and the Train B EDG was subsequently declared inoperable and removed from service for routine maintenance. Approximately 11 hours later the vendor informed the licensee of its recommendation to remove all of the new fuel injection pump supply lines previously installed on the Train A EDG due to concerns over the adequacy of the assembly method of the fuel line compression fittings. Based on this vendor recommendation, the licensee immediately declared Train A EDG inoperable. Since both EDG trains wer inoperable for approximately 11 hours, during which time no action was immediately taken to restore one to operability as required by TS 3.8.2.B, the licensee was inadvertently in a condition prohibited by TS. When the licensee determined that both EDG trains were inoperable, they entered TS 3.8.2.B, initaed actions to restore one EDG to operable status, and evaluated the issue for reportability and appropriately issued LER 50-412/2011-001, defective fuel injection pump supply lines provided by the diesel engine manufacturer results in an emergency diesel generator being inoperable, dated may 19, 2011. This LER reported that Beaver Valley, unit 2 had been an a condition that was prohibited by TS 3.8.2.B, which requires immediate action if both trains of EDG are inoperble while in Mode 6 operatins.
05000334/FIN-2011003-022011Q2Beaver ValleyFailure to timely correct Radiation Monitor deficienciesA Green, NRC-identified finding (FIN) was identified in that plans and actions to correct long-standing radiation monitor system instrument deficiencies where not accomplished in a timely manner, in accordance with FENOC CAP procedure NOP-LP2001. Specifically, FENOC failed to correct and return to service radiation monitor instruments for Unit 1 and 2 RSS HX (RM-1RW-100A,B,C,D and 2SWS-RQ100A, B,C,D), in a timely manner, requiring maintenance of alternate monitoring and challenges to assessing radiation detection and assessment during accident situations. This issue was entered into the licensee\'s corrective action program under CR(s) 1191673 and 11-89700. Traditional enforcement does not apply because the issue did not have an actual safety consequence or the potential for impacting NRC\'s regulatory function, and was not the result of any willful violation of NRC requirements. The inspectors determined that the finding was not similar to the examples for minor deficiencies contained in IMC 0612, Appendix E, Examples of Minor Issues. The finding is more than minor because it affects the Public Radiation Safety cornerstone. The finding is associated with the attribute of plant equipment and instrumentation (process radiation monitors) attribute of the Public Radiation Safety cornerstone to ensure adequate protection of public health and safety from exposure to radioactive materials released into the public domain as a result of routine civilian nuclear reactor operation. In accordance with IMC 0609.04 (Table 3a), Phase 1 - Initial Screening and Characterization of Findings, the finding was evaluated using IMC 0609 Appendix 0, Public Radiation Safety Significance Determination Process and determined to be of very low safety significance (Green) because the finding was not a failure to implement the effluent program or cause any public dose to be exceeded. The cause of this NCV relates to the cross-cutting aspect of Problem, Identification, and resolution, Corrective Action Program, in that FENOC personnel did not take timely corrective actions to develop and implement actions for long-standing radiation monitor deficiencies.
05000334/FIN-2011003-012011Q2Beaver ValleyFailure to Maintain Recirculation Spray Heat Exchangers in Chemical Wet LayupA Green, self-revealing non-cited violation (NCV) of TS 5.4.1, Procedures, was identified in that the Unit 2 Recirculation Spray System (RSS) Heat Exchangers (HXs) were not maintained in chemical wet layup, contrary to station procedures and industry guidance. Specifically, FENOC failed to maintain place corrosion inhibitors in the RSS HXs, resulting in significant HX corrosion, which led to degraded flow through the B RSS HX during a service water full flow test. This issue was entered into the licensee\'s corrective action program under CR 11-90430. Traditional enforcement does not apply because the issue did not have an actual safety consequence or the potential for impacting NRC\'s regulatory function, and was not the result of any willful violation of NRC requirements. The inspectors determined that the finding was not similar to the examples for minor deficiencies contained in IMC 0612, Appendix E, Examples of Minor Issues. The finding is more than minor because it affects the Mitigating Systems and Barrier Integrity cornerstones. The finding is associated with 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 and is also associated with the Structure Systems and Components (SSC) and barrier performance attribute of the Barrier Integrity cornerstone to provide reasonable assurance that physical design barriers (fuel cladding, reactor coolant system and containment) protect the public from radionuclide releases caused by accidents or events. In accordance with IMC 0609.04 (Table 4a), Phase 1 -Initial Screening and Characterization of Findings, the finding was determined to be of very low safety significance (Green) because the finding did not result in a loss of operability, nor was it a degradation of a radiological barrier, control room barrier, hydrogen igniter, or an open pathway. The cause of this NCV relates to the cross-cutting aspect of Human Performance, Work Control, in that FENOC personnel did not coordinate work activities consistent with nuclear safety. Specifically, FENOC did not coordinate work activities to complete the chemical wet layup condition to support long-term equipment reliability of the Unit 2 RSS HXs.
05000277/FIN-2011002-032011Q1Peach BottomNoneTS LCO 3.4.3 requires the safety function of 11 valves (any combination of SRVs and SVs) to be operable during operational Modes 1,2, and 3 or else be in Mode 3 within 12 hours and in Mode 4 within an additional 36 hours. Contrary to the above, two SRVs and one SV were determined to have their as-found setpoints in excess of the TS allowable tolerance, thus leaving 10 operable SRVs and SVs. The SRVs and SVs were replaced with refurbished valves for the 19th Unit 2 operating cycle. Additionally, LER 2-10-3 stated that PBAPS will pursue a change to the plant\'s licensing bases to increase SRV and SV setpoint tolerances to the ASME Code allowable + 3 percent tolerance. The licensee documented the event in JR 1120516. Since there was no actual loss of safety function as a result of this event, this issue is of very low (Green) safety significance. The LER associated with the event was documented in Section 40A3.2.
05000277/FIN-2011002-022011Q1Peach BottomNoneIn Modes 1, 2 and 3, with one ESW subsystem inoperable for more than seven days, TS Limiting Condition for Operation (LCO) 3.7.2, condition C, requires the unit to be in Mode 3 within 12 hours and in Mode 4 within 36 hours. Contrary to the above, since original construction and prior to September 13, 2010, an engineering evaluation determined that the \'A\' ESW subsystem was inoperable due to the degraded seismic capability of rod hanger 33HB-S143 that only affected the \'A\' ESW subsystem. During upgrades to the ESW discharge pipe support system during the week of September 13, 2010, PBAPS personnel identified that the original installation of the rod hanger had not been carrying adequate pipe load. This condition was considered as a condition prohibited by TS due to one subsystem of ESW being inoperable for greater than the time period allowed by TS. The cause of the event was due to an inadequate design drawing. PBAPS documented this issue in the CAP as IRs 1114812 and 1118711. Since there was no actual Joss of safety function as a result of this event, this issue is of very low (Green) safety significance. The LER associated with the event was documented in Section 40A3.1.
05000277/FIN-2011002-012011Q1Peach BottomFH Procedures Were Inadequate to Prevent Fuel from Contacting an ObstructionA Green self-revealing NCV of Technical Specification (TS) 5.4.1 Procedures was identified, because PBAPS\'s procedures for refueling equipment operation and core alterations were inadequate to prevent a fuel bundle from contacting a core spray inspection (CSl) submarine device while the fuel bundle was being transported from the core to the spent fuel pool (SPF). In particular, system operating (SO) procedure 18.1.A-2, Operation of Refueling Platform, and fuel handling (FH) procedure 6C, Core Component - Core Transfers, did not provide sufficient procedure steps, precautions, or human performance tools to prevent contact while the refueling platform was operated in the automatic mode and when core components were in close proximity to obstructions and interferences. The inspectors determined that the finding was more than minor because the finding was associated with the Procedure Quality attribute of the Barrier Integrity cornerstone and adversely affected the cornerstone\'s objective to provide reasonable assurance that physical design barriers (i.e., fuel cladding) protect the public from radionuclide releases caused by accidents or events. Although no fuel damage occurred during this event, the inadequate procedure resulted in a FH event that could have impacted the cladding and affected the cornerstone\'s objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. IMC 0609, SDP, Attachment 0609.04, Phase 1-lnitial Screening and Characterization of Findings, was used to evaluate the significance of the finding. Attachment 0609.04, Table 4a, was used to evaluate the impact of the finding on fuel clad integrity. Appendix G was considered for the evaluation, but was not used because it does not directly address fuel clad integrity. Based on the results of fuel sipping done in February 2011, PBAPS concluded that there was no damage to the clad integrity of the impacted fuel bundle that was permanently discharged to the SFP. Since the finding did not affect SFP cooling or inventory and since there was no damage to fuel clad integrity from the impact with the CSI submarine, the finding was determined to be of very low safety significance (Green). The finding has a cross-cutting aspect in Human Error Prevention Techniques in the Work Practices component of the Human Performance area. Specifically, PBAPS FH procedures did not require human error prevention techniques that were commensurate with the risk of moving fuel in close proximity to obstructions and interferences. (H.4(a))
05000354/FIN-2011002-012011Q1Hope CreekLicensee-Identified ViolationHope Creek TS 6.8.4.i, lnseryice Testing Program, requires the inservice testing of ASME Code Class 1,2, and 3 components in accordance with the ASME Boiler and Pressure Vessel Code. ASME Code requires that l BCPSV-4425, the RHR shutdown cooling common suction relief valve, a Class 1 valve, be tested every 24 months and that it open within a lift setpoint of +/- 3o/o of the specified code safety valve lift setting. Contrary to this requirement, on November 1, 2010, PSEG identified that l BCPSV-4425 opened above the +/- 3% acceptable range. Since the valve was last tested on October 25,2007, this constituted a failed late surveillance test. PSEG entered this issue into their CAP as notification 20484572. This licensee-identified NCV is of very low safety significance based on a Phase 1 SDP screening, because the relief valve lifted below the maximum rating of the piping. Thus, the condition resulted in the inoperability of the valve, but did not result in a loss of system safety function.
05000272/FIN-2011002-022011Q1SalemFailure to Submit an LER for a Condition Prohibited by TS Associated with Containment lsolationA self-revealing finding of very low safety significance was identified for the failure of PSEG to resolve a long standing issue with the reliability of the Unit 1 main generator voltage regulator (VR). A failure in the Unit 1 main generator VR resulted in an automatic reactor trip due to a turbine trip above 50 percent power. Corrective actions include the planned replacement of the VR with a nuclear industry proven design during the October 2011 refueling outage. PSEG entered this issue into their CAP as notification 20481250. The performance deficiency was more than minor because it is associated with the equipment performance attribute of the Initiating Events cornerstone and it adversely affected the 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. The finding was evaluated under IMC 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings. The inspectors determined that the finding is of very low safety significance (Green) because it does not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions will not be available. The inspectors determined that this finding has a cross-cutting aspect in the area of human performance, because PSEG affected long term plant safety by not minimizing long-standing equipment issues. Specifically, considering the increase in the number of Unit 1 main generator VR failures since 2007, PSEG did not resolve the lack of vendor and part support for the Unit 1 main generator VR in a timely manner. (H.2(a))
05000272/FIN-2011002-012011Q1SalemUnit 1 Main Generator Voltage RegulatorThe inspectors identified a Severity Level lV NCV of 10 CFR 50.73, Licensee Event Reporting System, because PSEG personnel did not provide a written report to the NRC within 60 days after discovery of a condition prohibited by Technical Specification (TS) 3.6.1, Containment lntegrity. This was an NRC-identified violation of reporting requirements and potentially impacted the regulatory process. This type of violation is dispositioned using the traditional enforcement process defined in the NRC Enforcement Policy. In accordance with Section 6.9.d of the Enforcement Policy, this violation is categorized as a Severity Level lV violation. PSEG documented the issue in their corrective action program and conducted an evaluation to determine why the assignment to submit an LER was missed. The inspectors determined that this traditional enforcement violation did not involve a Reactor Oversight Process (ROP) finding, therefore, no cross-cutting issue was assigned
05000317/FIN-2010005-012010Q3Calvert CliffsInadequate Corrective Actions Associated with Submerged SR CablesThe inspectors identified a non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion XVl, Corrective Actions, because Constellation did not establish and take adequate measures for conditions adverse to quality associated with submerged safety related (SR) cables including the 1A diesel generator (DG) cables. As a result, SR cables were subjected to a submerged environment for unknown or extended periods. lmmediate corrective action included entering this issue into their corrective action program (CAP), conducting an operability determination for the 1A DG, and increasing the frequency of manhole inspections. The finding is more than minor because it was associated with the Mitigating Systems cornerstone attribute of equipment performance and affected the associated cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, repeated submergence of medium voltage cables can cause excessive aging and degradation in the exposed sections of cable, which could significantly shorten its qualified life and cause unexpected failures. The inspectors determined that the finding is of very low safety significance because the finding is a design or qualification deficiency confirmed not to result in a loss of operability. This finding had a cross-cutting aspect in the area of problem identification and resolution, operating experience (OE), because Constellation did not implement and institutionalize OE through changes to station processes and procedures associated with submerged cables.
05000317/FIN-2010005-032010Q3Calvert CliffsInadequate Functionality Review of 0C Diesel Degraded ConditionThe inspectors identified a finding of very low safety significance because Constellation did not conduct an adequate functionality review following failure of the 0C diesel generator (DG) (the station blackout (SBO) diesel) battery charger. Specifically, Constellation did not take into account the Appendix R mission time in the functionality review. As a result, Constellation did not recognize that the 0C diesel was not available for its Appendix R function with its associated battery charger out-of-service (OOS), lmmediate corrective actions included entering this issue in the corrective action program (CAP) and providing instructions to operators to declare the 0C diesel not available anytime its associated battery charger is taken OOS. Additional corrective actions planned include changing 0l-264, 125 Volt Direct Current (VDC) System, to reflect that the battery charger is required to support the 0C diesel functionality. The finding is more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and affected the cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences, Specifically, Constellation did not recognize that the 0C diesel generator was not available for its Appendix R function with its associated battery charger OOS. The inspectors determined that the finding is of very low safety significance because it only affected the ability to reach and maintain cold shutdown conditions. The finding has a cross-cutting aspect in the area of human performance, resources, because Constellation did not ensure complete, accurate, and up-to-date procedures (0l-264) were available and adequate to assure nuclear safety (H.2.c of IMC 0310).
05000317/FIN-2010005-052010Q3Calvert CliffsFailure to Perform Testing of PORVs in Accordance with ASME OM CodeThe inspectors identified an unresolved item (URl)associated with the failure to perform inservice testing (lST) for the pressurizer PORVs in accordance with American Society of Mechanical Engineers (ASME) Code for the Operation and Maintenance of Nuclear Power Plants. In 2000, Constellation changed the preventive maintenance requirement for the PORVs at both units such that rather than being removed and overhauled every six years, the valves were removed and overhauled every cycle (every two years). ln 2004, Constellation began to functionally test the PORVs to meet their TS and IST surveillance requirements at the end of a unit\'s operating cycle in accordance with procedure STP-M- 673,\'PORV Response Time Test. This testing was performed on valves which were subsequently replaced by refurbished spares. This was done to reduce the number of actuations the inservice valves were subjected to at a pressure below the normal operating pressure. OE indicated that by testing the PORVs at the lower pressures prescribed by STP-M-673, the potential for seat leakage was increased due to insufficient pressure to fully reseat the main valve disc. The Inspectors\' review of this practice identified that testing established in 2004 was not a proper interpretation of the requirements of the ASME Code. Specifically, ISTC-3310 requires a valve to be stroke time tested to verify that the reference value was still valid, or to set a new reference value following any maintenance which could affect the performance of the valve. The mounting of the solenoid and the setting of the plunger on site may affect the performance of the PORV being installed. IST runs were not performed following replacement of both valves during refueling outages since 2004 for both units (1-ERV-402,1-ERV-404, 2-ERV-402, and 2-ERV-404)to verify or reestablish the valves\' reference values. In response to this inspector-identified concern, Constellation initiated CR-2010-01 1886. This item is unresolved pending inspector review of Constellation\'s completed evaluation and CAs for this issue, and a determination if the performance deficiency associated with this issue is more than minor. (URl 05000317131812010005-05, Failure to Perform Testing of PORVs in Accordance with ASME Code).
05000317/FIN-2010005-042010Q3Calvert CliffsInadequate Corrective Action to Address Equipment Repairs in the Material Processing FacilityThe inspectors identified a finding of very low safety significance associated with a non-cited violation (NCV) of Technical Specification 5.4.1 .a, Procedures, involving Constellation\'s failure to implement procedures to calibrate and maintain ventilation and radiation effluent monitoring equipment. Specifically, on December 9,2010, refurbishment of the steam generator (SG) nozzle dams and manway stud tensioners was in progress in the material processing facility; at that time, only one exhaust train of the ventilation system was in operation and a negative pressure of approximately one-half inch of water was not being maintained. lmmediate corrective actions included stopping all work in the building and completing the necessary repairs before restarting activities. The finding was more than minor because the failure to maintain the ventilation and radiation monitoring equipment affects the Radiation Protection cornerstone to ensure adequate protection of public health and safety from exposure to radioactive materials released into the public domain as a result of routine civilian nuclear reactor operation. The inspectors determined that the finding is of very low safety significance because it did not impair Constellation\'s ability to assess dose. Constellation did assess dose and the limits of 10 CFR 50 Appendix I and 10 CFR 20.1301(e) were not exceeded. The finding also has a cross-cutting aspect in the area of problem identification and resolution, Corrective Action, because appropriate corrective actions were not taken in a timely manner. The exhaust fan was out-of-service (OOS) for eight months, the supply fan was OOS for seven years, and the radiation monitor was OOS for most of four years (P.1.d or IMC 0310).
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