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05000311/FIN-2018003-0230 September 2018 23:59:59SalemFailure to Follow Generic Letter 89-13 Program ProcedureThe inspectors identified a Green NCV of 10 CFR Appendix B, Criterion V, Instructions, Procedures, and Drawings, because PSEG did not adequately follow Generic Letter (GL) 89-13 program procedure steps for performing inspections of the safety-related SW piping and components. Specifically, certain American Society of Mechanical Engineers (ASME) Nuclear Class III pressure retaining components were not inspected during SW system internal pipe inspections, as required by ER-AA-340, GL 89-13 Program Implementing Procedure, Revision 8, during SW system internal pipe inspections. Consequently, protective internal coating degradation on the 21 SW supply header two-inch branch connection was not identified and corrected, which resulted in through-wall leakage and significant weld material loss due to corrosion.
05000277/FIN-2018003-0130 September 2018 23:59:59Peach BottomHPCI System Exhaust Pressure Switches Exceeded Documented Qualified LifeThe inspectors identified a Green NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, because Exelon did not establish measures to ensure that environmental qualification requirements for qualified components were correctly translated into procedures and instructions. Specifically, the end-of-life replacement requirements for the Unit 2 HPCI exhaust pressure switches were not translated into maintenance procedures and instructions. As such, Exelon did not replace the switches prior to the end of their documented qualified life.
05000387/FIN-2018011-0130 September 2018 23:59:59SusquehannaFailure to conduct proper testing of 125 VDC molded case circuit breakers to confirm their design adequacy long-termThe inspectors identified a Green non-cited violation (NCV) of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion XI, Test Control. Specifically, Susquehanna has not established a program to adequately exercise and test safety-related 125VDC molded case circuit breakers (MCCBs) since initial plant operation.
05000354/FIN-2018003-0430 September 2018 23:59:59Hope CreekEnforcement 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, 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, 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.
05000247/FIN-2018003-0430 September 2018 23:59:59Indian PointInadequate Procedure for Turbine Startup Caused a Reactor TripA self-revealing Green NCV of TS 5.4.1, Procedures, was identified because Entergy did not provide adequate guidance in 2-SOP-26.4, Turbine Generator Startup, Synchronization, Voltage Control, and Shutdown. Specifically, Entergy did not provide adequate procedural direction to ensure the main turbine control oil stop valve Z was in the correct position. As a result, the steam generator water level exceeded the trip setpoint for the main boiler feed pumps which led the operators to insert a manual reactor trip.
05000293/FIN-2018003-0130 September 2018 23:59:59PilgrimFailure to Identify an Adverse Condition Associated with Elevated Standby Gas Treatment System Accumulator LeakageThe inspectors identified a Green non-cited violation (NCV) of Technical Specifications 3.7.B.1.c because Entergy exceeded the TS allowed outage time for the standby gas treatment system (SBGT) when the station did not identify an adverse condition associated with elevated air accumulator leakage in the system.
05000277/FIN-2018003-0330 September 2018 23:59:59Peach BottomReactor Core Isolation Cooling System Pressure Switch Failure Results in Condition Prohibited by TS - EA-18-108On April 22, 2018, during a routine surveillance test of the RCIC system, the RCIC turbine tripped approximately 28 seconds after startup, prior to the system reaching rated flow and pressure. Concurrent with the RCIC trip, an alarm was received for RCIC turbine high exhaust pressure; however, local indications did not indicate a true high pressure in the exhaust line. Therefore, the RCIC system was declared inoperable and TS 3.5.3, Condition A was entered, which requires the RCIC system to be restored to operable within 14 days. Troubleshooting determined that the B RCIC exhaust pressure switch (PS-3-13-72b) had prematurely tripped at normal operating pressure due to an age-related failure of the instrument diaphragm and O-ring. The RCIC system had been previously verified as operable during its last surveillance run on January 16, 2018. Corrective Actions: The failed pressure switch was replaced and the station performed an extent of condition review/inspection of similar pressure switch instruments. Following replacement of the switch, RCIC was retested and restored to operable on April 23, 2018. Furthermore, actions were established to modify the turbine trip logic to remove the single point trip vulnerability. Corrective Action Reference: IR 4129583 Enforcement:Violation: Peach Bottom Unit 3 TS 3.5.3 requires that the RCIC system shall be operable in Mode 1, and if RCIC becomes inoperable, it shall be returned to operable status within 14 days or the plant shall be placed in Mode 3 within the next 12 hours. Contrary to the above, based on relevant causal information, Unit 3 RCIC was likely inoperable prior to April 22, 2018, for a period greater than the TS allowed outage time of 14 days, and Unit 3 had not been placed in Mode 3. Specifically, on April 22, 2018, the Unit 3 RCIC turbine tripped during startup for a routine surveillance test due to a degraded turbine exhaust pressure switch which resulted in an inoperability time of greater than 14days. Internal inspection on the switch identified that it failed due to corrosion from water intrusion which had existed for an extended period of time. Severity/Significance: For violations warranting enforcement discretion, IMC 0612 does not require a detailed risk evaluation; however, safety significance characterization is appropriate. A Region I SRA performed a best estimate analysis of the safety significance using the Peach Bottom Unit 3 Standardized Plant Analysis Risk (SPAR) model, Version 8.51 and Systems Analysis Programs for Hands-On Integrated Reliability Evaluations (SAPHIRE), Version 8.1.8. This model was used to evaluate the internal events increase in core damage frequency (CDF) per year. The SRA performed a site visit to review Exelons fire model output to estimate the external risk contributor of the issue. The final risk evaluation estimated the total (internal and external events risk) increase in CDF to be in the mid E-6/yr range, or of low to moderate safety significance. The SRA evaluated the internal and external events risk contribution due to the inoperability of the RCIC system for an assumed 47 day exposure time. 16 The analyst used the guidance in the Risk Assessment Standardization Project (RASP) Handbook, Volume I, Section 2.4, Revision 2.0, to estimate an exposure time using a time divided by two (t/2) approach. This would represent the time from the last successful surveillance test divided by two. The approach is appropriate for periodically operated components that fail due to a degradation mechanism that gradually could affect the component during the standby period. Given this approach, the internal event contribution was calculated to estimate the internal event risk increase due to the conditional failure of the RCIC pump to successfully start. The increase for internal events was estimated at 2.5E-6/yr increase in CDF. The dominant sequence involved a loss of condenser heat sink, with operator action failure to depressurize, and HPCI system failures. The SRA noted from discussions with Exelon staff that the RCIC system was assumed to be non-recoverable given the nature of the failure. To estimate the external risk contribution, the SRA had several discussions and a site visit to review Exelons preliminary fire model outputs for the conditional failure of the RCIC system for the 47 days. The 47 days included a conservative additional day for repair time. The SRA reviewed Exelons fire risk analysis and noted that one of the dominant risk increase contributors was fire within the 13kV switchgear room. Several other fire areas were reviewed and the SRA noted that the core damage sequences appeared technically reasonable given the plant areas and values assumed for mitigating equipment. Exelons preliminary results showed an increase in external event CDF/yr for the conditional failure of RCIC for 47 days to be approximately 4.5E-6/yr. The SRA determined the results to be reasonable. Exelons model for internal events resulted in an increase in CDF/yr of 1.05E-6/yr which was considered to compare well with the NRC SPAR model. Exelon performed a review of the large early release frequency (LERF) impact and determined an overall increase in LERF due to both external and internal events for the RCIC failure for 47 days to be a nominal 6E-8/yr. Therefore, the SRA review of the dominant sequences and Exelons LERF results affirmed that LERF did not increase the risk over that determined from the increase in CDF. Basis for Discretion: The inspectors determined that the maintenance strategy for these switches was consistent with requirements and standards that existed at the time and that there was no relevant operating experience that would have reasonably necessitated consideration of additional maintenance actions. As a result, no performance deficiency was identified. The inspectors assessment considered: The industry, regulatory, and Exelon service life standards were reviewed for static O-ring pressure switches. Exelons assessment of the pressure switch service condition (critical, mild conditions, low-duty cycle) required a preventive maintenance task to perform periodic calibration and to replace the switch as-required. There was no time-based replacement task prescribed by any standard for this switch. The inspectors determined that Exelons assessment was adequate and the corresponding preventive maintenance activities met applicable standards. The subject pressure switch was installed during original construction and the calibration results of the pressure switch had been satisfactory from 2003 until the 2018 failure. The inspectors reviewed the maintenance and calibration history on the pressure switch and did not identify any adverse trends or conditions adverse to 17 quality that would have required further evaluation or replacement of the pressure switch. Industry operating experience information available to Exelon did not identify the potential for the age-related failure mode of the pressure switch o-ring and diaphragm that occurred at Peach Bottom. The NRC determined that it was not reasonable for Exelon to have been able to foresee and prevent this violation of NRC requirements, and as such, no performance deficiency existed. Therefore, the NRC has decided to exercise enforcement discretion in accordance with Sections 2.2.4 and 3.10 of the NRC Enforcement Policy and refrain from issuing enforcement action for the violation of TSs (EA-18-108). Further, because Exelons actions did not contribute to this violation, it will not be considered in the assessment process or the NRC Action Matrix
05000334/FIN-2018411-0130 September 2018 23:59:59Beaver ValleySecurity
05000352/FIN-2018010-0130 September 2018 23:59:59LimerickMinor ViolationDuring this inspection, the team reviewed the details and status of Exelons corrective actions. Relative to EDG voltage, the TSs specified a lower limit of 4160 Vac; however, Exelons existing analysis determined the lower EDG voltage limit should be 4235 Vac. Exelon determined that this higher voltage value was necessary in order to ensure full EDG operability and qualification when considering a specific criteria (voltage drop during the loading sequence) as per NRC Regulatory Guide 1.9, Application and Testing of Safety-Related Diesel Generators in Nuclear Power Plants. The team determined that there was not an operability concern because Exelon determined that, although the voltage drop during the starting of the largest electrical load was slightly below the Regulatory Guide 1.9 value, all required loads would, in fact, successfully start and run as designed when started at the 4160 Vac level. Further, the EDG voltage regulators are designed and calibrated to operate the EDGs at 4235 Vac. Notwithstanding, the team identified that the associated EDG surveillance procedures did not contain the higher, administrative limit of 4235 Vac as an acceptance criterion (4160 Vac was specified). The team reviewed this issue using Inspection Manual Chapter 0612, Appendix B, Issue Screening, and determined that the use of non-conservative acceptance criterion was a minor procedure violation because the EDGs were controlled and operated to maintain voltage at 4235 Vac (and 4160 Vac does not render the EDGs inoperable), and EDG reliability or availability were not adversely affected. Exelon entered this minor violation in their corrective action program as IR 4164579 to document and correct this deficiency. For EDG frequency, the TSs allowed an acceptance band (58.8 61.2 Hertz), which is a range typical of EDG transient loading conditions. However, as described in WCAP-17308-NP, and as determined by Exelon engineering staff, a more narrow band (59.9 60.2 Hertz) is the appropriate operating range for steady state EDG operation. Exelon has appropriately maintained the narrow band as the acceptance criteria in the associated EDG surveillance procedures (compensatory action until TSs are revised). However, during this inspection, the team identified that in 2016, Exelon had slightly widened the acceptable band a one-tenth hertz to 59.8 60.2 Hertz. Further review by the team identified that this change was not properly evaluated in accordance with Exelons procedure change process. In particular, the procedure change received a less rigorous review than a 10 CFR 50.59 screen would have provided; and the team concluded that this screen should have been performed. In response, Exelon evaluated past surveillance results and analyzed the lower frequency value of 59.8 Hertz, and determined there to be no adverse consequence at 59.8 Hertz. The team reviewed Exelons analysis and similarly concluded that there was no adverse safety impact. The team reviewed this issue using Inspection Manual Chapter 0612, Appendix B, Issue Screening, and determined that the improper procedure change was a minor procedure violation because there were no adverse consequences and EDG reliability or availability were not adversely affected. Exelon entered this minor violation in there corrective action program as IR 4160819 and IR 4161542 to document and correct this deficiency.
05000333/FIN-2018412-0130 September 2018 23:59:59FitzPatrickSecurity
05000443/FIN-2018003-0130 September 2018 23:59:59SeabrookPressurizer Safety Valve Outside of Technical Specification LimitsA self-revealing Severity Level IV NCV of Technical Specifications, All pressurizer code safety valves shall be OPERABLE with a lift setting of 2485 psig +/- 3%, was identified when one of the pressurizer code safety valves failed as-found set point testing. Specifically, it was determined that the safety valve had a high as-found set point pressure after the valve was removed from service during the previous refueling outage in April, 2017 (OR18) and the inoperable condition existed for a period of time longer than the allowed T.S. ACTION time.
05000336/FIN-2018003-0130 September 2018 23:59:59MillstoneFailure to Assure that Safety-Related Service Water Piping Conformed to the Procurement DocumentsThe inspectors identified a Green finding and associated non-cited violation (NCV) of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion VII, Control of Purchased Material, Equipment, and Services, when the licensee failed to identify that a replacement service water pipe spool (JGD-1-25) was not in conformance with the American National Standards Institute (ANSI) B31.1 code, a condition of the purchase order, and was installed in the plant.
05000354/FIN-2018003-0530 September 2018 23:59:59Hope CreekMinor 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 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) 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 constituted a minor violation that is not subject to enforcement action in accordance with the NRCs Enforcement Policy.
05000277/FIN-2018410-0130 September 2018 23:59:59Peach BottomSecurity
05000334/FIN-2018411-0230 September 2018 23:59:59Beaver ValleySecurity
05000247/FIN-2018003-0130 September 2018 23:59:59Indian PointInadequate Procedural Guidance for Spent Fuel Movement and Storage RequirementsThe inspectors identified a Green NCV of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion V, Procedures, when Entergy did not have appropriate documented instructions or written procedures for spent fuel movement and storage requirements adjacent to potentially degraded Boraflex panels. Specifically, configuration restrictions were not addressed in some cases and, therefore, did not comply with controls to meet the criticality analysis of record (CAOR) in 2016; and the resultant revised guidance did not accurately reflect the modeled supporting analysis
05000410/FIN-2018003-0130 September 2018 23:59:59Nine Mile PointFailure to Ensure that Thermal Power is Less Than or Equal to the Licensed Power LimitThe inspectors identified a Green finding and associated non-cited violation (NCV) of the NMPNS Unit 2 Operating License (NPF-69), Condition 2.C(1), Maximum Power Level, when Exelon did not ensure that thermal power was less than or equal to the licensed power limit of 3988 megawatts-thermal (MWth). Specifically, on multiple occurrences between May 22, 2018 and October 19, 2018, licensed operators in the main control room did not appropriately monitor and control 2-hour average thermal power at or below the licensed power limit. The inspectors determined the 2-hour average thermal power exceeded the licensed power limit outside of normal steady-state fluctuations, and did not take timely, effective corrective action to reduce thermal power below the licensed power limit when the 2-hour average was found to exceed the licensed power limit
05000352/FIN-2018003-0230 September 2018 23:59:59LimerickFailure to Correct Adverse Environmental Conditions Impacting Low Pressure Coolant Injection Outboard Primary Containment Isolation ValveA self-revealed Green NCV of 10 CFR Part 50, Appendix B, Criterion XVI was identified when Exelon failed to correct adverse environmental conditions affecting the Unit 1 LPCI outboard PCIV actuator that resulted in long term water intrusion, corrosion, and failure of the valve to stroke closed.
05000354/FIN-2018003-0230 September 2018 23:59:59Hope CreekInadequate 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.
05000247/FIN-2018003-0230 September 2018 23:59:59Indian PointContainment Fan Coolers 21 and 24 Motor Cooler Elbow Through-Wall Leaks Due to Excessive Service Water Flow Rates and Safety System Functional Failures of ContainmentA self-revealing Green NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, was identified when Entergy did not ensure that measures were established for the selection and review for suitability of application of materials, parts, equipment, and processes that are essential to the safety-related functions of the structures, systems, and components. Specifically, in 1998, when the former license-holder for Unit 2 decided to replace the original-construction large-radius, butt-welded elbow joints in the service water motor cooler return lines from the Unit 2 FCUs with a new design (a short radius, socket-weld fitting), these elbow joints were not properly evaluated for suitability of application. The service water flow velocity through the modified FCU return piping was in excess of the vendor-allowable flow velocity limit, which resulted in the gradual erosion of the motor cooler elbow joints, eventually leading to through-wall leaks on an ASME class III piping system inside containment, leading to breaches of containment integrity and safety system functional failures.
05000410/FIN-2018003-0230 September 2018 23:59:59Nine Mile PointMinor ViolationDuring the review of Licensee Event Report (LER) 05000220/2017-002-01, Manual Reactor Scram Due to Presesure Oscillations, the inspectors identified a minor violation of 10 CFR 50.9, Completeness and accuracy of information. The LER was found to be inaccurate. Specifically, the LER timeline contained inaccurancies regarding the time operators entered a special operating procedure and did not include an actuation of high-pressure coolant injection (HPCI). The timeline stated at 2:10 AM operators entered the special operating procedure for Pressure Regulator Malfunction, due to reactor pressure oscillations of 2-3 psig. At 2:27 AM operators inserted a manual scram of the reactor due to pressure oscillations exceeding procedural limits. This information was confirmed by a review of the operational logs for March 20, 2017. During OI Investigation 1-2018-002, it was determined that this entry was not accurate and although an exact time could not be established is was estimated to have been at 2:20 AM vice 2:10 AM. Additionally the timeline did not include a mention that at 2:16 AM unexpected turbine trip signal was received and HPCI was initiated due to a tagging error. Operators reset HPCI at 2:18 AM and restored main feedwater flow to restore Reactor Vessel water level. A sixty day telephone notification instead of a written licensee event report was conducted for this invalid initiation of HPCI was completed on May, 11, 2017, as EN 52747 as allowed by 10 CFR 50.73(a)(2)(iv). Screening: Violations involving the submittal of inaccrurate or incomplete information are evaluated under Traditional Enforecement because they impact the NRCs regulatory process. Accordingly, the inspectors evlauted this issue against the example violations in Section 6.9 of the NRC Enforcement Policy. Inspectors concluded that the violation is of minor safety significance because the inaccurate information did not change the NRCs review of the licensee event report. Enforcement: 10 CFR 50.9 requires that information provided to the Commission by a licensee shall be complete and accurate in all material respects. Contrary to the above, on June 22, 2015, Entergy provided information to the Commission that was not complete and accurate in all material respects. In the licensee event report, Exelon documented incorrect information that resulted in the NRC launching a substation further inquiry (OI investigation), but did not substantiate that licensed operators deliberately failed to follow a Technical Specifications required procedure. Exelon identified the inaccuracy and entered the issue into the corrective action program (IR 04091110) on January 7, 2018, and submitted LER 05000220/2017-002-01 on August 18, 2018, revising the timeline to show operators entering N1-SOP-31.2 at 2:20 AM vice 2:10 AM. The disposition of this violation closed Licensee Event Report 05000220/2017-002-01
05000289/FIN-2018003-0130 September 2018 23:59:59Three Mile Island1A Emergency Diesel Generator Lube Oil Leak Inadequate Corrective ActionsA self-revealed Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, was identified for failure to develop and implement adequate corrective actions to ensure the availability and reliability of the 1A emergency diesel generator.
05000336/FIN-2018011-0130 September 2018 23:59:59MillstoneReviews of Incoming Industry Operation Experience Not CompletedThe inspectors identified that Millstone could not demonstrate that incoming industry operational experience reports (ICES) since 2015 had been properly reviewed for applicability to Millstone and for those items that were applicable, were evaluated and corrective actions developed as necessary as required by program guidance. A population of over 1600 ICES reports were identified where it could not be determined if required reviews were complete. Because there are parallel processes which may have reviewed these items, additional review is necessary to determine whether this issue represents a performance deficiency that is of more than minor significance. Therefore, this item is characterized as an unresolved item (URI). The purpose of the operational experience program is to identify conditions adverse to quality (CAQs) found at other plants, evaluate whether the concern is applicable to either Millstone unit, and evaluate and develop corrective actions for those CAQs when necessary. The inspectors noted that a performance improvement report (PIR) is automatically created for the Dominion fleet whenever an OPEX report is received (regardless of its source). Once the corporate PIR is generated, each site is required to check a box that it was received and also disposition it. The PIR remains opened until each site has completed this action. Prior to 2015, the corporate Operating Experience Coordinator would perform an applicability review and assign the remaining items to the site for further evaluation. When the corporate organization was reorganized, the headquarters review of OPEX became mostly administrative and the individual sites were expected to fully disposition the report. Since 2015, more than 1600 OPEX records were discovered that required disposition for Millstone. These records were still open and no records exist to show whether reviews were completed. Therefore it is uncertain if all applicable ICES reports were reviewed. Planned Closure Actions: The NRC will conduct a problem identification and resolution annual sample using NRC IP 71152 once Dominion has notified the NRC that they have completed their review of the 1600 ICES reports. Licensee Actions: Dominion wrote Condition Report (CR) 1105042 to capture the issue, conducted an investigation, and developed a plan to review the 1600 ICES reports which have no documented reviews. Dominion anticipates this review will be completed by the end of the first quarter of 2019.Corrective Action Reference: CR 1105042NRC Tracking Number: 05000336 & 05000423/2018-011-01
05000334/FIN-2018003-0130 September 2018 23:59:59Beaver ValleyInadequate Verification of Full Low Head Safety Injection Suction PipingA self-revealed Green non-cited violation (NCV) of technical specification(TS)5.4.1, Procedures, was identified when FENOC failed to adequately implement procedure 1OM-52.4.R.2.A, Station Startup Mode 6 to Mode 1 Administrative and Local Actions, to verify that the low head safety injection (LHSI) suction pipes were full of water. Specifically, the non-destructive examination (NDE) inspector incorrectly determined that the suction pipes were full, which led to inoperability of one or more trains of LHSI for in excess of four hours on May 22, 2018,when the suction lines were found to be voided.
05000311/FIN-2018003-0130 September 2018 23:59:59SalemInadequate Chiller Maintenance ProceduresThe inspectors identified a Green NCV of TS 6.8.1, Procedures and Programs, when PSEG did not properly preplan maintenance activities in accordance with written instructions appropriate to the circumstances of safety-related chiller compressor tubing repairs and installation. Specifically, PSEG installed compressor oil tubing lines without appropriate work instructions, which led to insufficient separation, and use of a nylon strap/tie to support and route two adjacent lines of tubing, causing the tubing lines to rub and fret during normal compressor operation. Consequently, on March 5, 2018, the 22 chiller compressor tripped on low oil pressure as a result of oil leakage from tube fretting.
05000354/FIN-2018003-0330 September 2018 23:59:59Hope Creekinadequate 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.
05000247/FIN-2018003-0330 September 2018 23:59:59Indian PointContainment Fan Cooler 24 Through-Wall Service Water Leak Caused by Inadequate Application of Epoxy Coating Resulting in Corrosion and a Safety System Functional Failure of ContainmentA self-revealing Green NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified when Entergy did not ensure that activities affecting quality were prescribed by documented instructions or procedures, of a type appropriate to the circumstances, and that these activities were accomplished in accordance with these instructions, procedures or drawings. Furthermore, Entergy did not ensure that the instructions or procedures included appropriate quantitative or qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished. Specifically, Entergy did not ensure that the maintenance procedure for applying the internal EneconTM epoxy coating to the 24 fan cooler main cooler supply line elbow was adequate to ensure proper epoxy coating adherence, and Entergy did not adequately verify the coating adherence prior to placing the elbow in service. This resulted in a through-wall leak and a safety system functional failure of containment.
05000354/FIN-2018403-0130 September 2018 23:59:59Hope CreekSecurity
05000277/FIN-2018003-0230 September 2018 23:59:59Peach BottomInadequate Corrective Actions Result in the Failure of the E-3 EDGThe inspectors identified a self-revealing preliminary White finding associated with an apparent violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, because Exelon did not perform adequate corrective actions on the E-3 EDG scavenging air check valve assembly. Specifically, Exelon did not perform an adequate repair of an interference fit pin joint during maintenance activities in April 2017 and did not correct an oil leak on the check valve dashpot assembly identified in September 2017, which resulted in the E-3 EDG failure on June 13, 2018.
05000289/FIN-2018410-0130 September 2018 23:59:59Three Mile IslandSecurity
05000336/FIN-2018403-0130 September 2018 23:59:59MillstoneSecurity
05000334/FIN-2018011-0130 September 2018 23:59:59Beaver ValleyDuties of the Shift Technical Advisor for Control Room Evacuation during a Fire Event.The inspectors identified a Green non-cited violation (NCV) of Technical Specification (TS) 5.4.1(a), Procedures, related to the duties of the Shift Technical Advisor (STA) in response to a serious fire requiring control room evacuation. Specifically, procedure 1OM-56C.4.E, Shift Technical Advisors Procedure, Revision 23, directs the STA to perform substantial plant equipment operations outside of the control room (i.e., opening breakers, operating valves, electrical switching, etc.). These duties preclude the STA from maintaining sufficient independence to provide advisory technical support to the Unit 1 and 2 Operating Shift Crews as required by NOP-OP-1002 Conduct of Operations, Revision 12, and Unit 1 TS 5.2.2.f.
05000352/FIN-2018003-0130 September 2018 23:59:59LimerickFailure to Assess and Manage Risk Associated with Fuel Oil Storage Tank MaintenanceAn NRC-identified Green NCV of 10 CFR 50.65(a)(4) was identified when Exelon failed to assess and manage risk associated with fuel oil storage tank maintenance by not properly evaluating and establishing compensatory actions for maintaining availability of associated EDGs
05000317/FIN-2018410-0130 September 2018 23:59:59Calvert CliffsSecurity
05000336/FIN-2018410-0130 June 2018 23:59:59MillstoneSecurity
05000410/FIN-2018002-0130 June 2018 23:59:59Nine Mile PointFailure to Ensure Proper Control of the Standby Gas Treatment System Damper Valve, 2GTS*V2000B, Within Procedures, Materials, and Design Control MeasuresThe inspectors identified a Green finding and associated NCVof 10 CFRPart 50, Appendix B, Criterion III, Design Control, when Exelon failed to ensure proper control of the SGTS damper valve 2GTS*V2000B within procedures, materials, and design control measures. Specifically, on April 15, 2018 operators attempted to run B SGTS for containment purge; however, no flow was observed and the system was secured. Operators discovered the 2GTS*V2000B closed due to the failure of the operating mechanism to maintain control of the valve position.
05000272/FIN-2018002-0130 June 2018 23:59:59SalemInadequate Design Change for Service Water PumpsA self-revealing Green non-cited violation (NCV)of Title 10 of the Code of Federal Regulations(10 CFR) Appendix B, Criterion III, Design Control, was identified because PSEG item equivalency evaluation (IEE) 80102443 did not evaluate the use of a chromium oxide spray coating for suitability of application in a brackish river water environment. Consequently, the coating material delaminated, which resulted in a failed in-service test (IST), inoperability and unavailability of the 26 service water (SW) pump as well as the subsequent unavailability of the 16, 21,and 24 SW pumps to perform replacementsof those pumps with the same coating.
05000352/FIN-2018002-0130 June 2018 23:59:59LimerickFailure to Conduct Adequate Radiation Surveys and Evaluate Potential Radiological HazardsA self-revealing Green finding and associated NCV of 10 CFR 20.1501, Surveys and Monitoring: General, was identified when Exelon failed to perform adequate loose surface contamination surveys of the Unit 1 RWCU isolation valve room prior to authorizing work to hang shadow shielding near the HV-051-1F017A valve, and also during the conduct of the work itself. Exelon also did not identify very high levels of loose surface contamination on overhead piping and structures which surrounded the work area. This failure resulted in unplanned internal radiation exposures to three personnel, including an RPT who was assigned to monitor the radiological aspects of the work.
05000336/FIN-2018010-0330 June 2018 23:59:59MillstoneFailure to Correct Part 21 Power Supply DefectsThe team identified a finding of very low safety significance (Green) and associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings. Specifically, Dominion did not accomplish repairs to safety-related power supplies in accordance with instructions and procedures. The team identified that actions taken by Dominion to address Part 21 Report #48863, Foxboro Power Supply Potential Failures due to Defective Tie Wraps and Holder, were performed without procedure or engineering evaluations and the work activities performed were not documented. Specifically, instrumentation and control technicians altered the safety-related power supplies without approved design documents, plant procedures, or work orders, and records of the completed activities were not available
05000244/FIN-2018002-0130 June 2018 23:59:59GinnaIncorrect Scaling Factors in Reactor Vessel Level Monitoring System Instrumentation Uncertainty CalculationThe 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, when Exelon failed to ensure that adequate design control measures existed to verify the adequacy of the Reactor Vessel Level Monitoring System (RVLMS) uncertainty calculation. Specifically, Exelon failed to identify errors in the RVLMS uncertainty calculation which resulted in a reasonable doubt of operability for the system after a temporary modification was implemented.
05000293/FIN-2018002-0130 June 2018 23:59:59PilgrimFailure to Properly Implement the Fatigue Management Program Work Hour Controls for Covered WorkersThe inspectors identified a Green NCV of Title 10 of the Code of Federal Regulations (10 CFR) 26.205(d). During the period December 2017 to April 2018, Entergy did not properly control the work hours of several workers who performed work covered under 10 CFR 26.4(a). Specifically, on eleven occasions, workers exceeded one of the following work hour limits: (1) 16 work hours in any 24-hour period; (2) 72 hours in any 7-day period; or (3) 54 hours per week average over a 6-week rolling time period.
05000387/FIN-2018002-0130 June 2018 23:59:59SusquehannaControl Structure Chiller Inoperability Due to Identified Refrigerant Leaks Not CorrectedA Green finding 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 self-revealed when the licensee failed to promptly correct a condition adverse to quality associated with the B control structure chiller which rendered the B control structure chiller inoperable.
05000333/FIN-2018411-0130 June 2018 23:59:59FitzPatrickSecurity
05000286/FIN-2018002-0130 June 2018 23:59:59Indian PointReactor Pressure Boundary Leakage Due to Weld Failure in Reactor Vessel Head Penetration #3A self-revealing Severity Level IV NCV of Technical Specification (TS) 3.4.13.a, Reactor Coolant System Operational Leakage, was identified when Entergy operated the reactor in Mode 1 with pressure boundary leakage for a period of time longer than the allowable limiting condition of operation. Specifically, a leak in the J-weld around reactor pressure vessel (RPV) head penetration #3 occurred during the last operating cycle and was not identified until after the reactor was shutdown for a refueling outage.
05000220/FIN-2018002-0230 June 2018 23:59:59Nine Mile PointInadequate Procedure Causes Water Hammer Condition Resulting in Isolation and Inoperability of the 12 Train of the Emergency Condenser SystemThe inspectors identified a Green finding and associated NCVof 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, when Exelon did not provide appropriate quantitative or qualitative criteria and guidance to operators in procedure N1- OP- 13 Emergency Cooling System to return an emergency condenser loop to service without inducing a water hammer condition which caused operators to re-isolate the emergency condenser loop and declare it inoperable
05000272/FIN-2018403-0130 June 2018 23:59:59SalemSecurity
05000352/FIN-2018002-0230 June 2018 23:59:59LimerickUnit 1 Core Spray Pump Failed to Start Resulting in Condition Prohibited by Technical SpecificationsThe inspectors identified a Severity Level IV NCV of Unit 1 Technical Specification 3.5.1 because one core spray subsystem was inoperable from July 17, 2017, until October 5, 2017. Specifically, the Unit 1 C core spray pump did not start upon demand during testing and was declared inoperable because the pumps associated circuit breaker closing charging springs were not charged.
05000423/FIN-2018010-0230 June 2018 23:59:59MillstoneOver-Duty Breakers on Safety-Related Bus 34C on Unit 3The team identified a finding of very low safety significance (Green) and an associated NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control. Specifically, Dominion did not adequately evaluate the results of the Unit 3 short circuit calculations for the 4.16 kV breakers. Dominions evaluation of the short circuit calculation results did not identify that the breakers were non-conforming to the licensing basis. The teams review of the calculation results found that the momentary and interrupting duty ratings of the 4kV safety-related breakers associated with Bus 34C were not within their short-circuit ratings when evaluated under design fault condition and, therefore, not in accordance with the licensing basis of the plant.
05000219/FIN-2018410-0230 June 2018 23:59:59Oyster CreekSecurity
05000219/FIN-2018410-0130 June 2018 23:59:59Oyster CreekSecurity