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05000348/FIN-2018003-0130 September 2018 23:59:59FarleyUnit 1 Pressurizer Safety Valve Lift Pressure Outside of Technical Specification Tolerance BandA self-revealed SL IV NCV of TS 3.4.10, Pressurizer Safety Valves, was identified when a routine lift pressure test revealed that pressurizer safety valve Q1B13V0031C was lower than allowed by TS SR 3.4.10.1 for a duration that was longer than the conditions TS required action completion time.
05000334/FIN-2018411-0230 September 2018 23:59:59Beaver ValleySecurity
05000348/FIN-2018011-0130 September 2018 23:59:59FarleyFailure to ensure fire barrier penetrations (including fire dampers) in fire zones protecting safety-related areas shall be functional in accordance with NFPA 805 Section 3.11.3, Fire Barrier PenetrationsThe NRC identified a Green finding and associated non-cited violation (NCV) of the Farleys Renewed Operating License Condition 2.C.(4) Fire Protection for U1 and 2.C.(6) Fire Protection for U2. This finding was identified for failure to maintain all provisions of the approved FPP, as described in NFPA 805, 2001 Edition to ensure that all fire barrier penetrations (including fire dampers) in fire zones protecting safety-related areas shall be functional. The functional failure of the two fire dampers in the A and B SWIS Battery Rooms was a performance deficiency and determined to be more-than-minor because it affected the Reactor Safety Mitigating Systems cornerstone attribute of protection against external factors, a fire, and it affected the fire protection Defense in Depth (DID) strategies involving the confinement of fires and to protect systems important to safety. Additionally, if left uncorrected, the issue could potentially lead to a more significant safety concern during fire events.
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.
05000250/FIN-2018003-0130 September 2018 23:59:59Turkey PointVital Inverter Alternate AC Supply Cables Were Not Included in the Nuclear Safety Capability AssessmentOn June 25, 2018, the inspectors inquired about an open corrective action item documented in AR 2156812. AR 2156812 was originated by FPL on September 20, 2016, and documented that the NFPA 805 Nuclear Safety Capability Assessment (NSCA) circuit analysis failed to include and analyze cables associated with the alternate power supply to all vital inverters on either Turkey Point Unit. The vital inverters power vital plant instruments and controls and are normally powered by the vital DC batteries. The NSCA analysis incorrectly considered that the alternate AC power supply would be always available to power the vital inverters if the DC power supply was damaged by fire. However, the alternate power supply cables may be impacted by fire damage. Not correctly including the fire damage potential for the inverter alternate power supply cables resulted in a non-conservative analysis when the NSCA was performed. The inspectors inquired why compensatory measures in the form of fire watches were not established for the non-conservative NSCA analysis. In response to the inspectors questions, FPL determined that the non-conservative condition still existed and that it was potentially more than a minimal risk impact. FPL considered that if the fire Probabilistic Risk Assessment (PRA) evaluation determines the issue to not result in a risk increase of more than 1E-7/year for core damage frequency and no more than 1E-8/year for large early release frequency, that the change to the fire protection program to correctly analyze the vital inverter power supplies is no more than minimal risk impact. FPL initiated interim compensatory measures in the form of roving fire watches in all the affected Unit 3 and Unit 4 fire areas. FPL initiated AR 2270522 to document the associated interim compensatory measures. AR 2270522 also tracks completion of the necessary NSCA change and an associated fire PRA evaluation to correctly model the vital inverter power supply cables. FPL expects to complete the fire PRA evaluation in December 2018. Units 3 and 4 Operating License Condition 3.D., Transition License Conditions 1. requires, in part, that risk-informed changes to the licensees fire protection program may not be made without prior NRC review and approval unless the change has been demonstrated to have no more than a minimal risk impact, as described in Operation License Condition 3.D., Other Changes that May be Made Without Prior NRC Approval, 2. Fire Protection Program Changes that Have No More than Minimal Risk Impact. The results of FPLs fire PRA evaluation expected to complete in December 2018 are necessary to determine if this issue is a violation of Units 3 and 4 Operating License Condition 3.D., Transition License Conditions 1. This issue remains unresolved pending review of FPLs fire PRA evaluation.
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.
05000251/FIN-2018003-0230 September 2018 23:59:59Turkey PointInoperable Auxiliary Feedwater Steam Supply Flow PathA self-revealing Green NCV of 10 CFR 50, Appendix B, Criterion V, Procedures, was identified when FPL failed to ensure that the torque arm of the 4A steam generator (SG) auxiliary feedwater (AFW) steam supply valve, MOV-4-1403, remained engaged with its valve stem key. A disengaged torque arm subsequently caused the geared limit switch settings for the 4-1403 motor operator to become out of sync with the valve travel and rendered the AFW 4A SG supply flow path inoperable.
05000400/FIN-2018003-0130 September 2018 23:59:59HarrisFailure to Implement Adequate Periodic Exercising of Turbine Trip Solenoid Operated ValvesA self-revealing Green finding was identified for the licensees failure to establish and implement adequate preventive maintenance (PM) for exercising the turbine electro-hydraulic auto-stop trip (AST) solenoid operated valves (SOVs) in accordance with procedure AD-EG-ALL-1202, Preventive Maintenance and Surveillance Testing Administration. As a result of the failure to exercise the SOVs at the weekly vendor recommended frequency, three of the four SOVs experienced mechanical binding (sticking) which rendered the turbine emergency trip system incapable of tripping the main turbine within the time response requirements of Technical Specifications.
05000334/FIN-2018411-0130 September 2018 23:59:59Beaver ValleySecurity
05000400/FIN-2018002-0330 June 2018 23:59:59HarrisFailure to Adequately Document Changes to the Emergency PlanThe inspectors identified multiple examples of a Severity Level IV (SL-IV) NCV of 10 CFR 50.54(q)(3), for changes to the licensees radiological emergency plan (E-Plan) associated with protective action recommendation (PAR) procedures and emergency response equipment that failed to demonstrate that the changes would not reduce the effectiveness of the E-Plan. Specifically, the licensee did not provide an adequate analysis to demonstrate that the removal of the sheltering in-place PARs was not a reduction in effectiveness of the E-Plan. Additionally, the licensee did not perform an analysis demonstrating that the removal of a temporary diesel generator providing a backup source of power to the Technical Support Center (TSC) did not reduce the effectiveness of the E-Plan.
05000348/FIN-2018002-0230 June 2018 23:59:59FarleyFailure to develop adequate PM for diesel generator relaysA green self-revealed violation of Technical Specifications 5.4.1, Procedures was identified on May 16, 2018 when the 1B diesel generator (DG) failed to adequately load during a subsequent restart while performing FNP-1-STP-80.6, Diesel Generator 1B 24 Hour Load Test, Ver. 34.1. The licensee later determined that normally closed contacts on relay K3 associated with the field flashing circuit had high resistance which prevented proper field flashing of the diesel generator and resulted in 1B DG inoperability.
05000250/FIN-2018002-0130 June 2018 23:59:59Turkey PointUnit 3 Emergency Diesel Generator (EDG) Operability during Fuel Oil Transfer to Unit 4 Fuel Oil Storage TanksFrom April 2, through April 10, 2018, the 4B emergency diesel generator (EDG) was out of service for maintenance. On April 4, 2018, the licensee transferred diesel fuel oil (fuel) from the Unit 3 common storage tank, using the 3A EDG fuel transfer pump, 3P10A, to the 4B EDG storage tank. To perform the fuel transfer, operators aligned the 3A EDG fuel transfer system by: 1) removing the 3P10A control switch from the automatic position; 2) closed the air-operated fill valve CV-3-2046A, to the 3A EDG day tank, by isolating and venting its instrument air supply line; and, 3) opened normally locked-closed Unit 3 and Unit 4 fuel transfer manual valves. During the fuel transfer from Unit 3 to Unit 4, the automatic fuel transfer operation from the Unit 3 storage tank to the 3A EDG day tank was defeated. The licensee did not consider the 3A EDG inoperable in this alignment and credited operator manual actions (OMAs) to restore its day tank to automatic fill operation. Technical Specification (TS) surveillance requirement 4.8.1.1.2.b, requires in part, that, each diesel generator shall be demonstrated OPERABLE by demonstrating that a fuel transfer pump starts automatically and transfers fuel from the storage system to the day tank. The inspectors questioned if the licensee was in compliance with the surveillance requirement during the fuel transfer and if the 3A EDG was operable by crediting OMAs. The licensees initial assessment was that the 3A EDG remained operable during the fuel transfer. Additionally, the licensee described that this particular issue was previously reviewed and described in a condition report evaluation, 00-14-19, dated September 22, 2000. The evaluation concluded that automatic operation of the fuel transfer pump was required for EDG operability but automatic operation of the day tank fill valve was not required for operability. The 3A and 3B EDG day tank fill valves are pneumatically operated valves and rely on the non-safety grade instrument air system for operation. Additionally, the evaluation stated that since the instrument air system was non-safety related, and the large EDG day tanks provide ample run time for the EDGs, OMAs were considered part of the system design basis. The inspectors noted to the licensee that the Turkey Point TSs do not specifically credit OMAs associated with the EDG fuel transfer system in a limiting condition for operation (LCO). The inspectors also noted to the licensee that TS Surveillance Requirement (SR) 4.0.1 states Surveillance Requirements shall be met during the OPERATIONAL MODES or other conditions specified for individual Limiting Conditions for Operation unless otherwise stated in an individual Surveillance Requirement. TS SR 4.8.1.1.2.b. requires demonstrating that a fuel transfer pump starts automatically and transfers fuel from the storage system to the day tank. If CV-3-2046A fails closed on a loss of instrument air, the licensee has an off-normal operating procedure that uses local OMAs to align a compressed air bottle to open CV-3-2046A to align fuel to the 3A EDG day tank. UFFSAR section 9.15.1.1.2.1.5 stated in part, Air-operated valves in the transfer lines from the diesel oil storage tank to the day tank automatically open in response to signals developed by logic circuitry incorporating tank level and pump control switch positions. The valves can be locally opened using a separate air source in the event normal instrument air is not available. Section 9.15.1.3.1 described in part Sufficient time exists for providing an alternative air source for opening the day tank fill isolation valves should instrument air fail before the day tank is emptied. With respect to the fuel transfer evolution, the licensee stated that the restoration could be completed with OMAs in sufficient time prior to the day tank being depleted of fuel. The license initiated AR 2269269 to complete a design basis and license basis review on the EDGs for operability during cross unit fuel transfers. Interim actions included declaring the EDG out of service anytime a cross unit fuel transfer was performed. At the conclusion of the inspection period the licensee had not completed the design and license basis evaluation. It was indeterminate whether a performance deficiency exists. This issue remains unresolved pending review of the licensees design and license basis evaluation. Planned Closure Action: A review of the licensees design and license basis evaluation documented in AR 2269269 was required for closure and to determine a performance deficiency exists. Licensee Actions: The license entered this issue into the corrective action program as AR 2269269 to complete a design and license basis review of EDG operability during cross unit fuel transfers. Interim actions included declaring the EDG inoperable any time a cross unit fuel transfer was performed. Corrective Actions Reference: AR 2269269
05000400/FIN-2018002-0430 June 2018 23:59:59HarrisFailure to Implement Adequate Steam Generator Blowdown Demineralizer Control ProceduresA self-revealing Green NCV of Technical Specifications (TS) 6.8.1.a, Procedures and Programs, was identified for licensees failure to establish and implement adequate steam generator blowdown demineralizer control operating procedures resulting in exceeding secondary water chemistry Action Level 3 criteria for impurities in the steam generators. Specifically, the licensee did not implement adequate isolation valve controls between the demineralizer resin regeneration system and the feedwater system during resin regeneration activities. This open path allowed leakage of sulfates and chlorides into the feedwater system. The level of these impurities exceeded the secondary chemistry Action Level 3 threshold and resulted in an unplanned shutdown.
05000348/FIN-2018002-0330 June 2018 23:59:59FarleyFailure to Calibrate Portable Radiation Survey InstrumentsAn NRC-identified, green, NCV of 10 CFR 20.1501(c) was identified for the licensees failure to periodically calibrate portable instruments for the radiation measured. Specifically, high-range Geiger-Mueller (GM) survey instruments were not being calibrated for use above 300 R/hr
05000400/FIN-2018002-0530 June 2018 23:59:59HarrisFailure to Follow Secondary Water Chemistry Plan for Elevated Levels of Secondary Water ImpuritiesAn NRC-identified Green NCV of TS 6.8.4.c, Secondary Water Chemistry, was identified for the licensees failure to follow secondary water chemistry control requirements in accordance with procedure CSD-CP-HNP-0002, Harris Secondary Water Chemistry Strategic Plan. . Specifically, the licensee remained at 100% power for approximately 10 hours after entering secondary water chemistry Action Level 3 due to elevated chlorine and sulfates chemical impurity concentrations, which was contrary to the procedure requirements to downpower the unit to below 5% power as quickly as safe plant operation permits. This unit downpower delay allowed additional time for the chemical impurities to adversely affect the steam generators.
05000348/FIN-2018002-0430 June 2018 23:59:59FarleyFailure to implement timely corrective actions for charging pump discharge check valvesA green self-revealed NCV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action was identified for the licensees failure to promptly identify and correct a condition adverse to quality associated with the Unit 1 and 2 charging pump discharge check valves. Specifically, on July 30, 2014, condition report 846971 documented a green NCV due to inadequate acceptance criteria for testing check valves. The corrective actions to revise the acceptance criteria for these check valves were not implemented promptly. As a result, the licensee missed an opportunity to identify degradation of the check valves until April 2018 when the Unit 1 A and C and the Unit 2 C charging pump discharge check valves did not pass their surveillance tests when tested using the updated acceptance criteria.
05000400/FIN-2018002-0130 June 2018 23:59:59HarrisFailure to Promptly Identify and Correct a Condition Adverse to Quality For a Through-Wall Leak in the ESW Screen Wash PipingAn NRC-identified Green NCV of Title 10 Code of Federal Regulations (CFR) 50, Appendix B, Criterion XVI, Corrective Actions, was identified for the licensees failure to promptly identify and correct a condition adverse to quality involving through-wall leakage in the B train ESW screen wash piping. Specifically, on April 30, 2018, operators failed to initiate a work request or condition report after security personnel reported through-wall leakage in the B train ESW screen wash piping. No further follow-up or corrective actions were taken until May 3, 2018, when NRC inspectors identified the same through-wall piping leakage during a plant walkdown inspection and reported the degraded condition.
05000348/FIN-2018014-0130 June 2018 23:59:59FarleyFailure to Complete System Operator Rounds as Required per ProceduresDuring an NRC investigation completed on November 16, 2017, a SL IV Notice of Violation (NOV) of plant Technical Specification (TS) 5.4.1.a was identified when system operators failed to complete rounds as required per procedures. Specifically, on multiple occasions occurring from July 2016 through September 2016, four system operators (SOs) failed to complete various rounds as prescribed by documented instructions and procedures.Specifically, card reader data showed that the four SOs did not enter the rooms to record operating logs during their watch station rounds in accordance with the approved schedule, as required by NMP-OS-007-001, Conduct of Operations Standards and Expectations, and FNP-0-SOP-0.11, Watch Station Tours and Operator Logs.
05000400/FIN-2018002-0230 June 2018 23:59:59HarrisInadequate Fire Brigade Performance Assessment of Announced Fire DrillAn NRC-identified Green NCV of 10 CFR 50.48(c) and National Fire Protection Association (NFPA) Standard 805, Section 3.4.3, Training and Drills, was identified for the licensees failure to adequately assess the fire brigade performance during an announced fire drill conducted March 21, 2018. Specifically, the inspectors identified several fire brigade performance deficiencies, improvement items, and lessons learned that were not identified and documented in the licensees corrective action program during the fire drill critique as required by the licensees fire drill administrative control procedure.
05000395/FIN-2018411-0130 June 2018 23:59:59SummerSecurity
05000348/FIN-2018002-0130 June 2018 23:59:59FarleyHigh vibrations on the 1B Charging pumpA green self-revealed Non-Cited Violation (NCV) of Technical Specification 5.4.1, Procedures was identified for the failure to provide adequate work order (WO) instructions in work order SNC531734 for the 1B charging pump preventive maintenance on January 31, 2017. Excess grease was added to the pump shaft coupling which resulted in vibration amplitude above the required action range on the pump outboard bearing during a surveillance test on April 28, 2018.
05000334/FIN-2018403-0131 March 2018 23:59:59Beaver ValleySecurity
05000250/FIN-2018001-0231 March 2018 23:59:59Turkey PointFailure of radiation workers to notify Radiation Protection upon a spill of radioactively contaminated waterA self-revealing Green NCV of Technical Specification (TS) 6.8.1, Procedures and Programs, was identified for failure of radiation workers to notify Radiation Protection (RP), in accordance with procedure RP-AA-100-1002, Radiation Worker Instruction and Responsibilities, step 4.13.4, Spills and Observed Leaks, when a spill of radioactively contaminated water occurred. Specifically, on January 22, 2018, during a line-up of the 4D demineralizer resin fill isolation valve on the auxiliary building roof, two radiation workers (non-licensed operators) removed the weather-protective enclosure over the valve to verify its position. Upon removalof the enclosure, approximately half a gallon of highly contaminated water spilled onto the auxiliary building roof. The workers then attempted to clean up and decontaminate the area on their own with a water hose, rather than notify RP. This action spread the contamination into a larger area and into the site storm drain system
05000395/FIN-2018001-0131 March 2018 23:59:59SummerFailure to Perform an Adequate Risk Assessment With Consequent Reactor TripA self-revealed, Green NCV was identified for the licensees failure to adequately assess risk in accordance with 10 CFR 50.65(a)(4), Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, involving repairs to a non-safety related inverter, XIT-5905. This NCV closes LER 05000395/2017-005-00: Automatic Reactor Trip Due to Main Turbine Trip.
05000400/FIN-2018001-0131 March 2018 23:59:59HarrisAdequacy of Fire Brigade Response During Fire DrilThe inspectors identified an URI during the March 21, 2018, announced fire drill that was observed. The drill involved an electrical failure inside the A transfer panel located in the RAB 286 elevation A cable spread room. The fire scenario assumed the electrical failure caused an explosion and fire in the room. The inspectors noted several performance weaknesses during the drill:The fire brigade leader directed three fire brigade members into the fire hot zone to fight the fire as the attack team. Since there is a 5-member fire brigade, only two fire brigade members remain, one of which is the fire brigade leader (who also serves as the site incident commander (SIC)), to be part of the designated 2-out rescue team, required when fighting internal building fires. This 2-out rescue team is responsible, if necessary, for providing assistance or rescue for any or all of the attack team members. The inspectors were concerned that this fire brigade strategy could result in challenges with fire brigade leader command and control, and with the effectiveness of conducting rescues. The fire brigade leader could be hampered in his primary role of directing a site fire response while serving as a rescue team member. Adding to this complication, in locations where radios are not allowed inside some buildings with electrical sensitive equipment during firefighting, as was the case for this fire drill, it would be difficult for the fire brigade leader to communicate and coordinate with the control room or others during a rescue situation. Regarding the actual rescue activity, its effectiveness could be challenged since a two-person rescue team would be faced with potentially assisting/removing three attack members out of the hot zone. Based on discussions with licensee fire brigade training personnel following the drill, theinspectors learned that this 3-in, 2-out deployment was the current manner in which all internal building firefighting strategies and fire training was based upon.The fire brigade leader allowed the 3-man attack team to enter the fire hot zone with permission to commence firefighting prior to the 2-man rescue team arriving at the fire scenes pre-established incident command post and available for implementing rescue. The inspectors later learned that the rescue team, including the fire brigade leader, had arrived at the incident command post approximately five minutes after the attack team had entered the fire area. This delay involved the fire brigade leader completing his thermal protective clothing dressout in the locker room. The inspectors were concerned that under actual circumstances, if the 2-man rescue team were not ready and prepared to fulfill their rescue responsibilities upon entry of the attack team into the fire hot zone, the effectiveness of the rescue team could be challenged.The inspectors observed that no fire hose or other form of fire suppression was pulled or readily available for the 2-man rescue team to take with them should they have needed to enter the hot zone to rescue the attack team. When questioned about this, the inspectors were told that on the same fire hose that the attack team was using, a 1-1/2 inch gated wye valve had been connected, and the rescue team could have connected another 50-foot, 1-1/2 inch fire hose to it and used that hose as a rescue hose. However, the inspectors determined this was inadequate since to get to this hose connection, the rescue team would have to enter into the hot zone prior to reaching it. In addition, the inspectors learned that the use of this 1-1/2 inch gatedwye valve to create two hose streams for either attack or rescue that essentially splits the available flow capacity through a single 1-1/2 inch hose station nozzlewas allowed in multiple fire pre-plan strategies. At the conclusion of the inspection, the inspectors were continuing to assess whether the use of these gated wye valves had been formally reviewed by the licensee in the past to ensure that the flow capacity of fire hose streams would not be adversely impacted by their use during a fire.Planned Closure Actions: Pending completion of additional evaluations needed to determine whether the above fire brigade issues of concern represented performance deficiencies and if so, whether the performance deficiencies were of more than minor significance, this issue was identified as an unresolved item.Licensee Actions: The licensee initiated an NCR to address the inspectors concerns. In addition, until a more thorough review of their fire brigade program could be performed against their NFPA 805 fire program requirements, an operator standing instruction (#18-009, Fire Brigade 2-Out Response) was developed and implemented. This standing instruction directed the following specific fire brigade required actions:The brigade attack team will consist of two fire members to ensure the fire brigade SIC is not normally utilized as one of the 2-out members. If a runner is needed based on the fire area, the SIC may serve as a 2-out member, but this should be the exception.The 2-out members will establish a ready method of suppression that is accessible outside the fire zone. This should be the identified backup hose in the fire pre-plan. This hose does not need to be charged but should be flaked out and ready for use.The attack team will not enter the fire area, except when search and rescue is necessary, until the 2-out team is in the area with the suppression method ready for use.The inspectors determined that the licensees interim actions were adequate to ensure the fire brigade response would be effective if called upon pending resolution of the issues. Corrective Action Reference: NCR 02194468NRC Tracking Number: URI 05000400/2018001-01
05000334/FIN-2018403-0331 March 2018 23:59:59Beaver ValleySecurity
05000395/FIN-2018010-0231 March 2018 23:59:59SummerFailure to Verify the Seismic Qualification of Valcor Solenoid Operated Valve XVX06050ACalculation VCS-0423-DC-1, Valcor Voltage and Current Reducing Resistors, Rev. 0, dated September 10, 1981, located in Tab E1 of EQDP-H-VO4-V01 for solenoid operated valve XVX06050A, indicated a 300 ohm resistor was in series with the valve and that it reduced the voltage in the coil to approximately 32VDC at minimum conditions. The team questioned if the valve was seismically qualified at the lower voltage since the seismic qualification in test report QR 52600-515, Section 4.2.5, Seismic Vibrations, stated that it was performed at 108VAC. The team noted that the Valcor SOV was not installed in the same configuration that it was seismically qualified. The failure to ensure the valve was seismically qualified, as configured, did not ensure that damage would not occur during a seismic event. FSAR Section 3.10 stated that seismic qualification must be done in 7 Enclosureaccordance with IEEE 344-1971. Section 3.2.2.2 of IEEE 344-1971 states the device being tested should demonstrate its ability to perform its intended safety function and sufficient monitoring equipment should be used to evaluate its performance. The team determined that the licensee did not demonstrate the seismic qualification of valve XVX06050A in its current plant configuration at reduced voltage. Corrective Actions: On February 15, 2018, the licensee entered this issue into their corrective action program as CR 18-00686 and performed an immediate determination of operability to verify that the valve could still perform its intended safety function. Corrective Action Reference: CR 18-00686 Performance Assessment: The licensees failure to verify the adequacy of the seismic design and qualification of valve XVX06050A in accordance with IEEE 344-1971 was a performance deficiency (PD). The PD was determined to be more than minor because it adversely affected the Design Control attribute of the Barrier Integrity cornerstone and adversely affected the cornerstone objective of providing reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, the failure to verify the adequacy of design for seismic qualification of the valve resulted in the valve being installed in an unqualified configuration. The team used inspection manual chapter (IMC) 0609, Att. 4, Initial Characterization of Findings, issued December 7, 2016, for barriers, and IMC 0609, App. A, The Significance Determination Process (SDP) for Findings At-Power, issued June 19, 2012, and determined the finding to be of very low safety significance (Green) because the finding did not represent an actual open pathway in the physical integrity of reactor containment, containment isolation system, and heat removal components and did not involve an actual reduction in function of hydrogen igniters in the reactor containment. Since the underlying cause of the issue occurred on August 30, 1988, the team determined that no crosscutting aspect was applicable because the finding was not indicative of current licensee performance. Enforcement: Title10 CFR Part 50, Appendix B, Criterion III Design Control, requires, in part, that The design control measures shall provide for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculational methods, or by the performance of a suitable testing program. Contrary to the above, since August 30, 1988, the licensee failed to verify valve XVX06050A was seismically qualified in its current configuration in accordance with IEEE 344-1971. This violation is being treated as an NCV, consistent Section 2.3.2 of the Enforcement Policy.
05000400/FIN-2018410-0131 March 2018 23:59:59HarrisSecurity
05000395/FIN-2018010-0431 March 2018 23:59:59SummerUnjustified Qualified Life for ASCO ValvesThe NRC opened a Unresolved Item (URI) to determine if a performance deficiency was more than minor. In 1993, the licensees contractor, Impell Corporation, re-analyzed the qualified life established by ASCO qualification report AQR-67368 and a field notification from ASCO dated 10/27/1989. Impell erroneously used the heat rise temperatures from the field notification for both the AQR-67368 test samples accelerated aging temperature and the actual service temperatures in various plant locations. Replacing the actual test specimens documented accelerated aging temperature with an assumed temperature was not justified. As a result, when using the actual temperature identified in the qualification report, many of these solenoids are currently beyond their qualified lives. The licensee provided an alternate heat rise test report less limiting than the ASCO testing to justify that the ASCO valves were within their service lives, report 8058-001-2000-RA-0001-R00, Environmental Qualification Temperature Test of ASCO 206 and NP Series Solenoid Valves, dated June 2000. The teams evaluation must determine whether the alternate report is applicable to the licensee, and, if so, whether the test report indicated that the ASCO testing was invalid to conclude that the valves are currently within their qualified lives. 10 EnclosureNUREG-0588 Section 4(6) and Regulatory Guide 1.89, Rev. 1, Regulatory Position 5.c, required, in part, that the aging acceleration rate and the basis upon which it was established be described, documented, and justified. The team determined that the failure to justify the aging acceleration rate was a performance deficiency. However, a review of the additional information is warranted to determine if the performance deficiency is more than minor. The licensee entered the performance deficiency into their corrective action program as CR-18-00175 and determined that preliminary calculations indicated that the ASCO valves are currently operable based on the additional information provided for review.
05000364/FIN-2018001-0231 March 2018 23:59:59FarleyEnforcement Action (EA)-18-025:Unit 2 Main Steam Safety Valve (MSSV) Lift Pressure Outside of Technical Specification LimitsOn October 26, 2017, MSSV Q2N11V0012E was removed from service at Farley Nuclear Plant Unit 2 during a refueling outage, and on November 1, 2017 the valve was tested with steam at an offsite facility. As-found lift testing determined that the valve opened at 1171 psig steam pressure, which was 9 psig high outside the plant technical specification (TS) allowable lift setting range of 1096 psig to 1162 psig. The valve had been in service prior to the plant beginning commercial operation on July 30, 1981, until it was removed from the main steam system on October 26, 2017. The licensee last tested the valve, while installed on the main steam system, on April 5, 2016. The test results indicated the lift pressure was within +/- 1% of the TS 3.7.1 required set pressure of 1129 psig, and no set pressure adjustment was necessary for the valve. The licensee determined that the MSSV high as-found lift set-point did not have an adverse impact on the main steam system over-pressurization protection, since the valve as-found lift setpoint was lower than 110% of steam generator design pressure (1194 psig), and this condition would not have resulted in a loss of safety function. Therefore, the plant remained bounded by the accident analysis in the Final Safety Analysis Report (FSAR), based on the as-found condition. Corrective Action(s): The valve was replaced with an operable MSSV during the refueling outage prior to plant startup.Corrective Action Reference(s): The licensee entered this issue into their Corrective Action Program (CAP) as condition report (CR) 10426186 as found test results for MSSV Q2N11V0012E. Violation: Farley Nuclear Plant, Unit 2 Technical Specifications (TS) limiting condition for operation (LCO) 3.7.1, Main Steam Safety Valves (MSSVs), required five MSSVs per steam generator to be operable. Per TS Table 3.7.1-2, MSSV Q2N11V0012E must have a lift setting within the range of 1096 psig to 1162 psig, while the Unit was in modes 1, 2, and 3. With one MSSV inoperable and the Moderator Temperature Coefficient (MTC) zero or negative at all power levels, Action Statement, Condition A, Required Action A.1, required reducing thermal power to 87% RTP within 4 hours. If the required action and associated completion time is not met, Action Statement, Condition C, required that the unit be in mode 3 within 6 hours.Contrary to the above, the licensee determined the MSSV setting was outside the TS limits longer than 10 hours during the operating cycle between May 11, 2016 and October 15, 2017, while the Unit was in modes 1, 2, and 3. Severity/Significance: The inspection assessed the severity of the violation using Section 6.1 of the Enforcement Policy and determined the significance is appropriately characterized at Severity Level IV, due to the inappreciable potential safety consequences. The significance of this violation was informed, in part, using IMC 0609, Appendix A, The Significance Determination Process (SDP) for findings at Power, dated June 19, 2012. Basis for Discretion: The NRC exercised enforcement discretion in accordance with Section3.10 of the Enforcement Policy because the MSSV as-found lift pressure issue was not reasonably foreseeable and preventable. The inspectors reached this conclusion due to the fact that the licensee last tested the valve satisfactorily, while installed on the main steam system, on April 5, 2016, and during the period of time that the valve was in service, following May 11, 2016, there was no indication of valve degradation (e.g. seat leakage)
05000395/FIN-2018010-0631 March 2018 23:59:59SummerPotential Unjustified Activation Energy for Barton TransmittersThe contractor, Impell Corporation, changed the activation energy for the Barton transmitters from 0.5 eV to 0.78 eV. The 0.78 eV was based upon an academic paper documenting experimental work, apparently, performed for the early space program and apparently first published in 1965. The paper cautioned the reader that the methods used were experimental and were not validated. A 0.5 eV activation energy for electronics was documented by the Electric Power Research Institute (EPRI) report NP-1558, which attributed it to electron migration of aluminum. The report was available to the licensee at the time of the change. Reports published by the Institute of Electrical and Electronics Engineers (IEEE) indicated that activation energies for various electronic failure modes could range from 0.5-0.66. Impell did not document an independent failure modes and effects analysis to justify the activation energy that they used. The licensee did not find the original qualification activation energies to be in error or non-conservative. The licensee chose to use less limiting activation energies that may not have been proven to be justified. In addition, the licensee was unable to demonstrate acceptable margins for extrapolation uncertainty. FSAR Section 3.11.2.1.3 stated that the environmental qualification of Class 1E equipment is in conformance with RG 1.89, Rev. 1. The RG in Section C.5.c stated that the aging acceleration rate and activation energies used during qualification testing and the basis upon which the rate and activation energy were established should be defined, justified, and documented. NUREG 0588 Section 5(2), Qualification Documentation, specified, in part that a certificate of conformance by itself is not acceptable unless it is accompanied by test data and information on the qualification program. The licensee captured this issue in their corrective action program as CR-18-00500, and determined that the NRC challenged the qualified life for Barton installed as IPT00456 based on an activation energy. VC Summer engineering does not agree with the NRC, nor do the OEMs Barton, Weed/Foxboro and Rosemount who have reviewed their prior research and state that it is suitable and adequate for our applications. The team must determine whether the activation energy used for the Barton transmitters was appropriate and, if not, whether the licensee had the responsibility to verify the information provided by their vendors and contractors.
05000364/FIN-2018001-0331 March 2018 23:59:59FarleyEnforcement Action (EA)-18-026:Unit 2 Pressurizer Safety Valve Lift Pressure Outside of Technical Specification Tolerance BandOn October 26, 2017, pressurizer safety valve Q2B13V0031B was removed from service at Farley Nuclear Plant Unit 2, and on October 31, 2017 the valve was tested with steam at an offsite facility. As-found lift testing determined that the valve opened at 2455 psig steam pressure, which was low outside the plant technical specification allowable lift setting range of 2460 psig to 2510 psig. The valve had been installed and placed in service at Farley Nuclear Plant Unit 2 on April 22, 2013, and remained in service during three complete 18-month fuel cycles. Upon removal of valve Q2B13V0031B from Unit 2 on October 26, 2017, it was replaced with a similar operable refurbished valve. The licensee determined that the safety valve low as-found lift set-point did not have an adverse impact on reactor coolant system over-pressurization protection, since the valve continued to perform its reactor coolant system over-pressure protection function to prevent the system from exceeding the design pressure of 2485 psig. Therefore, the plant remained bounded by the accident analysis in the FSAR, based on the as-found condition. Corrective Action(s): The valve was replaced with a similar operable refurbished valve during the refueling outage prior to plant startup.Corrective Action Reference(s): The licensee entered this issue into their CAP program as CR10425733 PZR safety valve test results Violation: Farley Nuclear Plant Unit 2 TS LCO 3.4.10, Pressurizer Safety Valves, required three operable pressurizer safety valves with lift settings between 2460 psig and 2510 psig, while the Unit was in modes 1, 2, and 3. With one pressurizer safety valve inoperable, Action Statement, Condition A. Required Action A.1, required restoration of the valve to operable status within 15 minutes. If the required action and associated completion time is not met, Action Statement, Condition B, required that the unit be in mode 3 within 6 hours.Contrary to the above, the licensee determined the pressurizer safety valve setting was outside the TS limits longer than 6 hours and 15 minutes during the last operating cycle between May 9, 2016, and October 15, 2017, while the Unit was in modes 1, 2, and 3. Severity/Significance: The inspection assessed the severity of the violation using Section 6.1 of the Enforcement Policy and determined the significance is appropriately characterized at Severity Level IV, due to the inappreciable potential safety consequences. The significance of this violation was informed, in part, using IMC 0609, Appendix A, The Significance Determination Process (SDP) for findings at Power, dated June 19, 2012. Basis for Discretion: The NRC exercised enforcement discretion in accordance with section 3.10 of the NRCs Enforcement Policy because the pressurizer safety valve as-found lift pressure issue was not reasonably foreseeable and preventable. The inspectors reached this conclusion due to the fact that during the period of time that the valve was in service, following June 20, 2016, there were no main control room annunciators actuating for increasing pressurizer relief tank (PRT) pressure or safety valve tailpipe temperature.There was one occasion, on June 20, 2016, when there was evidence of possible seat leakage from valve Q2B13V0031B, based on main control room annunciators actuating for increasing pressurizer relief tank (PRT) pressure and safety valve tailpipe temperature. In addition, the low as-found lift set-point did not have an adverse impact on reactor coolant system over-pressurization protection, since the valve continued to perform its reactor coolant system over-pressure protection function to prevent the system from exceeding the design pressure of 2485 psig
05000250/FIN-2018001-0131 March 2018 23:59:59Turkey PointFailure to conduct post maintenance testing in accordance with ASME OM codeA Green NRC-identified NCV of 10 CFR 50.55a, Codes and Standards, was identified for the failure to adequately perform post maintenance testing on valve CV-4-2906, 4B emergency containment cooler (ECC) air-operated outlet valve, in accordance with the American Society of Mechanical Engineers (ASME) Operation and Maintenance (OM) Code, Subsection ISTC, Inservice Testing of Valves in Light-Water Reactor Nuclear Power Plants.
05000348/FIN-2017009-0231 December 2017 23:59:59FarleyFailure to Complete Corrective Action to Preclude Repetition of a Significant Conditions Adverse to QualityThe NRC identified a non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, for failure to ensure that a corrective action taken to preclude repetition (CAPR) of a significant condition adverse to quality would be implemented. The licensee closed the CAPR tracking item, Technical Evaluation (TE), prior to all affected Steam Flow Transmitter calibration procedures revisions being completed. The licensee entered this issue in the CAP as CR 10413319.The finding was more than minor because it was associated with the Human Performance attribute of the Mitigating System Cornerstone and adversely affected the cornerstone objective in that the licensee closed the TE prior to all affected Steam Flow Transmitter calibration procedures being revised which could potentially prevent th 3 fulfillment of a safety function needed to mitigate the consequences of an accident. Specifically, the licensee closed out the TE CAPR 980655 tracking item on August 24, 2017, when fourteen safety related steam flow transmitter calibration procedures revisions were not completed. Using IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, dated June 19, 2012, and IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, the finding was determined to have very low safety significance because it was not a design or qualification deficiency, did not represent an actual loss of a safety function of a system or a single train greater than its technical specification allowed outage time, and did not screen as potentially risk significant due to external events. The inspectors reviewed IMC 0310, Aspects Within Cross Cutting Areas, dated December 4, 2014, and determined that this finding had a cross-cutting aspect in the area of Procedure Adherence (H.8) because the licensee closed the tracking item prior to completing the corrective action to prevent recurrence.
05000261/FIN-2017007-0431 December 2017 23:59:59RobinsonCrouse-Hinds Qualification and Life ExtensionIntroduction: The inspectors identified an unresolved item (URI) involving three separate concerns that could affect the qualification of Robinsons Crouse-Hinds (C-H) electrical penetration assemblies (EPAs). First, the inspectors were concerned that a similarity analysis, which fulfilled the requirements of Commission memorandum and Order CLI 80-21, In the matter of Petition for Emergency and Remedial Action, and 10 CFR 50.49, Environmental Qualification for Electric Equipment Important to Safety for Nuclear Power Plants, may not have been completed. Second, the inspectors were concerned that Robinson may not have demonstrated that the penetrations electrical performance specifications were met using appropriate IEEE standards, as stated in the UFSAR. Third, the inspectors were concerned that the licensee may not have used appropriate methods when extending the qualified life of the C-H EPAs. Description: (1) In Robinsons initial Bulletin 79-01 response dated June 1980, to justify the qualification of the C-H EPAs by similarity, Robinson submitted a Westinghouse (WEC) qualification report AB-11/12/73, Qualification Tests for a Modular Penetration 5 dia. (Prototype B1), obtained from Brunswick nuclear station; a record of a phone conversation between Robinson and WEC, CPL-77-550, dated 11/29/1977; and a WEC design specification for the C-H EPAs, CPL-R2-E3, dated 6/26/1968. In the technical evaluation report (TER) dated July 8, 1982, that accompanied the NRC staff safety evaluation report (SER) dated January 5, 1983, 10 regarding the Robinson EQ Program, the C-H EPAs qualification was identified as Category IV Documentation Not Available. In the 1982 TER and NRC SER, these specific submitted documents were listed as reviewed and, the qualification of the C-H EPAs remained Category IV. In a licensee letter, dated March 2, 1984, the licensee documented a meeting with the NRC staff discussing Robinsons proposed methods of resolution for each of the EQ deficiencies identified. Robinson appeared to commit to documenting a similarity analysis between their C-H manufactured EPAs and other similar EPAs found acceptable by the NRC staff. In the 1985 final NRC SER, the staff found Robinsons proposed method of resolution specified in the March 2, 1984 letter, acceptable. However, the 1984 submittal summarized a January 18, 1984 meeting with NRC where it was stated the NRC would not perform any additional equipment review and it was left up to the utility to state the adequacy of the documentation. During the inspection, Robinson provided the documents originally submitted (AB- 11/12/73, CPL-77-550, and CPL-R2-E3) to the inspectors to justify qualification by similarity. The inspectors had concerns with these documents justifying similarity between the WEC and C-H EPAs. a) In a review of AB-11/12/73 and comparing it to what was known about the C-H EPAs, the inspectors identified that the materials used in the WEC EPAs were not identical or sufficiently similar in material composition or performance specifications. The WEC tested EPAs used silicone rubber O-rings, a proprietary WEC composition Q epoxy resin potting material as the internal filler, and had a 5 diameter. The C- H EPAs did not use O-rings, used room temperature vulcanized (RTV) silicone rubber potting material as the internal filler, a thin layer of Sty-Cast epoxy resin to seal the end opening exposed to a DBA, and has an approximately 11 diameter. b) The inspectors noted the performance requirements demonstrated by the WEC pressure tests did not appear to envelope the required Robinson DBA pressure performance. The WEC maximum pressure only developed 1286.9lbf at 105psig, and the C-H EPA would develop 3955.2lbf at 42 psig. The effects of the more substantial forces on the C-H EPAs was not addressed. c) In the review of specification, CPL-R2-E3, the inspectors noted that specification CPL-R2-E3 was actually an EBASCO specification rather than a WEC specification as had been stated, and that C-H had taken exception to the specification due to chemical incompatibilities between the RTV potting material and cable insulations specified by EBASC O. Many of the Robinson documents still specify these incompatible cable insulations for use with the C-H EPAs without justification. d) In the review of CPL-77-550, the inspectors noted that the record of the phone call did not have any suitably specific information that could justify similarity to the C-H in materials, performance specifications, or manufacturing methods. The inspectors are concerned that Robinson was unable to provide an acceptable similarity analysis to address the deviati ons between the tested and installed EPAs. The licensee entered this concern into t heir corrective action program as NCR 2161911, and determined the equipment was operable. 11 (2) Robinsons UFSAR Section 3.8.1.2 stated, in part, that electrical penetrations are designed and demonstrated by test to withstand, without loss of leak tightness, the containment post-accident environment and to meet the National Electric Code, IEEE - Proposed Guide for Electrical Penetration Assemblies in Containment Structures for Stationary Nuclear Power Reactors or subsequent issues of this standard, IEEE Electric Penetration Assemblies in Containment Structure for Nuclear Power Generating Stations (IEEE 317). In accordance with the IEEE 317 versions reviewed from 1971 to 1976, the performance requirements are to be met by test during all conditions from mild plant conditions (normal) to the most limiting environmental conditions produced during DBAs (accident), and post-accident conditions. When asked to provide the test documentation that met these original requirements, Robinson was not able to provide them. In addition, the inspectors noted that electrical calculation RNP-E-5. 30, Crouse-Hinds Electrical Penetration Ampacity, Short Circuit, and Heat Generation Calculation, revision 6, indicated that the current plant design exceeded the electr ical performance specification for some of the C-H EPAs, and thus these EPAs would not meet the UFSAR and IEEE 317 specifications. The inspectors requested evidence that Robinson met the required verifications testing specified in the UFSAR Section 3.8.1.2, and that those test conditions are bounding of the current electrical plant design described in RNP-E-5.30. The inspectors are concerned that Robinson may not be in conformance with statements in the UFSAR and 10 CFR 50, Appendix B, Criterion III, Design Control, which required, in part, that the design control measures shall provide for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculational methods, or by the performance of a suitable testing program. The licensee entered this issue into their corrective action program as NCRs 2159165 and 2164589. (3) The inspectors identified two concerns with the way Robinson extended the qualified life of the C-H EPAs. First, Robinson reverse calculated an activation energy which appears to be outside of known acceptable Arrhenius techniques. Second, Robinson derived activation energies from EPAs with materials that were not the same as in the C-H EPAs. The inspectors noted that the Division of Operating Reactors (DOR) guidelines, Guidelines for Evaluating Qualification of Class 1E Electrical Equipment in Operating Reactors, and NUREG 0588 both accepted Arrhenius techniques as acceptable methods for determining the qualified lives of components, and required that the materials be identical or be justified by analysis. For the first concern, UFSAR Section 3.11.3, Qualification Tests Results, specified the EQDPs contained the qualification justification analysis for EQ components. The EQDP-0900, for the C-H EPA, credited the WEC EQ report AB-11/12/73 for thermal aging life calculation. The WEC EQ report applied Arrhenius techniques in accordance with IEEE 98-1972, IEEE Standard for the Preparation of Test Procedures for the Thermal Evaluation of Solid Electrical Insulating Materials, and IEEE 101-1972, IEEE Guide for the Statistical Analysis of Thermal Life Test Data. The WEC EQ report indicated that they had determined an activation energy and the confidence bounds, but they did not include this information or the data used to derive it. The omitted information would be required to identify the limitations of what WEC had derived for their thermal aging. To derive the pseudo activation energy and extend the life of the C-H EPAs from 40 to 60 years, Robinson applied 12 an Arrhenius equation and discounted the limitations involved with using the Arrhenius extrapolation techniques as specified in known quality standards. For the second concern, the inspectors determined that there were material deviations between the WEC and C-H EPAs that could potentially invalidate the pseudo activation energy Robinson derived. Robinson derived a 1.018eV activation energy, when the silicone RTV known to be used in construction of the C-H EPA had a more limiting activation energy of 0.63eV. The 0.63eV would have significant negative effect on the qualified life of the C-H EPA, invalidating the life extension and current EQ status. In addition, the inspectors noted that in the Robinson license renewal application and safety evaluation report, NUREG 1785, Section 4.4.1.1, Summary of Technical Information in the Application, the licensee appeared to commit to using the Arrhenius method, as described in Electric Power Research Institute (EPRI) NP- 1558, A Review of Equipment Aging Theory and Technology. The inspector noted that NP-1558 was not a quality standard as required by general design criteria 1 and 10 CFR 50.54(jj); however, its use would have likewise invalidated the WEC information for the C-H life extension. The inspectors are concerned that despite the specifications in the IEEE quality standards and the information in EPRI report NP-1558, Robinson extrapolated an invalid qualified life for the EPAs possibly making them unqualified to withstand a DBA. The licensee entered this concern into their corrective action program as NCR 2164567. This URI is opened to determine if a performance deficiency or a violation exists. To resolve the various aspects of this URI, the inspectors need: (1) Actual material and performance specification similarity analysis or confirmation of licensing basis; (2) The documented verification testing that satisfies statements in UFSAR 3.8.1.2, and confirmation that the electrical performance specifications tested are bounding of the current plant design; and 3) Confirmation that the actual penetration materials needed to be used when extending the qualified life, and what is required for appropriate application of Arrhenius techniques. (URI 05000261/2017007-04, Crouse-Hinds Qualification and Life Extension)
05000395/FIN-2017007-0131 December 2017 23:59:59SummerFailure to Verify the Adequacy of Design for the EFW system when Supplied by SWThe NRC identified a non-cited violation (NCV) of Title 10 of the Code of Federal Regulations (CFR) Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to verify the emergency feedwater (EFW) pumps would be capable of taking suction from service water for an indefinite period of time as required by Updated Final Safety Analysis Report Section 10.4.9.2. The licensee entered this issue into their corrective action program (CAP) as condition report (CR) 17-05528 and performed an operability determination to verify the EFW pumps remained operable. The performance deficiency was determined to be more than minor because it was associated with the design control attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to evaluate worst-case design conditions resulted in a reasonable doubt that the EFW pumps could provide cooling water to the steam generators and perform their design basis function. The team determined the finding to be of very low safety significance (Green) because the finding was a deficiency affecting the design or qualification of a mitigating structure, system, and component (SSC), and the SSC maintained its operability. The team determined that no crosscutting aspect was applicable because the finding did not reflect current licensee performance
05000348/FIN-2017004-0331 December 2017 23:59:59FarleyFailure to Follow Procedure Resulted in Inoperable TDAFW pumpA self -revealing NCV of Technical Specification (TS) 5.4.1.a, Procedures, was identified when the Unit 1 Turbine Driven Auxiliary Feedwater (TDAFW) uninterruptible power supplies (UPS) swapped to a bypass power source during maintenance on November 5, 2017. As a result, the TDAFW pump was rendered inoperable. Failure to follow licensee procedure FNP-1-EMP-1352.01, TDAFW UPS Battery Weekly Battery Inspection, Version 19, as written was a performance deficiency. The operability of the TDAFW pump UPS was restored after approximately 3 hours. The licensee entered this issue into their Corrective Action Program (CAP) as Condition Report (CR) 10427370.The finding was more than minor because it was associated with the equipment performance attribute of the mitigating system cornerstone and adversely affected that cornerstone objective to ensure the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences since the TDAFW pump was rendered inoperable. The significance of this finding was evaluated using IMC 0609, Appendix A, The Significance Determination Process (SDP) for findings at Power, dated June 19, 2012. This finding was determined to be of very low safety significance (Green) because all of the mitigating systems screening questions were answered NO. The inspectors determined the finding had a cross-cutting aspect of Avoid Complacency in the Human Performance area because the individuals involved in this maintenance did not recognize or plan for the possibility of mistakes and appropriate error reduction tools were not implemented. (H.12)
05000338/FIN-2017403-0131 December 2017 23:59:59North AnnaSecurity
05000261/FIN-2017007-0331 December 2017 23:59:59RobinsonFailure to Determine Most Severe Containment Spray pHThe NRC identified a non-cited violation of 10 CFR Part 50.49, Environmental qualification of electric equipment important to safety for nuclear power plants, for the licensees failure to correctly determine the most severe composition of chemicals for containment spray for the purposes of environment al qualification of equipment in containment. Specifically, the licensee did not identify that the pH of the chemical spray could have been more severe than what was identified in the Environmental Qualification zone maps if the Spray Additive Tank (SAT) had been operated at its limits provided in procedures CP-001 and OST- 023. In response to this issue, the licensee placed the issue into their corrective action program as NCR 2162081, demonstrated operability by reviewing current and historical operating conditions of the tank, and implemented administrative controls to prevent exceeding the qualified pH limit. This performance deficiency was more than minor because if left uncorrected, the performance deficiency had the potential to lead to a more significant safety concern. Specifically, the containment spray pH could have exceeded the pH to which equipment inside containment was qualified, if the SAT had been operated at its procedural limits. The inspectors determined the finding to be of very low safety significance (Green) because the finding was a deficiency affecting the design or qualification of a mitigating structure, system, or component (SSC), and the SSC maintained its operability or functionality. A cross-cutting aspect was not assigned because the finding was not indicative of current licensee performance.
05000395/FIN-2017004-0331 December 2017 23:59:59SummerFailure of an Emergency Feedwater Auto Start Actuation SignalA self-revealing, Green, non-cited violation (NCV) of Technical Specification (TS) 3.3.2 was identified involving the failure of the C main feedwater pump to trip and resultant loss of an emergency feedwater auto start actuation signal. The licensee entered the issue in their corrective action program as condition report, CR-17-01611. The inspectors reviewed IMC 0612, Appendix B, Issue Screening, and determined that the PD was more than minor and therefore a finding because it impacted the Mitigating Systems Cornerstone by adversely affecting the cornerstone objective to ensure in part the availability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the equipment reliability attribute was impacted because a failure of the C main feedwater pump to trip when required rendered an EFW auto start actuation signal inoperable. The inspectors used IMC 0609, Significant Determination Process, Attachment 4, and Appendix A Exhibit 2, and determined that the finding was of very low safety significance, Green, because there was no design deficiency or loss of function. Specifically, EFW auto start capability remained operable for other functions to maintain short term heat removal capability. The inspectors reviewed IMC 0310, Aspects Within Cross Cutting Areas, and determined the cause of this finding involved the cross-cutting area of Human Performance and the aspect of problem identification and resolution, P.2, because the licensee had previous indications of water intrusion and feedwater pump control issues and failed to thoroughly evaluate to address the cause.
05000280/FIN-2017004-0231 December 2017 23:59:59SurryFailure to Identify a Non-Functional Flood Control BarrierAn NRC-identified Green NCV of 10 CFR Part 50, Appendix B, Criterion XVI was identified for the licensees fa ilure to identify a condition adverse to quality related to the material condition of the machinery equipment room (MER) 5 flood dike. Specifically, the inspectors identified on November 13, 2017, several bolts on the connecting plates of the dike that were visually not flush, and found to be loose. As a result, the licensee declared the MER 5 flood dike non-functional and the D and E main control room (MCR) chillers inoperable. This issue was documented in the licensees CAP as CR 1083839. As immediate corrective action, the licensee torqued all structural bolts to 12 ft-lbs and floor anchor nuts to 55 ft-lbs per WO 38103865619.The inspectors determined that failure to identify a condition adverse to quality associated with the material condition of the MER 5 flood dike was a PD. Specifically, the inspectors identified on November 13, 2017, several loose bolts on the connecting plates of the MER 5 flood dike. As a result, the licensee declared the MER-5 flood dike non-functional and the D and E main control room (MCR) chillers inoperable. The inspectors determined that the PD was more than minor because it was associated with the protection against external factors attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensee failed to ensure that WO 38103734871 and drawing 11548-FC-6L had fastener torque specifications and a re-torque requirement for the MER 5 dike after it was re-assembled; and failed to identify a non-functional MER 5 flood dike. Using IMC 0609.04, Initial Characterization of Findings, Table 2, dated June 19, 2012; the finding was determined to affect the Mitigating Systems Cornerstone. The inspectors screened the finding using IMC0609, Appendix A, SDP for Findings at-Power dated June 19, 2012, the inspectors determined that a detailed risk evaluation was required. A detailed risk evaluation of the PD was performed in accordance with IMC 0609 Appendix A by a regional Senior ReactorAnalyst (SRA) using input from the licensees full scope Probabilistic Risk Assessment model. The result of the bounding analysis was an increase in core damage frequency due to the performance deficiency of <1E-6/year, a Green finding of very low safety significance.This finding has a cross-cutting aspect in the evaluation component of the problem identification and resolution area, P.2, because the organization did not thoroughly evaluate issues to ensure that resolutions address causes and extent of conditions commensurate with their safety significance. Specifically, ETE SU-2017-0044, written for the May, 2017, non-functional MER 5 flood dike, did not thoroughly evaluate gasket type and bolting torque, when evaluating if epoxy was required for the assembly of the MER 5 flood dike.
05000261/FIN-2017007-0231 December 2017 23:59:59RobinsonFailure to Perform Required O-ring Replacement to Maintain QualificationThe NRC identified a non-cited violation of 10 CFR Part 50.49, Environmental qualification of electric equipment important to safety for nuclear power plants, for the licensees failure to correctly identify the maintenance required to maintain the core exit thermocouple reference junction box in a qualified state. Specifically, the licensee did not identify that the qualifying entity required that the cover O-ring be replaced on a 5 year frequency in addition to being replaced any time the junction box cover was removed, and due to this, the O-rings have not been replaced since original installation. In response to the issue, Robinson staff placed the issue in their corrective action program as NCRs 2157897 and 2161580, and demonstrated operability via analysis of the qualification test results. This performance deficiency was more than minor because it was associated with the Equipment Performance attribute of the Mitigating Systems Cornerstone, and adversely affected the cornerstone objective of ensuring availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, not maintaining the equipment in its qualified configuration affected its reliability. The inspectors determined the finding to be of very low safety significance (Green) because the finding was a deficiency affecting the design or qualification of a mitigating structure, system, or component (SSC), and the SSC maintained its operability or functionality. A cross-cutting aspect was not assigned because the finding was not indicative of current licensee performance.
05000251/FIN-2017004-0131 December 2017 23:59:59Turkey PointFailure to Perform an Adequate ASME BPVC Section XI Repair/Replacement Plan for a Code Class 1 and 2 ReplacementA NRC-identified NCV of 10 CFR 50.55a, Codes and Standards, was identified for the failure to adequately perform a Boiler and Pressure Vessel Code (BPVC) class 1 and 2 replacement activity in accordance with the Turkey Point Plant American Society of Mechanical Engineers (ASME) Section XI Repair/Replacement Program. Specifically, the licensee did not ensure a system leakage test conducted on October 19, 2017, was appropriately evaluated to meet the requirements of ASME Section XI for pre-service leakage testing of a Unit 4 high head safety injection (HHSI) cold leg injection check valve that was replaced on October 15, 2017. This issue was entered into the licensees Corrective Action Program (CAP) as ARs 2235484 and 2239149. Corrective actions included documenting a formal bases for current operability via a prompt operability determination and updating work order (WO) documentation to fully comply with ASME BPVC Section XI requirements. This performance deficiency was determined to be more than minor because an inadequate inservice inspection repair/replacement plan adversely affected the Reactor Coolant System (RCS) Equipment and Barrier Performance attribute of the Barrier Integrity Cornerstone objective to provide reasonable assurance that physical design barriers (fuel cladding, reactor coolant system, and containment) protect the public from radionuclide releases caused by accidents or events. In accordance with IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, the inspectors determined that the issue had very low safety significance because there was no actual degradation of the RCS boundary. This finding was assigned a cross-cutting aspect in the Procedure Adherence component of the Human Performance cross-cutting area, in that the licensee did not effectively evaluate and appropriately implement the ASME BPVC requirements in the 4-873A Repair/Replacement Plan which were reiterated in licensee administrative procedure 0-ADM-532, ASME Section XI Repair/Replacement Program (H.8).
05000395/FIN-2017004-0231 December 2017 23:59:59SummerFailure to Implement Corrective Actions to Restore Compliance for Previous NRC-identified Green NCV 05000395/2005007-01The inspectors identified a Green finding associated with a cited violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, for the failure to ensure that conditions adverse to quality as noted in a previous NRC-identified Green NCV, 05000395/2005007-01, EFW Flow Control Valves Are Susceptible to Plugging by Tubercles or Other Debris from Service Water, were corrected. The licensee entered the issue in their corrective action program as condition report, CR-17-04630. The inspectors determined that the failure to promptly identify and correct the conditions adverse to quality (CAQ) for a design in which the emergency feedwater (EFW) flow control valves were susceptible to plugging by tubercles or other debris from the service water (SW) system was a performance deficiency (PD). The inspectors reviewed IMC 0612, Appendix B and determined the PD was more than minor and therefore a finding, because it affected the Mitigating Systems Cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences and the respective attribute of design control because the EFW flow control valves were susceptible to plugging by SW debris. This finding had been evaluated and screened to a low safety significance (Green) and documented in the previous NRCidentified Green NCV, 05000395/2005007-01. Because the licensee failed to implement corrective actions and restore compliance in a timely manner, this violation is being treated as a cited violation, consistent with Section 2.3.3 of the NRC Enforcement Policy. The inspectors used IMC 0310 and determined this finding has a cross-cutting aspect of resolution in the area of Problem Identification and Resolution because the organization failed to take effective corrective actions to address issues in a timely manner commensurate with their safety significance and restore compliance (P.3).
05000261/FIN-2017007-0731 December 2017 23:59:59RobinsonJustification of Activation Energy of ASCO Solenoid Coil AssembliesIntroduction: The inspectors identified a URI concerning the qualified life of ASCO solenoid operated valves. The qualified life determined by the licensee utilized unvalidated information provided by a third-party, non-Appendix B vendor and discounted other critical materials in their weak-link analysis without providing justification in accordance with Regulatory Guide 1.89, Rev. 1. Description: In 2006, the Nuclear Utility Group for Environmental Qualification (NUGEQ) provided a letter suggesting methods to extend the qualified lives of the solenoid operated valves. The licensee modified the qualified life of their ASCO valves as described by NUGEQ and failed to validate and justify the informations acceptability for use. Inspectors determined that the use of MW-35 magnet wires activation energy in place of MW-16 was not appropriate as activation energies are material and failure specific, and are not transferrable between different material compositions. Furthermore, the inspectors determined that the licensee (and NUGEQ) failed to adequately justify the discounting of the other materials in the ASCO solenoid coils, which had lower activation energies than the MW-16 magnet wire as reported by ASCO in their qualification test reports. The failure to justify the discounting of MW-16 magnet wire and other identified limiting component of the ASCO coil assembly was a performance deficiency and a violation of 10 CFR 50.49. Regulatory Guide 1.89, Rev. 1, Regulatory Position 5.c requires, in part, that the basis upon which the rate and activation energy were established should be defined, justified, and documented. Contrary to the above, the licensee failed to justify and document their use of the MW-35 activation energy in place of all other identified limiting activation energies in the ASCO solenoid coil assembly. Additionally, 10 CFR 50.49(e)(5) requires, in part, that equipment be replaced before the expiration of its qualified life unless ongoing testing can demonstrate that the equipment has additional life. Contrary to the above, the licensee failed to demonstrate that the ASCO solendoid coil assemblies have additional life when they failed to justify their departure from ASCOs limiting activation energies. This URI is being opened to determine if this performance deficiency is more than minor. To resolve this URI, the inspectors need to review the licensees response to proposed questions regarding the validation and justification of the appropriate activation energy that will be used in determining the qualified life. (URI 05000261/2017007-07, Justification of Activation Energy of ASCO Solenoid Coil Assemblies)
05000280/FIN-2017004-0131 December 2017 23:59:59SurryInadequate Instructions for Corrective Maintenance on Unit 1 C RC Hot Leg Sample ValveA self-revealing, non-cited violation (NCV) of Surry Technical Specification (TS) 6.4.A.7 was identified for the failure to have detailed written procedures with appropriate instructions in design change packages (DCPs) 78-001, 80-007, and 84-369 when replacing 1-SS-HCV-101C, the Unit 1 C reactor coolant (RC) hot leg sample valve. This resulted in 1-SS-HCV-101C developing a through-wall leak on the tube to valve socket weld. Additionally, due to the reactor coolant system (RCS) boundary leakage, Unit 1 required an unplanned shutdown per TS 3.1.C.3 on August 9, 2017. This issue was documented in the licensees corrective action program (CAP) as condition report (CR) 1075404. During the shutdown, the licensee made an American Society of Mechanical Engineering (ASME) code repair by cutting and capping the tubing to stop the leak. 1-SS-HCV-101C will be restored to normal system configuration during the next refueling outage in April 2018.The inspectors determined that the failure of the licensee to have the instructions necessary to properly install the C RCS loop hot leg sample valve and tubing as required by Surry procedure SUI-0001 was a performance deficiency (PD). Specifically, DCPs 78-001,80-007, and 84-369 did not have instructions necessary to ensure the 1-SS-HCV-101C and the associated tubing was properly mounted to absorb the stresses applied to the valve and tubing during normal operation of the valve. As a consequence of the insufficient supports, 1-SS-HCV-101C experienced a through-wall leak on a socket weld on August 9, 2017, which subsequently required an unplanned shutdown of Unit 1. Using Inspection Manual Chapter (IMC) 0612, Appendix B, Issue Screening, dated September 7, 2012, the inspectors determined that the PD was more than minor because it was associated with the procedural quality attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset stability and challenge critical safety functions during shutdown as well as power operations. Using IMC 0609.04, Initial Characterization of Findings, Table 2, dated October 7, 2016; the finding was determined to adversely affect the Initiating Events Cornerstone. The inspectors screened the finding using IMC 0609, Appendix A, Significance Determination Process (SDP) for Findings at-Power dated June 19, 2012, and determined that it screened as Green because the deficiency did not cause a loss of mitigation equipment relied upon to transition the plant to a stable shutdown condition. This finding did not have a cross-cutting aspect because it is not considered current licensee performance.
05000334/FIN-2017007-0131 December 2017 23:59:59Beaver ValleyNon -Conservative Differential Pressure Value Used in Low Head Safety Injection Motor -Operated Valve Design AnalysisThe NRC team identified a finding of very low safety significance (Green) involving a non- cited violation of 10 CFR 50, Appendix B, Criterion III, Design Control, because FENOC staff did not establish measures to assure that the design bases were correctly translated into specifications, drawings, procedures, and instructions. Specifically, for the recirculation phase following a postulated small break loss -of-coolant accident, engineering staff determined the maximum differential pressure fo r motor- operated valves MOV -1SI -863A and MOV -1SI -863B to be the low head safety injection pump shutoff head, but the actual configuration could have resulted in a higher differential pressure at the valve due to allowable reactor coolant system leakage past downstream pressure isolation valves . In response, FENOC staff initiated corrective action program condition report s and assessed the deficiency , and concluded that affected motor -operated valves remained functional although with reduced valve thrust design margin . This finding was more than minor because it was associated with the Design Control attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 2 of IMC 0609, Appendix A, The SDP for Findings At -Power, the team determined that this finding was of very low safety significance (Green) because it was a design deficiency confirmed not to result in the loss of operability or functionality. This finding was not assigned a cross -cutting aspect because the issue did not reflect current licensee performance.
05000395/FIN-2017004-0131 December 2017 23:59:59SummerFailure to Accomplish Station Procedures for Severe WeatherThe NRC identified a Green finding (FIN) for the failure of the licensee to accomplish operations administrative procedure, OAP-109.1, Guidelines for Severe Weather, Rev. 4H, for adequate control of sandbags used for ground level plant building access door protection during a permissible maximum precipitation (PMP) or other adverse rainfall events. The licensee entered the issue in their corrective action program as condition reports, CR-17-05632 and CR-17-05783.The inspectors reviewed IMC 0612, Appendix B, Issue Screening, and determined the performance deficiency (PD) was more than minor and therefore a finding because the PD affected the Mitigating Systems Cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences and the respective attribute of protection against external factors (i.e., flooding). Specifically, without the sandbag container sealed, the licensee would not be able to expedite the sandbags into the protected area (PA), and degradation of the sandbags would have prevented use as specified. The inspectors reviewed IMC 0609, Attachment 4, Appendix A, and Exhibit 4, for the significance determination, and determined the finding was of very low safety significance, or Green, because the finding does not involve the total loss of any safety function, identified by the licensee through a probabilistic risk analysis (PRA), individual plant examination of external events (IPEEE), or similar analysis, that contributes to external event initiated core damage accident sequences (i.e., flooding). Specifically, the time afforded the licensee via weather forecasting would have allowed other measures to mitigate ingress of flood waters into plant areas.The inspectors reviewed IMC 0310, Aspects Within Cross-Cutting Areas, and determined the cause of the finding involved the area of human performance and the aspect of H.1:Resources: Leaders ensure that personnel, equipment, procedures, and other resources are available and adequate to support nuclear safety, because the licensee did not ensure that resources were available to check the security seals on the containers and the licensee did not ensure the sandbags were capable of meeting its intended function.
05000261/FIN-2017007-0531 December 2017 23:59:59RobinsonQuestions Regarding EQDP-0401 Method Used to Determine Activation Energy and Responsibility for VerificationIntroduction: The inspectors identified a URI concerning Robinsons requirement to verify the qualification of components (e.g., Rosemount transmitters) required to meet 10 CFR 50.49. Description: The Rosemount transmitters EQ described by Robinson EQDP-0401, referenced Wyle test report 45592-3 for qualification, which referenced NUREG 0588 Category 1 requirements. The Wyle report, Table III Aging Matrix, identified electronic components along with their respective activation energies (eV) and the references that identified the source of this information. The report specified that thin film metal resistors were the most limiting of these components. The reference for the thin film metal resistor activation energy was an IEEE white paper published in 1965, The Determination and Application of Aging Mechanisms Data in Accelerated Testing of Selected Semiconductors, Capacitors and Resistors. The validity of Wyles determination of activation energies was in question because their methods had not been validated, as stated in the IEEE white paper. The inspectors reviewed the other components in Table III of the Wyle report to verify what components were more limiting and determined that the metal film resistors were not the most limiting. The inspectors identified that the activation energy in the Wyle report for transistors was for metal enclosed transistors, 1.02eV, but the transistors used in the transmitter construction were actually plastic enclosed transistors with activation energies ranging from 0.5eV to 0.66eV. The transmitters used some carbon resistors that were more limiting than metal film resistors and were more sensitive to radiation synergisms. Further, the information in the IEEE white paper seemed to indicate a phase change with an associated more limiting activation energy in the range of the normal plant environmental temperatures. The licensee appeared to not have evaluated this phase change and used the less conservative activation energy from the IEEE white paper throughout their extrapolations. Finally, Robinson may not have reviewed the actual activation energy test data, the test plan and acceptance criteria for the activation energy, or information about the test program, or if any equivalent App. B program supported the informations quality. NUREG 0588 Section 5(2), specified that independent verification of similarity or equivalence must be established, and that it was incumbent on the applicant to have the necessary documentation to justify the adequacy of using data from similar or equivalent equipment. In addition, this Section 5(2) and NUREG 0588, Appendix E, specified, that for electrical equipment that will experience the environmental conditions of design basis accidents for-which it-must function, the licensee must provide: the qualification test plan, test setup, test procedures, acceptance criteria and a summary of test results that demonstrates the adequacy of the qualification program. Additionally, if analysis is used for qualification, justification of all analysis assumptions must be provided. Further, NUREG 0588 Section 4(5) specified that known material phase changes must be addressed; and Section 4(6) specified that the aging acceleration rate used during qualification testing, and the basis upon which the rate was established, should be described and justified. In NUREG 0588 Part II, the comment resolution to Section 4(6), it was specified that the testing of the equipment should be conducted using the most limiting (lowest) activation energy of the components. Standard IEEE 323-1974 Section 5, Principles of Qualification, specified, that principles and procedures for demonstrating qualification include assurance that any extrapolation or inference be justified by allowances for known potential failure modes and the mechanism leading to them. Section 5.1, Type Testing, specified that test alone satisfies qualification only if the equipment to be tested is aged, subjected to all environmental influences, and operated under post-event conditions to provide assurance that all such equipment will be able to perform their intended function for at least the required operating time. The inspectors identified other known failure mechanisms were not considered. For instance, electro-migration of aluminum in diodes, transistors, and Zener diodes present in the electronics has an activation energy between 0.5eV and 0.63eV, which is more limiting than what was used. This failure mechanism was identified in EPRI NP-1558, A Review of Equipment Aging Theory and Technology, and in many IEEE documents that were known at the time of qualification. Robinson used what appeared to be an unvalidated activation energy that also appeared to overlook a phase change that occurs within the licensees service conditions to extend the qualified life. The activation energy value and the method used to arrive at this value are in question. This URI is opened to determine if a performance deficiency or violation exists. To resolve the various aspects of this URI, the inspectors need to: (1) assess the validity of the methods used in the IEEE white paper, which includes addressing the apparent phase change; (2) assess the difference of the more limiting activation energies for the resistors used in the Robinson transmitters compared to the value the licensee is using (including addressing the more limiting activation energies for the other electronics in question); and (3) evaluate the self-heating effects of the junctions in the electronic components and its impact on activation energy. Finally, the inspectors need to assess what responsibilities and to what extent, the licensee has to ensure the activation energies provided by an Appendix B vendor, are accurate and reasonable. The licensee entered this concern into their corrective action program as NCR 2164598. (URI 05000261/2017007-05, Questions Regarding EQDP-0401 Method Used to Determine Activation Energy and Responsibility for Verification)
05000395/FIN-2017007-0331 December 2017 23:59:59SummerFailure to Identify a CAQ for Power Shield Catalog #609903-T501NThe NRC identified an NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Actions, for the licensees failure to identify that a deviation in equipment qualification of power shield relays in 480V switchgear XSW-1DB1 was a condition adverse to quality in their CAP. Specifically, the licensee failed to identify that Power Shield catalog #609903-T501N in purchase order NU-02SR750589 was not qualified to meet its original total integrated dose limit of 100,000 rads as stated in the Asea Brown Boveri 10 CFR Part 21 notification letter. The licensee entered this issue into their CAP as CR-17-05391 and performed an evaluation to determine there was reasonable assurance that the power shield relay in purchase order NU-02SR750589 could perform its intended safety function. The performance deficiency was determined to be more than minor because it was associated with the design control attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to identify that Power Shield catalog #609903-T501N in purchase order NU-02SR750589 was not qualified to the 1,350 rad TID specified in the equipment qualification database for zone AB-72 resulted in a reasonable doubt that the qualification requirements over the relays service life would be met. The team determined the finding to be of very low safety significance (Green) because the finding affected the design or qualification of a mitigating SSC and the SSC maintained its operability. The team determined that no crosscutting aspect was applicable because the finding did not reflect current licensee performance.