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05000266/FIN-2018003-02Point Beach2018Q3Licensee-Identified ViolationViolation: Point Beach Nuclear Plant, Units 1 and 2, Renewed Operating License Condition 4.F, requires the licensee to implement and maintain in effect all provisions of the approved fire protection program that comply with 10 CFR 50.48(a) and 10 CFR 50.48(c), National Fire Protection Association Standard NFPA 805, as specified in the license amendment requests and as approved in the safety evaluation report dated September 8, 2016.Section 1.5.1, Nuclear Safety Performance Criteria, of NFPA 805, stated in part, that fire protection features shall be capable of providing reasonable assurance that, in the event of a fire, the plant is not placed in an unrecoverable condition. To demonstrate this, the following performance criteria shall be met: (a) Reactivity Control; (b) Inventory and Pressure Control; (c) Decay Heat Removal; (d) Vital Auxiliaries; and (e) Process Monitoring.Section 1.5.1 (d), Vital Auxiliaries, of NFPA 805, stated that vital auxiliaries shall be capable of providing the necessary auxiliary support equipment and systems to assure that the systems required under (a), (b), (c), and (e) are capable of performing their required nuclear safety function. Contrary to the above, from March 16, 2018 through April 11, 2018, the licensee failed to ensure that vital auxiliaries were capable of providing the necessary auxiliary support equipment and systems to assure that the systems required under (a), (b), (c), and (e) are capable of performing their required nuclear safety function. Specifically, select 120 VAC instrument buses, needed as a vital auxiliary, would not have been energized during certain fire scenarios and compensatory measures were not implemented. Significance/Severity Level: The inspectors determined the performance deficiency was more than minor because it adversely affected the Mitigating Systems cornerstone attribute of Protection Against External Factors (Fire) and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). The inspectors assessed the significance of the finding using Inspection Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process. The finding did not screen to green using questions 1.5.1A and 1.5.1B and thus required a detailed risk evaluation. The Senior Reactor Analyst performed walkdowns of dominant fire sequences and conducted an onsite review of the licensee's fire calculation which confirmed that the increase in risk due to the finding was less than 1E6/year (Green).
05000416/FIN-2018002-07Grand Gulf2018Q2Loss of Shutdown CoolingA self-revealed,Green non-cited violation of Technical Specification 5.4, Procedures,for the licensees failure to follow written procedures was identified when the residual heat removal (RHR) system automatically isolated due to an inadvertent emergency core cooling system (ECCS) actuation. While the plant was shut down with the RHR system in decay heat removal mode, maintenance personnel inadvertently opened an incorrect valve during a transmitter calibration activity, which caused a false low reactor pressure vessel (RPV) water level signal, an ECCS actuation, and a loss of decay heat removal for approximately 31 minutes
05000282/FIN-2017004-04Prairie Island2017Q4Licensee-Identified ViolationTitle 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality shall be prescribed by documented procedures of a type appropriate to the circumstances and shall be accomplished in accordance with these procedures. Contrary to the above, on October 17, 2017, with Unit 2 in Mode 5, Cold Shutdown, the licensee failed to accomplish procedure 2C12.2, Purification and Chemical Addition Unit 2; Revision 34. Specifically, control room operators signed off steps as completed without validating that the procedure actions were performed in the field. These procedure steps that intended to close letdown valves and open purification valves, resulted in unintended transfer of primary coolant from the RCS to the chemical and volume control system hold-up tank instead of back to the RCS. In turn, this resulted in a reduction in RCS inventorywith reactor vessel level at approximately 1 foot below the flange (reduced inventory operations). Due to operators quickly recognizing a lack of letdown flow as discussed during a pre-job brief, the purification evolution was halted and actions were taken to restore reactor vessel level.Because the inspectors answered No to questions B.2 and B.3 under Exhibit 2, Initiating Events Screening Questions of IMC 0609, Appendix G, Attachment 1, Shutdown Operations Significance Determination Process Phase 1 Initial Screening and Characterization of Findings, the finding screened as very low safety significance (Green). Specifically, the loss of inventory event was self-limiting such that the leakage would have stopped before impacting the operating method of decay heat removal (shutdown cooling via RHR in this case). The issue was entered into the licensees CAP as CAP 501000003923. Corrective actions included an operations department human performance clock reset to share the lessons learned from the event.
05000416/FIN-2017007-07Grand Gulf2017Q4Licensee-Identified ViolationThe following violations of very low safety significance (Green) were identified by the licensee and are violations of NRC requirements which meet the criteria of the NRC Enforcement Policy for being dispositioned as non- cited violations. Technical Specification 5.4.1(a) requires written procedures to be established, implemented, and maintained as recommended by Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Section 4.e recommends, in part, instructions for startup of shutdown cooling and reactor vessel head spray system be prepared. Contrary to the above, from about 2004 until September 1, 2017, the 04-1-01-E12-2 instruction failed to provide instruction for placing the alternate decay heat removal system in service. Specifically, Step 4.9.2a.7(d) instructs an operator to, Manually control component cooling water temperature by throttling P44-F010A(B)(C), PSW inlet to CCW HXs. However, the purpose of that step is to throttle plant service water flow through the alternate decay heat removal system and component cooling water system to ensure both systems have plant service water flow, which is not accomplished by the instruction step. The licensee identified this procedural violation before the system was credited for availability during an inservice demonstration on September 1, 2017, and entered it in the corrective action program as Condition Report CR-GGN-2017-08643. The violation is of very low safety significance (Green) because, although the procedure did delay placing the system in service due to the procedure error, the system was capable of performing its design function, consistent with Inspection Manual Chapter 0609, Appendix G, Attachment 1, Exhibit 3 screening.
05000315/FIN-2017004-02Cook2017Q4Unit 1 Letdown System Safety Valve Lift During Preparations for CooldownRefueling Outage Activities a. Inspection Scope The inspectors reviewed the Outage Safety Plan (OSP) and contingency plans for the Unit 1 refueling outage (RFO), conducted September 13 through November 26, to confirm that the licensee had appropriately considered risk, industry experience, and previous site-specific problems in developing and implementing a plan that assured maintenance of defense-in-depth. During the RFO, the inspectors observed portions of the shutdown and cooldown processes and monitored licensee controls over the outage activities listed below: licensee configuration management, including maintenance of defense-in-depth commensurate with the OSP for key safety functions and compliance with the applicable TS when taking equipment out of service; implementation of clearance activities and confirmation that tags were properly hung and equipment appropriately configured to safely support the work or testing; installation and configuration of reactor coolant pressure, level, and temperature instruments to provide accurate indication, accounting for instrument error; controls over the status and configuration of electrical systems to ensure that TS and OSP requirements were met, and controls over switchyard activities; monitoring of decay heat removal processes, systems, and components; controls to ensure that outage work was not impacting the ability of the operators to operate the spent fuel pool cooling system; reactor water inventory controls including flow paths, configurations, and alternative means for inventory addition, and controls to prevent inventory loss; controls over activities that could affect reactivity; maintenance of secondary containment as required by TS; licensee fatigue management, as required by 10 CFR 26, Subpart I; refueling activities, including fuel handling and reactor assembly/disassembly; startup and ascension to full power operation, tracking of startup prerequisites, walkdown of the containment to verify that debris had not been left which could block emergency core cooling system suction strainers, and reactor physics testing; and licensee identification and resolution of problems related to RFO activities. Documents reviewed are listed in the Attachment to this report. Inspections activities performed in the third quarter coupled with those in the fourth quarter constituted one RFO sample as defined in IP 71111.2005. b. Findings (Opened) Unresolved Item 05000315/201700402, Unit 1 Letdown System Safety Valve Lift During Preparations for Cooldown Introduction: Shortly after the shutdown for the Unit 1 refueling outage in September 2017, the licensee was establishing conditions in the charging and letdown system for the upcoming cooldown. After lowering letdown flow and attempting to adjust pressure, a letdown safety valve lifted and failed to completely reseat. Review of plant parameters following the event revealed that the evolution created saturation conditions in the letdown system. Subsequently, the steam bubbles collapsed causing a water hammer that lifted and damaged a relief in the system. The event was discussed in Section 4OA3 of Inspection Report 05000315/05000316/2017003. Description: The inspectors reviewed the licensees follow up of the issue in the CAP and spoke to personnel in the operations and maintenance departments. The licensee identified potential issues in the areas of procedure adequacy, operator performance, and equipment performance. However, the inspectors could not reconcile information on plant conditions with licensees statements regarding the cause. Because of ambiguity regarding the cause, the inspectors could not determine whether the corrective actions taken by the licensee were adequate. The licensee determined that an apparent cause evaluation need not be done therefore the inspectors reviewed available data, including plant computer data and a prior event from 2004. Since it is unclear what, if any, performance deficiency exists associated with this issue, the inspectors determined an unresolved item (URI) was necessary pending further follow up of the issue.Following the lifting of the safety valve, the licensee isolated letdown to stop the remaining leakage through the valve. The licensee then cycled the valve sufficiently enough for it to reseat so letdown could be restored and the cooldown continued. The safety valve was later discovered to be damaged from the event, so it was also repaired. Walkdowns were also conducted of the letdown piping to ensure no damage had occurred during the pressure transient. As part of their corrective actions, the licensee made some changes to the letdown procedure, recalibrated a letdown flow control valve, and developed actions to cover the event and lessons-learned in training. However, as stated above, the inspectors were unable to determine if these were sufficient to address the prevailing cause of the issue. The inspectors developed a series of questions for the licensee to explore more of the details behind the various potential issues. In order close the URI, the inspectors need to review the licensees response to questions provided and review available documentation of the event. (URI 05000315/201700402, Unit 1 Letdown System Safety Valve Lift During Preparations for Cooldown)
05000395/FIN-2017003-03Summer2017Q3Failure to Adequately Assess the Risk for an Activity with Consequent Loss of Core CoolingThe inspectors identified a Green, NCV of 10 CFR 50.65(a)( 4), Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, involving the licensees failure to perform an adequate risk assessment for an activity involving restoration of the B train emergency bus to the normal supply and a subsequent loss of the B train residual heat removal (RHR) pump and a consequent loss of core cooling. The issue was entered into the licensees CAP as condition report, CR- 17- 03696 The inspectors reviewed IMC 0612, Appendix B, Issue Screening, dated September 7, 2012, and determined that the PD was more than minor and therefore a finding because it was associated with the Mitigating Systems Cornerstone, and adversely affected the cornerstone objective to ensure in part the availability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to perform an adequate risk assessment resulted in performance of an activity causing a vulnerability to operability of the running RHR pump and a consequent loss of core cooling. The finding was screened for risk significance using NRC IMC 0609.04 and routed to NRC IMC 0609, Appendix G. A detailed shutdown risk assessment was performed by a regional senior risk analyst using NRC IMC 0609 Appendix G and Attachments 1 and 2. The major analysis assumptions included: treatment of the PD as a loss of RHR with an initiating event likelihood of 1.0 using NRC IMC 0609 Appendix G, Attachment 2, worksheet 9 (loss of RHR in plant operating state 2); and recovery credit was applied for closing the alternate feeder breaker. The dominant sequence was a loss of RHR, failure to recover decay heat removal prior to reactor coolant system (RCS) boiling, failure to initiate RCS injection before core damage and failure to restore power to the B train safety bus. The RCS conditions of time to boil and time to core uncovery and availability of mitigating equipment limited the risk. The detailed risk evaluation determined that the PD represented an increase in core damage frequency <1.0E -6 a GREEN finding of very low safety significance. The inspectors reviewed IMC 0310, Aspects Within Cross Cutting Areas, dated December 4, 2014, and determined that this finding had a cross -cutting aspect in the area of Work Management (H.5), because the licensee did not perform an adequate risk assessment in accordance with their procedure.
05000346/FIN-2017003-01Davis Besse2017Q3Pinched Wiring Causing the Failure of Fuses Y210 and Y214An unresolved item (URI) was identified by the inspectors relating to the significance of pinched wires and licensees understanding of the condition and the extent of cause and condition. On July 6, 2017, during a planned replacement of fuse Y204 in electrical cabinet Y2, unrelated fuse Y214 blew. Both fuses were scheduled for replacement as part of the licensees project to replace Shawmut A25X style fuses that are susceptible to premature failure. The failure of fuse Y214 was unexpected, and the licensee was not able to discern a direct cause. The licensee determined that the failure was the fuse itself being so unstable that any perturbation was enough to cause failure. This failure resulted in multiple systems being declared inoperable including AFP 2, safety features actuation system channel 2, decay heat removal system interlock, and radiation element RE8447. On August 8, 2017, the same electrical cabinet, Y2, was opened for replacement of fuse Y216. Following the replacement, fuses Y210 and Y214 blew. The licensee attempted replacement of the fuses, but the replacement fuses blew again, shortly after being repowered. Initial licensee evaluation of the condition revealed thatthe wire bundle running along the hinge side of the cabinet door was unconstrained and two of the wires had become pinched between the door and cabinet frame, which damaged the wire insulation and allowed the wires to short circuit against the cabinet frame. The failure of Y210 and Y214 resulted in multiple systems being declared inoperable including AFP 2, safety features actuation system channel 2, decay heat removal system interlock, and emergency diesel generator 2. The licensee removed and replaced the damaged portion of the wires and used wire ties to constrain the wire bundle. The licensee entered this issue into their CAP as CRs 201707196 and 201708185. Because the licensee had yet to answer NRC inspector questions pertaining to the corrective actions and extent of condition by the end of this inspection period, the issue is being treated as a URI pending completion of the inspectors review. (URI 05000346/201700301, Examination of Extent of Cause and Condition of Pinched Wires in Electrical Cabinets)
05000498/FIN-2017002-01South Texas2017Q2Failure to Establish Procedures to Remove Reactor Vessel Head Vent Rig Results In Loss of Reactor Coolant System InventoryGreen . The inspectors documented a self -revealed, non -cited violation of Technical Specification 6.8.1.a, Regulatory Guide 1.33, Revision 2, February 1978, Appendix A, Section 9.d.(4). Specifically, inadequate written work instructions to remove the reactor vessel head vent rig and install a breathable foreign material exclusion cover resulted in installing a blind flange and a loss of reactor coolant system water while at lowered inventory. The licensee developed proper instructions and the blind flange was promptly removed to restore the vent path for the reactor vessel head. Reactor coolant system inventory was restored. This issue was entered into the licensees corrective action program as Condition Report 2017- 13155. The failure of the licensee to provide appropriate written work instructions to install a breathable foreign material exclusion cover following the removal of the reactor vessel head vent rig was a performance deficiency. The performance deficiency is more than minor because it was associated with the configuration control attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the licensee installed a blind flange, instead of a breathable foreign material exclusion cover on the reactor vessel head vent piping, which resulted in an inadvertent loss of reactor coolant during lowered inventory operations. Using Inspection Manual Chapter 0609, Appendix G, Shutdown Operations Significance Determination Process, dated May 9, 2014, Attachment 1, Exhibit 2, Initiating Events Screening Questions, the finding was determined to be of very low safety significance (Green) because the finding would not have resulted in a loss of decay heat removal if undetected for 24 hours, AND was determined to be self -limiting because level would have only lowered to the point at which it would have vented to the pressurizer and not lowered to the point of challenging decay heat removal function. The inspectors determined that the finding had a cross -cutting aspect in the area of human performance associated with work management. The licensee failed to implement an adequate process to execute work activities such that nuclear safety is the overriding priority. Specifically, contractors were supplied generic work instructions to remove the reactor coolant system head vent rig which resulted in a loss of reactor coolant system inventory (H.5).
05000461/FIN-2017002-03Clinton2017Q2Unexpected Start of the Division 3 Emergency Diesel GeneratoGreen . The inspectors documented a self -revealed finding o f very low safety significance and an associated non- cited violation of Title 10 of the Code of Federal Regulations (CFR) Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensees failure to follow steps in Work Order (WO) 04640788 while performing troubleshooting on blown power transformer fuses in the division 3 emergency diesel start circuitry. Specifically, the electricians opened test switches in the wrong electrical cubicle resulting in the unexpected start of the division 3 emergency diesel generator and a loss of power to the 1C1 bus from an offsite source. The licensee entered this issue into their corrective action program (CAP) as Action Request (AR ) 04012393. As corrective actions, the licensee performed a human performance review to identify the reasons the procedure was not followed and restored power to the 1C1 safety bus . The performance deficiency was determined to be more than minor because it impacted the Initiating Event s cornerstone at tribute of human performance and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the failure of the electrical maintenance technicians to follow their procedures resulted in a loss of power to the 1C1 electrical bus. T he finding was screened against the Initiating Event s cornerstone and determined to be of very low safety significance because the loss of power to the 1C1 bus occurred while Clinton was in a refueling outage when the high pressure core spray system was removed from service and not being relied upon for shutdown safety defense in depth. The loss of the 1C1 bus did not affect decay heat removal from the core, did not affect reactor coolant inventory, and the event occurred while the refuel cavity was flooded up for refueling operations. The inspectors determined that this finding affected the cross -cutting area of human performance in the aspect of avoid complacency where individuals implement 3 appropriate error reduction tools. Specifically, as documented in the licensees human performance review, the electricians performing the work did not utilize any human performance tools to flag the equipment to be operated and improperly performed the concurrent verification of the component to be manipulated. (H.12)
05000461/FIN-2017002-02Clinton2017Q2Failure to Perform Adequate Evaluation of Crane Rail ClipsGreen . The inspectors identified a finding of very -low safety significance and an associated cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the failure to properly verify the adequacy of design of the fuel building crane and crane support structure elements. Specifically, calculations involving the crane rail clips and clip bolts had multiple technical errors and failed to adequately demonstrate that the design met the design basis requirements. The licensee initiated corrective actions by documenting the deficiency in A R 4001089 and performed an evaluation demonstrating that the functionality of the crane was maintained. The finding was determined to be more -than -minor because it was associated with the design control attribute of the Barrier Integrity cornerstone and adversely affected the cornerstone objective of maintaining the functionality of the spent fuel pool (SFP) cooling system. Specifically, crane rail clip bolts were required to ensure structural integrity of structures, systems, and components described in the Updated Safety Analysis Report, 5 when subjected to design loads as part of safe load handling of heavy loads near the SFP and to ensure integrity of the spent fuel cask. In accordance with IMC 0609, Significance Determination Process , Attachment 0609.04, Initial Characterization of Findings, Table 2, the inspectors determined the finding affected the Barrier Integrity cornerstone because it was associated with SFP/fuel handling activities . Based on answering No to questions A through F in Table 3, the inspectors determined the finding could be evaluated using Appendix A, The Significance Determination Process for Findings At -Power, Exhibit 3, for the Barrier Integrity cornerstone screening questions. Based on the crane remaining functional, the inspectors answered No to Questions D.1 through D.4 because the finding did not adversely affect decay heat removal capabilities, did not result from fuel handling errors, did not result in loss of SFP inventory, and did not affect the SFP neutron absorber or fuel bundle misplacement ; therefore , the finding screened as having very -low safety significance. The finding was cross- cutting in the resolution aspect of the problem identification and resolution area because the licensee failed to take effective corrective actions in a timely manner to address issues identified earlier in the rail clip evaluations. (P.3)
05000416/FIN-2016008-01Grand Gulf2017Q2Failure to Have Alternate Decay Heat Removal CapabilityThe team identified two examples of a non -cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensees failure to have adequate procedures for activities affecting quality. Specifically, Grand Gulf Nuclear Station failed to have adequate procedures for feedwater, condensate, and shutdown cooling activities. The licensee implemented corrective actions to revise the procedures. The licensee entered this issue into their corrective action program as Condition Reports CR- GGN -2016- 08334, 08273, and 08290. The failure to have adequate procedures for activities affecting quality was a performance deficiency. Example (1) of this performance deficiency was more than minor, and therefore a finding, because it was associated with the procedure quality attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, not having procedural guidance for the alternate decay heat removal system alignment resulted in misalignment of the system and its subsequent inability to perform its required function if needed. A detailed risk evaluation (Attachment 2) calculated an increase in core damage frequency of 3.2E -7/year and an increase in large early release frequency of 7.3E -8/year, which has a very low safety significance (Green) . Example (2) of this performance deficiency was more than minor, and therefore a finding, because it was associated with the procedure quality attribute of the Initiating Events Cornerstone and affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown operations. Specifically, not having procedural guidance for feedwater isolation valve operation resulted in inadvertent over fill of the reactor vessel. This violation is associated with a finding having very low safety significance (Green). The team did not assign a cross -cutting aspect because the performance deficiency was not reflective of current plant performance .
05000416/FIN-2016008-02Grand Gulf2017Q2Failure to Have Adequate ProceduresThe team reviewed a self -revealed, non -cited violation of Technical Specification 3.4.10, Residual Heat Removal Shutdown Cooling System Cold Shutdown, for the licensees failure to verify an alternate method of decay heat removal was available when residual heat removal subsystem A was inoperable and unavailable due to a pump replacement. Specifically, the licensee inappropriately credited the alternate decay heat removal system as an available alternate method of decay heat removal. Credit for this system was inappropriate because, although the licensee believed the system had been aligned in standby, the alternate decay heat removal heat exchanger isolation valves had remained tagged closed, rendering the system unavailable to satisfy the technical specification requirement during the time period that residual heat removal subsystem A was unavailable. The licensee restored compliance by restoring residual heat removal subsystem A to available status . The licensee entered this issue into their corrective action program as Condition Report CR -GGN -2016 -07281. The failure to perform the required action to verify an alternate method of decay heat removal was available, when a residual heat removal shutdown cooling system was inoperable, was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it was 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. A detailed risk evaluation (Attachment 2) calculated an increase in core damage frequency of 3.2E -7/y ear and an increase in large early release frequency of 7.3E -8/year. Therefore, this violation is associated with a finding having very low safety significance (Green). The team determined the finding had a cross -cutting aspect within the human performance area, field presence, because leaders failed to reinforce standards and expectations in the work areas of the plant (H.2).
05000416/FIN-2016008-03Grand Gulf2017Q2Failure to Follow Operations ProceduresThe team identified a non -cited violation of Technical Specification 5.4.1.a , Procedures, for the licensees failure to implement procedures required by Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Specifically, contrary to procedures , on September 23, 2016, operations personnel failed to verify adequate plant service water flow to the alternate decay heat removal heat exchangers while placing the system in service . The licensee implemented corrective actions which included high intensity training to improve nuclear worker behaviors and clarifying the directions in the procedure. The licensee entered this issue into the corrective action program as Condition Report CR- GGN -2016- 08333. The failure to implement procedures , as required by Technical Specification 5.4.1. a, was a performance deficiency. This performance deficiency was more than minor, and therefore a finding, because , if left uncorrected, the failure to implement procedures as required by Technical Specification would have the potential to lead to a more significant safety concern. Using Inspection Manual Chapter 0609, Appendix G, Shutdown Operations Significance Determination Process , and Inspection Manual Chapter 0609, Appendix G, Attachment 1, Shutdown Operations Significance Determination Process Phase 1 Initial Screening and Characterization of Findings, the team determined that the finding was of very low safety significance (Green ) because it did not affect the design or qualification of a mitigating system structure, system , or component and did not directly prevent the alternate decay heat removal system from maintaining its functionality. The team identified a cross -cutting aspect the area of human performance, challenge the unknown, because individuals failed 4 to stop when faced with uncertain conditions and risks were not evaluated and managed before proceeding (H.11).
05000440/FIN-2017001-01Perry2017Q1Failure to Implement Procedures for Combating a Loss of Shutdown CoolingGreen. A finding of very-low safety significance and associated NCV of TS 5.4, Procedures, was identified by the inspectors for the failure to implement procedures for combating a loss of shutdown cooling (SDC). Specifically, the licensee failed to implement its procedure for combating a loss of SDC resulting from emergency service water (ESW) inoperability and during high decay heat load. This finding was entered into the licensees Corrective Action Program to perform analyses for various conditions to identify available alternate methods of decay heat removal and provide associated procedural guidance. The performance deficiency was determined to be more-than-minor because it was associated with the Mitigating Systems cornerstone attribute of design control and affected the cornerstone objective of ensuring the availability, reliability, and capability of mitigating systems to respond to initiating events to prevent undesirable consequences. The finding screened as very-low safety significance (Green) because it was a design deficiency that did not impact the operability or Probabilistic Risk Assessment functionality of any mitigating structures, systems, and components. The inspectors did not identify a cross-cutting aspect associated with this finding because it did not reflect current performance due to the age of the performance deficiency
05000461/FIN-2017001-02Clinton2017Q1Failed to Verify an Appropriate Alternate Method of Decay Heat RemovalGreen. The inspectors identified a finding of very low safety significance and an associated non-cited violation of 10 CFR 50.36(c)(2)(i), Limiting conditions for operation, for failing to meet/follow the required actions for limiting condition for operation 3.9.9 and 3.4.10. Specifically, the operators failed to verify a credited alternate decay heat removal method that would satisfy the required action for the limiting condition for operation. The licensee entered this issue into their corrective action program as AR 03987440. The corrective actions in response to this violation were to identify appropriate alternate methods of decay heat removal and incorporate them into the shutdown safety management program utilized during plant outages. The performance deficiency was determined to be more than minor because it impacted the Mitigating Systems cornerstone attribute of equipment performance and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, with the operators failing to identify a credited alternate method of decay heat removal and taking credit for the inoperable but in service RHR shutdown cooling train, the actual available methods that could have been credited were not verified to ensure their availability to provide the required function. The finding was screened against the Mitigating Systems Screening questions and determined to be of very low safety significance because the answer to all of the applicable screening questions was No. The inspectors determined that this finding affected the cross-cutting area of human performance in the aspect of conservative bias, where individuals use decision making practices that emphasize prudent choices over those that are simply allowable. Proposed actions are determined to be safe in order to proceed, rather than unsafe in order to stop. Specifically, the senior reactor operators at the station had historically credited inoperable RHR shutdown cooling subsystems as their own alternate decay heat remove method because they believed it was allowable without determining that it was safe in order to proceed. (H.14
05000354/FIN-2016004-01Hope Creek2016Q4Trip of Protected RWCU Pump during Maintenance ActivityGreen. A self-revealing very low safety significance (Green), non-cited violation of Title 10 of the Code of Federal Regulations (10 CFR) 50.65(a)(4) was identified for inadequately assessing and managing risks associated with maintenance activities to prevent plant transients that upset plant stability. Specifically, because PSEG did not identify a conflict with the reactor water cleanup (RWCU) pump trip logic prior to conducting a planned breaker swap, the A RWCU pump tripped while it was credited to as a defense-in-depth system for decay heat removal (DHR). PSEG assigned a corrective action to perform a work group evaluation and address lessons learned from this event. The issue was more than minor because it was associated with the Equipment Performance (availability) attribute of the Initiating Event cornerstones and adversely affected its objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown. Additionally, this issue was similar to IMC 0612, Appendix E, examples 7.e and 7.f, in that the resulting increased risk put the plant into a higher risk category. In this case, the plant risk would have been reclassified from Yellow to Orange when RWCU pump was unavailable during residual heat removal (RHR) shutdown cooling outage window. The inspectors evaluated the finding using IMC 0609, Appendix G, Shutdown Operations Significance Determination Process, Attachment 1, Exhibit 1, Initiating Event Screening Questions. The inspectors determined the finding was Green because no quantitative phase 2 analysis was required, and RWCU system was not identified as a major system on Table G1 for Decay Heat Removal safety function. This finding had a cross-cutting aspect in the area of Human Performance, Work Management, because PSEG did not identify and appropriately manage risk associated with the breaker swap activity. Specifically, PSEGs work order to swap the breaker was not planned or scheduled during a RWCU system outage window where the plant shutdown safety risk would have been properly managed (H.5).
05000313/FIN-2016004-02Arkansas Nuclear2016Q4Failure to Design Pipe Support for VibrationGreen. The inspectors documented a self-revealed finding and associated non-cited violation of 10 CFR 50 Appendix B Criterion III for the licensees failure to verify that the decay heat removal (DHR) system drain piping configuration and supports could withstand vibrations created during low pressure and high flow conditions. As a result, a cracked weld and unisolable leak in the DHR system occurred due to high cycle fatigue caused by those conditions. To correct this issue, the licensee repaired the leaking weld and designed and installed a new piping support and piping configuration to reduce vibrations during the expected operating conditions. The licensee entered this issue into the corrective action program as Condition Report CR-ANO-1-2016-03225. The failure to design the decay heat removal system piping to withstand expected vibrations from the systems cavitating venturis is a performance deficiency. The performance deficiency is more than minor because it was associated with the design control attribute of the initiating events cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, inadequate design of the DHR system piping support resulted in a leak that could have challenged the capability of both trains of the DHR system during shutdown on September 29, 2016. The inspectors performed an initial screening of the finding in accordance with NRC Inspection Manual Chapter (IMC) 0609, "Significance Determination Process," issued October 7, 2016, and were directed to IMC 0609, Appendix G, Attachment 1, "Shutdown Operations Significance Determination Process Phase 1 Screening and Characterization of Findings, since the finding pertained to a degraded condition while the plant was shutdown. Using IMC 0609, Appendix G, Attachment 1, dated May 9, 2014, the inspectors determined that the finding required a Phase 2 evaluation. A senior reactor analyst performed a Phase 2 evaluation in accordance with IMC 0609, Appendix G, Attachment 2, Phase 2 Significance Determination Process Template for PWR during Shutdown, dated February 28, 2005. The senior reactor analyst performed a Phase 2 evaluation which used realistic break characteristics and plant configuration changes to determine the significance to be of very low safety significance (Green). The inspectors determined this finding did not have a cross-cutting aspect because the most significant contributor did not reflect current licensee performance. Specifically, the licensee last reviewed and modified the pipe support configuration in 1996
05000298/FIN-2016004-04Cooper2016Q4Failure to Maintain Main Steam System Operating ProcedureThe inspectors reviewed a self-revealed, non-cited violation of Technical Specification 5.4.1.a for the licensees failure to maintain Station Procedure 2.2.56, Main Steam System, Revision 49, to prevent a main steam line high flow Group 1 primary containment isolation signal when opening an inboard main steam isolation valve. Specifically, the licensee failed to maintain Station Procedure 2.2.56 with adequate differential pressure limits for reopening closed main steam isolation valves during plant shutdown, which caused the unexpected closure of all the open main steam isolation and drain valves during the plant cooldown process. This resulted in a loss of the main steam line decay heat removal path, which caused reactor coolant system pressure and temperature to increase by approximately 13 psig and 3 degrees Fahrenheit, respectively, during the event. The immediate corrective actions were to reset the Group 1 isolation signal and open the main steam line drain valves to recommence plant cooldown. The licensee entered this deficiency into the corrective action program as Condition Report CR-CNS-2016-05835, and the licensee initiated an apparent cause evaluation to investigate this condition. The licensees failure to maintain Station Procedure 2.2.56 to prevent a main steam line high flow Group 1 isolation signal when opening an inboard main steam isolation valve, in violation of Technical Specification 5.4.1.a, was a performance deficiency. The performance deficiency was determined to be more than minor, and therefore a finding, because it was associated with the procedural quality attribute of the Initiating Events Cornerstone and affected the associated cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown. Specifically, the Group 1 isolation signal closed the main steam line drain valves, which resulted in a loss of the main steam line decay heat removal path and caused reactor coolant system pressure and temperature to increase. The inspectors determined Inspection Manual Chapter 0609, Appendix G, Attachment 1, Shutdown Operations Significance Determination Process Phase 1 Initial Screening and Characterization of Findings, dated May 9, 2014, was not applicable because plant temperature and pressure were not within the normal residual heat removal/decay heat removal system operating parameters. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, the inspectors determined that the finding screened as having very low safety significance (Green) because it did not cause both a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of a trip to a stable shutdown condition. A cross-cutting aspect was not assigned to this finding because the performance deficiency occurred in 1988 when the licensee changed the procedural limits for differential pressure across the main steam isolation valves when reopening them, and therefore, was not indicative of current licensee performance.
05000316/FIN-2016004-02Cook2016Q4Moisture Separator Reheater RuptureGreen. A self-revealed finding of very low safety significance (Green), occurred on July 6, 2016, when a portion of the Unit 2 Right Moisture Separator Reheater (MSR) B bellows assembly ruptured, causing a steam leak which damaged the adjacent turbine building wall. There were no associated violations of regulatory requirements since the piping was non-safety-related. Reacting to the rupture, operators tripped the reactor and isolated the leak by shutting the Main Steam Isolation Valves. While addressing a number of issues with the MSRs that occurred following a re-design of the internals in 2010, the licensee changed the design of the rods that hold the bellows assembly on each MSR pipe together. The design change called for tack welds to only be used on the end nuts of the rod. Contrary to the design change (EC51875), tack welds were placed on other nuts as well. The tack welds were determined to have changed the material properties of the rod in the vicinity of the welds, which caused cracking to initiate during operation. Eventually, the cracks grew to a point where two rods completely severed, causing the bellows to tear and rupture. Following the safe shutdown, the licensee repaired the bellows, inspected other rods, and restarted the plant. The issue was entered into their Corrective Action Program (CAP) as Action Request (AR)20167865. The issue was more than minor because it adversely affected the Design Control Attribute of the Initiating Events cornerstone because it resulted in a reactor trip and Unusual Event. Per the Significance Determination Process, a detailed risk evaluation was required because during the rupture operators had to close the Main Steam Isolation Valves, which isolated the main condenser (the preferred post-trip decay heat removal path). An NRC Regional Senior Reactor Analyst performed the evaluation and concluded the finding was of very low risk significance (Green). The inspectors determined the finding had an associated cross-cutting aspect in the Human Performance Area, specifically, H.12, Avoid Complacency. Specifically, site personnel did not plan for the possibility of mistakes, latent issues, and inherent risk, even while expecting successful outcomes.
05000354/FIN-2016003-03Hope Creek2016Q3Inadequate Procedure Adherence Resulted in a Loss of Shutdown CoolingA self-revealing non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, occurred when PSEG did not follow procedure during the transition from Cold Shutdown to refueling operations while filling up the reactor pressure vessel (RPV) to support RPV head cooling in preparation for reactor disassembly. This resulted in an automatic isolation of the operating residual heat removal (RHR) pump while it was providing decay heat removal in shutdown cooling. PSEG has entered this issue into their corrective action program (CAP) in notification (NOTF) 20684861, and corrective actions included performing a root cause evaluation for the event, revising the operating procedures to provide clarity, and conducting training with all operators on the lessons learned from the event. This issue was evaluated in accordance with IMC 0612, Appendix B, and determined to be more than minor since it was associated with the human performance attribute of the Initiating Events cornerstone and adversely affected its objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown, as well as power operations. The finding was evaluated using IMC 0609, Appendix G, Shutdown Operations Significance Determination Process (SDP), and per Attachment 1, Exhibit 2, required a Phase 2 risk evaluation which determined the safety significance of this performance deficiency to be in the mid E-8 range, or of very low safety significance (Green). The inspectors determined this finding has a cross-cutting aspect in the area of Human Performance, Conservative Bias, in that the operator did not use decision-making practices that emphasized prudent choices over those that are simply allowable, and the operators proposed action was not determined to be safe prior to proceeding with the action. Specifically, the operator did not ensure his actions were safe prior to aligning and operating the feedwater system to fill the RPV during plant cooldown using an uncommon method.
05000413/FIN-2016002-01Catawba2016Q2Failure to Adequately Implement RHR Operating ProcedureA self-revealing Green NCV of Technical Specifications (TS) 5.4.1.a, Procedures, was identified for the licensees failure to adequately implement a procedure for the operation of the Unit 1 residual heat removal (RHR) system. As a result, the breaker for the 1B RHR pump loop suction valve was left open, which resulted in the 1B train of emergency core cooling system (ECCS) being inoperable for greater than its TS allowed outage time. The licensee took immediate corrective actions to close the breaker and restore operability of the 1B train ECCS. The licensee entered this issue into their corrective action program as condition report (CR) 2014866. The licensees failure to adequately implement RHR system operating procedure, OP/1A/6200/004, Shutdown and Alignment for Standby Readiness, prior to plant startup was a performance deficiency (PD). The PD was determined to be more than minor because it was associated with the configuration control attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the performance deficiency resulted in the breaker for the 1B RHR pump loop suction valve being left open and the1B train of ECCS being inoperable for greater than its TS allowed outage time. The inspectors evaluated the significance of the finding using IMC 0609 Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 1, Section B and determined the finding to be of very low safety significance (Green) because the finding did not represent an actual loss of function of at least a single train for greater than its TS allowed outage time because 1ND37A (redundant decay heat removal (ND) 1B pump suction from reactor coolant (NC) Loop C) was still be able to provide the required permissive signal to open 1ND136B (ND supply to safety injection (NI) pump 1B). The performance deficiency had a cross-cutting aspect of teamwork in the area of human performance because operations did not communicate and coordinate activities associated with the RHR system to ensure nuclear safety is maintained. (H.4)
05000323/FIN-2016002-01Diablo Canyon2016Q2Misplaced Spent Fuel Assembly in the Spent Fuel PoolThe inspectors reviewed a self-revealed, non-cited violation of Technical Specification (TS) 5.4.1.a, Procedures, for the licensees failure to place a spent fuel assembly in its correct location in the spent fuel pool (SFP) in accordance with Procedure OP B-8H, Spent Fuel Pool Work Instructions. Specifically, the fuel handling crew moved spent fuel assembly TT69 to location E-37 rather than its intended location E-27. In response to this error, reactor engineering performed a technical specification verification in order to ensure that fuel assembly TT69 could remain in Cell E-37. The licensee suspended further fuel movements pending corrective action and remediation of the operators. The licensee entered this into the corrective action program as Notifications 50846834 and 50847067. The licensees failure to place a spent fuel assembly in its correct location in the SFP was a performance deficiency. The performance deficiency is more than minor, and therefore a finding, because it is associated with the configuration control attribute of the Barrier Integrity Cornerstone and adversely 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. Using Inspection Manual Chapter 0609, Attachment 04, Initial Characterization of Findings, and Appendix A, Exhibit 3, Barrier Integrity Screening Questions, the inspectors determined that the finding was of very low safety significance (Green) because: (1) the finding did not adversely affect decay heat removal capabilities from the spent fuel pool causing the pool temperature to exceed the maximum analyzed temperature limit specified in the site-specific licensing basis, (2) the finding did not result from fuel handling errors, dropped fuel assembly, dropped storage cask, or crane operations over the SFP that caused mechanical damage to fuel clad and a detectible release of radionuclides, (3) the finding did not result in a loss of spent fuel pool water inventory decreasing below the minimum analyzed level limit specified in the site-specific licensing basis, and (4) the finding did not affect the SFP neutron absorber, fuel bundle misplacement (i.e., fuel loading pattern error) or soluble Boron concentration. This finding had a cross-cutting aspect in the area of human performance associated with avoiding complacency. Specifically, individuals failed to recognize and plan for the possibility of mistakes, latent issues, and inherent risk, even while expecting successful outcomes and individuals failed to implement appropriate error reduction tools (Section 4OA2). (H.12)
05000483/FIN-2016001-01Callaway2016Q1Possible Incorrect Screening of the Spent Fuel Pool Decay Heat Removal Key Safety FunctionThe inspectors identified an unresolved item associated with the National Fire Protection Association (NFPA) Standard 805, Performance-Based Standard for Fire Protection for Light-Water Reactor Electric Generating Plants, non-power operations assessment. Specifically, the inspectors developed an issue of concern in that the licensee screened the potential loss of spent fuel pool cooling from further consideration for any fire event based on adequate procedural guidance and time when the procedures would not maintain the fuel in a safe and stable condition. On January 13, 2014, the licensee transitioned their fire protection program to a risk-informed, performance-based program based on NFPA Standard 805, Performance-Based Standard for Fire Protection for Light Water Reactor Electric Generating Plants. Paragraph 1.3.1 of NFPA Standard 805 requires licensees to provide reasonable assurance that a fire during any operational mode and plant configuration will not prevent the plant from achieving and maintaining the fuel in a safe and stable condition. Paragraph 1.5.1 of NFPA Standard 805 lists five nuclear safety performance criteria. These criteria provide requirements to demonstrate that fire protection features are capable of providing reasonable assurance that the plant is not placed in an unrecoverable condition in the event of a fire. For the decay heat removal nuclear safety performance criterion, the standard requires that decay heat removal shall be capable of removing sufficient heat from the reactor core or spent fuel such that fuel is maintained in a safe and stable condition. Paragraph 1.6.56 of NFPA Standard 805 defines safe and stable conditions: For fuel in the reactor vessel, head on and tensioned, safe and stable conditions are defined as the ability to maintain Keff <0.99, with a reactor coolant temperature at or below the requirements for hot shutdown for a boiling water reactor and hot standby for a pressurized water reactor. For all other configurations, safe and stable conditions are defined as maintaining Keff <0.99 and fuel coolant temperature below boiling. The licensee described how they satisfied the nuclear safety performance criteria in Calculation KC-26, Nuclear Safety Capability Assessment, Revision 1. The Nuclear Safety Capability Assessment applied to both power and non-power operations. For non-power operations, the licensee evaluated the spent fuel pool decay heat removal key safety function and determined that the spent fuel pool decay heat removal key safety function did not require a detailed review since adequate time was available, and procedural guidance was provided, for operators to respond to and mitigate a loss of spent fuel pool decay heat removal, even under full hot core offload conditions. The licensee stated that the shortest time to boil, under worst case conditions for a normal plant shutdown, was two hours. In addition, the licensee stated that all of the analyses to address a loss of spent fuel pool decay heat removal utilized a success criterion of no boiling. The licensee implemented the process outlined in Frequently Asked Question (FAQ) 07-0040, Non-Power Operations Clarifications, Revision 4, for the non-power operations assessment. This FAQ stated that licensees should conservatively assume the entire contents of a fire area are lost and document the loss of success paths. This FAQ also stated that licensees should specifically identify those areas (pinch points) that cause the loss of all success paths for a key safety function. The inspectors noted that the licensee did not perform these actions for the spent fuel pool decay heat removal key safety function because this key safety function was screened out from further consideration. If the licensee had evaluated the spent fuel pool decay heat removal key safety function using the process outlined in this FAQ, then the licensee would have assumed that both trains of spent fuel pool cooling are lost during a fire in the fuel handling building because both trains are located within the same fire area and were unprotected. This FAQ also stated that fire modeling may be used to determine if postulated fires in a fire area are expected to damage equipment (and cabling), thereby eliminating a pinch point. However, the licensee stated that no fire modeling was used to eliminate the identification of pinch point fire areas as part of the non-power operations assessment performed using the process in FAQ 07-0040. In the event that a fire in the fuel handling building disabled both trains of spent fuel pool cooling, operators were expected to enter Procedure OTO-EC-00002, Spent Fuel Pool High Temperature, Revision 9, due to the increasing temperature of the spent fuel pool. This procedure provided directions for operators to restore one or both trains of spent fuel pool cooling. Since both trains of spent fuel pool cooling were assumed lost due to the fire, the operators would be unable to restore spent fuel pool cooling using this procedure. After a period of time, the spent fuel pool would begin boiling and the level would begin lowering. At this time, operators were expected to enter Procedure OTO-EC-00001, Loss of SPF/Refuel Pool Level, Revision 13. Procedure OTO-EC-00001 directed the operators to open two normally locked essential service water valves to restore and maintain spent fuel pool level. The licensees procedures allowed the spent fuel pool to reach boiling conditions prior to restoring and maintaining level. Since NFPA Standard 805 defined safe and stable conditions, in part, as fuel coolant temperature below boiling, the procedures did not maintain the fuel in a safe and stable condition. The inspectors identified an issue of concern in that the licensee screened the potential loss of spent fuel pool cooling from further consideration for any fire event based on adequate procedural guidance and time when the procedures would not maintain the fuel in a safe and stable condition. The inspectors determined that additional information is required to determine if a performance deficiency exists. Specifically, the inspectors need to determine if this scenario should have been addressed as part of the current FAQ 07-0040 guidance, or if new guidance is needed to address this type of scenario where the full core has been offloaded to the spent fuel pool. On March 31, 2016, additional guidance was requested from the Office of Nuclear Reactor Regulation via a request to review and update FAQ 07-0040. This memorandum is documented in ADAMS as Accession Number ML16091A152. The licensee entered this issue of concern into the corrective action program as Callaway Action Request 201600726. This issue of concern is being treated as Unresolved Item 05000483/2016001-01, Possible Incorrect Screening of the Spent Fuel Pool Decay Heat Removal Key Safety Function.
05000346/FIN-2016001-06Davis Besse2016Q1Less than Adequate Procedural Instructions for Restoring Main Feedwater Following a Reactor TripA self-revealed finding of very low safety significance (Green), and an associated NCV of TS 5.4.1(a) were identified for the licensees failure to establish and implement adequate procedural guidance for restoring MFW following a reactor trip. Specifically, the guidance in licensee procedure DBOP06910, Trip Recovery Procedure, for restoring MFW to the SGs using the motor-driven feedwater pump (MDFP) did not ensure that the MFW piping had been sufficiently re-pressurized prior to opening the MFW to SG isolation valves. This lack of satisfactory procedural guidance allowed control room operators to prematurely open the MFW to SG No. 1 isolation valve, which resulted in a SFRCS actuation on the reverse delta pressure (P) function. This issue was entered into the licensees CAP. Corrective actions planned by the licensee included changes to licensee procedure DBOP06910, Trip Recovery Procedure, to ensure that MFW header pressure is greater that SG pressure prior to opening the MFW to SG isolation valves. This finding was of more than minor safety significance because it affected the design control and procedure quality attributes of the Mitigating Systems cornerstone of reactor safety, and adversely impacted the cornerstone objective of ensuring the availability, reliability, and capability of the units MFW system and main condenser for decay heat removal. The finding was determined to be of very low safety significance based on the results of a detailed risk evaluation conducted by the NRC Region III Senior Reactor Analyst (SRA). The inspectors determined that the finding had a cross-cutting aspect in the area of human performance. The inspectors assigned the cross-cutting aspect of Resources to the finding because the licensee had failed to ensure that the procedural instructions and guidance available to plant operators restoring MFW during reactor trip recovery actions took into account all relevant technical details (e.g., the differences between MFW piping runs, the amount of time needed to re-pressurize MFW piping, etc.)
05000263/FIN-2016008-01Monticello2016Q1Failure to provide acceptable Alternate Methods of Decay Heat RemovalThe inspectors identified an Unresolved Item associated with Technical Specification (TS) 3.4.8, Residual Heat Removal (RHR) Shutdown Cooling System Cold Shutdown. Specifically, the licensee failed to verify that the capability of the alternate methods of decay heat removal described in Operations Manual C.4-B.03.04.A, Loss of Normal Shutdown Cooling, were adequate to combat a loss of shutdown cooling resulting from the loss of one or two RHR subsystems while in MODE 4 with high decay heat load. The Limiting Condition for Operation (LCO) 3.4.8 of TS Residual Heat Removal Shutdown Cooling System Cold Shutdown, required in Mode 4, two RHR shutdown cooling subsystems shall be operable, and, with no recirculation pump in operation, at least one RHR shutdown cooling subsystem shall be in operation. The TS Bases Section 3.4.8, indicated that an operable RHR shutdown cooling subsystem consisted of one operable RHR pump, one heat exchanger, the associated piping and valves, and the necessary portions of the RHR Service Water System System capable of providing cooling water to the heat exchanger. The TS Bases Section 3.4.8 further indicated that the two subsystems have a common suction source and were allowed to have a common heat exchanger and common discharge piping. Thus, to meet the LCO, both pumps in one loop or one pump in each of the two loops must be operable. Since the piping and heat exchangers were passive components that were assumed not to fail, they were allowed to be common to both subsystems. When TS 3.4.8, LCO could not be met, Condition A, for one or two RHR shutdown cooling subsystems inoperable, the Required Action was to, verify an alternate method of decay heat removal was available for each inoperable RHR shutdown cooling subsystem. The completion time for the required action was 1 hour, and once per 24 hours thereafter. The TS Bases 3.4.8 for Condition A indicated that with one of the two required RHR shutdown cooling subsystems inoperable, the remaining subsystem was capable of providing the required decay heat removal. However, the overall reliability was reduced, therefore, an alternate method of decay heat removal must be provided. With both RHR shutdown cooling subsystems inoperable, an alternate method of decay heat removal must be provided in addition to that provided for the initial RHR shutdown cooling subsystem inoperability. This was to ensure the re-establishment of backup decay heat removal capabilities, similar to the requirements of the LCO. The bases further stated that the required cooling capacity of the alternate method should be ensured by verifying (by calculation or demonstration) its capability to maintain or reduce temperature. Alternate methods that can be used included (but not limited to) the Reactor Water Cleanup System by itself or using feed and bleed in combination with Control Rod Drive System or Condensate/Feed Systems. Abnormal Procedure, Operations Manual C.4-B.03.04.A, Loss of Normal Shutdown Cooling, provided instructions for establishing alternate methods for decay heat removal. The inspectors noticed that except for the alternate method as described below in the G-EK-1-45, the licensee was not able to show by calculation or demonstration that the systems and methods credited in this procedure would be capable of providing sufficient heat removal capability or appropriate levels of redundancy as required by TS 3.4.8. The G-EK-1-45 was a General Electric Letter to Northern States Power, Subject: Cold Shutdown Capability Report, dated April 22, 1981. This letter provided a report which described the capability of the Monticello Nuclear Generating Plant to achieve cold shutdown using only safety class systems and assuming the worst single failure. The alternate shutdown decay heat removal method used in the report credited combinations of the RHR pumps and heat exchangers in the suppression pool cooling mode of RHR to ensure suppression pool water temperatures were below the design limit. This method utilized the core spray system and safety relief valves to circulate reactor inventory to remove decay heat from the reactor. The inspectors noted that calculations supporting the above alternate strategy utilized an RHR subsystem that could be inoperable and/or unavailable and therefore may not be credited to comply with TS 3.4.8. Specifically, the inspectors were concerned that while the plant was in mode 4, with a credited one subsystem inoperable, the licensees credited alternate decay heat removal method that relied on an RHR subsystem, to perform the required suppression pool cooling function. The inspectors were concerned that relying on the only operable RHR subsystem for the alternate method did not meet the intent of the TS requirement as described in the TS Bases. Furthermore, the inspectors noticed for Mode 4 with two RHR subsystems inoperable, the licensee failed to verify by calculation or demonstrations that two additional redundant alternate decay heat removal methods existed with sufficient capacity to maintain the average reactor coolant temperature below 212 degrees Fahrenheit. During the inspection, the licensee indicated that the Boiling Reactor Owners Group was in the process of developing a draft TS Task Force Traveler to address the requirement of TS 3.4.8 and its Bases. Based on the information above, the inspectors were concerned that the plant Operations Manual was inadequate and failed to include alternate decay heat removal methods that would enable the licensee to comply with the requirement of TS 3.4.8. The Operations Manual was required per TS 5.4.1, Procedures, which required that written procedures shall be established, implemented, and maintained covering the emergency operating procedures. The inspectors determined that this issue was unresolved pending the actions by the licensee and the Boiling Reactor Owners Group and the NRC review of these actions. The licensee entered the inspectors concerns into their Corrective Action Program as AR 01516098.
05000346/FIN-2016001-05Davis Besse2016Q1Lack of Software Change Controls and Inadequate Corrective Action for an Operator Workaround Contributes to Complications Experienced During a Reactor TripA self-revealed finding of very low safety significance (Green) was identified for the licensees failure to implement a technically correct software change associated with the SG / Reactor Demand ICS control station. Specifically, a known logic error within the plants ICS would cause the SG / Reactor Demand control station to trip to manual from automatic coincident with a reactor trip. The licensee had instituted compensatory operator actions for this condition, but removed these actions in December 2015 when they implemented a software change to rectify the problem. However, the corrective actions were inadequate and the SG / Reactor Demand ICS control station unexpectedly tripped to manual from automatic when the unit tripped on January 29, 2016. The unexpected control station mode of operation change, combined with the absence of any compensatory operator actions, contributed to the SG No. 1 high level condition and the resultant SFRCS actuation. This issue was entered into the licensees CAP. Corrective actions taken by the licensee included initiating work on a new software change to rectify the issue of the SG / Reactor Demand ICS control station tripping from automatic to manual coincident with a reactor trip; reestablishing the operator workaround and associated compensatory actions for control room operators; and revising applicable procedures to incorporate current industry standards for controlling software life cycle changes to certain categories of software that interface with plant systems. This finding was of more than minor safety significance because it affected the design control and procedure quality attributes of the Mitigating Systems cornerstone of reactor safety and adversely impacted the cornerstone objective of ensuring the availability, reliability, and capability of the units MFW system and main condenser for decay heat removal. The finding was determined to be of very low safety significance because it did not represent a deficiency affecting the design or qualification of a mitigating SSC; it did not, in and of itself, represent a loss of system and/or function; it did not represent an actual loss of function of at least a single train for greater than its TS allowed outage time, or two separate safety systems being out-of-service for greater than their TS allowed outage times; and it did not represent an actual loss of function of one or more non-TS trains of equipment designated as high safety significant in accordance with the licensees maintenance rule program. The inspectors determined that the finding had a cross-cutting aspect in the area of problem identification and resolution. The inspectors assigned the cross-cutting aspect of Evaluation to the finding because the licensee had failed to thoroughly evaluate the issue of the SG / Reactor Demand ICS control station unexpectedly tripping from automatic to manual to ensure that the software change intended to resolve the issue actually addressed its cause.
05000456/FIN-2016001-05Braidwood2016Q1Failure to Ensure Unit 2 Startup Feedwater Pump AvailabilityThe inspectors identified a finding of very low safety significance when licensee personnel failed to ensure that the Unit 2 startup feedwater pump (SUFWP) was available during an 18 month operating cycle. Specifically, the licensee had failed to ensure that the pump oil pressure regulator was properly adjusted, and had failed to perform a post-maintenance test following on-line work in a manner to ensure that no new deficiency was introduced. The license entered this issue into their CAP as IR 2565442. Corrective actions consisted of updating the station SUFWP model work orders (WOs) to ensure that interlock continuity checks were performed as a part of the post-maintenance testing when necessary, and to include procedural steps to verify lube oil pressure when starting a SUFWP. The inspectors determined that the performance deficiency was more than minor because the issue was associated with the Procedural 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. Specifically, the Unit 2 SUFWP is a backup method of decay heat removal following a reactor trip, and is utilized in plant startup and shutdown procedures. A detail risk evaluation was performed and the performance deficiency was determined to be of very low safety significance based upon an evaluation bounding the risk to a Delta Core Damage Frequency (CDF) of 2.9E7/year. No cross-cutting aspect was identified because the cause of the failure were probable causes and not confirmed to be the actual cause.
05000346/FIN-2016001-04Davis Besse2016Q1Less than Sufficient Work Package Documentation and Instructions Resulted in an Inadequate Part Being Installed into the Plants Integrated Control SystemA self-revealed finding of very low safety significance (Green) was identified for the licensees failure to include an adequate bench check for a replacement integrated control system (ICS) module that was installed into the system during the plants 2014 refueling outage (RFO) into the work package instructions for that activity. Specifically, a defeat switch on the replacement Module 528 for the ICS rapid feedwater reduction (RFR) circuit installed as preventative maintenance during the plants 18th RFO was incorrectly wired and not detected during pre-installation checks. The incorrectly wired module prevented the ICS RFR function from occurring during the unit trip on January 29, 2016, which contributed to the Steam Generator (SG) No. 1 high level condition and the resultant steam and feedwater rupture control system (SFRCS) actuation. This issue was entered into the licensees CAP. Corrective actions taken by the licensee included replacement of ICS Module 528 with a spare properly configured for the RFR defeat switch function. Additionally, a proper data package to enable bench checking ICS Module 528 to verify the capability of the module to perform its intended function was created. The licensee also created training and lessons learned from this event. This finding was of more than minor safety significance because it affected the design control and procedure quality attributes of the Mitigating Systems cornerstone of reactor safety, and adversely impacted the cornerstone objective of ensuring the availability, reliability, and capability of the units main feedwater (MFW) system and main condenser for decay heat removal. The finding was determined to be of very low safety significance because it did not represent a deficiency affecting the design or qualification of a mitigating system, structure, or component (SSC); it did not, in and of itself, represent a loss of system and/or function; it did not represent an actual loss of function of at least a single train for greater than its Technical Specification (TS) allowed outage time, or two separate safety systems being out-of-service for greater than their TS allowed outage times; and it did not represent an actual loss of function of one or more non-TS trains of equipment designated as high safety significant in accordance with the licensees maintenance rule program. The inspectors determined that the finding had a cross-cutting aspect in the area of human performance. The inspectors assigned the cross-cutting aspect of Documentation to the finding because the licensee had failed to ensure that the instructions and other work package guidance available to maintenance personnel performing the ICS Module 528 replacement had contained provisions for an adequate bench check of the module prior to its installation.
05000458/FIN-2016009-01River Bend2016Q1Failure to Follow Procedure While Installing Jumpers for Shutdown CoolingThe team reviewed a self-revealing, non-cited violation of Technical Specification 5.4, Procedures, for the licensees failure to correctly implement Procedure SOP-0031, Residual Heat Removal System, Revision 326. SOP-0031, Attachment 5, Step 5.4.1, required that a retractable sheathed banana jumper be used when bypassing the 135-psi SDC isolation. Instead, the licensee used a standard banana jumper, which resulted in a short circuit and inadvertent closure of Valves E12MOV-F008, Shutdown Cooling Suction Valve, and E12MOV-F053A, Shutdown Cooling Injection Valve. This caused a loss of decay heat removal. This issue was entered into the licensees corrective action program as Condition Report CR-RBS-2016-0210. Corrective actions included revising Procedure SOP-0031 to include actions to de-energize the applicable valves while bypassing the 135-psi shutdown cooling isolation. The failure to use the correct jumpers as specified in Procedure SOP-0031 was a performance deficiency. This performance deficiency is more than minor, and therefore a finding, because it is associated with the human performance attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the shorting of contacts resulting from the use of incorrect jumpers caused a loss of shutdown cooling and decay heat removal. The team evaluated the finding using NRC Inspection Manual Chapter 0609, Appendix G, Attachment 1, Shutdown Operations Significance Determination Process Phase 1 Screening and Characterization of Findings. When applying Exhibit 2 - Initiating Events Screening Questions, the team determined the loss of residual heat removal event did not occur when the refuel cavity was flooded, and therefore it required a risk evaluation using the Appendix G, Attachment 3, Phase 2 Significance Determination Process Template for Boiling Water Reactors during Shutdown. The analyst determined that a modified but still conservative Phase 2 quantitative estimate in combination with qualitative and deterministic insights led to a final conclusion that the finding was of very low safety significance (Green). The finding has a field presence cross-cutting aspect within the human performance area because the licensee failed to promptly correct deviations from standards and expectations. Specifically, the licensee failed to correct deviations from standards and expectations during the performance of the pre-job brief and ensure proper communication and oversight is maintained in the control room during risk significant evolutions (H.2).
05000458/FIN-2016009-02River Bend2016Q1Failure to Establish Adequate Procedural GuidanceThe team reviewed a self-revealing, non-cited violation of Technical Specification 5.4, Procedures, for three examples of the licensees failure to establish sufficient procedural guidance. Specifically, the licensees operations and radiation protection procedures did not provide sufficient direction to plant personnel to expeditiously establish a reactor vessel vent path, restore from a loss of shutdown cooling, and perform time sensitive entries into radiologically controlled areas. This issue was entered into the licensees corrective action program as Condition Reports CR-RBS-2016-0210, CR-RBS-2016-0370, and CR-HQN-2016-0132. Corrective actions included revising the applicable procedures. The failure to establish adequate procedural guidance in accordance with Regulatory Guide 1.33 was a performance deficiency. Specifically, Procedures GOP-0002, Power Decrease/Plant Shutdown, Revision 72, and AOP-0051, Loss of Decay Heat Removal, Revision 313, failed to provide adequate direction to operations personnel to expeditiously establish a reactor vessel vent path and recover shutdown cooling following an isolation. Additionally, Procedure EN-RP-101, Access Control for Radiologically Controlled Areas, Revision 11, failed to provide adequate guidance to perform time sensitive entries into radiologically controlled areas. This performance deficiency is more than minor, and therefore a finding, because it is associated with the procedure quality attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensee failed to ensure that adequate procedural direction was provided to operations personnel following a loss of shutdown cooling. This resulted in a delay in the restoration of shutdown cooling and plant heatup. The team performed an initial screening of the finding in accordance with NRC Inspection Manual Chapter 0609, Appendix G, Shutdown Operations Significance Determination Process. Using Inspection Manual Chapter 0609, Appendix G, Attachment 1, Exhibit 3, Mitigating Systems Screening Questions, the team determined that the finding is of very low safety significance (Green) because it: (1) affected the design or qualification of a mitigating structure, system, or component, and (2) the structure, system, or component maintained its operability and functionality. A cross-cutting aspect is not being assigned to this finding due to the timing of the performance deficiency not being indicative of current licensee performance.
05000255/FIN-2015004-05Palisades2015Q4Licensee-Identified ViolationTitle 10 CFR 50.65(a)(1), requires, in part, that the holders of an operating license shall monitor the performance or condition of structures, systems, and components (SSCs), against licensee-established goals, in a manner sufficient to provide reasonable assurance that these SSCs, as defined in 10 CFR 50.65(b), are capable of fulfilling their intended functions. Title10 CFR 50.65(a)(2) states that monitoring as specified in 50.65(a)(1) is not required, where it has been demonstrated that the performance or condition of a SSC is being effectively controlled through the performance of appropriate preventive maintenance, such that the SSC remains capable of performing its intended function. Contrary to the above, as identified after the November 14, 2014, TDAFW pump trip, the licensee failed to demonstrate the performance or condition of the safety-related auxiliary feedwater system steam traps had been effectively controlled through the performance of appropriate preventive maintenance. Specifically, some of the safety-related steam traps, one relief valve, and one check valve associated with the steam supply piping of the turbine-driven AFW system were inappropriately classified in the maintenance rule program, resulting in inadequate and/or untimely maintenance being performed on these components, which probably contributed to the overspeed trip event. The licensee found 3 steam traps and one relief valve classified as non-critical components that were reclassified as high critical components and one steam trap and one check valve classified as run-to-failure components that were reclassified as high critical components. Some of these components also had no preventive maintenance (PM) strategies or ones that were not the correct frequency based on the component classification. The licensee identified this issue while conducting the equipment apparent cause evaluation for the overspeed trip event and documented actions to correct the issue in CR-PLP-2014-5477. The licensee performed inspections of all the steam traps required for the TDAFW pump operation and identified some issues with steam cutting, foreign material exclusion in the traps, and incomplete seat contact. These issues were corrected and PM changes have been made for all the system components mentioned above. The inspectors determined that the inconsistent equipment classifications and ineffective preventive maintenance strategy for the safety-related steam traps in the turbine-driven auxiliary feedwater system is considered a performance deficiency. The performance deficiency was more than minor because it was associated with the Equipment Performance attribute of the Mitigating Systems cornerstone and adversely impacted the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events. Specifically, the licensee identified that the degraded condition of the moisture removal system could have led to excess condensate being present in the steam supply line which had the potential to adversely affect the operation of the turbine for the TDAFW pump, contributing to the overspeed trip event. The inspectors screened the issue using IMC 0609, Appendix A, The SDP for Findings at Power, Exhibit 2, Mitigating Systems Screening Questions, and answered Yes to the question of does this finding represent a loss of system and/or function? This trip of the TDAFW pump on overspeed was evaluated as a failure that impacted the ability of the AFW system to provide the specific function, which could only be accomplished by this train, of decay heat removal via steaming of the A Steam Generator. The turbine-driven AFW pump was also determined to not be in a condition to meet performance requirements defined by the probabilistic risk assessment success criteria, which for AFW is a 24 hour mission time. Therefore, the issue was screened further in a detailed risk evaluation. A Region III Senior Reactor Analyst performed a detailed risk evaluation using the NRCs Standardized Plant Analysis Risk Model for Palisades, Revision 8.20. The SRA assumed the turbine driven AFW pump was unavailable to perform its function for a period of 3 days because the pump was successfully tested and returned to service on November 16, 2014. Given the short exposure period, the calculated delta core delta frequency was less than 1.0E-7/yr. As a result of the low calculated delta core delta frequency, no additional analysis of external event risk contribution or large early release risk contribution was necessary. The dominant core damage sequence was a station blackout followed by the failure of the turbine driven AFW pump and the failure to recover onsite or offsite power. Therefore, the finding screened as very low safety significance (Green).
05000387/FIN-2015004-04Susquehanna2015Q4Inadvertent Closure of the B Inboard MSIVA self-revealing finding of very low safety significance (Green) was identified when Susquehanna did not correctly validate a deficient condition associated with the Unit 1 B inboard main steam isolation valve (MSIV) direct current (DC) solenoid valve as an actual valve issue, vice indication-only, through the use of specific acceptance criteria as required by MT-AD-509, Control of Minor Maintenance Activities. By incorrectly concluding the issue was indication only, testing was allowed to be performed which inserted a half-isolation by de-energizing the alternating current (AC) solenoid valve on the B inboard MSIV. When this maintenance was performed, the B inboard MSIV closed unexpectedly, resulting in a reactor scram. The cause of the closure was the failure of the DC solenoid valve on the B inboard MSIV. Susquehanna entered the issue into the CAP as CR-2015-30721 and replaced the DC solenoid for the B MSIV. The finding is more than minor because it is associated with the equipment performance attribute of the Initiating Events cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during power operations. Specifically, the maintenance activity performed to validate the DC solenoid valve continuity was inadequate and as a result the testing was allowed to be performed which relied on DC solenoid valve continuity to prevent an MSIV closure. The inadvertent closure of the B inboard MSIV resulted in a high pressure scram. The inspectors evaluated the finding in accordance with IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 1, for the Initiating Events cornerstone. The inspectors determined the finding was of very low safety significance (Green) because it did not cause the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. Specifically, the condenser was maintained for decay heat removal via the bypass valves through the other three main steam lines following the trip. This finding had a cross-cutting aspect in the area of Human Performance, Challenge the Unknown, because Susquehanna did not stop when faced uncertain conditions and instead rationalized unanticipated test results. Specifically, the investigation of the extinguished continuity monitor focused on the possibility that it was an indication-only issue and failed to question the acceptability of the current values obtained during troubleshooting (H.11).
05000457/FIN-2015004-02Braidwood2015Q4Failure of Startup Feedwater Pump to Start During Plant ShutdownThe inspectors identified an URI based upon the startup feedwater pumps (SUFWPs) failure to start during a plant shutdown. In addition to being used in plant startups and shutdowns, the SUFWP is also credited in the licensees emergency operating procedure as a means to add water to the steam generators for decay heat removal if the safety-related auxiliary feedwater systems failed to function properly during an event. On October 4, 2015, operations attempted to start the Unit 2 SUFWP at low power in Mode 1 during plant shutdown activities for a refueling outage. Upon start, the SUFWP automatically tripped. The licensee completed an apparent cause evaluation to determine the reason why the pump did not start and run. At the end of the inspection period, the inspectors were awaiting additional information to complete their review to determine if this issue of concern constituted a performance deficiency. This URI will remain open pending this review.
05000483/FIN-2015003-02Callaway2015Q3Failure to Follow Operability Determination ProcedureThe inspectors identified a non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensees failure to follow their operability determination procedure. Specifically, when an auxiliary feedwater control valve failed to operate from the main control room, the licensee failed to evaluate the operability of the component in accordance with Procedure ODP-ZZ-00001, Addendum 15, Operability and Functionality Determinations. The immediate corrective action taken by the licensee was to evaluate the operability of the flow control valve. After determining that the equipment was inoperable, the licensee entered the required technical specification condition and performed the required technical specification actions. The licensee entered this issue into their corrective action program as Callaway Action Request 201502708. This performance deficiency is more than minor and, therefore, a finding, because, if left uncorrected, it has the potential to lead to a more significant safety concern if safety-related systems are not properly evaluated for operability. The finding affects the Mitigating System Cornerstone because the performance deficiency is related to the auxiliary feedwater systems ability to conduct short-term decay heat removal. Using Inspection Manual Chapter 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, the finding was determined to be of very low safety significance because it did not affect system design, did not result in a loss of system function, did not represent a loss of function of a single train for greater than its technical specifications allowed outage time, and did not cause the loss of function of one or more non-technical specification trains of equipment designated as high safety-significance. This finding has a cross-cutting aspect of challenge the unknown in the human performance cross-cutting area because the licensee did not stop when faced with uncertain conditions. Specifically, rather than declaring the system inoperable and allowing the process to evaluate the condition, the licensee declared the system operable without fully understanding the failure mechanism (H.11).
05000266/FIN-2015003-02Point Beach2015Q3Potential Failure of Multiple Safety-Related Trains During Flooding EventsThe inspectors identified a finding of very low safety significance and associated NCV of 10 CFR Part 50, Appendix B, Criterion III, "Design Control," for the licensees failure to ensure that a non-Category I (seismic) component failure, that results in flooding, would not adversely affect safety-related equipment needed to get the plant to safe shutdown (SSD) or to limit the consequences of an accident. Specifically, the design of Point Beach did not ensure that the Residual Heat Removal (RHR) pumps would be protected from all credible non-Category I (seismic) system failures. The licensees corrective actions included an extensive internal flooding design review, which will result in an updated Final Safety Analysis Report (FSAR) with a more detailed description of the stations flooding licensing basis; modifications to multiple flood barriers to bring them into compliance with the licensees flooding licensing basis; installation of additional flood level alarms where necessary, and evaluation or modification of service water (SW) piping to properly qualify it as seismic. The inspectors determined that the finding was more than minor because it was associated with the Design Control attribute of the Mitigating System cornerstone and affected the cornerstone objective of ensuring the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the inadequate design resulted in an unanalyzed condition and loss of safety function of the RHR system while the plants were in Modes 4, 5, and 6, when relying on the RHR system for decay heat removal. The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, dated June 19, 2012, and Appendix A, The Significance Determination Process for Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, dated June 19, 2012. The inspectors answered yes to question 2 of the screening questions because the finding represented a loss of safety function. Thus the inspectors consulted the Region III Senior Risk Analysts (SRAs) who performed a detailed risk evaluation and determined that the finding was of very low safety significance (Green). The inspectors determined that the associated finding did not have a cross-cutting aspect because the finding was not reflective of current performance.
05000458/FIN-2015002-01River Bend2015Q2Inadequate Operating Margin for Reactor Protection System A Motor Generator Set for Overvoltage Protection Results in Loss of Shutdown CoolingThe inspectors reviewed a finding for the licensees failure to raise the overvoltage setpoint on the reactor protection system A motor generator set when the output of the generator was raised. This resulted in a reduction of the operating margin between the overvoltage trip setpoint and normal operating voltage. As a result, a spike in the output of the A motor generator on February 24, 2015, exceeded the overvoltage trip setpoint and caused the reactor protection system motor generator set output breaker to open which resulted in a loss of shutdown cooling while the reactor was shut down for refueling operations. With spent fuel in the reactor vessel, reactor coolant temperature increased 6.4 degrees until reactor protection system A was re-energized and shutdown cooling was restored. The licensee entered this issue into their corrective action program as Condition Report CR-RBS-2015-01216. The performance deficiency is more than minor, and therefore a finding, because it is associated with the Initiating Events Cornerstone attribute of configuration control, and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the tripping of the reactor protection system A motor generator set output breaker, resulted in a loss of power to the reactor protection system. This subsequently caused a loss of shutdown cooling and decay heat removal while the plant was shut down for a refueling outage. The inspectors initially screened the finding in accordance with Inspection Manual Chapter 0609, Appendix G, Shutdown Operations Significance Determination Process. The inspectors used NRC Inspection Manual 0609, Appendix G, Shutdown Operations Significance Determination Process, dated May 5, 2014, to evaluate the significance of the finding. The finding did not require a quantitative assessment because adequate mitigating equipment remained available and the finding did not constitute a loss of control, as defined in Appendix G. Therefore, the finding screened as Green. A cross-cutting aspect to this finding is not being assigned as this performance deficiency occurred in 1988 and therefore is not indicative of current licensee performance.
05000293/FIN-2015002-01Pilgrim2015Q2Ineffective Corrective Actions leads to Loss of Decay Heat RemovalGreen. A self-revealing Green finding was identified when residual heat removal (RHR) pump B experienced cavitation during refueling and maintenance outage (RFO) 20 that was a result of inadequate corrective actions associated with equipment used to determine flow rate. Specifically, prior to placing augmented fuel pool cooling (AFPC) mode in service on April 26, 2015, Entergy did not ensure that the temporary flow transmitter was properly setup and calibrated because corrective actions from 2011 were not adequate to ensure proper setup in the future. As a result, when operators went to raise flow in accordance with their procedural requirement, RHR pump B experienced cavitation and operators secured the pump because the flow transmitter was inaccurately reading low. Entergys immediate corrective actions included entering the issue into the corrective action program (CAP) as condition report (CR)-2015-3724, re-calibrating and setting up the ultrasonic flow meter, and establishing a second ultrasonic flow meter to ensure proper flow. Inspectors performed a walkdown to ensure proper operation of the ultrasonic flow meters, and confirmed similar readings between the two flow meters on April 27, 2015. The finding is more than minor because it 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 and challenge critical safety functions during shutdown as well as power operations. Specifically, the B RHR pump was secured from AFPC mode 2 on April 26, 2015 when the installed ultrasonic flow meter did not read properly, leading to operation of the B RHR pump outside of flow limits specified in procedure 2.2.85.2 and cavitation of the pump. This finding was evaluated in accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 2, Section C.6 of IMC 0609, Appendix G, Attachment 1, Shutdown Operations Significance Determination Process Phase 1 Initial Screening and Characterization of Findings, the inspectors determined that this finding is of very low safety significance (Green) because while the performance deficiency resulted in the B RHR pump being secured due to cavitation, it did occur when the refuel canal/cavity was flooded and did not increase the likelihood of a fire or internal/external flood that could cause an shutdown initiating event. This finding has a cross-cutting aspect in the area of Problem Identification and Resolution, Evaluation, because Entergy staff did not thoroughly evaluate the issues associated with the ultrasonic flow meter in 2011 and 2013 to ensure that resolutions address causes and extent of conditions commensurate with their safety significance. Specifically, Entergys corrective action process did not thoroughly evaluate and develop appropriate corrective actions for CR-2011-1847 and CR-2013-2857 to ensure the cause was addressed to prevent challenges using ultrasonic flow meters during AFPC for both mode one and mode two.
05000397/FIN-2015002-01Columbia2015Q2Failure to Follow Procedures Associated with Operation of the Fuel Pool Cooling SystemThe inspectors reviewed a self-revealing non-cited violation of Technical Specification 5.4.1.a, Procedures, for the licensees failure to follow procedures associated with operation of the fuel pool cooling system. Specifically, on May 12, 2015, the licensee failed to follow operating procedures for the fuel pool cooling system resulting in a trip of the running fuel pool-cooling pump and subsequent lifting of a relief valve in the fuel pool cooling system. The standby fuel pool cooling pump automatically started to maintain fuel pool cooling. No significant change in refueling cavity level occurred since the plant was in the refueling mode of operation with the refueling cavity flooded approximately 23 feet above the reactor vessel flange. The licensee initiated Action Request 327593 to document the transient on the fuel pool cooling system and took immediate corrective action to disqualify the reactor operator pending remediation to address the human performance error. The performance deficiency was more than minor, and therefore a finding, because it adversely affected the configuration control attribute of the Barrier Integrity Cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Using NRC Inspection Manual Chapter 0609, Appendix A, Exhibit 3, Barrier Integrity Screening Questions, the inspectors determined the finding was of very low safety significance because (1) it did not adversely affect decay heat removal capabilities from the spent fuel pool causing the pool temperature to exceed the maximum analyzed temperature limit specified in the site-specific licensing basis, (2) it did not result from fuel handling errors, dropped fuel assembly, dropped storage cask, or crane operations over the spent fuel pool, (3) it did not result in a loss of spent fuel pool water inventory decreasing below the minimum analyzed level limit specified in the sitespecific licensing basis, and (4) it did not involve spent fuel pool neutron absorber or a fuel bundle misplacement. This finding had a cross-cutting aspect in the area of human performance, avoid complacency, in that the reactor operator failed to consider potential undesired consequences of his actions before performing work and failed to implement appropriate error-reduction tools such as self and peer checking (H.12)
05000285/FIN-2015002-05Fort Calhoun2015Q2Failure to Promptly Identify and Correct a Condition Adverse to Quality Involving a Spent Fuel Pool Cooling Vent Valve LeakThe inspectors identified a non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Actions, for the failure to promptly identify and correct a condition adverse to quality. Specifically, the licensee failed to take corrective action to replace spent fuel pool cooling system discharge header vent valve AC-898 after a leak was identified. A work order for the condition was opened in 2009 but was never implemented. Subsequently, a pressure boundary leak was identified in 2013 and misidentified in 2014 but was never addressed. The licensee replaced vent valve AC-898 and repaired the affected weld in April 2015. This issue was entered into the licensees corrective action program as Condition Report 2015-05038. The failure to promptly identify and correct a condition adverse to quality was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it adversely affected the design control attribute of the Barrier Integrity Cornerstone and affected the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. In accordance with Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 3, Barrier Integrity Screening Questions, the issue screened as having very low safety significance (Green) because the finding did not adversely affect decay heat removal capabilities from the spent fuel pool causing the pool temperature to exceed the maximum analyzed temperature limit specified in the site-specific licensing basis, did not result from fuel handling errors, dropped fuel assembly, dropped storage cask, or crane operations over the SFP that caused mechanical damage to fuel clad and a detectible release of radionuclides, did not result in a loss of spent fuel pool water inventory decreasing below the minimum analyzed level limit specified in the site-specific licensing basis, and did not affect the SFP neutron absorber, fuel bundle misplacement or soluble boron concentration. The inspectors determined that the finding had a basis for decision cross-cutting aspect in the area of human performance because leaders failed to ensure that the bases for operational and organizational decisions were communicated during multiple instances where the leak in valve AC-898 could have been repaired. (H.10)
05000285/FIN-2015002-07Fort Calhoun2015Q2Failure to Perform Functionality Assessments for the Spent Fuel Pool Cooling SystemThe inspectors identified a finding associated with the failure of operations personnel to follow procedures used to perform functionality assessments. Specifically, operations personnel failed to provide sufficient technical justification for the reasonable assurance of functionality of the spent fuel pool cooling system when boric acid leaks were identified on discharge header vent valve AC-898. Vent valve AC-898 was replaced and the issue was entered into the licensees corrective action program as Condition Report 2015-05856. The failure of operations personnel to follow station procedures to perform functionality assessments was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it adversely affected the design control attribute of the Barrier Integrity Cornerstone and affected the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. In accordance with Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 3, Barrier Integrity Screening Questions, the issue screened as having very low safety significance (Green) because the finding did not adversely affect decay heat removal capabilities from the spent fuel pool causing the pool temperature to exceed the maximum analyzed temperature limit specified in the site-specific licensing basis, did not result from fuel handling errors, dropped fuel assembly, dropped storage cask, or crane operations over the SFP that caused mechanical damage to fuel clad and a detectible release of radionuclides, did not result in a loss of spent fuel pool water inventory decreasing below the minimum analyzed level limit specified in the site-specific licensing basis, and did not affect the SFP neutron absorber, fuel bundle misplacement or soluble boron concentration. The inspectors determined that the finding had a training cross-cutting aspect in the area of human performance because the licensee did not provide training and ensure knowledge transfer to maintain a knowledgeable, technically competent workforce and instill nuclear safety values. (H.9)
05000275/FIN-2015002-06Diablo Canyon2015Q2High Voltage Insulator Flashover Resulted in Loss of 230 kV Offsite Power and Start of Emergency Diesel GeneratorsThe inspectors reviewed a self-revealing, Green finding for the licensees failure to adequately implement procedure OM7.ID1, Problem Identification and Resolution, to prevent a high voltage insulator flashover event in the 230 kV switchyard that occurred on October 31, 2014. Specifically, corrective actions from three previous root cause evaluations were not effective to prevent a loss of the 230 kV start-up power and subsequent auto start of all of the safety standby emergency diesel generators (EDGs). This issue was entered into the licensees corrective action program as Notification 50699230. The licensees failure to adequately implement procedure OM7.ID1, Problem Identification and Resolution was a performance deficiency. The performance deficiency was more than minor because it was associated with the human performance attribute 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. Specifically, this failure resulted in another high-voltage insulator flashover, which resulted in loss of 230 kV offsite startup power and activation of all safety-related EDGs, on October 31, 2014. In accordance with IMC 0609.04, Initial Characterization of Findings, the inspectors determined that the impact of the finding on Unit 1 should be evaluated using Exhibit 1 of IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings at Power, and further determined that this finding required a detailed risk evaluation by the regional senior risk analyst because the finding involved a partial loss of offsite power, a support system that contributes to the likelihood of an initiating event and affected mitigation equipment. The risk analyst determined that, with the 230 kV system de-energized, any plant transient would result in a plant-centered loss of offsite power. Therefore, the risk analyst calculated the incremental conditional core damage probability for an exposure period of 9 hours to be 2.09 x 10-7, which is lower than the 1 x 10-6 threshold in the significance determination process; this finding is of very low safety significance (Green) for Unit 1. In accordance with IMC 0609.04, Initial Characterization of Findings, the inspectors determined that the impact of the finding on Unit 2 should be evaluated using IMC 0609, Appendix G, Shutdown Operations Significance Determination Process, because the finding pertained to operations, an event, or a degraded condition while the plant was shut down. Unit 2 was shutdown in a refueling outage when the event occurred on October 31, 2014. Because of the shutdown configuration of Unit 2, the loss of 230 kV support system did not impact the ability to continue to provide decay heat removal for the unit. Therefore, the analyst determined qualitatively that this finding is also of very low safety significance (Green) for Unit 2. This finding has a cross-cutting aspect of work management, in the area of human performance, for failing to implement a process of planning, controlling, and executing work activities such that nuclear safety is an overriding priority. Specifically the licensee failed to effectively plan and coordinate preventative maintenance strategies associated with root causes from previous high-voltage insulators flashover or failures since 2008 to prevent the loss of offsite 230 kV and the transient on October 31, 2014 (H.5).
05000285/FIN-2015002-02Fort Calhoun2015Q2Failure to Perform a Valid 40-Month Inservice TestThe inspectors identified a non-cited violation of 10 CFR 50.55a(g)(4) for the failure to perform a valid 40-month inservice test of the spent fuel pool cooling system. Specifically, the licensee failed to identify an existing through-wall leak on discharge header vent valve AC-898 that invalidated the test. The licensee replaced vent valve AC-898 and repaired the affected weld in April 2015. This issue was entered into the licensees corrective action program as Condition Report 2015-05038. The failure to perform a valid 40-month inservice test of the spent fuel pool cooling system was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it adversely affected the design control attribute of the Barrier Integrity Cornerstone and affected the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. In accordance with Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 3, Barrier Integrity Screening Questions, the issue screened as having very low safety significance (Green) because the finding did not adversely affect decay heat removal capabilities from the spent fuel pool causing the pool temperature to exceed the maximum analyzed temperature limit specified in the site-specific licensing basis, did not result from fuel handling errors, dropped fuel assembly, dropped storage cask, or crane operations over the SFP that caused mechanical damage to fuel clad and a detectible release of radionuclides, did not result in a loss of spent fuel pool water inventory decreasing below the minimum analyzed level limit specified in the site-specific licensing basis, and did not affect the SFP neutron absorber, fuel bundle misplacement or soluble boron concentration. The inspectors determined that the finding had a conservative bias cross-cutting aspect in the area of human performance because individuals failed to use decision making-practices that emphasized prudent choices over those that are simply allowable. Although the licensee had previously identified the leak in valve AC-898 and determined that the leak had compromised the structural integrity of the system, the licensee failed to fix the leak. (H.14)
05000263/FIN-2015002-02Monticello2015Q2Failure to Measure Interpass TemperatureThe inspectors identified a Green NCV of Title 10 CFR Part 50, Appendix B, Criterion IX, Control of Special Processes, for a failure to measure the interpass temperature while performing welding on diesel generator fuel oil modification supports. Consequently, welding was performed without the Code and Procedure required interpass temperature being Monitored on a number of welds, a parameter which can affect the mechanical properties of the material being welded. To restore compliance, the welder proceeded to measure the interpass temperatures on the balance of the welds and verified that the interpass temperature did not exceed that allowed by procedure. The licensee entered this issue into its CAP (CAP 1475767). The inspectors determined that this issue was more than minor in accordance with IMC 0612, Appendix B, Issue Screening, dated September 7, 2012, because the inspectors answered yes to the more than minor question, If left uncorrected, would the performance deficiency have the potential to lead to a more significant safety concern? Specifically, absent NRC intervention, the welder would have completed all of the welds without having measured the interpass temperature, a welding parameter which can affect the mechanical properties (e.g., impact properties) of some materials being welded, and if left uncorrected could lead to a potential failure of the weld in service. In accordance with Table 2, Cornerstones Affected by Degraded Condition or Programmatic Weakness, of IMC 0609, Attachment 4, Initial Characterization of Findings, issued June 19, 2012, the inspectors checked the box under the Mitigating Systems Cornerstone because leakage on the Emergency Diesel Generator (EDG) fuel oil system could cause core decay heat removal to be degraded. The inspectors determined this finding was of very-low safety significance (Green) based on answering yes to the question in Part A of Exhibit 2, Mitigating Systems Sc reening Questions, in IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, issued on June 19, 2012. Specifically, the inspectors answered yes to the screening question If the finding is a deficiency affecting the design or qualification of a mitigating Structure, System, or Component (SSC), does the SSC maintain its operability or functionality? The welder proceeded to measure the interpass temperatures on the balance of the welds and verified that the interpass temperature did not exceed that allowed by procedure, and the issue did not result in the actual loss of the operability or functionality of a safety system. The inspectors determined that the primary cause of the failure to monitor the interpass temperature procedure was related to the cross-cutting component of Problem Identification and Resolution, Operating Experience (P.5). Specifically, the organization failed to effectively implement external operating experience in a timely manner.
05000354/FIN-2015008-01Hope Creek2015Q1Inadequate Preventive Maintenance for Safety-Related Optical Isolators in the Residual Heat Removal SystemThe inspectors identified a Green NCV of TS 6.8.1.a, Procedures and Programs, regarding PSEGs failure to adequately establish, implement, and justify a replacement frequency for the Residual Heat Removal (RHR) system optical isolators AT14 and AT18. These optical isolators were the most likely cause of an October 2013 RHR pump trip that resulted in a loss of shutdown cooling (SDC) during Hope Creeks R18 refueling outage. PSEG determined that the optical isolators did not have an established replacement frequency, and they had been installed since original plant construction. PSEG replaced the optical isolators and established a replacement preventive maintenance (PM) task going forward. The inspectors determined that PSEG had previous opportunity to identify the deficient PM strategy and replace the optical isolators prior to the October 2013 loss of SDC. In response to this finding, PSEG plans to conduct a causal evaluation and document the basis for their new PM frequency. This issue is more than minor because it was associated with the equipment performance attribute of the initiating events cornerstone, and adversely affected the cornerstone objective of limiting the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the RHR optical isolators were determined to be the most likely cause of the B RHR pump trip and associated loss of SDC on October 17, 2013. The inspectors, with the assistance of a Region I Senior Reactor Analyst (SRA), used IMC 0609, Appendix G, Shutdown Operations Significance Determination Process, to evaluate the safety significance of this issue. Based upon Appendix G, Attachment 1, Exhibit 2, this issue required a Phase 2 analysis, because the performance deficiency resulted in an actual loss of decay heat removal event. Using Attachment 3, Phase 2 Significance Determination Process Template for BWRs During Shutdown, Worksheet 5, the SRA determined this issue was of very low safety significance (Green). The inspectors determined that the finding has a cross-cutting aspect in the area of Problem Identification and Resolution, Evaluation, which states that licensees thoroughly evaluate issues to ensure that resolutions address causes and extent of conditions commensurate with their safety significance. In this case, when the PCM template process was initially implemented in 2008, PSEG failed to evaluate AT14 and AT18 against the applicable PCM template (Signal Conditioner Electronic) and generate replacement PMs. Although this performance deficiency dates back to 2008, the inspectors determined the issue is reflective of current licensee performance, because PSEGs root cause evaluation (RCE) and the associated PM change request (PCR), conducted in 2013, constituted a second missed opportunity for PSEG to evaluate the applicable PCM template against the PM strategy for AT14 and AT18.
05000410/FIN-2014005-03Nine Mile Point2014Q4Missed Surveillance Test of Alternate Decay Heat Removal Secondary Containment Isolation ValvesThe inspectors identified a Green NCV of Unit 2 Technical Specification (TS) 5.4, Procedures, for Exelons failure to properly perform procedure N2-OSP-GTS-R001, Secondary Containment Integrity Test, Revision 01100. Specifically, Exelon staff failed to ensure spectacle flanges associated with alternate decay heat (ADH) secondary containment isolation were properly installed. As a result, surveillance testing associated with ADH check valves 2ADH*V21A/B and 2ADH*V22A/B was not performed to ensure secondary containment integrity as required by N2-OSP-GTS-R001. Exelon immediately entered this issue into their CAP as issue report (IR) 2403311. Exelon entered TS Surveillance Requirement (SR) 3.0.3, Limiting Condition for Operability Applicability, which is used when a licensee discovers that a surveillance test requirement has not been performed. As required by the TS, Exelon completed a risk evaluation of the missed surveillance and determined large early release frequency remained low without ADH secondary containment isolation. Exelon also performed extent-of-condition inspections for other systems which may not have proper alignment to ensure they are meeting TS requirements. On December 4, Exelon rotated the spectacle flanges to the no flow isolation position to ensure secondary containment integrity was maintained The finding is more than minor because it is associated with the configuration control attribute of the Barrier Integrity cornerstone objective to provide reasonable assurance tha physical design barriers protect the public from radionuclide releases caused by accident or events. Specifically, by performing N2-OSP-GTS-R001 in 2012 and 2014 without first ensuring the spectacle flanges were properly installed, Exelon did not verify the secondar containment requirements of TS SR 3.4.6.1 were maintained. Additionally, this issue wa similar to Example 3.d in IMC 0612, Appendix E, Examples of Minor Issues, in that th failure to implement the TS SR as required was not minor if the surveillance had not bee conducted. By not correctly testing the secondary containment in 2012 and 2014, the SR o TS 3.4.6.1 was not met. In accordance with IMC 0609.04, Initial Characterization o Findings, and Exhibit 3 of IMC 0609, Appendix A, The Significance Determination Proces for Findings At-Power, the inspectors determined this finding is of very low safet significance (Green) because the finding only represents a degradation of the radiologica barrier function provided for the control room, or auxiliary, spent fuel pool (SFP), or standb gas treatment system (boiling water reactor). This finding has a cross-cutting aspect in th area of Human Performance, Avoid Complacency, because Exelon staff did not implemen appropriate error reduction tools. Specifically, operators did not use error reduction tools t ensure the spectacle flanges were installed in the no flow position and as a result, the failed to leak test the ADH check valves in the secondary containment drawdown test a required by N2-OSP-GTS-R001 (H.12).
05000454/FIN-2014005-02Byron2014Q4Liquid Penetrant Testing Procedure Did Not Meet ASME CodeThe inspectors identified a finding of very low safety significance and an associated NCV of 10 CFR Part 50, Appendix B, Criterion IX, Control of Special Processes, for the failure to perform a Liquid Penetrant Test (PT) in accordance with the American Society for Mechanical Engineers (ASME) Code while performing a surface examination on reactor coolant pump (RCP) flywheel 2A/D483. The vendor conducted a demonstration in an attempt to show the differences in bleed-out between the two dwell times, to demonstrate continued functionality of the flywheel. The results showed little if any difference in the growth of the bleed-out given the additional time. The licensee was developing an action plan to address the non-conformance and restore compliance. The issue was entered into the licensees CAP as IR 02393595 and IR 02399248. The inspectors determined that this issue was more than minor in accordance with IMC 0612, Appendix B, Issue Screening, dated September 7, 2012, because the inspectors answered "Yes" to the More-than-Minor question, If left uncorrected, would the performance deficiency have the potential to lead to a more significant safety concern? Specifically, since the liquid penetrant testing developer minimum dwell time may not have been met, the liquid penetrant examination was not assured to accurately measure a rejectable flaw. Absent NRC intervention, the potential would exist for a rejectable flaw to remain in service, affecting the operability of affected systems. In accordance with Table 2, Cornerstones Affected by Degraded Condition or Programmatic Weakness, of IMC 609, Attachment 4, Initial Characterization of Findings, issued June 19, 2012, the inspectors checked the box under the Mitigating Systems Cornerstone because failure of the RCP flywheel could degrade core decay heat removal. The inspectors determined this finding was of very-low safety significance (Green) using Part A of Exhibit 2, Mitigating Systems Screening Questions, in IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, issued on June 19, 2012. Specifically, the issue did not result in the actual loss of the operability or functionality of a safety system; and therefore the inspectors answered "Yes" to the screening question If the finding is a deficiency affecting the design or qualification of a mitigating SSC, does the SSC maintain its operability or functionality? The vendor subsequently performed demonstrations to show that the bleed-out from an indication would not change appreciably when implementing the additional dwell time. The licensee was still evaluating its planned corrective actions. However, the inspectors determined that the continued non-compliance did not present an immediate safety concern because the licensee/vendor reasonably determined the RCP flywheel remained functional. The finding had a cross-cutting aspect of Change Management in the area of Human Performance (IMC 0310 H.3) in that leaders failed to use a systematic process for evaluating and implementing change so that nuclear safety remains an overriding priority. Specifically, the licensee failed to ensure that the vendor changed its procedure to reflect the requirements of the current edition of the ASME Code adopted by the licensee.
05000528/FIN-2014005-03Palo Verde2014Q4Licensee-Identified ViolationTitle 10 CFR 50.59(d)(1) requires, in part, that the licensee shall maintain records of changes in the facility, of changes in procedures, and of tests and experiments made pursuant to paragraph (c) of this section. These records must include a written evaluation which provides the bases for the determination that the change, test, or experiment does not require a license amendment pursuant to paragraph (c)(2) of this section. Contrary to the above, prior to August 28, 2014, the licensee failed to perform an evaluation against the criteria in 10 CFR 50.59(c)(2) for a change to the facility. Specifically, the licensee identified that Licensing Document Change Request 04-F020, performed on March 4, 2005, had changed the FSAR description of the auxiliary feedwater system. The new revision stated that portions of the auxiliary feedwater system, which are not contained within a Seismic Category I structure or installed underground, have been analyzed to show that the probability of being struck by a tornado missile is sufficiently low and do not require tornado missile protection. Previously, the FSAR described that all components of the auxiliary feedwater system were either enclosed by a Seismic Category I structure or are installed underground. This change had been inappropriately screened out of the 50.59 process in 2005. The licensees 50.59 screening did not recognize that this change to the FSAR description constituted a de facto change to the design of the facility. Consequently, the licensee failed to perform an evaluation against the criteria in 10 CFR 50.59(c)(2). On August 28, 2014, the licensee recognized the auxiliary feedwater recirculation lines do not meet the original FSAR criteria of being protected from tornado missiles. The licensee initiated PVAR 4568732 to document the lack of tornado missile protection for the auxiliary feedwater minimum flow recirculation lines. The licensee performed an immediate operability determination on August 29, 2014 and determined that there was a reasonable expectation that the auxiliary feedwater system would provide adequate decay heat removal following a tornado. The inspectors reviewed the licensees operability determination and verified that the licensee intends to submit a license amendment request for acceptance of the as-built configuration of the auxiliary feedwater system. Because the failure to implement the requirements of 10 CFR 50.59 had the potential to impact the NRCs ability to perform its regulatory function, the team evaluated the performance deficiency using traditional enforcement. In accordance with Section 2.1.3.E.6 of the NRC Enforcement Manual, the inspectors evaluated this finding using the significance determination process to assess its significance. The finding required a detailed risk evaluation because it involved the failure of two or more trains in a multi-train system. A Region IV senior reactor analyst performed a bounding detailed risk evaluation and determined that the bounding delta-CDF was less than 3.5E-8/year. In accordance with Section 6.1.d of the NRC Enforcement Policy, this violation is categorized as Severity Level IV violation because the resulting change was evaluated by the SDP as having very low safety significance (i.e., Green finding). This issue has been entered into the licensees corrective action program as CRDR 4570021.
05000313/FIN-2014004-01Arkansas Nuclear2014Q3Improper Maintenance on Circuit Breaker Caused Loss of Unit 1 Decay Heat Removal PumpInspectors documented a Green self-revealing non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensees failure to ensure activities affecting quality were accomplished in accordance with documented instructions. Specifically, the licensee failed to follow Job Order JO-00968863 for replacement of a prop spring in circuit breaker MA137. As a result, the wrong prop spring was replaced, reducing the reliability of the Unit 1 train B decay heat removal pump P-34B and ultimately causing a failure of the pump to start. The licensee corrected the condition by replacing the breaker and returning the pump to service. The issue was documented in Condition Report CR-ANO-1-2013-00701. The inspectors determined that the failure to follow Job Order JO-00968863 in 1998 for replacement of a prop spring in circuit breaker MA137 was a performance deficiency. The performance deficiency was more than minor because it was associated with the human performance attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences, and was therefore a finding. Specifically, the failure to replace the appropriate prop spring in 1998 adversely affected the availability and reliability of Unit 1 decay heat removal pump P-34B and caused a failure to start in 2013. In accordance with Inspection Manual Chapter 0609, Attachment 4, Initial Characterization of Findings, and Appendix G, Attachment 1, Shutdown Operations Significance Determination Process Phase 1 Initial Screening and Characterization of Findings, Exhibit 3, Mitigating Systems Screening Questions, the inspectors determined the finding to be of very low safety significance (Green) because the finding did not represent a loss of system safety function and did not represent an actual loss of safety function of at least one train for greater than its technical specification allowed outage time. The inspectors determined that there was no cross-cutting aspect associated with this finding because the cause of the performance deficiency occurred more than three years ago, and was not representative of current licensee performance.
05000424/FIN-2014004-06Vogtle2014Q3Licensee-Identified ViolationTechnical Specification LCO 3.0.2 requires that Upon discovery of a failure to meet an LCO, the Required Actions of the associated Conditions shall be met, except as provided in LCO 3.0.5 and LCO 3.0.6. Technical Specification LCO 3.3.3 requires that two channels of containment sump water level wide range PAM instrumentation be operable. Contrary to the above, during a channel check on June 26, 2014, at approximately 07:30 a.m., the Unit 1 shift supervisor failed to enter the required action statement for TS LCO 3.3.3, Condition B when one Unit 1 containment sump water level wide range channel was noted to be failed high. Inoperability of the transmitter was not recognized until July 9, 2014 during a control board walk down, and the LCO was entered at 5:00 p.m. Upon investigation, it was determined that the channel was indicating incorrectly on June 23, 2014, prior to the channel check. The licensee documented this event in their corrective actions program as CRs 837302 and 837838. Using IMC 0609 Phase 1 Initial Screening and Characterization of Findings, the finding was determined to affect the mitigation systems cornerstone because of the effect on long term core decay heat removal in the event of a LOCA. Because this was a single failure that did not represent an actual loss of safety system or function, the operability of the additional channel, among other indications, would have been sufficient to inform operators of an accident condition, and the inspectors determined this to be a Green finding of very low safety significance.
05000458/FIN-2014007-05River Bend2014Q3Failure to Promptly Correct Adverse Conditions Associated with Non-cited Violation 05000458/2011008-06The inspectors identified a Green, non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, which states, Measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and nonconformances are promptly identified and corrected. Specifically, the licensee failed to promptly correct a condition adverse quality by implementing compensatory measures to restore compliance with the standby service water system 30-day mission requirements pending NRC approval of a license amendment. On July 8, 2014, the licensee implemented compensatory measures to restore compliance to ensure a 30-day inventory in the standby service water system. This issue was entered into the corrective action program as Condition Report CR-2014-3212. This performance deficiency was more than minor, and therefore a finding, because, if left uncorrected, it would lead to a more significant safety concern. Specifically, the licensee failed to implement compensatory measures to ensure the standby service water system would meet its 30-day mission requirement. In accordance with NRC Inspection Manual Chapter 0609, Attachment 4, Initial Screening and Characterization of Findings, the finding represented a loss of system safety function in that the ultimate heat sink could not meet its 30-day mission time to provide decay heat removal. Therefore, a detailed risk evaluation was necessary. An assessment was performed in accordance with Inspection Manual Chapter 0609, Appendix M, Significance Determination Process Using Qualitative Criteria. The finding was determined to be of very low safety significance (Green) because the frequency of events that would require long term use of the ultimate heat sink is very low and the difference in the failure probability to replenish the ultimate heat sink in 10 days versus 30 days is very small. This was because an early depletion of the inventory would be easily detected and would become a priority. At the time that replenishment would be needed, plant conditions should be stable and local transportation arteries should be restored. This finding has a cross-cutting aspect associated with evaluation in the area of problem identification and resolution because the licensee failed to thoroughly evaluate problems to ensure that resolutions address cause and extent of condition commensurate with their safety significance (P.2).
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