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05000354/FIN-2018003-05Hope Creek2018Q3Minor ViolationDuring the review of LER 05000354/2018-003-00 and -01, Feedwater Isolation Valve Leakage Exceeded Technical Specification Limit, the inspectors identified a condition prohibited by TS. Specifically, TS 3.6.1.2.d requires that Primary Containment Leakage rates shall be limited to a combined leakage rate of less than or equal to 10 gpm for all containment isolation valves which form the boundary for the long-term seal of the feedwater lines, when tested at 1.10 Pa (1.1 times the calculated peak containment internal pressure related to the design basis accident) or 55.7 psig. TS surveillance requirement (SR) 4.6.1.2.g states that these valves be tested at least once per 18 months. Contrary to this requirement, on April 18, 2018, during the TS required SR for LLRT of the F032B, PSEG was unable to achieve the required test pressure and could not determine a leakage rate.Screening: The inspectors evaluated the issue above in accordance with the guidance in the NRCs Enforcement Policy, IMC 0612, Appendix B, Issue Screening, and Appendix E, Examples of Minor Issues, and determined the issue was a minor violation because, although PSEG did not successfully complete the TS required SR because they could not attain the required test pressure, there were no actual safety consequences. Specifically, PSEGs technical evaluation (70200206-0085) estimated the leak rate through the F032B to be approximately 3 gpm, and determined that the potential leakage through the F032B would not have posed a challenge to its ability to establish and maintain the required feedwater seal for 30 days post-LOCA. Enforcement: PSEG has taken actions to restore compliance by repairing and successfully testing the valve, and revising their LLRT procedures to: 1) update administrative limits and actions that are required when limits are exceeded; and, 2) include specify the exact size and length of tubing required for the testing. This inability to comply with TS 3.6.1.2.d constituted a minor violation that is not subject to enforcement action in accordance with the NRCs Enforcement Policy.
05000316/FIN-2018003-01Cook2018Q3Misaligned Heater Level Column Valves Leads to Manual Reactor TripA self-revealed, Green finding was identified when the operators manually tripped the Unit 2 reactor in response to a hi-hi level in the Left Moisture Separator Drain Tank. On May 6, 2018, the Unit 2 reactor was at approximately 12 percent power following a startup at the conclusion of the spring 2018 refueling outage. While the station continued to make preparations to start the main turbine and synchronize with the grid, the moisture separator drain tank hi level alarm was received and remained standing for the better part of the shift. The drain tank collects condensed steam and water from the moisture separator reheater and associated high pressure turbine exhaust lines and routes it either to the condenser or #4 feedwater heaters. The day shift operators were hesitant to continue on with starting the main turbine until the cause of the alarm could be determined. Due to a series of miscommunications between day shift, night shift, the outage control center, and personnel performing troubleshooting, the night shift crew believed it was acceptable to continue with the turbine startup with the alarm still standing. The turbine was synchronized to the grid and power was stabilized at approximately 29 percent power with the alarm in for most of the turbine startup and synchronization. The alarm cleared for a period of time at 29 percent power, but then returned along with the hi-hi drain tank level alarm. Per the alarm response procedures, the operators tripped the reactor and main turbine to protect the turbine from excessive water in the system. Later investigation by the site revealed that the level columns for the #4 feedwater heaters had been left isolated following work and testing associated with the replacement of the #5 feedwater heaters. While the Operations Department had completed a valve lineup on the system per their startup procedures, which put the level columns in service, the Projects Department had not finished all of the work on the heaters at the time the lineup was performed. As a result, workers subsequently isolated the columns to complete testing after the Operations lineup was complete. A step in the Projects test procedure EC51366TP001 directed workers to specifically inform the operators that the level columns were isolated following testing and that the system was ready to be lined up per operations procedures. However, the workers did not provide that detail, and simply stated that the test was complete. As a result, operations did not know the valves had been taken out of alignment. Contributing to the issue, the outage schedule did not provide any logic ties to ensure all work was complete on the heaters before allowing operations to do their valve lineups. With the level columns isolated during startup, the #4 heaters indicated an erroneous level. This resulted in the operators believing that the heaters were at a normal operating level when in fact, they were full. Therefore, when the operators (per procedure) opened a high pressure turbine exhaust valve to the 4A heater, this created a pathway for water to flow from the #4 heaters, through the high pressure turbine exhaust lines, and into the moisture separator drain tank. The excessive flow of water caused the hi and hi-hi alarms in the drain tank which then led to the reactor/turbine trip.
05000313/FIN-2018003-05Arkansas Nuclear2018Q3Failure to Maintain Main Feedwater Pump B Discharge Pressure in Band Caused a Reactor TripThe inspectors reviewed a self-revealed, Green finding and associated non-cited violation of Arkansas Nuclear One, Unit 1, Technical Specifications 5.4.1.a, for the licensees failure to implement Procedure OP-1102.002, Plant Startup, Revision 106. Specifically, control room operators failed to maintain main feedwater pump discharge pressure in the required band to control flow to the steam generators during a plant startup. As a result, the only operating main feedwater pump tripped on high discharge pressure, causing an automatic reactor trip.
05000354/FIN-2018003-02Hope Creek2018Q3Inadequate Procedures for Restoration of the A Reactor Feed Pump Turbine Following MaintenanceA self-revealing Green finding (FIN) was identified for PSEGs inadequate procedures that controlled the restoration of the A reactor feedwater pump turbine (RFPT) trip instrumentation following system maintenance. Specifically, the pumps axial position instrumentation was not re-zeroed following a rotor replacement. As a result, on May 21, 2018, the A RFPT tripped while HCGS was operating at approximately 97 percent rated thermal power (RTP), which led to an unplanned automatic recirculation runback to approximately 70 percent of RTP.
05000410/FIN-2018003-02Nine Mile Point2018Q3Minor ViolationDuring the review of Licensee Event Report (LER) 05000220/2017-002-01, Manual Reactor Scram Due to Presesure Oscillations, the inspectors identified a minor violation of 10 CFR 50.9, Completeness and accuracy of information. The LER was found to be inaccurate. Specifically, the LER timeline contained inaccurancies regarding the time operators entered a special operating procedure and did not include an actuation of high-pressure coolant injection (HPCI). The timeline stated at 2:10 AM operators entered the special operating procedure for Pressure Regulator Malfunction, due to reactor pressure oscillations of 2-3 psig. At 2:27 AM operators inserted a manual scram of the reactor due to pressure oscillations exceeding procedural limits. This information was confirmed by a review of the operational logs for March 20, 2017. During OI Investigation 1-2018-002, it was determined that this entry was not accurate and although an exact time could not be established is was estimated to have been at 2:20 AM vice 2:10 AM. Additionally the timeline did not include a mention that at 2:16 AM unexpected turbine trip signal was received and HPCI was initiated due to a tagging error. Operators reset HPCI at 2:18 AM and restored main feedwater flow to restore Reactor Vessel water level. A sixty day telephone notification instead of a written licensee event report was conducted for this invalid initiation of HPCI was completed on May, 11, 2017, as EN 52747 as allowed by 10 CFR 50.73(a)(2)(iv). Screening: Violations involving the submittal of inaccrurate or incomplete information are evaluated under Traditional Enforecement because they impact the NRCs regulatory process. Accordingly, the inspectors evlauted this issue against the example violations in Section 6.9 of the NRC Enforcement Policy. Inspectors concluded that the violation is of minor safety significance because the inaccurate information did not change the NRCs review of the licensee event report. Enforcement: 10 CFR 50.9 requires that information provided to the Commission by a licensee shall be complete and accurate in all material respects. Contrary to the above, on June 22, 2015, Entergy provided information to the Commission that was not complete and accurate in all material respects. In the licensee event report, Exelon documented incorrect information that resulted in the NRC launching a substation further inquiry (OI investigation), but did not substantiate that licensed operators deliberately failed to follow a Technical Specifications required procedure. Exelon identified the inaccuracy and entered the issue into the corrective action program (IR 04091110) on January 7, 2018, and submitted LER 05000220/2017-002-01 on August 18, 2018, revising the timeline to show operators entering N1-SOP-31.2 at 2:20 AM vice 2:10 AM. The disposition of this violation closed Licensee Event Report 05000220/2017-002-01
05000416/FIN-2018003-01Grand Gulf2018Q3Failure to Develop Adequate Work InstructionsA self-revealed, Green finding was identified when feedwater heater drain tank oscillations caused a feedwater perturbation which required a manual reactor scram. Specifically, the licensee failed to develop appropriate work instructions for filling and venting the feedwater heater 6A level transmitters.
05000313/FIN-2018011-02Arkansas Nuclear2018Q3Failure of Both Arkansas Nuclear One Units to Establish Adequate Corrective Actions Resulting in Excessive Instances of Damaged and Broken Internals of the Emergency Feedwater Pum o Turbine Steam Admission Check Valves.An NRC identified Green, non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Actions," was identified for failure to establish an adequate corrective action program and the resulting inability to correct a deficient system design which resulted in damaged and broken internals of the check valves admitting steam to the emergency feedwater turbine.
05000530/FIN-2018003-01Palo Verde2018Q3Failure to Maintain Command and Control During a Feedwater Control Valve MalfunctionWhile reviewing the licensee response to a Unit 3 feedwater pump trip, reactor cutback, reactor trip, and main steam isolation system actuation on June 27, 2018, the inspectors identified that the licensee did not meet the command and control standards outlined in station Procedure 40DP-9OP02 Conduct of Operations, Revision 72. Specifically, senior reactor operators in the control room did not effectively coordinate manual main feedwater output adjustments in the control room or operator actions in the field in response to an apparent valve failure with the activities of non-licensed operators locally evaluating the equipment condition in the field. These uncoordinated actions resulted in a significant plant transient
05000400/FIN-2018002-04Harris2018Q2Failure to Implement Adequate Steam Generator Blowdown Demineralizer Control ProceduresA self-revealing Green NCV of Technical Specifications (TS) 6.8.1.a, Procedures and Programs, was identified for licensees failure to establish and implement adequate steam generator blowdown demineralizer control operating procedures resulting in exceeding secondary water chemistry Action Level 3 criteria for impurities in the steam generators. Specifically, the licensee did not implement adequate isolation valve controls between the demineralizer resin regeneration system and the feedwater system during resin regeneration activities. This open path allowed leakage of sulfates and chlorides into the feedwater system. The level of these impurities exceeded the secondary chemistry Action Level 3 threshold and resulted in an unplanned shutdown.
05000315/FIN-2018002-05Cook2018Q2Minor ViolationWhile there did appear to be a reduction in operational errors being made in the field while manipulating equipment (such as during clearance activities and in performing certain evolutions) the inspectors noted a trend in configuration control issues. Most of these dealt with some kind of operation department interface or coordination with another department. In one case, valves associated with feedwater heater level control were left closed following a project to replace some of the heaters, which contributed to a manual reactor trip due to high moisture-separator drain tank level when starting the plant following the Unit 2 refueling outage. Other examples were Chemistry and Operations department coordination on an non-essential service water (NESW) valve alignment which led to NESW being isolated to generator seal oil cooling during plant startup, poor coordination between Maintenance and Operations which resulted in a containment penetration being left open, a pressure gauge remaining isolated after the Projects department completed the heater drain pump replacements, and the failure to ensure that valve-closure tests were done following the feedwater heater replacements. Another identified trend was in the area of post-maintenance testing (PMT). During the refueling outage on Unit 2, both the NRC and the licensee identified instances of improper PMTs being scheduled for safety-related equipment. Inspectors identified work on an EDG fuel oil transfer pump that did not have an in-service test (IST) scheduled. The licensee identified the lack of a time response test following a motor-driven AFW pump motor replacement, was a repeat issue from the previous outage. The licensee also identified the lack of an IST following a seal replacement on a CCW pump. In each case, the issues were discovered and corrected before equipment was restored to fully operable status. In response to the trend, the licensee reviewed other work on safety-related equipment for the outage to confirm the proper PMTs would be done. No other issues were identified. Finally, early in the observation period, the inspectors noted a trend in procedure quality for maintenance activities on safety-related equipment. There were instances regarding Turbine-Driven Auxiliary Feedwater (TDAFW) pump linkages where better procedure direction could have precluded binding and governor-valve travel issues. Additionally, while replacing a TDAFW governor, a snap ring was inadvertently left out of a coupling due to insufficient procedure detail. Regarding the EDGs, the licensee discovered instructions for assembly of air start check valves did not contain the torque guidance that the vendor drawings stipulated. In response to this trend, the licensee started to perform deliberate reviews of OE before maintenance on some safety-related equipment, to verify maintenance instructions had up-to-date guidance before starting work. No violations or findings were identified by the inspectors. 12 Licensee management acknowledged the issues discussed by the inspectors.
05000458/FIN-2018012-06River Bend2018Q2Failure to Provide Adequate Procedures for Post-Scram RecoveryThe inspectors reviewed a self-revealed, non-cited violation of Technical Specification 5.4.1.a for the licensees failure to establish, implement and maintain a procedure required by Regulatory Guide 1.33, Revision 2, Appendix A, dated February 1978. Specifically, Procedure OSP-0053, Emergency and Transient Response Support Procedure, Revision 22, which is required by Regulatory Guide 1.33, inappropriately directed operations personnel to establish feedwater flow to the reactor pressure vessel using the main feedwater regulating valve as part of the post-scram actions. This resulted in the main feedwater regulating valves being operated outside their design limits. This resulted in catastrophic failure of the main feedwater regulating valve variseals and subsequent damage to multiple fuel assemblies.
05000382/FIN-2018002-02Waterford2018Q210 CFR 50.59 Evaluation Associated with Emergency Feedwater Logic ModificationThe licensee changed the emergency feedwater logic, as described in the Updated Final Safety Analysis Report (UFSAR), Section 7.3.1.1.6, from flow control mode to level control mode during a safety injection actuation signal. To accomplish this change, the licensee had to modify the following logic system signals and setpoints: steam generator critical level, steam generator lo level, steam generator lo-lo level, safety injection actuation, control board manual control, and the steam generator lo-lo level annunciator. The NRC team questioned whether the emergency feedwater modification required additional information to determine if the 10 CFR 50.59 evaluation was adequate, or if NRC approval was needed for the change. Specifically, the NRC team questioned if the emergency feedwater logic change: used a method of evaluation other than what was described in the UFSAR (e.g. the use of the TRANFLOW program) or would result in a more than minimal increase in the likelihood of occurrence of a malfunction of a system important to safety. Specifically, because the emergency feedwater logic change introduced the potential to overcool the reactor, and substituted a previous automatic action for manual operator action, the NRC team questioned if the change and associated 50.59 evaluation addressed these concerns. Planned Closure Actions: The NRC and the licensee are working to gather more information related to the Final Safety Analysis Report-described methods for steam generator analyses and if the change resulted in a more-than-minimal increase in risk. Specifically, the licensee plans to provide an analysis that demonstrates the emergency feedwater logic change would not result in a more than minimal increase in the likelihood of an overcooling accident. Licensee Actions: The licensee has implemented a compensatory measure to take manual control of the emergency feedwater system during a safety injection signal such that an overcooling event will be prevented. Corrective Action References: CR-WF3-2017-06067, CR-WF3-2017-05882, CR-WF3-2017-05173
05000400/FIN-2018002-07Harris2018Q2Minor ViolationA minor, self-revealing violation of TS 6.8.1.a, Procedures and Programs,was identified for failure to follow procedure AD-OP-ALL-0200, Clearance and Tagging. On April 7, 2018, while the plant was in Mode 3 at 0 percent power, the licensee isolated breaker DP-1A-1 circuit 28 in accordance with clearance OPS-1-18-5015-DEH MODS-0093. Isolating this breaker caused an unexpected auto start signal for both motor driven auxiliary feedwater (MDAFW) pumps for a loss of last running main feed pump despite the 1B main feedwater pump still being in operation. Both MDAFWs started and operators manually secured the 1B main feedwater pump to maintain proper feedwater flow to the steam generators. TS 6.8.1.a, requires, in part, that written procedures be implemented covering activities referenced in Regulatory Guide 1.33, Revision 2, dated February 1978, including safety-related activities carried out during operation of the reactor plant. Procedure AD-OP-ALL-0200, Section 5.5, step 4, states Clearance impacts must be evaluated to ensure that effects on systems and components outside of the boundary are identified and are acceptable, or properly dispositioned. Contrary to this requirement, the licensee did not identify that the isolation of breaker DP-1A-1 circuit 28 would cause the MDAFWs to auto start in Mode 3 when developing clearance OPS-1-18-5015-DEH MODS-0093. Screening: The violation is minor because the impact to the plant was minimal; the unit was in Mode 3 throughout the event, the reactor remained subcritical, and feedwater flow to the steam generators was not lost. Enforcement: Because the performance deficiency is minor, it will not be subject to enforcement action in accordance with the NRCs Enforcement Policy. The licensee entered this issue into their CAP as NCR 02196873. The associated LER is closed.
05000458/FIN-2018012-02River Bend2018Q2Failure to Identify and Correct a Broken Feedwater Chemistry ProbeTwo examples of a self-revealed non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, were identified for the licensees failure to identify that a broken chemistry probe in the feedwater system had the potential to cause an adverse impact on plant safety, and promptly implement appropriate measures to address that condition.
05000458/FIN-2018012-05River Bend2018Q2Failure to Develop an Adequate Operational Decision-Making Issue for Compensatory Measures Related to a Degraded Condition of the Feedwater System Sparger NozzlesThe inspectors identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure to develop an adequate Operational Decision-Making Issue (ODMI) document per Procedure EN-OP-111, Operational Decision-Making Issue Process. Specifically, the licensee failed to develop an ODMI that provided adequate guidance to the operators for safely operating the plant with degraded feedwater sparger nozzles.
05000458/FIN-2018012-07River Bend2018Q2Failure to Perform 10 CFR 50.59 Evaluation for Main Feedwater System Sparger Nozzle DamageThe inspectors identified a Severity Level IV non-cited violation of 10 CFR 50.59 , Changes, Tests, and Experiments, for the licensees failure to provide a written safety evaluation for the determination that operation with compensatory measures for damaged feedwater sparger nozzles did not require a license amendment pursuant to 10 CFR 50.90, Application for amendment of license, construction permit, or early site permit. Specifically, the licensee failed to recognize that compensatory measures prohibiting operation in single loop conditions required technical specification changes, and as such required prior NRC approval.
05000445/FIN-2018001-04Comanche Peak2018Q1Inadequate Maintenance Procedure for Feedwater ValvesThe inspectors reviewed a self-revealed Green,non-cited violation of Technical Specification 5.4.1, Procedures, associated with the licensees failure to prescribe adequate procedures for performing maintenance on the feedwater bypass control valves. Specifically, the licensees procedure failed to specify the correct torque on the handwheel screw locknut, resulting in a loose locknut which led to a control valve failure and a turbine trip. This finding was entered into the licensees corrective action program as Condition Report CR-2017-009139.
05000458/FIN-2018001-02River Bend2018Q1Installation of an Incorrectly Specified Relay Causes Plant Transient and Reactor ScramThe inspectors reviewed two examples of a self-revealed finding for the licensees installation of an incorrectly specified relay in 1) the control circuitry for the feedwater level control systemand 2) the turbine generator voltage regulator circuitry. In each instance, the incorrectly specifiedrelay failed in service, causing a plant transient and automatic reactor scram
05000390/FIN-2018010-01Watts Bar2018Q1Potential Failure to Request NRC Approval to Increase the OPT and OTT Response TimesThe reactor trips that protect from fuel damage that could result from departure from nucleate boiling around the fuel are identified as over-temperature-change-in-temperature (OTT) and over-power-change-in-temperature (OPT). The trips use the temperature from the reactor coolant systems hot legs as inputs into complex equations. In 1991, the licensee requested a license amendment to upgrade the Temperature Averaging System (TAS) and protection system to digital technology (Eagle 21 protection system). The Westinghouse topical reports (TR) for the TAS and Eagle 21 was reviewed and the TAS was approved with conditions for the RTD response times, electronic delay times, and surveillance test uncertainties in NUREG 847, the Safety Evaluation Report (SER), Supplement 8 dated January 1992. The SER specified, that the overall response time (RTD response time plus electronics delay) for the new RdF RTDs is 0.5 second longer (6.5 vs. 6.0 seconds) than the former Rosemount RTDs. This leaves a margin of 0.5 second (7.0-6.5) between the analysis and overall RTD response time. The breakdown of components used to arrive at the overall response time is 5.5 seconds for the RTD/thermowell and a conservative electronics delay of 1.0 second. The applicant stated that it will use the loop current step response (LCSR) test to measure RTD response time. A 10-percent allowance for LCSR test uncertainty will be used to ensure an overall channel response time of 7.0 seconds or less. ...During initial startup testing, actions will be taken to correct any resistance temperature detector (RTD) channel with an overall response time of greater than 7.0 seconds including electronics delay and a 10-percent allowance for loop current step response test uncertainty. After any such corrective action, the channel will be retested to verify an overall response time of 7.0 seconds or less (the value assumed in pertinent safety analyses). In 1997, licensee Design Change Notice (DCN) 39293 was implemented to increase the RTD response time. It stated, the response time requirement for OPT reactor trip was increased from 7 seconds to 8 seconds. This time includes RTDs, electronic processing, and trip circuit delays. As a result, the allowance for the sensor response time can be increased from 5.5 to 6.5 seconds. The Reactor Protection System Description, N3-99-1003, and the Technical Requirements Manual (TRM) were revised to reflect the change in response time for this channel. The change appeared to account for the 1.0 second electronic delay, but did not appear to account for the 10-percent allowance for LCSR test uncertainty, which would be derived from the RTD/thermowell delay. The uncertainty margin would appear to increase from 0.5 to 0.6 seconds. This change was implemented without NRC review and approval. In 2015, during hot functional testing of Unit 2 TAS RTDs, the RTD/thermowell delay did not meet the 6.5s required by the TRM from the change in 1997. On May 23, 2015, DCN 66327 was implemented to increase the response time again. The DCN stated, this DCN increases the total Narrow Range RTD response time from 8 to 9 seconds while changing the sensor response time from 6.5 to 8 seconds. Westinghouse has evaluated this change in letter WBT-D-5476 and determined that existing analyses are not impacted by this change. In this new response time the 1.0 second electronic delay and 8 second RTD/thermowells delay appeared to be accounted for, but not the margin for LCRS test uncertainty. If the 10-percent allowance for LCSR test uncertainty were accounted for, the total response time would appear to increase to 9.8 seconds. Westinghouse used a total response time of 9.0 seconds for their analyses at the direction of TVA, per WBT-TVA-3027, Revision 0, (5.10) PIN ELICB-055 Evaluation to Support a 9.0-second Total RTD Response Time, August 2015. The 10 percent LCSR uncertainty does not appear to have been included. Westinghouse letter LTR-TA-15-92, Transient Analysis Evaluation of an Increased RTD Delay Time for Watts Bar Unit 2, Rev. 0, stated, in part, due to the limiting nature of the (Steam Line Break) SLB w/ (Rod Withdrawal at Power) RWAP event, in which no margin currently exists to the departure from nucleate boiling ratio (DNBR) safety analysis limit (SAL), the inclusion of a 9.0-second total RTD response time resulted in a 0.55% DNBR penalty. For the feed water event, defined as a reduction in feedwater temperature, the Westinghouse letter stated, in part, key event results for both of the multiple-loop cases were impacted by the delay in receiving the OPT trip. While substantial margin was maintained to the DNBR limit of 1.38, the peak core heat flux values slightly exceeded the limit value of 121%. The letter concluded that the slower responding RTDs did not significantly impact the non-LOCA transient analyses and that the acceptance criteria for the events continued to be met, with the exception of the SLB w/ RWAP. However, generic DNB margin will be allocated to offset the 0.55% DNBR penalty associated with the evaluation. As such, the non-LOCA transient analyses can support operation of Watts Bar Unit 2 with a total RTD delay time of up to 9.0 seconds. The inspectors questioned the licensee to understand why the 10-percent allowance for LCSR test uncertainty was not accounted for in the Westinghouse analyses, and to what extent it could have affected the results. In addition, the inspectors questioned whether the 10-percent uncertainty was adequate in the current installation configuration. The inspectors also questioned how the LCSR test could account for increased thermal resistance between the RTDs and the thermowells. The test may not measure the actual delay time from the hot leg across the thermowell thermal resistance to RTD. The original installations relied on specific RTD thermowell bonding to establish a predictable thermal resistance and initial response time. It is unclear how this was performed for this installation to determine the actual response time. The 10 CFR 50.59 evaluation was performed May 22, 2016. This issue has been captured in the Corrective Action Program (CAP) as CR 1398934, Potential failure to request lic. amendment to change OPdT/OTdT response time
05000461/FIN-2018001-02Clinton2018Q1Failure to Identify a Single Point Vulnerability Results in Manual Reactor ScramA self-revealed Green finding was identified for the licensees failure to identify a single point vulnerability in accordance with procedure ERAA2004, Revision 1. Specifically, during a site single point vulnerability review of the feedwater system, the licensee failed to identify a single point vulnerability that subsequently resulted in a loss of a feedwater heating string. The loss of the heater string caused a drop in temperature in the reactor of 100 degrees which prompted a manual scrambe initiated by the operators
05000335/FIN-2018001-01Saint Lucie2018Q1Improper Evaluation of LCV-9005 position setpoints Leads to AFASOn November 19, 2013, during reactor startup activities, feedwater bypass valves, A (LCV-9005) and B (LCV-9006), were found to be operating at different throttle positions while maintaining their respective steam generator water levels. Valves LCV-9005 and 9006 were both originally installed in April 1978. LCV-9005 was replaced in 1994, with an equivalent valve, due to obsolescence. The original valve had a full open stroke length of 1.5 inches (in.), while the new equivalent valve had a full open stroke length of 2 in. to provide the same flow as the original valve. When installed, LCV-9005 was set up to limit its stroke length to 1.5 in., matching the replaced valve, and the associated drawings were never revised to show that the new valve had a full 2 in. open stroke length. In 2009, the distributed control system (DCS) was installed utilizing these drawings and was setup under the assumption that both valves, LCV-9005 and LCV-9006, were the same model valves and stroke lengths.The DCS system was designed to provide a signal to throttle the feedwater bypass valves following a reactor trip to 20 percent open to provide approximately 5 percent feed flow in order to recover steam generator water levels utilizing main feedwater. During Unit 2 startup activities in November 2013, the licensee noted a discrepancy in the valve positions for LCV-9006 and LCV-9005 when they were providing steam generator water level control. The licensee placed the issue in the corrective action program under Action Request (AR) 1921720 and determined that it was necessary to evaluate a revision of the LCV-9005 DCS setpoint, which was accomplished by an engineering condition evaluation under AR 1925428. The engineering condition evaluation was inadequate in that it failed to recognize the differences in the two different model valves, and therefore failed to provide adequate corrective actions to address performance issues associated with these differences.The final recommendation from AR 1925428 was that the current LCV-9005 setting did not impose any risk to the plant operation, as the 2A steam generator level had been within acceptable range with no control room alarm observed. Therefore, no setpoint change was required at that point.On October 26, 2017, following a Unit 2 trip, LCV-9005 was sent a digital DCS demand signal to be 20 percent open. Since the valve was locally set to have a maximum stroke of 1.5 in. instead of 2 in. open, the actual flow through the valve was less than 5 percent. This resulted in flow lower than needed to maintain 2A steam generator level, and caused level to lower, which eventually resulted in an actuation of the A train auxiliary feedwater actuation system (AFAS). Corrective Action(s):The licensee implemented corrective actions to: 1) properly set up LCV-9005 in order for it to have a full stroke length of 2 inches so that it could provide the required feedwater flow and, 2) update associated drawings to include correct stroke lengths.Corrective Action Reference(s): This issue was entered into the licensees CAP as AR 2232869
05000445/FIN-2018001-05Comanche Peak2018Q1Failure to Correct a Significant Condition Adverse to QualityThe inspectors identified a Green,non-cited violation of 10CFR 50, Appendix B, Criterion XVI, Corrective Action, associated with the licensees failure to take corrective action for the identified cause of a significant condition adverse to quality. Specifically, a feedwater bypass control valve vibrated open resulting in a turbine trip and initiation of auxiliary feedwater. The licensee determined that the cause was an inadequate procedure for performing maintenance on the feedwater bypass control valves, but failed to correct the inadequate procedure after identifying it as the cause of a control valve failure and a turbine trip. This finding was entered into the licensees corrective action program as Condition Report CR-2018-000959.
05000454/FIN-2018010-04Byron2018Q1Use of 10 CFR 50.54(x) for Unit AFW Cross-TieIn 2008, the licensee added steps to Emergency Operating Procedure (EOP) 1/2BFR-H.1, Response to Loss of Secondary Heat Sink, to use the MDAFW train of a non-accident unit to combat a loss of all feedwater event in the opposite unit by using a recently installed unit cross-tie. The EOPs also directed operators to enter the technical specification LCO action statement for the unit donating the MDAFW train because the MDAFW trains were not designed and licensed to be shared between the reactor units.In 2011, the resident inspectors noted that the EOP change resulted in more than a minimal increase in the likelihood of occurrence of a malfunction of a SSC important to safety previously evaluated in the Updated Final Safety Analysis Report because the Updated Final Safety Analysis Report described the MDAFW trains as non-shared systems. However, the licensee implemented this change without prior NRC approval. As a result, the inspectors documented a Severity Level IV NCV of 10 CFR 50.59 in Inspection Report 05000454/2011004; 05000455/2011004 as NCV 05000454/2011004-02; 05000455/2011004-02, Modification of the Auxiliary Feedwater System Without Prior NRC Approval (REF: Accession No. ML 113070678).As corrective actions to this NCV, the licensee removed the steps in the EOPs that directed the unit cross-tie to be used and removed credit for the cross-tie in the stations Probabilistic Risk Assessment model. However, on August 8, 2017, the licensee added direction in EOP1/2BFR-H.1 to use the Unit Auxillary Feedwater cross-tie by invoking 10 CFR 50.54(x). Specifically, the change added a note and a caution that provided direction to initiate the MDAFW unit cross-tie before bleed and feed. The note stated:If at any time it has been determined that restoration of feed flow to any SG is untimely or may be ineffective in heat sink restoration, then the AF crosstie should be implemented per Step 5 (Page 8). The caution stated: The AF crosstie should be implemented per Step 5 if other attempts to restore feed flow to the SG(s) will not prevent the initiation of feed and bleed. Step 5 provided instructions on how to perform the cross-tie and did not include instructions on when to initiate it. The caution also stated Use of the AF crosstie requires invoking 50.54(x).During this inspection period, the inspectors challenged the use of 10 CFR 50.54(x) to implement this permanent change. In addition, the inspectors noted that the licensees 10 CFR 50.59 screening for the procedure change did not include in its review the added note and caution statements. Because the added note and caution were the only procedure provisions that provided direction on when to use the MDAFW cross-tie, the 10 CFR 50.59 screening did not review the instructions about when to use the MDAFW cross-tie. As a result, the screening failed to determine that the change may have required a technical specification change and, thus, a license amendment as originally planned.At the end of the inspection, the NRC continued to evaluateif a performance deficiency and or violation occurred. This Unresolved Item will remain open pending the outcome of this ongoing review.
05000220/FIN-2018001-01Nine Mile Point2018Q1Potential Failure to Submit an 8-Hour Event Notification for a Valid Actuation of HPCOn March 18, 2018,at 1:18 a.m., during the Unit 1maintenance outage while the unit was in cold shutdown, operators received multiple low level alarms on the GEMAC 11 and 12 level indications. Operators responded by adjusting reactor water cleanup reject flow and the feedwater minimum flow control valve to raise reactor water level. Upon the operators making the adjustment to reactor water level, the feedwater low flow control valve was slow to respond, but eventually opened more rapidly, and the increased flow from feedwater resulted in a rapid rise in reactor water level. At 1:28 a.m., indicated reactor water level rose to the 95-inch trip setpoint for the 11 and 12 Yarway level indication instruments, resulting in a turbine trip and HPCI initiation signal. The HPCI pumps were tagged out and thus did not inject, and the turbine was offline for the shutdown. The 11 and 12 Yarway level indication instruments provide reactor protection system logic inputs for reactor vessel water level; however, the Yarway level indication instruments are not density compensated. Therefore, under cold shutdown conditions, actual reactor vessel water level was lower than indicated water level on the 11 and 12 Yarways. During cold shutdown conditions, the GEMAC level instruments, which are calibrated to cold shutdown conditions, provide an accurate indication of actual reactor vessel water level. The GEMAC instruments both indicated well below the trip setpoint of 95 inches (indicated ~72 inches) when the turbine trip and HPCI initiation signal were received. Exelon determined that this event was not reportable under 10 CFR 50.72.Title 10 CFR 50.72(b)(3)(iv)(A) states, Any event or condition that results in valid actuation of any of the systems listed in paragraph (b)(3)(iv)(B) of this section, except when the actuation results from and is part of a pre-planned sequence during testing or reactor operation. (B) The systems to which the requirements of paragraph (b)(3)(iv)(A) of this section apply are: 10 (5) BWR reactor core isolation cooling system; isolation condenser system; and feedwater coolant injection system. Planned Closure Action(s): The inspectors requested the 10 CFR 50.72 subject matter experts at the Office of Nuclear Reactor Regulation (NRR) and Office of General Council (OGC) to review whether this was a valid actuation and thus reportable. The inspectors are opening an unresolved item (URI) to determine if a performance deficiency exists.Licensee Action(s): Licensee entered the concern into their corrective action program, and communicated with NRC Region I and NRR Staff. Exelons position is that the event was not reportable. Corrective Action Reference:IR 04116336 NRC Tracking Number: 05000220/2018001-01
05000395/FIN-2017004-02Summer2017Q4Failure to Implement Corrective Actions to Restore Compliance for Previous NRC-identified Green NCV 05000395/2005007-01The inspectors identified a Green finding associated with a cited violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, for the failure to ensure that conditions adverse to quality as noted in a previous NRC-identified Green NCV, 05000395/2005007-01, EFW Flow Control Valves Are Susceptible to Plugging by Tubercles or Other Debris from Service Water, were corrected. The licensee entered the issue in their corrective action program as condition report, CR-17-04630. The inspectors determined that the failure to promptly identify and correct the conditions adverse to quality (CAQ) for a design in which the emergency feedwater (EFW) flow control valves were susceptible to plugging by tubercles or other debris from the service water (SW) system was a performance deficiency (PD). The inspectors reviewed IMC 0612, Appendix B and determined the PD was more than minor and therefore a finding, because it affected the Mitigating Systems Cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences and the respective attribute of design control because the EFW flow control valves were susceptible to plugging by SW debris. This finding had been evaluated and screened to a low safety significance (Green) and documented in the previous NRCidentified Green NCV, 05000395/2005007-01. Because the licensee failed to implement corrective actions and restore compliance in a timely manner, this violation is being treated as a cited violation, consistent with Section 2.3.3 of the NRC Enforcement Policy. The inspectors used IMC 0310 and determined this finding has a cross-cutting aspect of resolution in the area of Problem Identification and Resolution because the organization failed to take effective corrective actions to address issues in a timely manner commensurate with their safety significance and restore compliance (P.3).
05000220/FIN-2017004-05Nine Mile Point2017Q4Licensee-Identified ViolationThe following violation of very low safety significance (Green) was identified by Exelon and is a violation of NRC requirements which meets the criteria of the NRC Enforcement Policy for being dispositioned as a NCV. Title 10 CFR 50.65(a)(4) requires, in part, ...the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activities. Exelon procedure WC-AA-101-1006, On-Line Risk Management and Assessment, Revision 001, Section 4.1.3, states to consider work activities that cause equipment to be unavailable (e.g., trains of systems) for assessment of risk under the requirements of 10 CFR 50.65(a)(4). Contrary to the above, on October 17, 2017, Exelon identified a discrepancy in PARAGON (risk software) that resulted in an improper risk assessment for the days planned work. Review and correction of the error resulted in an elevated risk condition of Yellow during Nine Mile Point Unit 1, 11 feedwater pump (FW) maintenance. This performance deficiency was determined to be more than minor because it adversely affected the human performance attribute of the Mitigating Systems cornerstone and affected cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, on October 17, 2017, Exelon identified a planned activity that resulted in an unplanned Yellow risk activity during planned maintenance of the 11 FW pump. In addition, IMC 0612, Appendix E, Examples of Minor Issues, under Section 7, Maintenance Rule, Example E for inadequate risk assessment states in part that a more-than-minor issue would put the plant into a higher licensee-established risk category. The finding was evaluated using IMC 0609, Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process. The finding was determined to affect the overall plant risk with the 11 FW Pump being out of service for maintenance with PARAGON not elevating the overall plant risk from green to yellow. The risk deficit was elevated and determined to not be greater than 1E-6 event per year for Incremental Core Damage Probability Differential and not greater than 1E-7 events per year for Incremental Large Early Release Probability Differential. Therefore, the finding was determined to be of very low safety significance (Green). Exelon entered this issue into its CAP as IR 04064241.
05000443/FIN-2017004-03Seabrook2017Q4Inadequate Procedure Implementation Results in a Manual Reactor TripA self-revealing Green finding was identified for inadequate implementation of procedure MA 4.5, Configuration Control, Revision 18. Specifically, maintenance technicians failed to properly implement MA 4.5 while backfilling steam generator instrumentation, and inadvertently left an instrumentation valve partially open instead of fully open. This resulted in slow response of the instrument, and ultimately a high steam generator level, a feedwater isolation signal and a manual reactor trip. NextEra promptly rechecked other similar valves, then performed a root cause evaluation that eventually led to additional technician training and improved configuration controls during such evolutions. This finding is more than minor because it is associated with the configuration control 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 failure to effectively implement MA 4.5 resulted in a valve being left out of its required position, a subsequent lack of steam generator water level control during low power operations, and ultimately required a manual reactor trip. In accordance with IMC 0609.04, Initial Characterization of Findings, issued June 19, 2012, and Exhibit 2 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, issued June 19, 2012, the inspectors determined that this finding is of very low safety significance (Green), because the fin ding did not cause 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. Additionally, the finding has a cross-cutting aspect in the area of Human Performance, Work Management, because the organization did not implement a process of planning, controlling, and executing the work activity such that nuclear safety was the overriding priority. Specifically, NextEra did not ensure that a steam generator backfilling activity was properly executed, which resulted in the slow response of a steam generator level indication, the overfeeding of the steam generator, a feedwater isolation signal, and the ultimate requirement to trip the reactor. (H.5)
05000395/FIN-2017004-03Summer2017Q4Failure of an Emergency Feedwater Auto Start Actuation SignalA self-revealing, Green, non-cited violation (NCV) of Technical Specification (TS) 3.3.2 was identified involving the failure of the C main feedwater pump to trip and resultant loss of an emergency feedwater auto start actuation signal. The licensee entered the issue in their corrective action program as condition report, CR-17-01611. The inspectors reviewed IMC 0612, Appendix B, Issue Screening, and determined that the PD was more than minor and therefore a finding because it impacted the Mitigating Systems Cornerstone by adversely affecting the cornerstone objective to ensure in part the availability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the equipment reliability attribute was impacted because a failure of the C main feedwater pump to trip when required rendered an EFW auto start actuation signal inoperable. The inspectors used IMC 0609, Significant Determination Process, Attachment 4, and Appendix A Exhibit 2, and determined that the finding was of very low safety significance, Green, because there was no design deficiency or loss of function. Specifically, EFW auto start capability remained operable for other functions to maintain short term heat removal capability. The inspectors reviewed IMC 0310, Aspects Within Cross Cutting Areas, and determined the cause of this finding involved the cross-cutting area of Human Performance and the aspect of problem identification and resolution, P.2, because the licensee had previous indications of water intrusion and feedwater pump control issues and failed to thoroughly evaluate to address the cause.
05000346/FIN-2017004-03Davis Besse2017Q4Failure to Prescribe Appropriate Work Instructions for an Activity Affecting QualityA self-revealed finding with an Apparent Violation (AV) of Title 10 of the Code of Federal Regulations (CFR) Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, and an associated violation of technical specification (TS) 3.7.5, Emergency Feedwater (EFW), was identified on September 13, 2017, due to the licensees apparent failure to prescribe appropriate work instructions for an activity affecting quality of the safety-related auxiliary feedwater (AFW) system. Specifically, the licensee apparently did not provide appropriate instructions to maintain an adequate amount of oil in the AFW turbine bearing oil sumps, resulting in the failure of AFW 1 on September 13, 2017. The licensee entered this issue into the CAP as CR201709443 and CR201709857, immediately replaced the damaged bearing, and updated the lubrication manual data sheets to include sight glass marking dimensions per vendor guidance. The apparent performance deficiency was determined to be more than minor because the finding was associated with the Mitigating Systems cornerstone attribute of equipment performance and potentially adversely affected the cornerstone objective of ensuring the availability, capability and reliability of equipment that respond to initiating events. Specifically, the apparent performance deficiency resulted in the failure of the AFW 1. Using IMC 0609, Attachment 4, Initial Characterization of Findings, and IMC 0609 Appendix A, The Significance Determination Process for Findings at Power, issued June 19, 2012, the finding was screened against the mitigating systems cornerstone. The inspectors determined the finding represented an apparent actual loss of function of at least a single train for greater than its technical specification allowed outage time. Therefore, a detailed risk evaluation will be performed by a regional senior reactor analyst. Because the safety characterization of this finding is not yet finalized, it is being documented with a significance of to be determined (TBD). The inspectors determined this finding affected the cross-cutting aspect of challenge the unknown in the area of Human Performance, where individuals stop when faced with uncertain conditions. Risks are evaluated and managed before proceeding. Specifically, licensee personnel apparently did not stop when faced with uncertain conditions in the preventive maintenance procedure for replacing the AFPT sight glasses. Although the replacement of the AFPT 1 inboard bearing sight glass occurred in 1997, the licensee had the opportunity to challenge the lack of detail in the work instructions in late 2014 when the AFPT 2 outboard bearing sight glass was replaced. (H.11)
05000416/FIN-2017007-06Grand Gulf2017Q4Failure to Ensure Adequate Design Control Measures Are in Place Associated with Leakage Control SystemsThe team identified a Green, non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, which states, in part, Measures shall be established to assure that applicable regulatory requirements and the design basis...for those structures, systems, and components to which this appendix applies are correctly translated into specifications, drawings, procedures, and instructions. Specifically, prior to October 17, 2017, the licensee failed to provide adequate procedures or training to licensed operators to ensure the main steam isolation valve-leakage control system and feedwater leakage control system are manually started consistent with the licensees design basis assumptions. In response to this issue the licensee has provided specific guidance and training to the operators. This finding was entered into the licensees corrective action program as Condition Report CR-GGN-2017-09112. The team determined that the failure to ensure adequate design control measures are translated into procedures and training is a performance deficiency. The performance deficiency is more than minor, and therefore a finding, because it was associated with the barrier performance attribute of the Barrier Integrity Cornerstone and adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, the plant was operated at power for an extended period of time without adequate procedures and training for licensed operators to ensure that the system would be placed in service in a manner that ensured radiological leakage across main steam isolation valves and through feedwater pi ping is addressed during a postulated accident. In accordance with Manual Chapter 0609, Significance Determination Process, Attachment 4 (effective date October 7, 2016); and the corresponding Appendix A, The Significance Determination Process (SDP) f or Findings At-Power, Exhibit 3, Barrier Integrity Screening Questions (issue date June 19, 2012); the issue was evaluated using Appendix H, Containment Integrity Significance Determination Process (issue date May 6, 2004). Because the opportunities to ensure the design control measures were correctly captured in procedures and instructions for the main steam isolation valve-leakage control system and feedwater leakage control system were in 2001 and 1987, respectively; and the licensee instituted a time-critical operator action program within the last year to prevent such issues from occurring, the issue was determined to have very low safety significance (Green). The performance deficiency was not indicative of current performance. Therefore, no cross-cutting aspect is being assigned.
05000287/FIN-2017004-02Oconee2017Q4Failure to Properly Risk Screen Work Within Two Feet of a Single Point Vulnerability ComponentA self-revealing Green NCV of Oconee Nuclear Station TS, Section 5.4, Procedures, was identified for the licensees failure to identify and properly risk screen work within 2 feet of a single point vulnerability (SPV) component in accordance with procedure AD-OP-ALL-0201, Protected Equipment. Specifically, the transmission and Oconee organizations failed to recognize that planned maintenance on a breaker in the 525 kilovolt (kV) switchyard was within 2 feet of an SPV component and, as a result, appropriate planning and oversight were not in place to prevent a plant trip during maintenance activities. The licensee entered this issue into their CAP as NCR 02138958. Corrective actions included revisions to station and transmission procedures to ensure inclusion of appropriate SPV program information, addition of the SY special emphasis code to all switchyard type work which require coordination of transmission resources, and the addition of the T1 trip/transient risk special emphasis code to all breaker failure relays in the 230 kV and 525 kV switchyard cabinets containing SPV components.The licensees failure to identify and properly risk screen the planned maintenance on PCB-57 as work within 2 feet of an SPV component in accordance with AD-OP-ALL-0201 was a performance deficiency. The performance deficiency was determined to be more than minor because it was 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, human errors led to a Unit 3 main generator lockout, which resulted in a reactor trip. The finding was assessed using IMC 0609, Attachment 4 and IMC 0609, Appendix A. The inspectors determined the finding was of very low safety significance (Green) because the finding did not represent a transient initiator that caused both a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition (i.e. loss of condenser, loss of feedwater). The inspectors utilized IMC 0310, Aspects Within the Cross-Cutting Areas, dated December 4, 2014, and determined the finding had a cross-cutting aspect of work management in the human performance area, because the organization failed to implement a process of planning, controlling, and executing work activities such that nuclear safety is the overriding priority. The work process failed to include the identification and management of risk commensurate to the work and the need for coordination with different groups or job activities. (H.5)
05000395/FIN-2017004-04Summer2017Q4Licensee-Identified ViolationTS 6.8.1, Procedures and Programs, requires, in part, that written procedures shall be implemented covering the activities recommended in Appendix A of Regulatory Guide 1.33, Rev. 2, Section 8, Procedures for Control of Measuring and Test Equipment and for Surveillance Tests, Procedures and Calibrations. Contrary to this, on October 23, 2017, the licensee identified they had failed to correctly implement STP-220.002, Turbine Driven Emergency Feedwater Pump and Valve Test, Rev. 9, to return the TDEFW pump governor speed control manual adjustment knob to the required position during the surveillance test conducted on the previous shift. The inspectors reviewed IMC 0609 Appendix A and Attachment 4 for Mitigating Systems to determine the finding was of very low safety significance, Green, because there was no design deficiency, loss of system, and the loss of function for the single train was less than the TS LCO action time and less than 24 hours. The licensee has documented this problem in their CAP as CR-17-05588.
05000251/FIN-2017004-03Turkey Point2017Q4Inadequate Installation of Outdoor Use Electrical Enclosures Results in Manual Reactor TripA self-revealing finding (FIN) was identified for failure to ensure the 4B and 4C main feedwater regulating valve (MFRV) control circuits remained free from the effects of water intrusion or condensation in electrical enclosures. Specifically, a hand selector switch (HSS) enclosure for the 4C MFRV redundant positioners was flooded during wind-driven rain and resulted in the 4C MFRV failing closed, lowering 4C steam generator water level, and a subsequent Unit 4 manual reactor trip initiated by control room operators.Engineering Change (EC) 246879 appropriately selected NEMA-4X rated enclosures for the HSSs but associated SPEC-C-065 did not provide critical configuration details for the enclosure installations. Water collected in the 4B and 4C MFRV positioner HSS enclosures because the penetrations were on top of the enclosures and not properly sealed and the bottom of the enclosure did not have a weep hole.This performance deficiency was determined to be more than minor because it was associated with the design control attribute of the Initiating Events Cornerstone and adversely affected the cornerstones objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown, as well as power operations, because the failure resulted in lowering steam generator water levels and caused control room operators to complete a fast load reduction and manually trip the reactor. In accordance with NRC IMC 0609, Appendix A, The Significance Determination Process for Findings at Power, the inspectors determined that the issue had very low safety significance because it only caused a reactor trip and did not cause the loss of mitigating equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. Since EC 246879 and associated work orders were completed in 2013, the inspectors determined the finding was not indicative of current licensee performance and was not assigned a cross-cutting aspect.
05000410/FIN-2017004-04Nine Mile Point2017Q4Ineffective Correction Action Results in Failure of Instrument Air SystemThe inspectors documented a self-revealing Green finding (FIN) of CNG-CA-1.01-1000, Corrective Action Program, Revision 01100, because Nine Mile Point Nuclear Station (NMPNS) failed to implement corrective actions at NMPNS Unit 2 to remove and replace all un-annealed red brass piping for the instrument air system during the April 2008 refueling outage. Specifically, on July 13, 2017, Unit 2 experienced a rupture of un-annealed red brass instrument air pipe which resulted in a feedwater pump trip and a reactor recirculation pump runback to 49 percent. Exelons corrective actions for the July 13, 2017 failure of un-annealed red brass instrument air piping included wrapping the instrument air piping with a material that both supports the piping and prevents potential stress corrosion cracking. Exelon has developed work orders to replace the piping in the upcoming outage in spring 2018. Exelon also improved staff training for accountability and work checking to verify that generated work orders are completed and closed out. Exelon entered this issue into the corrective action program (CAP) as issue report (IR) 04031685, and performed a corrective action program evaluation (CAPE). This finding is more than minor because it is associated with the design control attribute of the Initiating Events cornerstone and affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during power operations. Specifically, NMPNS staff failed to complete corrective actions to replace Unit 2 un-annealed red brass instrument air piping, which was susceptible to stress corrosion cracking, resulting in a feedwater pump trip and a reactor recirculation runback to 49 percent on July 13, 2017. The inspectors evaluated the finding using IMC 0609, Attachment 4, Initial Characterization of Findings, issued on October 7, 2016, and Exhibit 1 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, issued June 19, 2012. The inspectors determined that the finding was of very low safety significance (Green) because it did not result in the complete or partial loss of a support system that contributes to the likelihood of, or cause, an initiating event and affected mitigation equipment. The inspectors determined that this finding did not have a cross-cutting aspect because the performance deficiency occurred greater than 3 years ago; therefore, it is not considered to be indicative of current plant performance.
05000395/FIN-2017007-01Summer2017Q4Failure to Verify the Adequacy of Design for the EFW system when Supplied by SWThe NRC identified a non-cited violation (NCV) of Title 10 of the Code of Federal Regulations (CFR) Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to verify the emergency feedwater (EFW) pumps would be capable of taking suction from service water for an indefinite period of time as required by Updated Final Safety Analysis Report Section 10.4.9.2. The licensee entered this issue into their corrective action program (CAP) as condition report (CR) 17-05528 and performed an operability determination to verify the EFW pumps remained operable. The performance deficiency was determined to be more than minor because it was associated with the design control 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 failure to evaluate worst-case design conditions resulted in a reasonable doubt that the EFW pumps could provide cooling water to the steam generators and perform their design basis function. The team determined the finding to be of very low safety significance (Green) because the finding was a deficiency affecting the design or qualification of a mitigating structure, system, and component (SSC), and the SSC maintained its operability. The team determined that no crosscutting aspect was applicable because the finding did not reflect current licensee performance
05000461/FIN-2017003-04Clinton2017Q3Flow Control Valves Not Locked Out Results in Reactor Recirculation Pump RunbackThe inspectors documented a self-revealed finding of very low safety significance and an associated NCV of Technical Specification (TS) 5.4.1, Procedures, for the licensees failure to establish sufficient instructions in station procedure Clinton Power Station (CPS) 3103.01, Feedwater (FW), Revision 31e, for changing modes of operation for the nuclear steam supply system. Specifically, the station procedure did not provide instructions requiring the locking out the flow control valves (FCVs) to prevent a reactor recirculation FCV runback while changing the feedwater pump lineup resulting in an unexpected plant transient and 9.2 percent change in reactor power. The licensee entered this issue into their corrective action program (CAP) as Action Request (AR) 04007861. As corrective actions, the licensee revised their CPS 3103.01 procedure to require that the FCVs be locked out prior to shifting reactor feed water pumps. The performance deficiency was more than minor in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, dated September 7, 2012,because the finding was associated with the procedure quality 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 failure to have adequate procedures for shifting feedwater pumps during a plant shutdown on May 7, 2017, resulted in an unexpected recirculation pump run back and a 9.2 percent change in reactor power. Using IMC 0609, Attachment 4, Initial Characterization of Findings, andAppendix A, The Significance Determination Process for Findings At-Power, issuedJune 19, 2012, the finding was screened against the Initiating Events cornerstone and determined to be of very low safety significance because the event did not cause a reactor scram. The inspectors determined 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 and a proposed action is determined to be safe in order to proceed, rather than unsafe in order to stop. Specifically, the procedure provided for the option to lockout the reactor 3 recirculation flow control valves if deemed necessary during a shift of the reactor feedwater pumps and the operations crew did not make the prudent choice of locking out the valves before determining that it was safe to proceed. (H.14)
05000250/FIN-2017007-04Turkey Point2017Q3Failure to Verify the Adequacy of Design for Component Protective CoversThe NRC identified a Green non-cited violation of Title 10 Code of Federal Regulations Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to verify the adequacy of design for the non-safety related component protective covers attached to safety related equipment. For immediate corrective actions, the licensee entered this into their corrective action program as AR 02220993 and removed visibly degraded protective covers. 3 The performance deficiency was determined to be more than minor because it was associated with the Design Control attribute and of the Initiating Events Cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as pow er operations. Specifically, the failure to ensure the quality and qualification of commercial components and assemblies to maintain adequate mounting to Class 1E equipment increased the likelihood of inadvertent component failures, and thus increased the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. The team determined the finding to be of very low safety significance because the finding did not cause a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition (e.g. loss of condenser, loss of feedwater). This finding was not assigned a cross-cutting aspect because the issue did not reflect current licensee performance.
05000280/FIN-2017007-01Surry2017Q3Failure to Evaluate Design Maximum Ambient Temperature Effect on Main Steam Valve HouseThe NRC identified a non-cited violation of 10 CFR 50, Appendix B, Criterion III, Design Control, for the licensees failure to correctly evaluate the heat-up of the Main Steam Valve House (MSVH), which contains the auxilliary feedwater pumps as well as other safety-related mitigating systems. The violation was entered into the licensees corrective action program as Condition Reports 1077007 and 1077684 and the licensee conducted a preliminary calculation and evaluation to determine the actual temperature increase and determined that the equipment located in MSVH remained operable. The performance deficiency was determined to be more than minor because it was associated with the Design Control 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 failure to evaluate worst-case design conditions resulted in a decreased margin for reliability and capability of mitigating systems contained in the MSVH. The inspectors determined the finding to be of very low safety significance (Green) because the finding was a deficiency affecting the qualification of a mitigating structure, system, or component (SSC), and the SSC maintained its operability or functionality. This finding was not assigned a cross-cutting aspect because the underlying cause was a legacy issue and not indicative of current performance.
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 .
05000346/FIN-2017008-01Davis Besse2017Q2Failure to Maintain Adequate Room Temperature in the Emergency Feedwater FacilityGreen . A finding of very low safety significance was identified by the inspectors for failing to maintain adequate room temperature in the emergency feedwater facility (EFWF) to support equipment operation. Specifically, the inspectors identified temperatures below freezing in multiple loca tions on emergency feedwater (E FW) system piping and in the E FWF basement. In response, the licensee installed heaters to raise room temperature. This finding is not a violation of NRC requirements. The inspectors determined that failing to maintain adequate room temperature in the EFWF to support equipment was cont rary to Nuclear Energy Institute ( NEI ) 12 06, Diverse and Flexible Coping Strategies (FLEX) Implementation Guide, Rev. 2 and was a performance deficiency. The finding is of more than minor significance because it was associated with the cornerstone attribute of protection against external factors and adversely affected the mitigating systems cornerstone objective . A detailed risk evaluation (DTE) determined the findin g was ( Green) . This finding was assigned a cross- cutting of Challenge the Unknown . (H.11)
05000263/FIN-2017002-01Monticello2017Q2Low Reactor Water Level During Shutdown of 11 Reactor Feedwater PumpA self-revealed finding of very-low safety significance and a Non-Cited Violationof Technical Specification 5.4.1.a occurred on April 15, 2017, due the licensees failure to establish, implement and maintain procedures regarding shutdown operations. Specifically, Operations Manual B.06.05-05 did not account for the state of the opposite train of feedwater when shutting down the 11 Reactor Feedwater Pump. Licensee use of the inadequate procedure placed equipment in a configuration where no condensate flow path to the reactor existed causing reactor water level to lower to a point where trip/isolation set-points were reached. This caused an unplanned Reactor Protection System (RPS) trip and Partial Group II Isolation. The licensee initiated Corrective Action Program (CAP) 1555785 to document the reactor water level transient, RPS trip and Partial Group II Isolation. Immediate corrective actions includedopening the 11 Reactor Feedwater Pump discharge valve to restore reactor water level allowing reset of the Group II isolation and RPS trip. Subsequent licensee actions included development of expectations via an Operations Memo and revision to Operations Manual B.06.0505 as well as Procedure 2204 and Procedure 2167 to ensure abnormal equipment lineups are addressed such that unexpected procedure interactions are avoided.The inspectors determined the failure to establish, implement and maintain procedures regarding shutdown operations as required by Technical Specification 5.4.1.a was a performance deficiency that required an evaluation. The inspectors assessed the significance of this finding using IMC 0609, Attachment 4, and IMC 0609, Appendix A, Exhibit 1, Section B, and determined a detailed risk evaluation was required because the finding caused a reactor trip and loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition (e.g., loss of feedwater). A Senior Reactor Analyst performed a detailed risk evaluation using bounding assumptions and the change in Core Damage Frequency was calculated to be 9E7/year (Green). The inspectors determined that the contributing cause that provided the most insight into the performance deficiency was associated with the cross-cutting area of Human Performance, Change Management aspect, because licensee leaders did not use a systematic process for evaluating and implementing change so that nuclear safety remains the overriding priority.
05000293/FIN-2017002-01Pilgrim2017Q2Failure to Follow Procedure Requirements for the Control of a Flood Protection BarrierAn NRC-identified Green finding was identified because Entergy personnel did not follow Procedure 1.3.135, Control of Doors, to adequately control a condenser bay flood protection door. Specifically, on May 22, 2017, Entergy personnel failed to control door 25A, which is designed to mitigate condenser bay flooding to preclude adversely impacting the important to safety instrument air system. Entergys short-term corrective actions included closing the door and providing additional operator training. This issue was entered into the CAP as CR 2017-5746. The performance deficiency is more than minor because it is associated with the configuration control attribute of the Mitigating Systems cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding was evaluated using IMC 0609, Appendix A, Exhibit 4, External Events Screening Questions, issued June 19, 2012, with respect to the degraded safety function of the flood barrier door. The finding was determined to be of very low safety significance (Green) because the failure of the flood door was determined to not degrade the instrument air system ability to support the feedwater injection function or the alternate injection through the control rod drive system. This is because the backup diesel driven compressor was available to be started locally and supply the instrument air headers. The finding also did not involve the total loss of any safety function. The finding has a cross-cutting aspect in the area of Human Performance - Procedure Adherence, because Entergy personnel did not follow processes, procedures, and work instructions. Specifically, Entergy personnel did not follow procedural requirements to adequately control flood protection door 25A. (H.8)
05000313/FIN-2017002-04Arkansas Nuclear2017Q2Licensee-Identified ViolationTitle 10 CFR 50.55a(g)4, Inservice Inspection Standards Requirement for Operating Plants, states in part, Throughout the service life of a pressurized water -cooled nuclear power facility, components that are classified as ASME Code Class 1, Class 2, and Class 3 must meet the requirements set forth in Section XI of the ASME Code. The ASME Section XI, Article IWA - 2610, requires that all welds and components subject to a surface or volumetric examination be included in the licensees inservice inspection program. This includes identifying system supports in the inservice inspection plan, per ASME Section XI, Article IWA -1310. Contrary to the above, prior to March 9, 2017, the licensee did not ensure that all welds and components subject to a surface or volumetric examination were included in the licensees inservice inspection. Specifically, the licensee did not apply the applicable inservice inspection requirements for surface or volumetric examination to all portions of the Unit 2 emergency feedwater system within the system ASME Code Class 3 boundary. The licensee identified that they failed to include the emergency feed pump supports in their inservice inspection program. The licensee entered this issue into their corrective action program as Condition Report CR- ANO -2-2016 -01023 and reasonably determined the emergency feedwater system remained operable. The licensee restored compliance by inspecting the supports, with no degradation identified, and entering the emergency feedwater pump supports into the ASME Section XI program. The finding was of very low safety significance (Green) because the finding did not 34 represent an actual loss of safety function of a system or train and did not result in the loss of a single train for greater than technical specification allowed outage time. This issue was entered into the licensees corrective action program as Condition Report CR- ANO -2-2016- 01023.
05000220/FIN-2017002-02Nine Mile Point2017Q2Licensee-Identified ViolationThe following violation of very low safety significance (Green) was identified by Exelon and is a violation of NRC requirements which meets the criteria of the NRC Enforcement Policy for being dispositioned as an NCV.Technical Specification 6.4 Procedures, Section 6.4.1, states, in part, that, written procedures and administrative policies shall be established, implemented and maintained ... that cover the following activities: a. The applicable procedures recommended in Regulatory Guide (RG) 1.33, Appendix A, November 3, 1972.Appendix A of RG 1.33 lists typical safety-related activities which should be covered by written procedures. Section I.1 of RG 1.33 includes procedures for performing maintenance which can affect the performance of safety-related equipment and should be properly pre-planned and performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances. Section 4.3.4 of MA-AA-796-024, Scaffold Installation, Inspection, and Removal, Revision 11 states to ensure an adequate inspection is performed upon completion of scaffold erection for planned maintenance. Contrary to the above, on June 29, 2017 it was identified by Exelon staff that a scaffold surrounding the 11 feedwater flow control valve, FCV-29-141, would have prevented manual operation as required in accordance with EOP-1, NMP1 EOP Support Procedure, Revision 01601 Attachment 26, Reactor Pressure Valve Level Control Through Feedwater Pumps 11 and 12 flow control valves, and other special operating procedures during the previous 45 days.The inspectors evaluated the finding using IMC 0609.04, Initial Characterization of Findings, and Exhibit 2 of IMC 0609 Appendix A, The Significance Determination Process for Findings At-Power, issued June 19, 2012. The inspectors determined that the finding was of very low safety significance (Green), because the finding was not a design or qualification deficiency, did not represent a loss of system safety function, and did not screen as potentially risk significant due to seismic, flooding, or severe weather initiating event. Because this violation was determined to be of very low safety significance and entered into the CAP as IR 4027382, it is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy.
05000293/FIN-2017002-02Pilgrim2017Q2Reporting of Unplanned Scrams with Complications Performance Indicator for Feedwater Regulating Valve ScramThe inspectors identified an unresolved item (URI) associated with Entergys reporting of Unplanned Scrams with Complications PI data for the third quarter of 2016. Description. On September 6, 2016, PNPS operators initiated a manual reactor scram based on oscillating feed flow as a result of a malfunction with feedwater regulating valve (FRV) A. As a result of high reactor vessel water level, all of the reactor feed pumps tripped, the HPCI and RCIC systems isolated, and a Group 1 isolation signal was present, initiating closure of the MSIVs. In order to maintain pressure control of the reactor, SRV 3B was manually cycled. This event was reported under Licensee Event Report (LER) 05000293/2016-007-00. During the scram response, PNPS operators were required to use an SRV to maintain reactor pressure control, but Entergys submittal of PI data for the third quarter of 2016 does not count the scram as an Unplanned Scram with Complications, which is required by EN-LI-114, Regulatory Performance Indicator Process. This URI is being opened to determine if a performance deficiency exists pending resolution of the differing interpretation of guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guidance, Revision 7, at the next scheduled Reactor Oversight Process Working Group Meeting. (URI 05000293/2017002-02, Reporting of Unplanned Scrams with Complications Performance Indicator for Feedwater Regulating Valve Scram)
05000293/FIN-2016011-03Pilgrim2017Q1Failure to Issue Appropriate Corrective Actions to Preclude Repetition for the Causes of the September 2016 ScramThe NRC team identified a Green finding because Entergy did not issue appropriate CAPRs in accordance with Entergy procedure EN-LI-102, Corrective Action Process, Revision 28. Specifically, Entergy did not issue adequate CAPRs associated with Root Cause 1 of the feedwater regulating valve failure in September 2016 that resulted in a manual scram. As a result of the NRC teams questions, Entergy issued procedure 1.13.2, Vendor and Technical Information Reviews, Revision 0, as continuous use to ensure that planners will always have the checklist in-hand when planning work to ensure that appropriate vendor technical information is always included in applicable work instructions. Entergy entered the NRC teams concerns in the corrective action program as CR-PNP-2017-00687 and CR-PNP-2017-00936. The performance deficiency was more than minor because it is associated with the equipment performance attribute of the Initiating Events cornerstone and if left uncorrected, the performance deficiency would have the potential to lead to a more significant safety concern. Specifically, if left uncorrected, the performance deficiency could have the potential to result in repetition of a significant condition adverse to quality, loss of control of feedwater regulating valve 642A and a manual scram. The NRC team evaluated the finding using Exhibit 1, Initiating Events Screening Questions, of IMC 0609, Appendix A, Significance Determination Process for Findings At-Power, and determined this finding did not cause a reactor trip or the loss of mitigation equipment relied upon to transition the plant from the onset of a trip to a stable shutdown condition. Therefore, the NRC team determined the finding was of very low safety significance (Green). The NRC team determined that the finding had a cross-cutting aspect in the area of Human Performance, Procedure Adherence, because individuals did not follow processes, procedures, and work instructions. Specifically, Entergy did not follow procedure EN-LI-102, which provides the station standards for crafting a corrective action and states, in part, that the corrective action descriptions must be worded to ensure that the adverse condition or cause/factor is addressed (H.8).
05000250/FIN-2017001-01Turkey Point2017Q1Inadequate Operational Decision-Making Procedure Implementation Results in Feedwater Heater Water HammerGreen: A self-revealing finding was identified for the failure to adequately implement OP-AA-105-1000, Operational Decision Making (ODM) procedure that was used to establish plant conditions for the repair of the Unit 3 condensate tube leak in the 3B feedwater heater (FWH). The failure to implement all the steps of OP-AA-105-1000, Operational Decision Making, to establish plant conditions for the repair of the Unit 3 condensate tube leak in the 3B FWH was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the configuration control and procedure quality attributes of the initiating events cornerstone and adversely affected the cornerstones objective to limit the likelihood of events that upset plant stability. Specifically, not implementing the ODM procedure steps 2.3, Rigorous Evaluation, and Steps 2.5, Effective Implementation, of Attachment 3, resulted in an incorrect revision to procedure 3-ONOP-081.02 which led field operators to close the extraction steam to the 5B FWH too quickly and without due-precaution to prevent a rapid decrease in the 5B FWH shell pressure and caused significant water hammer and resulted in a fast load reduction and reactor trip. Using Inspection Manual Chapter (IMC) 0609, Appendix A, The Significance Determination Process (SDP) for Findings at Power, the inspectors determined that the issue had very low safety significance (Green) because the event did not cause both a reactor trip and a loss of mitigating equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. The finding was assigned a cross-cutting aspect of resources in the area of human performance, in that, leaders ensure that personnel, equipment, procedures, and other resources were available and adequate to support nuclear safety. Specifically, the ODM team did not ensure that the revised procedure was adequate to preclude water hammer. (H.1).
05000220/FIN-2017001-02Nine Mile Point2017Q1Failure to Identify and Correct a Non- Conforming Condition in Safety-Related UPSsGreen. The inspectors documented a self-revealing Green NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Actions, for the failure to identify and correct a non-conformance (an inadequate capacitor) in safety-related uninterruptable power supplies (UPSs) 162 and 172. Between 2008 and 2017, this non-conformance led to multiple component failures, loss of vital power supplies, plant transients, and in one case, loss of the emergency condenser safety function. Specifically, in 2003, during a preventative maintenance activity, NMPNS installed a commercially dedicated capacitor (part number C-805) that was not rated for the normal service temperature for the application. This resulted in chronic overheating, reduction of service life, and in seven cases failures (internal shorts of C-805) which resulted in the loss of the associated safety-related UPS. Upon identification, Exelon entered each failure into the CAP conducted an apparent cause evaluation (ACE) following the 2016 and 2017 failures, and developed corrective actions to replace the underrated capacitors. The performance deficiency was determined to be more than minor because it affected 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 the critical safety functions during shutdown as well as power operations. Specifically, the underrated capacitors failure resulted in the loss of a vital alternating current (AC) bus, a support system and in one case the unplanned loss of a safety function required to bring and maintain the plant in safe shutdown. In accordance with IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, a detailed risk assessment was required. Using the NMPNS Unit 1 Standardized Plant Analysis Risk (SPAR) Model Version: 8.21, model date January 28, 2010, a Region I senior reactor analyst ran a zero maintenance condition assessment with basic events for emergency condenser (EC) motor operated valve (MOV) 39-09R and EC MOV 39-10R, normally closed condensate return isolation valves, failed for a duration of one hour. The results were a CDP of 1.37E-08. The dominant risk sequences involved loss of feedwater and loss of offsite power. As a result, the finding is of very low safety significance (Green). The performance deficiency for this finding occurred in 2008. Because the performance deficiency occurred greater than 3 years ago and is not indicative of current performance based upon the corrective actions taken following the 2016 failure, there is no cross-cutting aspect assigned to this finding.
05000528/FIN-2017007-01Palo Verde2017Q1Failure to Analyze Shutdown Cooling and Feedwater Lines for High-Energy Line Break Pipe Whip EffectsGreen. The team identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, which states, in part, Measures shall be established to assure that applicable regulatory requirements and the design basis, as defined in 50.2 and as specified in the license application, for those structures, systems, and components to which this appendix applies are correctly translated into specifications, drawings, procedures, and instructions. Specifically, from August 11, 1982, to March 3, 2017, the licensee did not analyze dynamic pipe whip effects of a main feedwater line for a high-energy line break of a shutdown cooling line. In response to this issue, the licensee performed immediate and prompt operability evaluations and determined that the piping systems remained operable and could withstand the effects of a high-energy line break. This finding was entered into the licensees corrective action program as Condition Report CR-17-02815. The team determined that the failure to perform an adequate analysis for shutdown cooling and feedwater lines for high-energy line break pipe whip effects was a performance deficiency. This finding was more-than-minor because it was associated with the design control 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 failure to analyze the main feedwater piping for high-energy line break effects called the operability of the piping system into question. In accordance with Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, Exhibit 2, Mitigating Systems Screening Questions, the issue screened as hav ing very low safety significance (Green) because it was a design or qualification deficiency that did not represent a loss of operability or functionality; did not represent an actual loss of safety function of the system or train; did not result in the loss of one or more trains of non-technical specification equipment; and did not screen as potentially risk significant due to seismic, flooding, or severe weather. The team determined that this finding did not have a cross- cutting aspect because the most significant contributor to the performance deficiency did 3 not reflect current licensee performance. Specifically, the licensee performed the calculation in 1982 and revised it in 1991; therefore, the performance deficiency occurred outside of the nominal three-year period for present performance.
05000335/FIN-2016012-01Saint Lucie2016Q4Failure to Maintain Component Configuration Control Resulted in a Complicated Reactor TripTo Be Determined (TBD). A self-revealing finding was identified for the licensees failure to maintain configuration control of the inadvertent energization lockout relay manual synchronization circuitry as required by licensee procedures MA-AA-100 and ADM-08.12, during the October 2013 modification to the Unit 1 automatic main generator synchronization circuit. The performance deficiency was more than minor because it was associated with the human performance attribute of the Initiating Events Cornerstone and it adversely affected the associated cornerstone objective of limiting the likelihood of events that upset plant stability and challenge critical safety functions because it resulted in an actual plant trip. The inspectors screened the finding under the initiating events cornerstone using Attachment 4 (October 7, 2016) and Appendix A (June 19, 2012) of Inspection Manual Chapter 0609, Significance Determination Process (April 29, 2015). The inspectors determined the finding required a detailed risk evaluation because the finding caused a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition (e.g. loss of condenser and loss of feedwater). A preliminary significance characterization of White has been assigned. The preliminary finding involved the cross-cutting area of human performance associated with the cross-cutting aspect of avoiding complacency because the individuals involved failed to recognize and plan for the possibility of mistakes, latent issues, and inherent risk and failed to implement human error reduction tools associated with configuration control. (H.12)