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05000445/FIN-2018010-0230 September 2018 23:59:59Comanche PeakFailure to Provide Procedural Guidance for the Failure of a Component Cooling Water Surge Tank Makeup ValveThe inspectors identified a Green, non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure to provide procedural guidance for the failure of a component cooling water surge tank makeup valve.
05000482/FIN-2018201-0230 September 2018 23:59:59Wolf CreekSecurity
05000275/FIN-2018003-0130 September 2018 23:59:59Diablo CanyonMultiple Examples of Scaffolding in Place Greater Than 90 Days Without Required EvaluationThe inspectors identified a Green, non-cited violation of 10 CFR 50, Appendix B, Criterion V, Procedures, because PG&E personnel failed to follow the requirements of AD7.ID5, Scaffold Material Structure. Specifically, 20 instances of scaffold structures installed in the plant were identified that had been in place for greater than 90 days without required 10 CFR 50.59 reviews being completed.
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.
05000369/FIN-2018012-0130 September 2018 23:59:59McGuireFailure to Translate Seismic Mounting Requirements for 125 VDC Vital Batteries into Installation and Replacement ProcedureThe inspectors identified a Green finding and associated non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion III, Design Control, when the licensee failed to translate the mounting requirements for seismic qualification contained in NLI technical calculation C-017-074-2, Vital Instrumentation & Control Batteries & Racks Equipment Qualification Calculation, Rev. 0, into their battery replacement and installation procedure IP/0/A/3061/003, 125 Volt Vital Battery Maintenance and Repair, Rev. 23
05000456/FIN-2018003-0230 September 2018 23:59:59BraidwoodMinor ViolationAll Braidwood Station EDG governors were replaced during the late 1990s. During design testing, the licensee noted that the historical EDG frequency response had changed slightly due to installation of new electronic governors. Prior to these governor replacements, EDG frequency was always above 57 hertz (Hz) during load sequencing. However, with the newly installed electronic governors, 1A and 2A EDG frequency was observed to dip below the 57 Hz under frequency relay setpoint following start of the 1A and 2A motor-driven AF pumps. (Note that because the 1B and 2B AF pumps are diesel-driven, there is no corresponding impact on the 1B or 2B EDGs.) As a result, an external 2-second time delay, provided by an Agastat time delay relay, was incorporated into the under frequency trip logic for the 1A and 2A EDGs to provide an additional margin for frequency recovery following motor-driven AF pump load starts. The Braidwood governor modification was installed in 1998, with the external time delay added to the 1A and 2A EDGs as part of the design changes to prevent inadvertent actuations of the under frequency logic.During the licensees investigation into the issue discussed in the subject LER, it was identified that the external Agastat time delay was installed incorrectly on the 1A EDG. Specifically, the original trip logic wiring had not been properly removed, which permitted the actuation of the under frequency trip after the original 0.5 second internal time delay through the bypassing of the additional 2.0 second external time delay. The wiring error was introduced during the original modification installation in October 1998. Screening: The inspectors determined that the error was of minor safety significance. Absent the mechanical binding of the manual fuel trip lever and associated linkage, as discussed in NCV 05000456/201800301 in this report, the 1A EDG had performed reliably and satisfactorily during surveillance testing prior to the Unit 1 refueling outage testing in April of 2018. Additionally, the inspectors determined that the error, having occurred some 20 years ago, was not indicative of current licensee performance.Violation: This failure to comply with the requirements of 10 CFR Part 50, Appendix B, Criterion III , Design Control, constitutes a minor violation that is not subject to enforcement action in accordance with the NRCs Enforcement Policy.
05000454/FIN-2018003-0130 September 2018 23:59:59ByronMinor ViolationOn June 14, 2018, the licensee performed IST surveillance 2BOSR 5.5.8.DO1, Test of the Diesel Oil Transfer System, on the 2A diesel oil transfer pump. On June 19, 2018, the inspectors noted that an issue concerning the calibration of the Flexim ultrasonic flow meter used during the test had not been documented in the licensees Corrective Action Program (CAP). Specifically, the calibration sticker on the flow meter used during the surveillance test indicated that the instrument was calibrated to a 5 percent accuracy when the ASME OM Code required an instrument accuracy of 2 percent. The inspectors discussed the issue with licensee management. The licensee subsequently confirmed that the instrument calibration did not meet ASME OM Code requirements and entered this issue into their CAP.Title 10 CFR Part 50, Appendix B, Criterion XII, Control of Measuring and Test Equipment, requires that measures be established to assure that tools, gages, instruments, and other measuring and testing devices used in activities affecting quality are properly controlled, calibrated, and adjusted at specific periods to maintain accuracy within necessary limits. Licensee procedure ERAA321, Administrative Requirements for Inservice Testing,Section 4.10.3, states, in part, that instrument accuracy and range requirements are specified in the applicable ASME Code Edition/Addenda. ASME OM Code Paragraph ISTB-3510, General, states, in part, that instrument accuracy shall be within the limits of Table ISTB-35101, Required Instrument Accuracy. Table ISTB35101 states that the required instrument accuracy for determining flow rate is 2 percent. Screening: The failure to implement programmatic controls that ensured measurement and test equipment was calibrated to the accuracy requirements of the ASME OM Code was a performance deficiency. The instruments used in IST surveillances were later re-certified to meet the required 2 percent accuracy in the ASME OM Code with no required adjustments. As a result, the performance deficiency was determined to be minor because the inspectors answered No to all of the more-than-minor screening criteria in IMC 0612, Appendix B. The licensee generated Issue Report (IR) 04149294 to document this issue in their CAP. This issue was also incorporated into a corrective action program evaluation (CAPE) report evaluating an adverse trend identified with ASME test performance at the site (AR 04154533). Violation: The failure to comply with 10 CFR Part 50, Appendix B, Criterion XII, Control of Measuring and Test Equipment, constituted a minor violation that was not subject to enforcement action in accordance with the NRCs Enforcement Policy.
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.
05000482/FIN-2018010-0130 September 2018 23:59:59Wolf CreekFailure to Follow ProceduresThe team identified two examples of a Green, non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for failure to follow procedures.
05000275/FIN-2018003-0230 September 2018 23:59:59Diablo Canyon4 kV Vital Switchgear Room Ventilation Degraded or Non-Conforming Condition and Associated Compensatory Measure Not Corrected in a Timely MannerThe inspectors identified a Green, non-cited violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, because PG&E personnel failed to promptly correct a degraded or non-conforming condition associated with an open operability condition. Specifically, PG&E personnel did not promptly correct a degraded condition associated with an open operability determination and corresponding compensatory measure related to Unit 1 and Unit 2, 4 kV vital switchgear ventilation for a period of over 4 years. This time period included two refueling outages for Unit 1 and three refueling outages for Unit 2.
05000446/FIN-2018011-0130 September 2018 23:59:59Comanche PeakFailure to Maintain a Quality Record Complete and Accurate in All Material RespectsThe inspectors identified an apparent violation of 10 CFR 50.9, in that the licensee appears to have failed to maintain information required by the Commissions regulations that was complete and accurate in all material respects. Specifically, following equipment manipulation and an unanticipated loss of inventory in a portion of the reactor coolant system, the licensee appears to have failed to maintain complete and accurate information in condition report CR-2017-005788 relative to the cause of the loss of inventory event and the identified condition adverse to quality in the corrective action program. Description: On April 28, 2017, following an attempt to fill the refueling water storage tank (RWST) that resulted in a lowering level in the volume control tank (VCT), a licensed reactor operator (RO) admitted that he provided incomplete or inaccurate information to licensee personnel on a number of occasions. Specifically, the RO stated that after he realized that valve 2-FCV-110B, reactor coolant system makeup to charging pump suction isolation valve,was not aligned properly he did not alert the control room, and when others assumed the valve was leaking by he did not correct them. The RO also admitted that he knowingly submitted a written statement where he indicated that the valve had been closed and reported the same in Condition Report CR-2017-005788 that he drafted, which was not accurate. As a result, the NRC has identified an apparent willful violation of 10 CFR 50.9, Completeness and Accuracy of Information
05000482/FIN-2018003-0230 September 2018 23:59:59Wolf CreekFailure to Submit a Licensee Event Report for a Condition Prohibited by Technical SpecificationsThe inspectors identified a Severity Level IV non-cited violation of 10 CFR 50.73(a)(2)(i)(B), because the licensee did not provide a written licensee event report (LER) to the NRC within 60 days. Specifically, the licensee did not provide a written LER to the NRC within 60 days of identifying a condition prohibited by the plants Technical Specifications associated with inoperability of control room emergency ventilation system train B for longer than its Technical Specification allowed outage time. As a result, the NRCs ability to regulate was impacted.
05000316/FIN-2018003-0130 September 2018 23:59:59CookMisaligned Heater Level Column Valves Leads to Manual Reactor TripA self-revealed, Green finding was identified when the operators manually tripped the Unit 2 reactor in response to a hi-hi level in the Left Moisture Separator Drain Tank. On May 6, 2018, the Unit 2 reactor was at approximately 12 percent power following a startup at the conclusion of the spring 2018 refueling outage. While the station continued to make preparations to start the main turbine and synchronize with the grid, the moisture separator drain tank hi level alarm was received and remained standing for the better part of the shift. The drain tank collects condensed steam and water from the moisture separator reheater and associated high pressure turbine exhaust lines and routes it either to the condenser or #4 feedwater heaters. The day shift operators were hesitant to continue on with starting the main turbine until the cause of the alarm could be determined. Due to a series of miscommunications between day shift, night shift, the outage control center, and personnel performing troubleshooting, the night shift crew believed it was acceptable to continue with the turbine startup with the alarm still standing. The turbine was synchronized to the grid and power was stabilized at approximately 29 percent power with the alarm in for most of the turbine startup and synchronization. The alarm cleared for a period of time at 29 percent power, but then returned along with the hi-hi drain tank level alarm. Per the alarm response procedures, the operators tripped the reactor and main turbine to protect the turbine from excessive water in the system. Later investigation by the site revealed that the level columns for the #4 feedwater heaters had been left isolated following work and testing associated with the replacement of the #5 feedwater heaters. While the Operations Department had completed a valve lineup on the system per their startup procedures, which put the level columns in service, the Projects Department had not finished all of the work on the heaters at the time the lineup was performed. As a result, workers subsequently isolated the columns to complete testing after the Operations lineup was complete. A step in the Projects test procedure EC51366TP001 directed workers to specifically inform the operators that the level columns were isolated following testing and that the system was ready to be lined up per operations procedures. However, the workers did not provide that detail, and simply stated that the test was complete. As a result, operations did not know the valves had been taken out of alignment. Contributing to the issue, the outage schedule did not provide any logic ties to ensure all work was complete on the heaters before allowing operations to do their valve lineups. With the level columns isolated during startup, the #4 heaters indicated an erroneous level. This resulted in the operators believing that the heaters were at a normal operating level when in fact, they were full. Therefore, when the operators (per procedure) opened a high pressure turbine exhaust valve to the 4A heater, this created a pathway for water to flow from the #4 heaters, through the high pressure turbine exhaust lines, and into the moisture separator drain tank. The excessive flow of water caused the hi and hi-hi alarms in the drain tank which then led to the reactor/turbine trip.
05000390/FIN-2018003-0130 September 2018 23:59:59Watts BarConfiguration Control Error Results in Actual Auxiliary Building Internal Flooding EventA self-revealed Green finding and associated NCV of Technical Specification (TS) 5.7.1, Procedures, was identified when the licensee failed to maintain adequate configuration control in the high pressure fire protection (HPFP) system in accordance with station configuration control procedure, NPG-SPP-10.2, Clearance Procedure to Safely Control Energy. Specifically, the licensee failed to restore HPFP system vent and drain valves to their appropriate configuration prior to returning the system to service which resulted in a significantly large amount of HPFP system water (on the order of 10,000 gallons) being introduced into many areas (including all levels) of the Unit 1 side of the auxiliary building and wetting numerous structures, systems, and components (SSCs) (including cables, ventilation ducts, motor-operated valves, etc.)
05000445/FIN-2018003-0130 September 2018 23:59:59Comanche PeakFailure to Maintain the Ability to Withstand a Station BlackoutThe inspectors identified a Green, non-cited violation of 10 CFR Part 50.63 for the licensees failure to maintain the ability to withstand and recover from a station blackout. Specifically, the licensees approved coping analysis for each unit required the availability of equipment on the non-blacked-out unit, and the licensee failed to maintain the required equipment available.The licensee entered this violation into their corrective action program as condition report CR-2017-011090.
05000391/FIN-2018003-0230 September 2018 23:59:59Watts BarUnauthorized Entry Into a High Radiation AreaA self-revealed Green finding and associated NCV of TS 5.11.1.e was identified when the licensee failed to maintain current survey information and failed to inform a worker of increased dose rates in a high radiation area. As a result, a worker received an electronic dosimeter alarm on the Unit 2 pressurizer platform due to changing radiological conditions associated with a reactor mode change.
05000482/FIN-2018201-0330 September 2018 23:59:59Wolf CreekSecurity
05000369/FIN-2018411-0130 September 2018 23:59:59McGuireSecurity
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
05000413/FIN-2018010-0230 September 2018 23:59:59CatawbaOperability of the VZ and RN Systems were not AssuredThe team identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control for the failure to assure that applicable regulatory requirements for the safety-related service water pump house environmental controls were correctly translated into specifications, drawings, procedures, and instructions. Specifically, the licensee failed to translate the IEEE 279-1971 design basis and requirements for the environmental controls.
05000327/FIN-2018411-0130 September 2018 23:59:59SequoyahSecurity
05000482/FIN-2018010-0230 September 2018 23:59:59Wolf CreekFailure to Establish an Adequate Procedure for Operator Time Critical Actions ValidationThe team identified a Green, non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for failure to have an adequate Procedure. Procedure AI 21-016, Operator Time Critical Actions Validation, Revision 14, Attachment B Time Sensitive Action List, does not have unique identifiers for cross referencing the records to the procedure.
05000275/FIN-2018404-0130 September 2018 23:59:59Diablo CanyonSecuritySECURTIY
05000445/FIN-2018010-0130 September 2018 23:59:59Comanche PeakFailure to Establish Test Program to Verify Residual Heat Removal Suction Valve CapabilityThe inspectors identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion XI, Test Control, for the failure to establish a test program to ensure that residual heat removal suction isolation valves would perform adequately in service.
05000445/FIN-2018003-0230 September 2018 23:59:59Comanche PeakFailure to Establish Adequate Procedural Guidance for Processing Technical Changes Performed by A Vendor on Installed Plant EquipmentThe inspectors identified a Green, NCVof 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, associated with the licensees failure to establish an adequate procedure for controlling and processing vendor documents and vendor technical information. This resulted in the licensees failure to properly evaluate changes made by vendors to plant equipment. Specifically, the licensee allowed vendors to make physical changes to a component cooling water pump shaft and main steam isolation valve actuators without evaluating these changes.
05000482/FIN-2018010-0430 September 2018 23:59:59Wolf CreekFailure to Identify 125 VDC Equalizing Voltage Exceeded Design RequirementsThe team identified a Green, non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the failure to verify or check the adequacy of design calculation NK-E-001, 125 Volt Direct-Current (VDC) Class 1E Battery System Sizing, Voltage Drop and Short Circuit Studies, Revision 4. The licensee failed to recognize that the actual 125 VDC Class 1E bus voltages had exceeded the maximum design limit voltages for downstream equipment identified in the calculation, and they had not placed any limits on voltages which could exceed the design limit of 140 VDC on the Class 1E System components.
05000315/FIN-2018010-0130 September 2018 23:59:59CookRecord Retention Requirements of the Boron Injection Tank and its Associated Support StructureThe inspectors identified an Unresolved Item concerning the Title 10 of the Code of Federal Regulations, Part 50, Appendix B, and ASME Code requirements for the BIT and its associated support structure calculation of record. Updated Final Safety Analysis Report (UFSAR) Section 2.9.2 delineated the BIT Seismic Classification as Class 1. The BIT was part of the Emergency Core Cooling System piping system, and is Seismic Class I. In addition, UFSAR Table 6.2-1 and UFSAR Table 6.2-3 delineated the BIT was designed in accordance with ASME Boiler and Pressure Vessel Code, Section III, Class C. Additionally, Subsection C under Section IIII Article N-2111, stated, in part, The requirements of Section VIII of the Code shall apply to the materials, design, fabrication, inspection and testing, and certification of Class C vessels.... The inspectors reviewed Drawing No. 113E275; 900 Gallon BIT; Revision 5 which contained the design specification for the BIT. Also the inspectors reviewed Struthers Wells Calculation No. 2-70-07-30717; Seismic Stress Calculations for BITs; 07/02/1970 which contained the BIT support structure qualification. The inspectors reviewed Calculation No. DC-D-12-MSC-8 Attachment A, page A.10-10 and page A.9-28; Revision 2 which contained the applied nozzle loads at the BIT inlet and outlet nozzles. Lastly, the inspectors reviewed Document No. 546 CRI 109890; Westinghouse Purchase Order for BIT; 06/22/1970 which contained design requirements for the BIT. During the review of aforementioned design basis documents the inspectors identified the following examples in which the licensee did not have a calculation of record to address the following ASME code requirements: ASME Section VIII, Division 1, Subsection A, General Requirements, Part UG-22 titled Loading states, in part, the loadings to be considered in designing a vessel shall include: Internal or external design pressure (as defined in Par. UG-21), Impact loads, including rapidly fluctuating pressures: Weight of the vessel and normal contents under operating or test conditions. (This includes additional pressure due to static head of liquids), Superimposed loads such as other vessels, operating equipment, insulation, corrosion-resistant or erosion-resistant linings and piping, Wind loads, and earthquake loads where required, Reactions of supporting lugs, rings, saddles or other types of supports (see Appendices D and G) and the effects of temperature gradients on maximum stress. The inspectors identified that the licensee did not have a calculation of record to address the applied loadings due to dead weight of the vessel, fluid weight inside of the vessel, design temperature of 300 degrees Fahrenheit and earthquakes (Operating Basis Earthquake and Safe Shutdown Earthquake) on the BIT vessel shell and head ASME Section VIII, Division 1, Subsection A, General Requirements, Part UG-54 titled Supports states, in part, All Vessels shall be supported and the supporting members shall be arranged and/or attached to the vessel in such a way as to provide for the maximum imposed loadings (see Par. UG-22).. The inspectors identified that the licensee did not have a calculation of record to address the applied loadings due to the superimposed piping loads at the BIT inlet and outlet nozzle to the BIT support structure as well as the applied loading due to the design temperature of 300 degrees Fahrenheit. Secondly, the inspectors identified that no calculation of record existed for the welded connection between the support legs and the baseplate. Thirdly, no calculation of record existed for the welded connection between the support legs and the BIT. Lastly, the self-weight and self-weight seismic excitation of the support structure was not considered in the applied stresses of the support structure calculation of record. In response to the inspectors concern, the licensee initiated AR 2018-7104, Lack in Documentation for BIT 1-TK-11, 07/12/2018. In addition, the licensee performed an operability review and reasonably determined the BIT remained operable. Near the end of the inspection period, the licensee provided the inspectors additional information relevant to the calculation record retention requirements as defined by the ASME Code and the DC COOK Quality Assurance Program Document which will require additional review to determine whether a violation exists. Therefore, this issue is considered an unresolved item pending completion of inspector review and evaluation and discussion with the Office of Nuclear Reactor Regulation and Office of the General Counsel.
05000390/FIN-2018003-0330 September 2018 23:59:59Watts BarFailure to Collect Compensatory Samples for an Out-of-Service Effluent MonitorThe inspectors identified a Green finding and associated NCV of TS 5.7.2.3 when the licensee failed to take compensatory samples in accordance with Table 1.1-1 of the Offsite Dose Calculation Manual when the Unit 1 steam generator blowdown effluent monitor was out of service. Specifically, radiation monitor 1-RM-90-120/121 was inoperable from April 27 to May 27, 2018, and compensatory samples were not collected and analyzed within the required frequency of at least once per 24 hours.
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
05000414/FIN-2018003-0130 September 2018 23:59:59CatawbaFailure to Follow Maintenance Procedure Results in Damage to the 2A EDG During TestingA Green self-revealed NCV of Technical Specification 5.4.1.a, Procedures, was identified for Catawbas failure to follow procedure TE-MN-ALL-0202, Transformer and Apparatus Testing, during maintenance on the 2A EDG. Specifically, the licensees failure to follow TE-MN-ALL-0202, resulted in damage to the voltage regulator circuit and the unexpected shutdown of the diesel during post maintenance testing (PMT) on June 11, 2018. The licensee entered this issue in the corrective action program (CAP) as Condition Report (CR) 2212222
05000482/FIN-2018010-0330 September 2018 23:59:59Wolf CreekFailure to Correct Reoccurring Problems with Time Critical/Sensitive Action ActivitiesThe team identified a Green, non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, for the licensees failure to correct reoccurring problems with completing Time Critical/Time Sensitive Action issues.
05000483/FIN-2018003-0130 September 2018 23:59:59CallawayFailure to perform 10 CFR 50.59 evaluation for compensatory measures associated with stagnant, inactive loopThe inspectors identified an unresolved item related to implementation of 10 CFR 50.59, Evaluations Changes, Tests and Experiments, for the licensees failure to perform an adequate evaluation for compensatory measures for a stagnant, inactive loop. The inspectors identified an unresolved item related to implementation of 10 CFR 50.59, Evaluations Changes, Tests and Experiments, for the licensees failure to perform an adequate evaluation for compensatory measures for a stagnant, inactive loop. The licensee enacted compensatory measures to support atmospheric dump valve/turbine-driven AFW pump operability due to an issue identified for natural circulation cooldown with a faulted steam generator (i.e., inactive loop). A reduction in the Technical Specification 3.4.16 dose equivalent iodine (DEI) limit (from 1Ci/gm to 0.4Ci/gm) was imposed without a 10 CFR 50.59 evaluation and/or license amendment. Specifically, the licensee did not consider the compensatory measure of reducing Technical Specification 3.4.16 limits on DEI-131 as a change to technical specifications.The licensee considered this a temporary action that did not meet the intent of 10 CFR 50.90 for a technical specification change.
05000446/FIN-2018011-0230 September 2018 23:59:59Comanche PeakFailure to Follow a Quality Procedure Associated with the Reactor Makeup and Chemical Control SystemThe inspectors reviewed a self-revealed, Green, non-cited violation of Technical Specification 5.4.1.a for the licensees failure to follow a quality procedure associated with the reactor makeup and chemical control system which resulted in an unanticipated loss of inventory from the volume control tank in the reactor coolant system. Specifically, on April 28, 2017, a reactor operator failed to complete step 5.2.7.G in quality procedure SOP-104B, Reactor Make-up and Chemical Control System, which would isolate the volume control tank from the chemical and volume control system, prior to directing a nuclear equipment operator to complete subsequent steps 5.2.7.K and 5.2.7.L, which opened isolation valves to the refueling water storage tank. These actions resulted in the unanticipated loss of inventory from the volume control tank into the refueling water storage tank.
05000482/FIN-2018201-0430 September 2018 23:59:59Wolf CreekSecurity
05000391/FIN-2018003-0430 September 2018 23:59:59Watts BarInadequate Sensitive Equipment Control Results in Unit 2 Reactor Trip on April 12, 2018A self-revealed Green finding and associated NCV of Title 10 of the Code of Federal Regulations (CFR) Part 50, Appendix B, Criterion V, Instructions, Procedures, Drawings, was identified for the licensees use of a procedure that was not appropriate to the circumstances, which led to the conduct of improperly planned maintenance on sensitive equipment, ultimately resulting in a reactor trip. Specifically, an inadequacy was identified in station procedure 0-TI-12.10, Control of Sensitive Equipment, which lists the sensitive equipment defined, in part, as equipment that could cause a unit trip, on which work activities are required to be appropriately planned and conducted in a manner that will preclude a unit trip. The procedure did not list the high side reactor coolant system loop flow transmitter common drain line as sensitive equipment, which allowed the licensee to improperly perform maintenance on it without the appropriate planning and control necessary to preclude the Unit 2 reactor trip that occurred on April 12, 2018.
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 3.4.2.2, 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-2018403-0130 September 2018 23:59:59MillstoneSecurity
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.
05000482/FIN-2018003-0130 September 2018 23:59:59Wolf CreekFailure to Correct Degraded Performance of a Safety-Related Tornado DamperThe inspectors identified a Green non-cited violation of 10 CFR Part 50, Criterion XVI, Corrective Action, for the licensees failure to promptly correct a condition adverse to quality associated with a safety-related tornado damper. Specifically, damper GTD0002 failed tests in 2012 and 2015, and following maintenance on the damper in 2017, again failed its next as-found test on February 8, 2018. As a result, this safety-related tornado dampers ability to close during a design basis tornado event was adversely impacted.
05000413/FIN-2018010-0130 September 2018 23:59:59CatawbaInadequate Engineering Analyses to Support Design Basis RequirementsThe team identified four examples of a Green non-cited violation of title 10 Code of Federal Regulations Part 50, Appendix B, Criterion III, Design Control. Specifically, Catawba failed to verify the electrical design of safety-related switch gear for the emergency core cooling system equipment and distribution systems (4160 volts-alternating-current (VAC), 600 VAC, and 125 volt-direct- current (VDC)): 1) Some circuit breakers had inadequate voltages that did not meet the minimum qualified requirements (90 VDC), 2) The design was not evaluated for the effects of electrical transients on control voltages that could affect the assumptions in the plant safety analyses for sequencing of loads and potentially affect the control fuses, 3) The effects of degraded voltages was not correlated to the component protection devices to prevent damage or unavailability of equipment during an event, and 4) Motor control centers and components located in the diesel control area were not qualified to perform their safety function during expected environmental transients.
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.
05000482/FIN-2018201-0130 September 2018 23:59:59Wolf CreekSecurity
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.
05000369/FIN-2018003-0130 September 2018 23:59:59McGuireFailure to Adequately Document the Basis for a Change to the Emergency PlanThe inspectors identified a SL IV NCV of Title 10 of the Code of Federal Regulations (CFR), Part 50.54(q)(3), for changes made to the McGuire Nuclear Station (MNS) Radiological Emergency Plan (E-Plan) that failed to demonstrate the changes would not reduce the effectiveness of the E-Plan. Specifically, the licensee did not provide an adequate analysis to determine that the removal of specific procedure references was not a reduction in effectiveness of the MNS E-Plan
05000456/FIN-2018003-0130 September 2018 23:59:59BraidwoodInadequate Detail in Maintenance Procedure for Emergency Diesel Generator 2-Year Inspection Contributed to 1A Emergency Diesel GeneratorFuel Rack BindingA self-revealed finding of very low safety significance (i.e., Green) and an associated Non-Cited Violation (NCV) of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified for the licensees failure to include adequate detail within their maintenance procedures to enable proper lubrication of the emergency diesel generator (EDG) fuel rack control linkage. Specifically, the preventative maintenance template for the fuel rack control linkage required that the manual fuel trip lever and associated linkage be lubricated every 2 years. However, the licensees implementing 2year maintenance procedure failed to include specific instructions to disassemble the lever assembly for lubrication. This lack of lubrication contributed to the mechanical binding of the emergency diesel generator fuel rack and failure of the 1A EDG during surveillance testing on April 22,2018.
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.
05000482/FIN-2018007-0230 June 2018 23:59:59Wolf CreekMinor ViolationPerformance Deficiency: Failure to promptly identify and correct known-defective switches in inservice safety-related breakers, or to control nonconforming breakers accepted into warehouse stores, as required by 10 CFR 50 Appendix B Criteria XV and XVI. In February 2008, the licensee received a notification from GE Hitachi of reduced reliability of some safety-related circuit breakers due to defective cutoff switches internal to the breakers. The licensee incorrectly screened this information as not applicable to the Wolf Creek Generating Station. In August 2011, after licensee engineers received the information again from industry peers, the licensee screened the information as applicable. The licensee then added steps to its overhaul and pre-install test procedures to check for the defective subcomponent. These steps were performed during subsequent regularly scheduled overhaul or pre-install tests, with the last affected switches being replaced in June 2014 and the last potentially susceptible safety-related breaker being inspected in March 2015. The team determined that because the station had information on the defect in February 2008, but did not correct the condition until 2014 and did not confirm that it was corrected until 2015, the licensee had failed to promptly identify and correct a condition adverse to quality. Further, the licensee failed to inspect or place administrative controls on potentially affected spare breakers that had been accepted into warehouse stores, though the added steps in the pre-install procedure likely would have prevented a defective component from being installed. However, by failing to segregate the potentially affected components until they were inspected, the licensee failed to comply with quality assurance requirements for control of nonconforming components. On June 26, 2018, the licensee put a hold on four potentially affected breakers that were in warehouse stores. The licensee documented this performance deficiency in CR 124693. Screening: The performance deficiency was minor because the licensee did not experience an inservice failure as a result of the defect during the 6 years they remained in service and had a procedure in place that would likely have prevented a defective spare from being issued for installation. Therefore, there was no adverse effect on the mitigating systems cornerstone objective and there was no potential to create a more significant safety concern. Enforcement: This failure to comply with 10 CFR 50 Appendix B Criteria XV and XVI constitutes a minor violation that is not subject to enforcement action in accordance with the NRCs Enforcement Policy.
05000483/FIN-2018002-0130 June 2018 23:59:59CallawayFailure to Adequately Assess and Manage Risk Associated with Switchyard Work During a Planned Risk Significant Turbine-Driven Auxiliary Feedwater Pump Equipment OutageThe inspectors identified a Green, non-cited violation of 10 CFR 50.65(a)(4), Requirements for monitoring the effectiveness of maintenance at Nuclear Power Plants, for the licensees failure to adequately assess and manage risk associated with switchyard work during a planned risk significant turbine-driven auxiliary feedwater pump equipment outage. Specifically, the licensee failed to properly classify switchyard work and manage the risk as required by Procedures APA-ZZ-00322, Appendix F, Online Work Integrated Risk Management, Revision 16, and ODP-ZZ-00002, Appendix 2, Risk Management Actions for Planned Risk Significant Activities, Revision 13.
05000275/FIN-2018008-0130 June 2018 23:59:59Diablo CanyonEmergency Diesel Generator Mission Time for Operability EvaluationsThe team identified an unresolved item (URI) related to diesel generator (DG) mission time for operability evaluations. On December 3, 2016, an operator discovered during rounds that the air inlet boot seal on DG 1-2 had degraded, and subsequently, an inspection of the other diesel generators (DGs) revealed that the DG 2-2 boot seal was also degraded. The licensee performed an operability evaluation and concluded that the DGs were operable based on a mission time of 24 hours. The licensee then performed a past operability evaluation, concluding that the DGs had remained able to perform their safety function for this stated 24-hour mission time despite the deficiency; therefore no licensee event report was required by 10 CFR 50.73. The team requested information related to the basis of the 24-hour mission time. The licensee provided a non-controlled reference document, Engineered Safety Feature (ESF) Equipment Mission Time, to the licensees operability determination Procedure OM7.ID12. The document listed the mission time for the DGs as 7 days (24 hours, 6 hours). The 6 and 24 hour values depend on the particular accident sequence and electrical power recovery time, and were from a letter sent to the NRC related to the licensees Individual Plant Examination of External Events (IPEEE), which is a plant-specific probabilistic risk assessment (PRA). The 7-day value is related to the required diesel fuel oil storage volume as discussed in Technical Specification Bases 3.8.3. The document also states that the licensee has no defined post-accident operation / mission times because such times are not mandated by regulation or recommended by NRC guidance. The team noted, however, that IPEEEs do not typically evaluate accidents past 24 hours, and furthermore, IMC 0326, Operability Determinations and Functionality, states that the use of PRA or probabilities of occurrence of accidents or external events is not consistent with the assumption that the event occurs, and is not acceptable for making operability decisions. Additionally, Procedure OM7.ID12 defines mission time as the duration of structure, system, or component (SSC) operation that is credited in the current licensing bases for the SSC to perform its specified safety function; however, as documented above by the licensee, there is no design or licensing basis mission time for the DGs. The licensees definition of mission time is essentially the same as described in IMC 0326. The inspectors performed a brief review of documents related to mission times. Technical Specification Limiting Condition for Operation 3.8.3, Diesel Fuel Oil, Lube Oil, Starting Air, and Turbocharger Air Assist, requires verification of diesel fuel oil level to satisfy a 7-day fuel oil storage requirement. Additionally, NUREG-1407 discusses an Electric Power Research Institute approach that defines and evaluates the capacity of those components required to bring the plant to a stable condition (either hot or cold shutdown), and maintain that condition for at least 72 hours. Also, the ESF equipment mission time document referenced several 30-day mission times for SSCs that would require emergency power from either offsite power, if available, or the DGs. The team also performed a search of previous NRC findings at the DCPP, Unit 1 and 2, and found one reference to a 7-day mission time for the DGs in NRC Pilot Engineering Inspection Report 2006005. The inspectors also reviewed NEI 97-04, Design Bases Program Guidelines, Revised Appendix B, Guidance and Examples for Identifying 10 CFR 50.2 Design Bases. The Appendix describes how the 10 CFR 50.2 design bases of a facility are a subset of the current licensing basis and are required pursuant to 10 CFR 50.34(a)(3)(ii) and (b) and 10 CFR 50.71(e), to be included in the updated Final Safety Analysis Report (FSAR). Title 10 CFR 50.2 design bases consist of design bases functions and design bases values. Design bases values are the values or ranges of values of controlling parameters established as reference bounds for design to meet design bases functional requirements. In other words, the 10 CFR 50.2 design bases include the bounding conditions under which SSCs must perform their design bases functions and may be derived from normal operation, or any accident or events for which SSCs are required to function. Because 10 CFR 50.71(e), IMC 0326, and Procedure OM7ID.12 indicated that DG mission time should be part of the design and licensing bases, and documented in the FSAR, but a DG mission time design and licensing basis does not appear to exist at DCPP, Units 1 and 2, the inspectors could not determine that an appropriate mission time was used for a past operability determination. Therefore, the team could not conclude that the licensee had not missed a 10 CFR 50.73 event report because of a potentially incorrect assumption about DG mission time. This is applicable to both units. Planned Closure Action(s): In order to resolve this issue, the NRC needs to determine whether or not the basis for the 24-hour DG mission time is appropriate by determining which standard or standards apply to mission time at DCPP, Units 1 and 2. Licensee Action(s): Because the licensees position is that the DG mission time is not a part of their current licensing or design basis, they maintain that the 24-hour mission time used in the past operability determination was adequate to provide reasonable assurance of operability and, therefore, no event report was required. However, prior to this inspection and because of other uncertainties in determining mission times, the licensee generated Notification 50832335 to reassess the mission times associated with the ESF equipment. The intent is to develop the bases for ESF equipment mission time in a controlled document. However, this effort is not yet complete and, as such, the mission time for the DGs has not been evaluated under this notification. Corrective Action Reference(s): Notifications 50832335, 50882125, 50882140, and 50882498.
05000424/FIN-2018002-0130 June 2018 23:59:59VogtleFailure to Adequately Load Emergency Deisel Generator (EDG) During 24-Hour Endurance TestAn NRC-identified Green NCV of Vogtle Nuclear Station TS, Section 5.4.1.a, Procedures, was identified for the licensees failure to implement the EDG 24-hour endurance surveillance procedure 14668A-1, Train A Diesel Generator Operability Test, revision 7.2, to operate the EDG as close as practicable to 3390 kVAR. Specifically, the licensee failed to carry out procedure steps and provisions that would assist in loading the EDG closer to the TS value of 3390 kVAR. The failure to follow procedure 14668A-1 and get as close as practicable to 3390 kVAR was a performance deficiency.