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05000354/FIN-2018403-0230 September 2018 23:59:59Hope CreekLicensee-identifiedLicensee-Identified Violation
05000354/FIN-2018003-0330 September 2018 23:59:59Hope CreekSelf-revealinginadequate Procedures for Fuel Conditioning Results in Multiple Fuel LeaksThe inspectors documented a self-revealing Green NCV of TS 6.8.1, Procedures and Programs, when PSEG did not maintain adequate procedures for fuel conditioning. Specifically, PSEGs procedure for selecting the appropriate fuel PCI rules, NF-AB-440, BWR Fuel Conditioning, did not provide adequate guidance for protection of the fuel during restart from the April 2018 refueling outage (RF21). As a result, PSEGs selection non-conservative PCI rules resulted in three PCI fuel leaks.
05000354/FIN-2018003-0430 September 2018 23:59:59Hope CreekNRC identifiedEnforcement Action (EA)-18-044: EGM on Dispositioning BWR Licensee Noncompliance With TS Containment Requirements During Operations With A Potential For Draining The Reactor Vessel (EGM-11-003)From April 19 through April 29, 2018, HCGS performed OPDRVs without establishing secondary containment integrity. An OPDRV is an activity that could result in the draining or siphoning of the reactor pressure vessel water level below the top of fuel, without crediting the use of mitigating measures to terminate the uncovering of fuel. TS 3.6.5.1, Secondary Containment Integrity, requires that secondary containment integrity be maintained, and is applicable during OPDRVs. The required action for this specification without secondary containment integrity in this condition of applicability is to suspend OPDRVs. As reported in LER 05000354/2018-001, HCGS conducted the following OPDRVs during the period of secondary containment inoperability: Control rod drive mechanism replacements; Local power range monitor replacements; and Cavity let down via Reactor Water Clean Up system. Additionally, an unplanned OPDRV occurred due to RHR system relief valves seat leakage. NRC EGM 11-03, EGM on Dispositioning BWR Licensee Noncompliance With TS Containment Requirements During Operations With A Potential For Draining The Reactor Vessel, Revision 3, provides, in part, for the exercise of enforcement discretion only if the licensee demonstrates that it has met specific criteria during an OPDRV activity. The inspectors assessed that HCGS adequately implemented these criteria. In accordance with EGM 11-003, in order to continue to receive enforcement discretion, a license amendment request (LAR) must be submitted and accepted for review within 12 months of the NRC staffs publication of the generic change that occurred on December 20, 2016. The inspectors verified that PSEG submitted the required LAR on September 20, 2017 (ADAMS Accession No. ML17265A847), and that it was subsequently accepted by the NRC for review by a letter dated October 25, 2017 (ADAMS Accession No. ML17299A009). Corrective Action: PSEG submitted an LAR to adopt TS Task Force Traveler 542, Reactor Pressure Vessel Water Inventory Control, on September 20, 2017, that was subsequently accepted by the NRC for review on October 25, 2017. (After the end of the inspection period, on October 30, 2018, the NRC staff responded (ML18260A203) to PSEGs LAR dated September 20, 2017, and issued License Amendment No. 213 that revised the technical specifications to adopt TSTF-542, Revision 2. Corrective Action Reference: 20792923 15 Enforcement: Violation: TS 3.6.5.1, Secondary Containment Integrity, requires that secondary containment integrity be maintained, and is applicable during OPDRVs. The required action for this specification without secondary containment integrity in this condition of applicability is to suspend OPDRVs. Contrary to the above, from April 19 through April 29, 2018, HCGS performed OPDRVs without secondary containment integrity. Therefore, set and maintain secondary containment integrity during OPDRVs without suspending the operation was considered a condition prohibited by TSs as defined by 10 CFR 50.73(a)(2)(i)(B). Basis for Discretion: The NRC is exercising enforcement discretion in accordance with Section 3.5, Violations Involving Special Circumstances, of the NRC Enforcement Policy because all criteria described in EGM 11-003 were met and enforcement discretion was previously authorized by EA-2017-071; therefore, no enforcement action will be issued for this violation. The disposition of this violation closes LER 05000354/2018-001-00.
05000354/FIN-2018003-0530 September 2018 23:59:59Hope CreekNRC identifiedMinor 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.
05000354/FIN-2018403-0130 September 2018 23:59:59Hope CreekNRC identifiedSecurity
05000354/FIN-2018003-0230 September 2018 23:59:59Hope CreekSelf-revealingInadequate 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.
05000354/FIN-2018002-0130 June 2018 23:59:59Hope CreekSelf-revealingInadequate Instructions for Station Service Water Pump MaintenanceA self-revealing Green non-cited violation (NCV)of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified for PSEG providing inadequate written instructions for the performance of maintenance to ensure the station service water (SSW) system remains capable of performing its safety function. Specifically, the PSEG maintenance procedure for SSW pump and motor removal and replacement did not provide adequate instruction to prevent galvanic corrosion when connecting the B SSW pump to its seismic supports, which ultimately resulted in the pump failing its in-service test due to elevated vibration levels on February 18, 2018.
05000354/FIN-2018001-0131 March 2018 23:59:59Hope CreekNRC identifiedImplementing Procedures for Beyond Design Basis FLEX Mitigating Strategies Not FollowedA Green finding was identified by the inspectors for multiple examples of PSEG not following the station specific procedures that implement the Salem and HCGS Final Integrated Plans for Beyond Design Basis Diverse and Flexible Coping Strategies (FLEX) Mitigating Strategies, EM-SA-100-1000 and EM-HC-100-1000, respectively. Specifically, since compliance with the FLEX order was met on November 10, 2016, PSEG did not follow the common PSEG fleet preventive maintenance (PM) process and diesel fuel oil testing program procedures, MA-AA-716-210, CY-AB-140-410, and SC.OP-LB.DF-0001 for the annual fuel oil sampling of FLEX equipment. In addition to this, between December 6, 2017, and March 8, 2018, PSEG did not follow site specific procedures for FLEX equipment unavailability and mitigation capability protection in accordance with the HCGS and Salem procedures, OP-HC-108-115-1001 and OP-SA-108-115-1001, Operability Assessment and Equipment Control Program, respectively.
05000354/FIN-2018001-0231 March 2018 23:59:59Hope CreekNRC identifiedConcern Regarding As-Found Values for Safety Relief Valve Lift Setpoints Exceed Technical Specification Allowable LimitOn October 22, 2016, PSEG staff received results that the as-found setpoint tests for the main steam SRV pilot stage assemblies had exceeded the lift setting tolerance prescribed in technical specification 3.4.2.1. Specifically, ten of the 14 pilot stage assemblies tested experienced drift beyond the +/- 3 percent tolerance permitted by technical specification3.4.2.1. PSEG staff concluded that the cause of the setpoint drift was attributed to corrosion bonding between the pilot disc and seating surfaces, and that is consistent with industry experience. This condition was reportable under 10 CFR 50.73(a)(2)(i)(B) as any operation or condition which was prohibited by the plants technical specifications. Based on a review of the Cycle 20 test results of the main steam SRV pilot stage assembly setpoint tests, and the nature of the predominant failure mechanism (corrosion bonding), the inspectors concluded that an unacceptable number (greater than one) of SRVs likely and reasonably became inoperable at some indeterminate time during the operating cycle. As documented in Inspection Results, 71152, Observations in this report, there is a history of SRV lift setpoint test failures due to a long-standing, generic issue with Target Rock 2-stage SRVs. In particular, PSEG staff has been active with the Boiling Water Reactor Owners Group in evaluating SRV setpoint drift issues, and has an auditable history of their implementation of corrective actions, specifically intended to address their chronic SRV setpoint drift issue. Notwithstanding their efforts, PSEG staff has been unsuccessful in realizing an improvement in SRV performance in this area. PSEG staff has elected to implement additional corrective actions beginning the spring 2018 refueling outage. Specifically, they plan to reinstitute platinum coating of the pilot valve disc, and they plan to install the recently redesigned 3-stage Target Rock SRV in a phased approach.While this issue has not been effectively resolved, PSEGs post-test evaluations have demonstrated that, in their as-found condition, the SRVs would have satisfactorily performed their intended safety function (i.e.,mitigating the consequences of a postulated accident); and therefore, was of low safety significance.Additional NRC review is necessary to determine the appropriateness of PSEGs corrective actions to date, given the corrective action options available, and whether there was an associated violation of NRC requirements in addition to the consequential violation of technical specification 3.4.2.1. Planned Closure Actions: The NRC is continuing a review of the generic issue with the 2-stage Target Rock SRVs and the associated safety significance. The results of this review will be considered in determining the appropriateness of PSEGs corrective actions to date and whether an associated violation of NRC requirements existed, as well as the characterization of the consequential violation of technical specification 3.4.2.1.PSEG Actions: Specific to the fall 2016 SRV lift setpoint test results, all 14 of the SRVs were refurbished and adjusted as necessary; and were all tested and demonstrated to meet the required +/- 1 percent as-left tolerance prior to installation. PSEG also planned additional corrective actions, to be implemented during the spring 2018 refueling outage, including: 1) to re-evaluate the platinum coating process of the pilot valve disc for the existing 2-stage SRVs, and 2) to procure and install the recently re-designed 3-stage Target Rock SRV in a phased approach. Finally, PSEG communicated with the SRV vendor concerning the re-design of the 3-stage SRV following a prior identification (May 2015) of a substantial safety hazard to ensure that the re-design addressed the identified problems.Corrective Action References: Notification/Order 20747318, 20772038, and 80110848 This review closes LER 05000354/2016-003 and Supplemental LER 05000354/2016-003-01
05000354/FIN-2018410-0131 March 2018 23:59:59Hope CreekNRC identifiedSecurity
05000354/FIN-2017004-0231 December 2017 23:59:59Hope CreekNRC identifiedInadequate Design Control of Emergency Diesel Generator Speed SwitchThe inspectors identified a Green non-cited violation (NCV) of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion III, Design Control, because PSEG did not adequately provide for verifying or checking the adequacy of design by the performance of design reviews. Specifically, PSEGs equivalent change package (ECP) 80112197, did not assure that the design change ECP 80119127 was adequately reviewed prior to approval, which led to the installation of a defective model A-416 speed switch (SS), and subsequent failure of the D emergency diesel generator (EDG) to start. PSEGs immediate C/As were to remove the new failed model 416 SS and reinstall the prior model 8 SS. Additionally, PSEG entered this issue into their CAP, performed a causal evaluation, and assigned C/As to address their design change process (DCP) gaps by revising procedures and conducting training.This issue was more than minor because it was associated with the Design Control attribute of the Mitigating Systems cornerstone, and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). In accordance with IMC 0609.04, Initial Characterization of Findings, dated October 7, 2016, and Exhibit 2 of IMC 0609, Appendix A, The SDP for Findings At-Power, dated June 19, 2012, the inspectors determined that this finding is of very low safety significance (Green) because the performance deficiency was not a design or qualification deficiency, did not involve an actual loss of safety function, did not represent the actual loss of a safety function of a single train for greater than its technical specification (TS) allowed outage time, did not represent an actual loss of function of one or more non-TS trains of equipment designated as high safety-significant in PSEGs maintenance rule program (MRP) for greater than 24 hours. This finding had a cross-cutting aspect in the area of Problem Identification and Resolution, operating experience (OE), because PSEG did not ensure that the organization systematically and effectively collect, evaluate, and implement relevant internal and external OE in a timely manner. Specifically, PSEG did not effectively collect or review previous Part 21 issues related to the new SS as part of the OE review in their DCP. (P.5)
05000354/FIN-2017004-0131 December 2017 23:59:59Hope CreekNRC identifiedScaffold Installed with Insufficient Separation from Safety Related EquipmentThe inspectors identified a finding of very low safety significance (Green) and associated non-cited violation (NCV) of Title 10 of the Code of Federal Regulations(10 CFR) Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, because PSEG did not ensure adequate separation was maintained between temporary scaffolding and safety related equipment per procedure MA-AA-796-024, Scaffold Installation, Inspection and Removal. Specifically, 12 instances of scaffolding installed in the plant were identified by the inspectors with inadequate clearance to safety related equipment specified in PSEG procedures and no corresponding engineering evaluations to support these deviations. PSEGs corrective actions (C/As) included entering all of these discrepancies into their corrective action program (CAP), conducting walk downs of all scaffolding near safety related equipment, and initiating an operations standing order to ensure all scaffolding is reviewed by operations prior to and during installation.This issue was more than minor because it affected the protection against external factors (seismic) attribute of the mitigating systems cornerstone and its objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, 12 instances of scaffolding installed in the plant were identified by the inspectors with inadequate clearance to safety related equipment specified in PSEG procedures and no corresponding engineering evaluations to support these deviations. Additionally, this performance deficiency was similar to example 4.a in IMC 0612, Appendix E, Examples of Minor Issues, issued August 11, 2009, which states that the issue of failing to appropriately evaluate scaffold installation as required by procedures is more than minor if the licensee routinely failed to perform engineering evaluations on similar issues, or if the later evaluation determined that safety related equipment was adversely affected. The issue was evaluated in accordance with IMC 0609, Appendix A, The SDP for Findings At-Power, dated July 1, 2012, and determined to be of very low safety significance (Green) since it did not involve the loss or degradation of equipment or function specifically designed to mitigate a seismic event. This finding is related to the cross-cutting area of Human Performance, Field Presence, because PSEG managers did not ensure supervisory and management oversight of work activities, including contractors and supplemental personnel, such that nuclear safety is supported. Specifically, all of the scaffolding deficiencies that were identified by the inspectors had been in place for weeks without being noticed by PSEG personnel or supplemental workforce. (H.2)
05000354/FIN-2017007-0130 September 2017 23:59:59Hope CreekNRC identifiedSecondary Containment Integrity Not Maintained Due to Door not Properly DoggedGreen. The team identified a Green, non-cited violation (NCV) of Technical Specification (TS) 3.6.5.1, for failure to maintain secondary containment integrity. Specifically, while Hope Creek station was operating in mode 1, PSEG personnel did not ensure secondary containment door R-4302 was properly latched (dogged) closed in accordance with procedure CC-AA-201, Plant Barrier Control Program . The licensees failure to ensure the door was properly dogged closed was a performance deficiency and resulted in a degraded secondary containment barrier for approximately 44 hours. The team determined that PSEG operated in violation of the TS LCO which requires restoration of secondary containment integrity within 4 hours or be in at least hot shutdown within the next 12 hours and in cold shutdown within the following 24 hours. Following identification of the door condition by the team PSEG personnel properly dogged the door closed restoring secondary containment. This finding was determined to be of more than minor significance because it is associated with the configuration control attribute of the Barrier Integrity cornerstone and affected the cornerstone objective of providing reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, in its un-dogged position the door would not have remained closed, as required to maintain secondary containment integrity, during all design basis accidents. Using IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power , Exhibit 3, Barrier Integrity Screening Questions, the team determined that this finding was of very low safety significance (Green) because the finding did not represent an actual open pathway in the physical integrity of primary reactor containment (valves, airlocks , etc.), containment isolation system (logic and instrumentation), and heat removal components. The finding was determined to be associated with the cross-cutting area of Human Performance - Procedure Adherence (H.8), in that, licensee personnel did not follow process, procedures, and work instructions which required the secondary containment door to be closed and dogged.
05000354/FIN-2017002-0130 June 2017 23:59:59Hope CreekLicensee-identifiedLicensee-Identified ViolationOn February 27, 2017, during power ascension after completing a rod pattern adjustment, HCGS exceeded the fuel conditioning limit specified in their Boiling Water Reactor ( BWR ) Fuel Conditioning procedure, NF -AB- 440. Specifically, when all of the control rods were at their target positions, with reactor power at 89 percent RTP, the on- shift Reactor Engineer ran a core monitor predictor case which showed three percent more margin to the fuel conditioning limit than the predictions used in the written reactivity management plan. The Reactor Engineer then ran core predictions using this result. With these results, the Reactor Engineer recommended to the Control Room Supervisor to proceed to 100 percent RTP with no ramp rate restrictions. PSEG completed power ascension to 100 percent RTP and then a subsequent core monitor predictor case showing the fuel conditioning limit had been exceeded (maximum nodal power of 0.55 kilowatt/ foot which exceeded the maximum allowed value of 0.450 kilowatt/ foot). PSEG determined that weaknesses in the reactivity maneuver (ReMA) process and the application of the ReMA process allowed the on- shift Reactor Engineer to make a knowledge- based decision and implement a change to the ReMA without increased monitoring requirements. Failure to operate within the procedurally specified limits was a performance deficiency. TS 6.8.1.a requires, in part, that written procedures be established and implemented covering the procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. OP -AB- 300- 1003, BWR Reactivity Maneuver Guidance, states in step 4.2.11.4, the high limit should be set at the limit specified in NF- AB- 440. In Attachment 5 of NF -AB -440, operators are directed to maintain the fuel conditioning limits within the specified maximum allowable threshold of 0.45 kilowatt/ foot . Contrary to the TS 6.8.1.a requirements specified above, PSEG did not implement their ReMA in accordance with their procedures for reactivity maneuvers. Shortly after reaching 100 percent RTP power, PSEG identified that the fuel conditioning limit had been exceeded and took immediate actions to reduce power per procedure, categorize the issue as a level 3 reactivity management event, and analyze off -gas and reactor coolant samples to ensure no indications of a fuel defect existed as a result of the event. The issue was entered into PSEGs CAP as NOTF 20757793, and the 20 operating department implanted prompt action to communicate the cause of the error to all operators and qualified reactor engineers. In addition, procedural reviews and additional management observations of power maneuvering activities were put in place. The inspectors determined this issue was more than minor because the performance deficiency impacted the Human Performance attribute of the Barrier Integrity Cornerstone and adversely impacted the cornerstone objective to provide reasonable assurance that the physical design barrier (fuel cladding) protect the public from radionuclide releases caused by accidents or events. Specifically, PSEG not adhering to the fuel conditioning limits specified in their procedures could result in fuel clad damage (increased probability of fuel failure as a result of pellet -clad interaction) and adversely impact nuclear safety . The inspectors determined that the issue was of very low safety significance (Green) because no apparent fuel damage occurred.
05000354/FIN-2017008-0131 March 2017 23:59:59Hope CreekSelf-revealingImproper Preventive Maintenance Deletion Results in the Inoperability of the A Control Room HVAC SystemGreen . A self -revealing Green non- cited violation ( NCV ) of Technical Specification ( TS ) 6.8.1, Procedures and Programs, as described in Regulatory Guide (R G) 1.33, Revision 2, February 1978, was identified when PSEG did not maintain an appropriate preventive maintenance ( PM ) schedule for the A control room heating, ventilation and air conditioning (HVAC ) system. Specifically, PSEG inadvertently deactivated a PM activity to perform periodic cleaning of the A control room return air fan (AVH -415) low flow switch pitot tubes that resulted in the A train of the control room emergency filtration ( CREF ) to be 3 unavailable on November 23, 2016 . PSEG performed corrective actions to clean the clogged pitot tubes associated with the AH -415 flow switch, re -activate the inadvertently deleted PM, and identify the extent of condition in other systems . This issue was more than minor because it was associated with the structures, systems and components ( SSC ) and barrier performance attribute of the Barrier Integrity Cornerstone (under the areas to measure associated with the radiological barrier function of the control room); 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. The inspectors determined that the finding was of very low safety significance (Green) in accordance with IMC 0609, Attachment 4 and Appendix A, Exhibit 3, because the finding only represented a degradation of the radiological barrier function for the control room. The inspectors determined that there was no cross -cutting aspect associated with this finding since it was not representative of current PSEG performance. Specifically, the causal factors associated with this finding occurred in 2010, which was outside the nominal three- year period of consideration and were not considered representative of present performance in accordance with IMC 0612
05000354/FIN-2017001-0231 March 2017 23:59:59Hope CreekSelf-revealingInadequate Preventive Maintenance Replacement Schedule for the HPCI Overspeed Trip Tappet Reset Spring)A self-revealing Green non-cited violation (NCV) of TS 6.8.1, Procedures, was identified because PSEG did not establish an appropriate preventive maintenance (PM) schedule for the high pressure coolant injection (HPCI) overspeed trip system reset spring. Specifically, PSEGs major inspection PM frequency and scope justification for the HPCI turbine major inspection and overhaul PM was determined to be inadequate. As a result, the HPCI overspeed tappet reset spring was not replaced for 8.5 years, resulting in the reset springs force falling below the required force range. As a result, on April 7, 2016, the HPCI turbine tripped and then reset shortly after being started because of the low reset spring force, making the HPCI system unable to automatically initiate and inject at rated flow within 35 seconds as required per TSs. PSEGs immediate CAs included replacing the reset spring, adding replacement of the spring to the 6.87 year HPCI environmental qualification (EQ) PM, and evaluating the storage requirements for similar springs in inventory. The issue was more than minor because it was associated with the Equipment Performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the inadequate PM frequency and scope for the reset spring resulted in the low spring force due to the springs age allowing the trip tappet assembly to float upward on a HPCI system start-up and tripping the turbine when no actual overspeed condition existed. In accordance with IMC 0609.04, Initial Characterization of Findings, dated October 7, 2016, and Exhibit 2 of IMC 0609, Appendix A, The SDP for Findings At-Power, dated June 19, 2012, the inspectors determined that this finding was Green because it was not a design or qualification deficiency, did not involve an actual loss of safety function, did not represent the actual loss of a safety function of a single train for greater than its TS allowed outage time and did not represent an actual loss of function of one or more non-TS trains of equipment designated as high safety-significant in PSEGs MRP for greater than 24 hours. Specifically, following the overspeed trip on April 7, 2016, HPCI was restored to operable status in approximately 36 hours. The inspectors determined there was no cross-cutting aspect associated with this finding since it was not representative of current PSEG performance as the inadequate PM schedule for the HPCI overspeed trip tappet assembly reset spring involved multiple missed opportunities to re-evaluate the PM scope and frequency from 2005 through 2009. In accordance with IMC 0612, the causal factors associated with this finding occurred outside the nominal three-year period of consideration and were not considered representative of present performance.
05000354/FIN-2017001-0131 March 2017 23:59:59Hope CreekSelf-revealingInadequate Control of Defective Material Causes the A EDG to Fail to StartA self-revealing very low safety significance (Green) NCV of Title 10 of the Code of Federal Regulations (10 CFR) 50, Appendix B, Criterion VIII, Identification and Control of Materials, Parts and Components, was identified because PSEG did not have adequate control measures to prevent the use of defective parts. Specifically, following the C emergency diesel generator (EDG) speed switch (SS) failure on August 4, 2016, PSEGs control measures did not prevent the installation of the previously failed SS, with susceptible degradation due to the components previous failure history, known manufacturing and design deficiencies, and damage sustained during the receipt inspection process, into the A EDG on January 6, 2017. Consequently, less than one month later on February 3, 2017, the A EDG failed to start due to a failed SS. PSEGs corrective actions (CAs) included replacing the SS, identifying an equivalent replacement for the currently installed SS design, scheduling the replacement of the new SSs, and performing extent of condition inspections and testing of all the installed and spare EDG SSs. The issue was more than minor because it was associated with the Equipment Performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective of ensuring the reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, PSEGs installation of a previously failed SS, with susceptible degradation due to the components previous failure history, known manufacturing and design deficiencies, and damage sustained during the receipt inspection process, into the A EDG on January 6, 2017, led to the A EDG failing to start on February 3, 2017. In accordance with IMC 0609.04, Initial Characterization of Findings, dated October 7, 2016, and Exhibit 2 of IMC 0609, Appendix A, The SDP for Findings AtPower, dated June 19, 2012, the inspectors determined that this finding was Green because it was not a design or qualification deficiency, did not involve an actual loss of safety function, did not represent the actual loss of a safety function of a single train for greater than its technical specifications (TSs) allowed outage time, and did not represent an actual loss of function of one or more non-TS trains of equipment designated as high safety-significant in PSEGs maintenance rule program (MRP) for greater than 24 hours. This finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Evaluation, because PSEG did not thoroughly evaluate issues to ensure that resolutions address causes and extent of conditions commensurate with their safety significance. Specifically, PSEG did not thoroughly evaluate their previous failure analyses (FA) performed on the failed SSs to ensure that resolutions addressed the actual failure mode(P.2).
05000354/FIN-2017001-0331 March 2017 23:59:59Hope CreekSelf-revealingOperations with a Potential to Drain the Reactor Vessel (OPDRV) Without Secondary ContainmentOn October 23, 24, and 31, 2016, during a planned refueling outage with the reactor cavity flooded up in Mode 5, Hope Creek conducted multiple OPDRVs without an operable secondary containment. The conduct of an OPDRV without establishing secondary containment integrity is a condition prohibited by TS as defined by 10 CFR 50.73(a)(2)(i)(B). Secondary containment is required by TS 3/4.6.5.1 in Operational Condition (*), which is a condition when recently irradiated fuel is being handled during an OPDRV. The required action for this specification is to suspend handling recently irradiated fuel and OPDRV operations. In this case, the specific OPDRVs were control rod drive mechanism replacements (8:40 a.m. on October 23, 2016, through 10:50 p.m. on October 23, 2016), local power range monitor replacements (10:50 p.m. on October 23, 2016, through 8:07 a.m. on October 24, 2016), additional control rod drive mechanism and local power range monitor replacements (8:07 a.m. on October 24, 2016, through 8:23 a.m. on October 25, 2016), and the fill and vent for the A and B RRP seal (11:21 a.m. on October 31, 2016, through 12:02 p.m. on November 1, 2016). The OPDRVs were completed in accordance with PSEG procedure OP-HC-108-102, "Management of Operations with the Potential to Drain the Reactor Vessel (OPDRV)," Revision 5, dated October 6, 2016. These OPDRVs were completed and exited at 12:02 p.m. on November 1, 2016. The NRC issued EGM 11-003, Revision 3, Enforcement Guidance Memorandum on Dispositioning Boiling Water Reactor Licensee Noncompliance with Technical Specification Containment Requirements During Operations with a Potential For Draining the Reactor Vessel, on January 15, 2016, which provides, in part, for the exercise of enforcement discretion only if the licensee demonstrates that it has implemented specific interim actions during any OPDRV activity. The inspectors determined that PSEGs implementation of these specific interim actions during these OPDRV activities were adequate and met the intent of EGM 11-003, Revision 3. The inspectors assessments of PSEGs implementation of these criteria during each of the multiple OPDRV activities are described below: The inspectors observed that, as required by the EGM, the OPDRV activity was logged in the control room narrative logs and that the log entry appropriately recorded the safety-related pump (B RHR) that was the standby source of makeup designated for the evolution. The inspectors noted that the reactor vessel water level was maintained at least 22 feet and 2 inches over the top of the reactor pressure vessel (RPV) flange in compliance with the minimum water level allowed by Hope Creek TS limiting condition for operation (LCO) 3.9.8 applicability. The inspectors also noted that at least one safety-related pump was the standby source of makeup designated in the control room narrative logs for the evolution with the capability to inject water equal to, or greater than, the maximum potential leakage rate from the RPV for a minimum time period of 4 hours. PSEG reported that the worst case estimated time to drain the reactor cavity to the RPV flange was 36.6 hours, which met the EGM criteria of greater than 24 hours. The inspectors verified that the OPDRV was not conducted in Mode 4 and that PSEG did not move recently irradiated fuel during the OPDRV. The inspectors noted that PSEG had in place a contingency plan for isolating the potential leakage path. The inspectors verified that two independent means of measuring RPV water level (one alarming) were available for identifying the onset of loss of inventory events with sufficient time to close secondary containment before reactor water level reached the top of the RPV flange. Technical Specification 3.6.5.1 is applicable in Operational Conditions 1, 2, 3 and (*). This TS requires that secondary containment integrity shall be maintained. Operational Condition (*) is defined, in part, as being during OPDRV. TS 3.6.5.1, action b, states, in part, in operational condition (*) suspend operations with a potential for draining the reactor vessel. Contrary to the above, between 8:40 a.m. on October 23, 2016, and 12:02 p.m. on November 1, 2016, Hope Creek Generating Station did not maintain secondary containment integrity while conducting OPDRV activities. Because the violation was identified during the discretion period described in EGM 11-003 Revision 3, the NRC is exercising enforcement discretion in accordance with NRC Enforcement Policy Section 2.2.4, Exceptions to Using Only the Operating Reactor Assessment Program, and Section 3.5, Violations Involving Special Circumstances, and, therefore, will not issue enforcement action for this violation. In accordance with EGM 11-003 Revision 3, each licensee that receives discretion must submit a license amendment request within 4 months of the NRC staffs publication in the Federal Register of the notice of availability for a generic change to the STS to provide more clarity to the term OPDRV. The inspectors observed that PSEG is tracking the need to submit a license amendment request in its CAP as NOTF 20559547 (Order 70138857). No findings were identified. This LER is closed.
05000354/FIN-2017403-0131 March 2017 23:59:59Hope CreekLicensee-identifiedLicensee-Identified Violation
05000354/FIN-2016004-0131 December 2016 23:59:59Hope CreekSelf-revealingTrip of Protected RWCU Pump during Maintenance ActivityGreen. A self-revealing very low safety significance (Green), non-cited violation of Title 10 of the Code of Federal Regulations (10 CFR) 50.65(a)(4) was identified for inadequately assessing and managing risks associated with maintenance activities to prevent plant transients that upset plant stability. Specifically, because PSEG did not identify a conflict with the reactor water cleanup (RWCU) pump trip logic prior to conducting a planned breaker swap, the A RWCU pump tripped while it was credited to as a defense-in-depth system for decay heat removal (DHR). PSEG assigned a corrective action to perform a work group evaluation and address lessons learned from this event. The issue was more than minor because it was associated with the Equipment Performance (availability) attribute of the Initiating Event cornerstones and adversely affected its objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown. Additionally, this issue was similar to IMC 0612, Appendix E, examples 7.e and 7.f, in that the resulting increased risk put the plant into a higher risk category. In this case, the plant risk would have been reclassified from Yellow to Orange when RWCU pump was unavailable during residual heat removal (RHR) shutdown cooling outage window. The inspectors evaluated the finding using IMC 0609, Appendix G, Shutdown Operations Significance Determination Process, Attachment 1, Exhibit 1, Initiating Event Screening Questions. The inspectors determined the finding was Green because no quantitative phase 2 analysis was required, and RWCU system was not identified as a major system on Table G1 for Decay Heat Removal safety function. This finding had a cross-cutting aspect in the area of Human Performance, Work Management, because PSEG did not identify and appropriately manage risk associated with the breaker swap activity. Specifically, PSEGs work order to swap the breaker was not planned or scheduled during a RWCU system outage window where the plant shutdown safety risk would have been properly managed (H.5).
05000354/FIN-2016004-0231 December 2016 23:59:59Hope CreekSelf-revealingInadequate Implementation of a Design Change Causes Multiple B Channel Instruments to be InoperableGreen. A self-revealing Green non-cited violation (NCV) of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion III, Design Control, and Technical Specification (TS) 3.0.4 was identified for PSEG not effectively implementing the design change package (DCP) process. Specifically, PSEG inadequately implemented their configuration change control procedure, CC-AA-103, and a design change package (DCP 80108179) for rerouting a B channel instrument line (LT-N085B) by not fully restoring the system upon completion of the DCP on November 3, 2016. As a consequence, multiple main control room (MCR) indicators became inoperable without PSEG identifying the problem until operators transitioned the reactor plant to startup, Operational Condition (OPCON) 2 or Mode 2, on November 9, 2016. This constituted a violation of TS 3.0.4 because PSEG transitioned to OPCON 2 while multiple limiting conditions for operability (LCO) were not met. PSEGs corrective actions included securing the reactor startup, conducting system troubleshooting/restoration prior to recommencing the reactor startup, completing an apparent cause evaluation of the issue and an extent of condition on all DCPs completed during the refueling outage, and revising their preventive maintenance procedures to ensure that the instrument racks are properly backfilled on a frequent reoccurring basis and following any instrument rack maintenance. The issue was more than minor because it was associated with the human performance attribute of the mitigating systems cornerstone and adversely affected its objective to ensure the availability and reliability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage), in that, multiple B channel reactor water level instruments that fed the RPS logic were inoperable. Additionally, the finding was similar to IMC 0612, Appendix E, example 3.g, which describes an operator not following a procedure and making a mode change without all the required equipment operable. The IMC 0609, Appendix G, Shutdown Operations Significance Determination Process (SDP), Section 4.1 Scope, states that if the plant is shut down and the entry conditions for Residual Heat Removal/Decay Heat Removal (RHR/DHR) and RHR/DHR cooling have not been met then Appendix G does not apply. Because of this, the finding was evaluated using IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power. Per Exhibit 2, Mitigating Systems Screening Questions, the finding was determined to be of very low safety significance (Green) because although the finding represented a deficiency affecting the qualification of a mitigating system and caused multiple B channel instruments to be inoperable, it did not represent a loss of system and/or function, or an actual loss of function for greater than its TS allowed outage time. This finding had a cross-cutting aspect in the area of Human Performance, Work Management, in that PSEG did not implement a process of planning, controlling, and executing work activities such that nuclear safety was the overriding priority. Specifically, PSEG did not ensure restoration activities for the completed DCP ensured the affected instrumentation was returned to an operable status. (H.5)
05000354/FIN-2016003-0430 September 2016 23:59:59Hope CreekSelf-revealingInadequate Corrective Actions for Main Control Room Chiller Positioner FailureA self-revealing non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, was identified for PSEGs inadequate corrective actions to address a condition adverse to quality (CAQ). Specifically, PSEGs corrective actions to address a December 2013 failure of the A main control room (MCR) chiller pressure control valve (PCV) positioner were inadequate and did not ensure that the component was appropriately managed in their shelf life program. As a result, PSEG restored the A MCR chiller with a PCV positioner that exceeded its specified shelf life by 10 years, and ultimately failed due to its age. PSEGs corrective actions included conducting an extensive extent of condition (EOC) of similar positioners installed at the site (both Salem and Hope Creek), reviewing the shelf life program, and documenting an operability evaluation (70189201) for the currently installed positioners until they can be replaced. This finding is more than minor because it was associated with the equipment performance attribute of the mitigating systems cornerstone, and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). The degraded positioners being installed in both MCR chillers affected the reliability and availability of the A and B MCR chillers, which provide cooling for the MCR, emergency switchgear rooms, and the safety auxiliaries cooling system pump rooms. Using Exhibit 2 of IMC 0609, Appendix A, the inspectors determined that this finding is of very low safety significance (Green) because, although the performance deficiency (PD) affected the design/qualification of the A MCR chiller operability, it did not result in an actual loss of safety system function because the B chiller was still available, and it did not represent a loss of function of one or more than one train for more than its TS allowed outage time or greater than 24 hrs. The B MCR chiller remained available and the A MCR chiller was restored to an operable status within 6 hours of failing. This finding had a cross-cutting aspect in the area of Human Performance, Procedure Adherence, because PSEG did not follow the process and procedure that ensures the shelf life program for safety-related components is properly maintained. Specifically, PSEG did not ensure that the shelf life of the MCR chiller PCV positioners were adequately managed in the shelf life program by verifying the correct shelf life of 14 years was correctly assigned.
05000354/FIN-2016003-0230 September 2016 23:59:59Hope CreekNRC identifiedUntimely Submittal of an LER for a Condition that Could Have Prevented Fulfillment of a Safety FunctionThe Inspectors identified a Severity Level IV (SLIV) NCV of 10 CFR 50.73(a)(2)(v) for because PSEG did not submit a Licensee Event Report (LER) within 60 days of an event or condition that could have prevented the fulfillment of a safety function at any time within 3 years of the date of discovery. Specifically, while performing an in-service retest of the HPCI system, the turbine tripped on overspeed shortly after startup due to low spring force on the overspeed assembly reset spring. This condition allowed the overspeed tappet to trip the turbine without an actual overspeed condition present, rendering the system inoperable and unable to automatically initiate and inject at rated flow within 35 seconds as required per TSs and the design basis, thus preventing the fulfillment of a safety function. PSEGs corrective actions included documenting the missed LER in the corrective action program (CAP) in notification (NOTF) 20741046, and submitted LER 05000354/2016001-00 under 10 CFR 50.73(a)(2)(v)(D) on October 04, 2016. The inspectors evaluated this issue using the traditional enforcement process because the performance deficiency had the potential to impede or impact the NRCs regulatory process. Specifically, the failure to submit an LER under 10 CFR 50.73(a)(2)(v)(D) within 60 days of an event or condition that could have prevented the fulfillment of a safety function at any time within 3 years of the date of discovery could impact the NRCs regulatory process. The inspectors reviewed this issue in accordance with IMC 0612 and the Enforcement Manual; violations of 10 CFR 50.73 are dispositioned using the traditional enforcement process. The inspectors reviewed Section 6.9.d.9 of the NRC Enforcement Policy and determined this violation was a Severity Level IV violation because PSEG did not submit the LER as required by 10 CFR 50.73 did not cause the NRC to reconsider a regulatory position or undertake substantial further inquiry. The performance deficiency was screened against the Reactor Oversight Process (ROP) per the guidance of IMC 0612, Appendix B, Issue Screening, and no associated ROP finding was identified. In accordance with IMC 0612, Appendix B, this traditional enforcement issue is not assigned a cross-cutting aspect.
05000354/FIN-2016003-0130 September 2016 23:59:59Hope CreekSelf-revealingInadequate Implementation of Adverse Condition Monitoring Actions for the High Pressure Coolant Injection SystemA self-revealing preliminary White finding and apparent violation (AV) of Title 10 of the Code of Federal Regulations (CFR), Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, and Technical Specification (TS) 3.5.1.c, Emergency Core Cooling Systems - High Pressure Coolant Injection (HPCI), was identified because PSEG did not detect and act upon an adverse trend of water intrusion into the HPCI oil system. Specifically, PSEG did not adequately implement procedure OP-AA-108-111, Adverse Condition Monitoring (ACM) and Contingency Planning, and the ACM HC 15-008 action to perform monthly HPCI turbine oil analysis for water contamination with known steam leakage by the Steam Admission Valve (FD-F001). Because these monthly oil samples were collected but were not analyzed for water content, PSEG did not identify significant moisture contamination in the HPCI oil system and thus take the necessary response actions. As a result, on August 6, 2016, the HPCI governor control valve (FV-4879) failed to stroke open as required due to moisture-induced corrosion that degraded its hydraulic actuator (EG-R). Consequently, PSEG violated TS 3.5.1.c because, based on failure of the FV-4879 and the EG-R to actuate on August 6, 2016, the NRC determined that the HPCI system was inoperable for a period greater than its technical specification (TS) allowed outage time of 14 days. PSEGs immediate corrective actions included entering the issue into their Corrective Action Program (CAP) (NOTFs 20737383, 20738402 and 20738403); repairing the HPCI turbine insulation; replacing the HPCI EG-R; flushing the HPCI turbine oil system; and replenishing the system with new oil. This finding is more than minor because it adversely affected the equipment performance attribute of the Mitigating Systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, a loss of safety function occurred when elevated water concentration in the HPCI oil system corroded the EG-R, preventing the FV-4879 valve from opening and the HPCI system from starting/running. This resulted in HPCI system inoperability for greater than the 14 days allowed by TS. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 2 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, the inspectors screened the finding for safety significance and determined that a detailed risk evaluation (DRE) was required based on the HPCI system being inoperable for greater than the TS allowed outage time of 14 days. The DRE was performed by a Region I senior reactor analyst (SRA) and concluded that the condition resulted in an increase in core damage frequency (CDF) of low E-6/yr., or of low-to-moderate safety significance (White). The SRA determined the increase in Large Early Release Frequency (LERF) was low E-7/yr., consistent with the significance determined for the internal and external event CDF. This finding had a cross-cutting aspect in the area of Human Performance, Conservative Bias, because PSEG did not use decision-making practices that emphasize prudent choices over those that are simply allowable. In addition, PSEG did not take timely action to address degraded conditions commensurate with their safety significance.
05000354/FIN-2016404-0130 September 2016 23:59:59Hope CreekNRC identifiedSecurity
05000354/FIN-2016404-0230 September 2016 23:59:59Hope CreekNRC identifiedSecurity
05000354/FIN-2016003-0330 September 2016 23:59:59Hope CreekSelf-revealingInadequate Procedure Adherence Resulted in a Loss of Shutdown CoolingA self-revealing non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, occurred when PSEG did not follow procedure during the transition from Cold Shutdown to refueling operations while filling up the reactor pressure vessel (RPV) to support RPV head cooling in preparation for reactor disassembly. This resulted in an automatic isolation of the operating residual heat removal (RHR) pump while it was providing decay heat removal in shutdown cooling. PSEG has entered this issue into their corrective action program (CAP) in notification (NOTF) 20684861, and corrective actions included performing a root cause evaluation for the event, revising the operating procedures to provide clarity, and conducting training with all operators on the lessons learned from the event. This issue was evaluated in accordance with IMC 0612, Appendix B, and determined to be more than minor since it was associated with the human performance attribute of the Initiating Events cornerstone and adversely affected its objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown, as well as power operations. The finding was evaluated using IMC 0609, Appendix G, Shutdown Operations Significance Determination Process (SDP), and per Attachment 1, Exhibit 2, required a Phase 2 risk evaluation which determined the safety significance of this performance deficiency to be in the mid E-8 range, or of very low safety significance (Green). The inspectors determined this finding has a cross-cutting aspect in the area of Human Performance, Conservative Bias, in that the operator did not use decision-making practices that emphasized prudent choices over those that are simply allowable, and the operators proposed action was not determined to be safe prior to proceeding with the action. Specifically, the operator did not ensure his actions were safe prior to aligning and operating the feedwater system to fill the RPV during plant cooldown using an uncommon method.
05000354/FIN-2016007-0130 June 2016 23:59:59Hope CreekNRC identifiedInadequate Testing of Emergency Diesel Generator Takeover Switches and Remote Shutdown Panel Transfer/Isolation RelaysThe team identified a finding of very low safety significance, involving a noncited violation of Hope Creek Operating License Condition 2.C.(7) for failure to implement and maintain in effect all provisions of the approved Fire Protection Program (FPP). Specifically, PSEG did not adequately test the Emergency Diesel Generator (EDG) emergency takeover switches and Remote Shutdown Panel (RSP) transfer/isolation relays to assure they were capable of performing their intended function, as described in the FPP. PSEG subsequently performed additional testing and a detailed operability evaluation, which concluded that the effected equipment would function as intended. This finding was more than minor because it was similar to example 3.k of Inspection Manual Chapter (IMC) 0612, Appendix E, "Examples of Minor Issues," and was associated with the Protection Against External Factors (e.g., fire) attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability and reliability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). The team performed a Phase 1 Significance Determination Process (SDP) screening, in accordance with IMC 0609, Appendix F, "Fire Protection SDP." This issue screened to very low safety significance (Green) because it did not affect the ability to reach and maintain a stable hot shutdown condition. The finding did not have a cross-cutting aspect because it was a legacy issue and was not considered to be indicative of current licensee performance.
05000354/FIN-2016007-0230 June 2016 23:59:59Hope CreekNRC identifiedInadequate Testing of the Remote Shutdown Panel RCIC Flow Control Circuit (The team identified a finding of very low safety significance, involving a noncited violation of Hope Creek Technical Specification (TS) Surveillance Requirement (SR) 4.3.7.4.2, "Remote Shutdown System Instrumentation and Controls." Specifically, PSEG did not adequately test all components of the Reactor Core Isolation Cooling (RCIC) flow control circuit on the RSP to demonstrate operability. This finding was more than minor because it was similar to example 3.k of Inspection Manual Chapter (IMC) 0612, Appendix E, and was associated with the procedure quality attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of the RCIC system. The inspectors evaluated this finding using IMC 0609.04, "Initial Characterization of Findings," and IMC 0609, Appendix A, Exhibit 2, "Mitigating Systems Screening Questions." This issue was determined to be of very low safety significance (Green) because it did not represent an actual loss of function of a single train mitigating system for greater than its TS Allowed Outage Time. The finding did not have a cross-cutting aspect because it was a legacy issue and was not considered indicative of current licensee performance.
05000354/FIN-2016002-0130 June 2016 23:59:59Hope CreekNRC identifiedInadequate Maintenance Rule Monitoring of Multiple Systems, including the Effluent Radiation Monitoring System and the Reactor Core Isolation Cooling SystemThe inspectors identified a Green NCV of Title 10 of the Code of Federal Regulations (10 CFR) 50.65(a)(2) due to an inadequate maintenance rule (MR) monitoring of the effluent radiation monitoring system (RMS) and the reactor core isolation cooling (RCIC) system. Specifically, PSEG did not properly evaluate maintenance rule functional failures (MRFFs) for both systems in accordance with its Maintenance Rule Program (MRP). Consequently, unaccounted for maintenance preventable functional failures (MPFFs) in both the effluent RMS and RCIC systems caused each system to exceed their MR performance criteria, requiring (a)(1) evaluations. PSEGs corrective actions (CAs) include placing the effluent RMS system in (a)(1) monitoring status and establishing monitoring goals, evaluating the RCIC system for (a)(1) monitoring status, and performing procedure revisions of affected procedures. The performance deficiency was determined to be more than minor in accordance with IMC 0612, Appendix B, Issue Screening, dated September 7, 2012, because it was associated with both the Plant Facilities/Equipment and Instrumentation attribute of the Public Radiation Safety cornerstone (effluent RMS) and the Equipment Performance attribute of the Mitigating Systems cornerstone (RCIC). The inspectors determined that this finding was of very low safety significance (Green) using: IMC 0609, Appendix D, Public Radiation Safety Significance Determination Process, dated February 12, 2008; and, Exhibit 2 of IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012. This finding was associated with a cross-cutting aspect of Human Performance, Consistent Process, which states that individuals use a consistent, systematic approach to make decisions. Specifically, PSEG did not to properly evaluate the impact of equipment failures in the effluent RMS and RCIC system when making MRFF determinations. (H.13)
05000354/FIN-2016002-0330 June 2016 23:59:59Hope CreekLicensee-identifiedLicensee-Identified ViolationAccording to 10 CFR 50.74, each licensee shall notify the NRC within 30 days of a change in an operators or senior operators status including termination of any operator or senior operator. Contrary to this requirement, in NOTF 20727574, PSEG identified that Hope Creek staff did not notify the NRC of the resignation of a licensed reactor operator. The licensed reactor operator resigned on November 12, 2015, but PSEG did not notify the NRC of the change in status until May 9, 2016. This issue meets the criteria for a SL IV violation because the May 9, 2016, notification did not result in increased inspection activities or cause the NRC to reconsider a regulatory position.
05000354/FIN-2016002-0230 June 2016 23:59:59Hope CreekNRC identifiedFailure to Scope the Filtration, Recirculation, and Ventilation System Effluent Radiation Monitor in the Maintenance RuleThe inspectors identified a Green NCV of 10 CFR 50.65(b)(2) due to inadequate MRP monitoring of effluent RMS performance. Specifically, PSEG did not include the filtration, ventilation, and recirculation system (FRVS) ventilation stack radiation monitor within the scope of the MRP. PSEGs CAs include scoping the FRVS ventilation stack radiation monitor into the MRP, evaluating the components historical performance, and placing the system in (a)(1) monitoring status. The inspectors determined the performance deficiency was more than minor in accordance with IMC 0612, Appendix B, Issue Screening, dated September 7, 2012, because it was associated with the Plant Facilities/Equipment and Instrumentation attribute of the Public Radiation Safety cornerstone, and adversely affected the cornerstone objective to ensure adequate protection of public health and safety from exposure to radioactive materials released into the public domain as a result of routine civilian nuclear reactor operation. This finding was associated with a cross-cutting aspect of Problem Identification and Resolution, Resolution, which states that licensees take effective CAs to address issues in a timely manner commensurate with their safety significance. Specifically, PSEG completed a MR focused area self-assessment in July 2014 that identified a potential deficiency in the scoping of systems used in Hope Creek emergency operating procedures (EOPs), but had not yet implemented the planned CAs. (P.3)
05000354/FIN-2016001-0131 March 2016 23:59:59Hope CreekSelf-revealingUntimely correction of a Condition Adverse to Quality Associated with High Vibrations on the C Emergency Diesel GeneratorA self-revealing finding of very low safety significance (Green) and associated NCV of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion XVI, Corrective Action, were identified when PSEG did not correct a condition adverse to quality (CAQ). Specifically, despite identifying a potential CAQ on November 3, 2014, associated with high vibrations on the C emergency diesel generator (EDG) jacket water (JW) braided flexible hose during a system walkdown, no notification (NOTF) was generated, no evaluation of the high vibration condition was conducted, and the CAQ was not promptly corrected as required by the corrective action program (CAP). Subsequently, during a monthly surveillance run conducted on January 4, 2016, the C EDG was declared inoperable when a large JW leak developed in the aforementioned braided flexible hose. PSEGs corrective actions included replacing the failed flexible hose and performing extent of condition walkdowns on the other EDGs JW piping structural supports. PSEG also conducted simple troubleshooting on the piping and support structures of all the EDGs, and plans to initiate a vibration monitoring program of the EDGs and EDG support systems. The inspectors determined that the finding was more than minor because it was associated with the Equipment Performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective of ensuring the reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, not correcting the high vibrations on the JW piping resulted in an unplanned shutdown of the diesel, inoperability and unavailability when the leak worsened to a point where PSEG determined that the EDG could not meet its 24-hour mission time. In accordance with IMC 0609.04, Initial Characterization of Findings, dated June 19, 2012, and Exhibit 2 of IMC 0609, Appendix A, The SDP for Findings At-Power, dated June 19, 2012, the inspectors determined that this finding is of very low safety significance (Green) because the performance deficiency was not a design or qualification deficiency, did not involve an actual loss of safety function, did not represent the actual loss of a safety function of a single train for greater than its technical specification (TS) allowed outage time, and did not represent an actual loss of function of one or more non-TS trains of equipment designated as high safety-significant in PSEGs maintenance rule program for greater than 24 hours. This finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Identification, because PSEG did not implement the CAP with a low threshold for identifying issues and did not identify issues completely, accurately and in a timely manner in accordance with the CAP. Specifically, the issue of high vibrations on the C EDG JW braided flexible hose was identified by PSEG, but was not placed into CAP, leading to the issue not being properly documented or evaluated to ensure the cause of the high vibrations was addressed in a timely manner.
05000354/FIN-2016001-0231 March 2016 23:59:59Hope CreekLicensee-identifiedLicensee-Identified ViolationIn Modes 1, 2, and 3, Hope Creek TS 3.4.2.1, "Safety Relief Valves," requires that 13 of the 14 SRVs open within of +/- 3 percent of the specified code safety valve function lift settings or else be in Mode 3 within 12 hours and in Mode 4 within the next 24 hours. Contrary to this requirement, on June 2, 2015, PSEG identified that two or more SRVs had as-found set points in excess of the TS allowable tolerance. Subsequent testing revealed that 10 of 14 SRVs lifted above the TS specified pressure band, thus leaving 4 operable SRVs. PSEG entered this issue into their CAP as NOTF 20692390. PSEG corrective actions included replacing the pilot assembly for each of the 14 SRVs with a fully tested spare assembly, and evaluating options to replace the currently installed SRVs with a new design that eliminates set point drift events. The inoperability of the 10 SRVs did not result in a loss of system safety function based on engineering analyses that showed that the SRVs would have functioned to prevent a reactor vessel over-pressurization and that postulated piping stresses would not exceed allowable limits. The inspectors independently reviewed PSEGs associated technical evaluations and determined that PSEG used adequate engineering rigor and conservatively bounded the condition. The inspectors determined that this finding is of very low (Green) safety significance based on a SDP issue screening, because the SRVs would have functioned to prevent a reactor vessel over-pressurization (no loss of safety function). The closure of the LER associated with this event was documented in Section 4OA3.1.
05000354/FIN-2015007-0131 December 2015 23:59:59Hope CreekNRC identifiedFailure to establish appropriate acceptance criteria for RHR and core spray pump start times during simulated LOCA/LOP testing.The team identified a finding of very low safety significance involving a non-cited violation of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, because PSEG did not establish appropriate acceptance criteria for the time allowed for starting the residual heat removal (RHR) and core spray pumps during simulated loss-of-coolant accident/loss-of-offsite power (LOCA/LOP) conditions in the 18-month integrated emergency diesel generator (EDG) surveillance test (ST) for the vital 4KV buses. Specifically, the ST acceptance criteria failed to confirm that the pumps started in accordance with the design basis loading sequence described in the design analyses and Updated Final Safety Analysis Report Table 8.3-1. PSEGs short-term corrective actions included reviewing LOCA/LOP test results and plant historical data to confirm current operability of the RHR and core spray pumps, and initiating corrective action notifications to determine the appropriate ST acceptance criteria and to trend pump start times. The team determined that the failure to specify adequate acceptance limits for the design basis assigned start times for the RHR and core spray pumps during LOCA/LOP conditions in the 18-month integrated EDG ST procedure was a performance deficiency. The performance deficiency was more than minor because it was associated with the procedure quality attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The team evaluated the finding in accordance with IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings at Power, Exhibit 2 Mitigating Systems Screening Questions, and determined that the finding was of very low safety significance (Green) because the finding was a design deficiency that did not result in the loss of operability or functionality. The team determined that this finding has a cross-cutting aspect in Human Performance, Documentation, in that PSEG failed to maintain accurate test acceptance documentation to aid plant staff in the identification of equipment performance that was outside the acceptable limits of design.
05000354/FIN-2015004-0131 December 2015 23:59:59Hope CreekNRC identifiedFailure to Follow CAP Procedures to Ensure Functionality of the Main Control Room during a Station BlackoutThe inspectors identified a Green finding because PSEG did not follow procedures to ensure that an identified condition adverse to quality (CAQ) was adequately evaluated, documented, and corrected. Specifically, PSEG identified a CAQ associated with a station blackout (SBO) design calculation used to justify the main control room (MCR) heat load during a loss of ventilation, but failed to adequately evaluate, document and correct the CAQ. This CAQ challenged the reasonable assurance of functionality of the MCR during an SBO event and required PSEG to complete a detailed technical evaluation (TE) to prove functionality was maintained. PSEGs corrective actions included performing a detailed TE to ensure MCR temperatures during an SBO would not have exceeded a functionality limit, and initiating actions to ensure issues identifying a potential CAQ receive the appropriate screening by operators, engineering and management staff. PSEG also revised SBO procedures to ensure the proper electrical loads were included when required to be shed in the event of an SBO event. PSEG documented the issue in the corrective action program (CAP) as Notification (NOTF) 20704285. This finding was more than minor because it was associated with the human performance attribute of the Mitigating Systems cornerstone and adversely affected its objective to ensure the capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the potential existed for the analyzed MCR heat load to be exceeded, affecting the ability of the MCR to remain functional during an SBO event. Additionally, the finding was similar to IMC 0612, Appendix E, examples j and k, in that, a design engineering calculation error resulted in a condition where there was a reasonable doubt of operability of a structure, system, or component (SSC). The finding was screened for significance in accordance with IMC 0609, Appendix A, Significance Determination Process (SDP) for Findings-at-Power, issued June 2, 2012. The finding screened as very low safety significance (Green) using Exhibit 2 for Mitigating Systems Screening Questions, because the finding is a deficiency affecting the design or qualification of a mitigating SSC, but the affected SSC maintains its operability and/or functionality. Specifically, the design calculation error was a CAQ that challenged the reasonable assurance of functionality of the MCR during an SBO event and required a TE to prove functionality of the MCR during an SBO event was maintained. The inspectors determined this finding has a cross-cutting aspect in the area of Problem Identification and Resolution (PI&R), Evaluation, in that PSEG did not thoroughly evaluate the issue to ensure that resolutions address causes and extent of conditions, commensurate with its safety significance. Specifically, issues of concern need to be properly classified, prioritized, and evaluated according to their safety significance, and operability and reportability determinations are developed, when appropriate. In this case, PSEG did not properly classify or evaluate an identified CAQ per their procedures.
05000354/FIN-2015007-0231 December 2015 23:59:59Hope CreekNRC identifiedInadequate work order instructions and drawings resulting in improper installation of a safety-related SW valve.Green. The team identified a finding of very low safety significance involving a non-cited violation of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, because PSEG did not provide adequate work order instructions for the reinstallation of service water (SW) pump discharge isolation valve EAHV-2198C following planned valve maintenance in October 2013. Specifically, the inadequate work order instructions contributed directly to maintenance technicians installing the valve in the opposite orientation compared to the intended orientation. PSEG entered this issue into their corrective action program. In addition, PSEGs corrective actions included completing several associated technical evaluations, calculations, operability determinations, and motor-operated valve performance tests. The team determined that the failure to provide adequate work order instructions for the installation of safety-related SW valve 2198C was a performance deficiency. The team determined that this performance deficiency was more than minor in accordance with IMC 0612, Power Reactor Inspection Report, Appendix B, because it was associated with the procedure quality attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems (SW) that respond to initiating events to prevent undesirable consequences. Additionally, the team determined that it was more than minor in accordance with IMC 0612, Appendix E, Example 3j, because PSEGs associated operability and technical evaluations did not adequately consider the worst case conditions, resulting in a potential underestimation of the maximum required opening torque and in a condition where there was a reasonable doubt on the operability of the C SW train. The team evaluated the finding in accordance with IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings at Power, Exhibit 2 - Mitigating Systems Screening Questions, and determined that the finding was of very low safety significance (Green) because the finding was a deficiency that affected the design and qualification of safety-related SW valve 2198C but did not result in the loss of operability or functionality. The team determined that this finding has a cross- cutting aspect in Human Performance, Documentation, in that PSEG failed to ensure that design documentation and work packages were complete, thorough, accurate, and current.
05000354/FIN-2015004-0231 December 2015 23:59:59Hope CreekLicensee-identifiedLicensee-Identified ViolationFrom 2010 to 2014, Hope Creek made a total of 12 shipments of radioactive waste for disposal, four of which contained a category 1 quantity of radioactive material, and eight which contained a category 2 quantity of radioactive material of concern. PSEG did not implement a transportation security plan for these shipments in violation of the requirements of 10 CFR 71.5, Transportation of Licensed Material, and 49 CFR 172, Subpart I, Safety and Security Plans. This performance deficiency adversely affected the Public Radiation Safety cornerstone attribute of Program and Process based on inadequate procedures associated with the transportation of radioactive material. The finding was determined to be of very low safety significance (Green) because Hope Creek had an issue involving transportation of radioactive material, but it did not involve: (1) a radiation limit that was exceeded; (2) a breach of package during transport; (3) a certificate of compliance issue; (4) a low level burial ground non-conformance; or (5) a failure to make notifications or provide emergency information. This issue was documented in the PSEGs CAP as NOTF 20674767. Corrective actions included issuance of new procedure RP-AA-600-1009, revision of procedure LS-AA-1020, Implementation of Significant Rules and Orders, Revision 1, and contracting with a vendor to receive regular, prompt notifications of potentially applicable rule changes in the Federal Register.
05000354/FIN-2017010-0131 December 2015 23:59:59Hope CreekNRC identifiedFailed to follow site procedures resulting in a reactor scramEnclosure 1 Factual Summary of NRC Office of Investigations (OI) Case No. 1-2016-003 On September 28, 2015, an instrument and control (I&C) technician completed procedure HC.IC-FT.SA-0001, Redundant Reactivity Contro l System (RRCS) Division I Channel A and successfully tested the A channel of the RRCS. The I&C technician then proceeded into procedure HC.IC-FT.SA-0003, RRCS Division I Channel B to test the B channel of the RRCS. While the technician was performing this procedure, the reactor tripped. To determine the cause of the reactor trip, on September 30, 2015, PSEG performed complex troubleshooting, which included reviewing the data saved from plant parameters. Based on the troubleshooting, PSEG determined that the I&C technician had made an error during the surveillance testing, causing both RRCS channels to trip and the reactor to scram. OI interviewed a PSEG staff engineer involved in the troubleshooting. The engineer testified that he analyzed real-time printouts of reactor parameters at the time of the event to recreate the scenario on the reactor simulator. The engineer stated that, from the simulation, it was determined that the I&C technician had incorrect ly selected the A channel of RRCS and then selected the B channel with the test input still inserted in the A channel. This error then caused the reactor recirculation pumps to trip leading to the reactor scram. Additionally, the engineer testified that the full RRCS system wa s reviewed as part of the troubleshooting and no other failures were identified. The I&C technician testified that he had received training and was fully qualified to perform surveillances of the RRCS and had performed this particular surveillance numerous times. The technician acknowledged that he had received training on procedure use and adherence and understood that if an issue occurred, to stop and resolve the issue before moving forward in the procedure. The I&C technician stated that on September 28, 2015, he and another technician had been assigned to perform the RRCS surveillance on the Division 1 A and B channels. The technician testified that the cause of the reactor scram was something went wrong with RRCS, adding that he did not make any mistakes or deviate from the procedure. The I&C technician could not provide an explanation for the contradiction between PSEGs determination for the cause of the scram (i.e. human performance erro r) and the technicians own testimony. OI reviewed the copy of HC.IC-FT.SA-0003, used by the I&C technician on September 28, 2015. The technician had initialed the warning at the start of the applicable section of the procedure which stated Extreme caution should be exercised with key functions on Display Monitor. Careless keyboard manipulation can c ause a reactor scram. If any doubt or questions arise, THEN CONTACT Job Supervision immediately. Contrary to this warning, the I&C technician, as proven through plant data, did not stop and contact supervision after incorrectly selecting the A channel of RRCS. Instead, he selected the B channel with the test inputs still inserted in the A channel. OI concluded based on the preponderance of evidence, that the I&C technician deliberately failed to follow this procedure. ENCLOSURE 2 APPARENT VIOLATION Hope Creek Generating Station Technical Specification 6.8.1.d, Procedures and Programs, requires that written procedures shall be established, implemented, and maintained for surveillance and test activities of safety-related equipment. HC.IC-FT.SA- 0003, Redundant Reactivity Control System Division 1 Channel B, C-22-N-403E, N402E ATWS Recirculation Pump Trip, cautions that Careless keyboard manipulation can cause a reactor scram. IF any doubt or questions arise, THEN contact Job Supervisor immediately. Contrary to the above, on September 28, 2015, PSEG did not properly implement a procedure for a surveillance activity of safety-related equipment when the individual performing an RRCS surveillance test made an error and rather than immediately stopping and informing the job supervisor, attempted to correct the error. Specifically, when manipulating the keyboard, the individual selected the wrong channel to test. Rather than contacting the job supervisor, the individual attempted to correct for the error by selecting the proper channel with test inputs still inserted in the other channel, which ultimately led to a dual recirculation pump trip, alternate rod insertion (ARI) initiation, and a reactor scram.
05000354/FIN-2015403-0131 December 2015 23:59:59Hope CreekNRC identifiedSecurity
05000354/FIN-2015003-0330 September 2015 23:59:59Hope CreekLicensee-identifiedLicensee-Identified ViolationIn OPCON 4, Hope Creek TS 3.5.2, ECCS - Shutdown, requires that at least two low pressure ECCS subsystems be operable, and with only one ECCS subsystem operable, two subsystems shall be restored to an operable status within four hours or all OPDRV activities must be suspended. Contrary to this requirement, from May 4, at 4:00 a.m. through May 5, 2015, at 10:42 a.m., PSEG conducted an RPV cold hydrostatic test, classified as an OPDRV activity, with only one low pressure ECCS subsystem operable. This condition existed for approximately 30 hours and 42 minutes. TS compliance was restored at 10:42 a.m. on May 5, 2015, when a second low pressure ECCS subsystem was returned to an operable status. PSEG reported this in accordance with 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by TS. PSEG entered this issue into their CAP as NOTF 20692069. PSEGs corrective actions for this issue included submitting the required LER per 10 CFR 50.73, performing a causal evaluation, and revising the operability assessment procedure to include guidance clarifying the ECCS TS requirements and determination of operability. The failure to comply with TS 3.5.2 did not have any actual consequences or loss of system safety function because other low pressure ECCS subsystems were available for inventory makeup. Therefore, this finding is of very low (Green) safety significance based on an SDP issue screening, because the ECCS subsystems would have functioned to provide reactor vessel inventory makeup. The closure of the LER associated with this event was documented in Section 4OA3.2 of this report.
05000354/FIN-2015003-0130 September 2015 23:59:59Hope CreekNRC identifiedInaccurate Information Provided to the NRC in License Amendment Request for Service Water Bay Watertight DoorsThe inspectors identified a severity level IV (SL IV) NCV of Title 10 of the Code of Federal Regulations (10 CFR) 10.50.9(a), Completeness and Accuracy of Information, for PSEGs failure to provide accurate and complete information in a license amendment request regarding technical specification (TS) 3.7.3 Flood Protection. This information was material to NRC because it was used, in part, as the basis for the approval and issuance of a license amendment to remove the Unit 2 service water intake structure (SWIS) watertight doors from TS flood protection requirements. PSEGs corrective actions include reinstatement of the Unit 2 watertight doors in the technical requirements manual (TRM) flood protection requirements. Additionally, since the inaccurate license change request submittal in 1998, PSEG implemented LS-AA-117, Written Communications, which requires that all license amendment requests and documents submitted to the NRC under oath and affirmation shall receive a Technical Verification Team review. The Technical Verification Team review consists of a page-by-page review of the subject document that identifies and validates all statements of fact, assumptions, data inputs and calculations which could alter the conclusions reached in the document. The inspectors evaluated this issue using the traditional enforcement process because the performance deficiency had the potential to impact the NRCs ability to perform its regulatory function. Specifically, this violation impacted the regulatory process in that the inaccurate information was material to the NRCs determination that there was reasonable assurance the proposed removal of the Unit 2 SWIS bay watertight doors from the Hope Creek TSs would not result in plant operations that would endanger the health and safety of the public. The inspectors concluded that had the information been complete and accurate at the time provided, it likely would have resulted in a reconsideration of this regulatory position. The inspectors determined that the performance deficiency identified is a Severity Level IV violation, because: the risk associated with an external flooding event at Hope Creek is very low (less than 10-8 per year), the flood protection TS requirement has been changed to a TRM requirement, and the procedure revision to HC.OP-AB.MISC-0001, Acts of Nature, ensured that all of the SWIS exterior doors would be closed during high river water level conditions. The performance deficiency was screened against the Reactor Oversight Process (ROP) per the guidance of IMC 0612, Appendix B, Issue Screening, and no 4 associated ROP finding was identified. In accordance with IMC 0612, Appendix B, this traditional enforcement issue is not assigned a cross-cutting aspect.
05000354/FIN-2015003-0230 September 2015 23:59:59Hope CreekSelf-revealingUnauthorized Locked High Radiation Area EntryA self-revealing Green NCV of TS 6.12.2 was identified when a worker entered a posted locked high radiation area (LHRA) without proper authorization. Specifically, the worker entered the LHRA without being signed onto the proper radiation work permit (RWP) or receiving a pre-entry LHRA briefing, and subsequently received a dose rate alarm. Upon identification, PSEG promptly restricted the workers access to the radiologically controlled area (RCA). This condition has been entered into PSEGs corrective action program (CAP) as notification (NOTF) 20701814. This finding was more than minor since it was associated with the program and process attribute of the Occupational Radiation Safety cornerstone and adversely affected its objective to ensure the adequate protection of the worker health and safety from exposure to radiation from radioactive material during routine reactor operation. Additionally, the finding was similar to IMC 0612, Appendix E, Example 6.h, which describes an improper entry into a high radiation area (HRA). Specifically, the worker entered the LHRA without being signed on to the proper RWP, without receiving a pre-entry LHRA briefing from radiation protection (RP) staff, and subsequently received a dose rate alarm. The finding was evaluated using IMC 0609, Appendix C, Occupational Radiation Safety Significance Determination Process, issued August 19, 2008, where it screened to very low safety significance (Green) since it was not associated with an as low as is reasonably achievable (ALARA) issue, did not involve an overexposure, did not constitute a substantial potential for overexposure, and did not compromise PSEGs ability to assess dose. The inspectors determined this finding has a cross-cutting aspect in the area of Human Performance, Avoid Complacency, in that the worker did not recognize and plan for the possibility of mistakes, latent issues, and inherent risk, even while expecting successful outcomes. Specifically, the worked lacked situational awareness when they became distracted and crossed a radiological boundary without the appropriate authorization.
05000354/FIN-2015404-0130 June 2015 23:59:59Hope CreekNRC identifiedSecurity
05000354/FIN-2015404-0230 June 2015 23:59:59Hope CreekNRC identifiedSecurity
05000354/FIN-2015002-0230 June 2015 23:59:59Hope CreekNRC identifiedFailure to Request a Generic Fundamentals Examination Waiver for a Senior Operator License ApplicantDuring a review of recently issued operator licenses, the NRC identified an NCV of 10 CFR 50.9 associated with the licensees failure to request a Generic Fundamentals Examination (GFE) waiver for a Senior Operator License applicant. Compliance was restored on May 4, 2015, when the licensee submitted a letter to the NRC which provided additional information concerning the issue. The Senior Reactor Operator (SRO) applicant had completed classroom instruction and successfully passed a licensee administered GFE on August 16, 2013, and had passed an NRC prepared GFE when previously licensed as a reactor operator at another utility. The applicant met the requirements to request a waiver to sit for the exam and would have been granted a waiver if it had been requested. The inspectors determined that traditional enforcement applied to this performance deficiency (PD), as the issue impacted the NRCs ability to perform its regulatory function. Specifically, the NRC relies upon the licensee to ensure all license applicants have completed the preparation requirements of NUREG-1021. The PD was determined to be Severity Level IV because it fits the SL-IV example of Enforcement Policy Section 6.4.d.1.a, Violation Examples: Licensed Reactor Operators. This section states, Severity Level IV violations involve for example ...cases of inaccurate or incomplete information inadvertently provided to the NRC that does not contribute to the NRC making an incorrect regulatory decision as a result of the originally submitted information. Because the applicant met the requirements for a waiver and the waiver would have been granted if it had been requested, the performance deficiency did not cause the NRC to make an incorrect regulatory decision. The performance deficiency was screened against the Reactor Oversight Process (ROP) per the guidance of IMC 0612, Appendix B, Issue Screening. No associated ROP finding was identified and no cross-cutting aspect was assigned.
05000354/FIN-2015002-0130 June 2015 23:59:59Hope CreekSelf-revealingFailure to Identify and Correct a Condition Adverse to Quality Associated with Safety Relief Valve Inlet PipingA self-revealing Green NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Actions, was identified involving PSEGs failure to promptly identify and correct a condition adverse to quality. Specifically, PSEG did not identify and initiate a Corrective Action Process Notification Report for numerous tooling marks on the Reactor Coolant System (RCS) inlet piping connecting the Safety Relief Valves (SRVs) to the primary system following periodic removal and replacement. PSEG determined that the tooling marks could have resulted in stress risers on the RCS piping, making the pipe prone to cracking, and reduced the margin to the piping minimum wall thickness. PSEGs corrective actions included blending the tooling marks on all 14 SRV inlet pipes, verifying thickness above the minimum wall value, completing ultrasonic thickness measurements and magnetic particle surface examinations of the piping, and completing an RCS operational pressure test to verify the operability and functionality of the SRV inlet piping. This finding was more than minor because it was associated with the human performance attribute of the Barrier Integrity cornerstone and adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers (fuel cladding, reactor coolant system and containment) protect the public from radionuclide releases caused by accidents or events. The inspectors used IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, which states in the Barrier Integrity section that for all non-pressurized thermal shock issues, the inspectors should evaluate the issue under the initiating events cornerstone (Exhibit 1). Using Exhibit 1 for Transient Initiators, the inspectors determined that the finding was of very low safety significance (Green), because after a reasonable assessment of the degradation; the condition did not adversely impact RCS leakage or functionality of available Loss of Coolant Accident (LOCA) mitigation capabilities. Specifically, the SRV inlet piping safety-related function, relied upon for accident mitigation and pressure relief, remained operable. The inspectors determined this finding has a cross-cutting aspect in Human Performance, Work Management, because the organization did not implement a process of planning, controlling, and executing work activities such that nuclear safety is the overriding priority. The work process did not include the identification of risk (risk of the torque tool damaging the SRV pipe, and the failure to identify damage during inspections when performing maintenance on the SRVs) commensurate to the work and the need for coordination with different groups or job activities.
05000354/FIN-2015002-0330 June 2015 23:59:59Hope CreekNRC identifiedConditions Prohibited by Technical Specifications Due to Core Spray InoperabilitiesOn March 31, 2015, at 1:42 p.m., the breaker for 'A' Core Spray (CS) pump failed to close during normal surveillance testing. Technical Specification (TS) 3.5.1.a was entered for one inoperable CS subsystem. The breaker was replaced and the surveillance was satisfactorily performed, and the 'A' CS subsystem was declared operable on March 31, 2015, at 8:00 p.m. PSEG performed troubleshooting which indicated that the failure in the breaker control device most likely existed since the last breaker operation on January 8, 2015, at 10:00 a.m., and vendor failure analysis concluded that the spring in the breaker control device failed due to cyclic fatigue, preventing the breaker from closing. Accordingly, PSEG determined that the A CS subsystem was inoperable for longer than the TS allowed outage time (7 days). Therefore, the condition was determined to be reportable per 10 CFR 50.73(a)(2)(i)(B) as any operation or condition prohibited by TS. During the review of this event, PSEG also determined that 'B' CS subsystem was inoperable from February 9, 2015, at 3:00 a.m., until February 10, 2015, at 3:32 p.m. (36 hours and 32 minutes) when planned maintenance was performed on the 'B' EDG. This condition was determined to be reportable per 10 CFR 50.73(a)(2)(v) as an event or condition that could have prevented the fulfillment of a safety function. The inspectors reviewed the LER and LER supplement, the associated causal analysis (ACE 70175101) and corrective actions, the completed vendor failure analysis on the breaker control device, interviewed PSEG staff, related corrective action program (CAP) notifications and walked down associated components. The inspectors found that the vendor failure analysis indicated: 1. Fatigue where the spring bends, or kinks, to form the hook that attaches the spring to the contact carrier inside the control device; and, 2. Permanent deformation, or a visible gap, in the spring coil turns. In discussing the failure analysis with PSEG, the inspectors determined that the bend, or kink, in the spring for the hook is a known high stress location and the kink introduces an additional stress riser that promotes fatigue crack initiation, which occurred over several stress cycles, suggesting that the spring failed due to an accumulation of operations of the breaker control device. PSEG engineering also indicated that the permanent deformation, or visible gap, in the spring coil turns were most likely caused during manufacturing, prior to the breaker control device assembly. Based on a review of PSEGs preventative maintenance strategy, CAP documents, ABB safety and non-safety related breaker failure history, no previous operating experience, and the fact that the cause of the inoperability, a failed spring inside the sealed breaker control device that was still within the manufacturers recommended life span, was due to a manufacturing defect that could not have been identified during inspection and testing or avoided through management controls, the inspectors determined that this type of failure was not within PSEGs ability to foresee and correct. Therefore, the inspectors determined there was no licensee performance deficiency associated with the violation of the TS 3.5.a.1 limiting conditions for operation. NRC Inspection Manual Chapter 0612, Appendix B, Issue Screening, directs disposition of 31 such issues using traditional enforcement in accordance with the Enforcement Policy. The inspectors used Enforcement Policy, Section 6.1.d.1, Reactor Operations, to evaluate the significance of this violation, and concluded that the violation was more than minor and best characterized as a Severity Level IV violation in that the issue was associated with a failure to comply with a technical specification action requirement. In reaching this conclusion, the inspectors considered that the underlying technical finding would have been evaluated as having very low safety significance (i.e. Green) under the Reactor Oversight Process using NRC IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, dated June 19, 2012 because, although the issue involved the potential loss of system and/or function and therefore required a detailed risk evaluation, the calculated delta core damage frequency (CDF) was mid E-8. Because this change in CDF was less than 1E-7, no further evaluation of external events or large early release frequency was required. Because it was not reasonable for PSEG to have been able to foresee and prevent the violation, the NRC determined no performance deficiency existed. Thus, the NRC has decided to exercise enforcement discretion in accordance with NRC Enforcement Policy Section 2.2.4, Exceptions to Using Only the Operating Reactor Assessment Program, and Section 3.5, Violations Involving Special Circumstances, and refrain from issuing enforcement action for the violation (EA-15-147). Further, because PSEGs action and/or inaction did not contribute to this violation, it will not be considered in the assessment process or the NRCs action matrix. This LER is closed.
05000354/FIN-2015002-0430 June 2015 23:59:59Hope CreekNRC identifiedOperations with a Potential to Drain the Reactor Vessel (OPDRV) Without Secondary ContainmentOn April 14, 15, 17, 20, 27 and 29, 2015, during a planned refueling outage and the reactor cavity flooded up in Mode 5, Hope Creek conducted multiple OPDRVs without an operable secondary containment. The conduct of an OPDRV without establishing secondary containment integrity is a condition prohibited by TS as defined by 10 CFR 50.73(a)(2)(i)(B). Secondary containment is required by TS 3/4.6.5.1 in Operational Condition *, which is a condition during an OPDRV. The required action for this specification is to suspend OPDRV operations. In this case, the specific OPDRVs were the removal of the scram air header from service (2:00 to 5:15 p.m. on April 14, 2015), B RRP seal replacement (4:36 a.m. on April 15, 2015, through 2:55 a.m. on April 24, 2015), control rod drive replacements (2:17 p.m. on April 17, 2015, through 1:02 p.m. on April 20, 2015), Local power range monitor replacements (3:13 a.m. on April 20, 2015, through 6:40 a.m. on April 23, 2015), scram discharge volume tagging (1:14 to 1:26 p.m. on April 27, 2015), and the fill and vent for the B RRP seal (8:41 p.m. on April 29, 2015, through 6:45 a.m. on April 30, 2015). The OPDRVs were completed in accordance with PSEG procedure OP-HC-108-102, "Management of Operations with the Potential to Drain the Reactor Vessel." These OPDRVs were completed and exited at 6:45 a.m. on April 30, 2015. The NRC issued EGM 11-003, Revision 2, Enforcement Guidance Memorandum On Dispositioning Boiling Water Reactor Licensee Noncompliance With Technical Specification Containment Requirements During Operations With A Potential For Draining The Reactor Vessel, on December 13, 2013, which provides, in part, for the exercise of enforcement discretion only if the licensee demonstrates that it has implemented specific interim actions during any OPDRV activity. The inspectors determined that PSEGs implementation of these specific interim actions during these OPDRV activities were adequate and met the intent of EGM 11-003, Revision 2. The inspectors assessments of PSEGs implementation of these criteria during each of the multiple OPDRV activities are described below: The inspectors observed that, as required by the EGM, the OPDRV activity was logged in the control room narrative logs and that the log entry appropriately recorded the safety-related pump (A RHR) that was the standby source of makeup designated for the evolution. The inspectors noted that the reactor vessel water level was maintained at least 22 feet and 2 inches over the top of the RPV flange in compliance with the minimum water level allowed by Hope Creek TS LCO 3.9.8 applicability. The inspectors also noted that at least one safety-related pump was the standby source of makeup designated in the control room narrative logs for the evolution with the capability to inject water equal to, or greater than, the maximum potential leakage rate from the RPV for a minimum time period of 4 hours. PSEG reported that the worst case estimated time to drain the reactor cavity to the RPV flange was 26 hours, which met the EGM criteria of greater than 24 hours. The inspectors verified that the OPDRV was not conducted in Mode 4 and that PSEG did not move recently irradiated fuel during the OPDRV. The inspectors noted that PSEG had in place a contingency plan for isolating the potential leakage path. The inspectors verified that two independent means of measuring RPV water level (one alarming) were available for identifying the onset of loss of inventory events with sufficient time to close secondary containment before reactor water level reached the top of the RPV flange. TS 3.6.5.1 is applicable in Operational Conditions 1, 2, 3 and * requires that secondary containment integrity shall be maintained. Operational Condition * is defined, in part, as being during OPDRV. TS 3.6.5.1, action b, states, in part, in operational condition, * suspend operations with a potential for draining the reactor vessel. Contrary to the above, between 2:00 p.m. on April 14, 2015, and 6:45 a.m. on April 30, 2015, Hope Creek Generating Station did not maintain secondary containment integrity while conducting OPDRV activities. Because the violation was identified during the discretion period described in EGM 11-003 Revision 2, the NRC is exercising enforcement discretion in accordance with NRC Enforcement Policy Section 2.2.4, Exceptions to Using Only the Operating Reactor Assessment Program, and Section 3.5, Violations Involving Special Circumstances, and, therefore, will not issue enforcement action for this violation. In accordance with EGM 11-003 Revision 2, each licensee that receives discretion must submit a license amendment request within 4 months of the NRC staffs publication in the Federal Register of the notice of availability for a generic change to the STS to provide more clarity to the term OPDRV. The inspectors observed that PSEG is tracking the need to submit a license amendment request in its corrective action program as notification 20559547. This LER is closed.
05000354/FIN-2015001-0131 March 2015 23:59:59Hope CreekSelf-revealingFailure to Identify and Correct a Condition Adverse to Quality Associated with the Reactor Core Isolation Cooling System Insulation and OilA self-revealing finding of very low safety significance (Green) and associated non-cited violation (NCV) of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion XVI, Corrective Action, was identified because PSEG did not promptly identify and correct a condition adverse to quality (CAQ). Specifically, PSEG failed to identify a deficiency with the reactor core isolation cooling (RCIC) turbine thermal insulation on July 28, August 19, and November 18, 2014; and failed to initiate a notification (NOTF) identifying an adverse trend in RCIC oil moisture content and level on November 18, 2014 and in January 2015. The failure to identify and correct a CAQ resulted in high moisture content in the RCIC oil. PSEGs corrective actions included replacing the RCIC system oil on February 19, 2015 and repairing the non-conforming turbine insulation on February 25, 2015. The performance deficiency (PD) was determined to be more than minor because it affected the Equipment Performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). This PD was also similar to examples 3.j and 3.k of NRC IMC 0612, Appendix E, in that the increased moisture content in the RCIC oil created a reasonable doubt of operability of the RCIC system. The inspectors determined the finding to be of very low safety significance (Green) in accordance with Exhibit 2 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, dated June 19, 2012, because: it was not a deficiency affecting the design or qualification of the mitigating system; it did not represent a loss of system function; it did not represent the loss of function for any TS system, train, or component beyond the allowed TS outage time; and it did not represent an actual loss of function of any non TS trains of equipment designated as high safety significance in accordance with PSEGs maintenance rule program. The inspectors determined the finding had a cross-cutting aspect in the area of Problem Identification and Resolution (PI&R), Trending, because PSEG did not periodically analyze information from the corrective action program and other assessments in the aggregate to identify programmatic and other common cause issues. Specifically, PSEG did not analyze multiple RCIC system oil sample results or RCIC system NOTFs in the aggregate to identify a CAQ.