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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.
05000334/FIN-2018411-0230 September 2018 23:59:59Beaver ValleySecurity
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-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.
05000280/FIN-2018003-0130 September 2018 23:59:59SurryFailure to Control a Modification on the Containment Spray SystemAn NRC-identified Green non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion III, Design Control, was identified for the licensees failure to control the modification for installation of a drain line on the Unit 1 A Containment Spray (CS) pump bearing housing. This resulted in the drain line being blocked by boric acid and inoperability of the Unit 1 A CS pump.
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-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.
05000395/FIN-2018003-0230 September 2018 23:59:59SummerMinor ViolationThe inspectors concluded that rotation of the safety-related SW pipe support, SWH-4021, was a condition adverse to quality (CAQ) identified in CR-04-01705. The inspectors also concluded that the failure to correct this CAQ was a minor violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, which states in part that CAQs are promptly identified and corrected. Screening: The inspectors determined that the degradation of SWH-4021 was minor based on the absence of any deformed components on the pipe support, and that the respective train of the SW system remained overall operable. The licensee corrected the CAQ during the quarter using WO 1813577, Return SWH-4021 to design requirements. Enforcement: This failure to comply with 10 CFR 50, Appendix B, Criterion XVI constitutes a minor violation that is not subject to enforcement action in accordance with the NRCs Enforcement Policy.
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-2018411-0130 September 2018 23:59:59Beaver ValleySecurity
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.
05000348/FIN-2018014-0230 June 2018 23:59:59FarleyFailure to Provide Complete and Accurate Information Related to System Operator RoundsDuring an NRC investigation completed on November 16, 2017, a SL IV NOV of 10 CFR 50.9, Completeness and Accuracy of Information, was identified when system operators failed to provide complete and accurate information related to system operator rounds. Specifically, on multiple occasions occurring from July 2016 through September 2016, information required by regulations to be maintained by the licensee was not complete and accurate in all material respects. Four SOs failed to comply with the procedural requirements of NMP-OS-007-001, Conduct of Operations Standards and Expectations, and FNP-0-SOP-0.11, Watch Station Tours and Operator Logs, in that on multiple occasions the SOs recorded data for certain readings without ever entering the corresponding area.
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-2018002-0330 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-2018002-0130 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.
05000281/FIN-2018002-0130 June 2018 23:59:59SurryFailure to Follow Preventative Maintenance Procedure Results in Additional Failures of Emergency Bus Undervoltage and Degraded Voltage RelaysAn NRC-identified Green NCV of Surry Technical Specification (TS) 6.4.D was identified for the failure to follow procedure ER-AA-102, Preventative Maintenance Program, which resulted in the Unit 2 H emergency bus degraded voltage (DV) relay failure on March 13, 2018, and the Unit 2 J emergency bus under voltage (UV) relay failure on May 21, 2018, while the unit was operating at rated thermal power (RTP).
05000395/FIN-2018411-0130 June 2018 23:59:59SummerSecurity
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.
05000400/FIN-2018002-0630 June 2018 23:59:59HarrisFailure to Implement Viable Compensatory Actions with Seismic Monitoring System Out of Service for Planned Preventive MaintenanceAn NRC-identified Green NCV of 10 CFR 50.54(q)(2) was identified for the licensees failure to follow and maintain the effectiveness of its emergency plan that meets the requirements of the risk-significant emergency planning standard 10 CFR 50.47(b)(4). Specifically, the licensee failed to implement viable compensatory actions while conducting planned preventive maintenance that rendered both seismic monitoring systems unavailable for 53.5 hours resulting in a loss of emergency assessment capability for declaring a Notification of Unusual Event under Emergency Action Level (EAL) HU2.1 for a seismic event.
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
05000339/FIN-2018011-0130 June 2018 23:59:59North AnnaFailure to ensure compliance with the Technical Specification (TS) 5.4.1.a requirement relevant to procedures for plant firesThe NRC identified a Green finding and associated non-cited violation (NCV) of the TS 5.4.1.a requirement to establish and maintain fire contingency action procedures based upon the licensees failure to effectively perform reviews during the revisions of the procedures in accordance with procedure VPAP-0502, Procedure Process Control. The failure led to undetected errors and was a performance deficiency that was determined to be more than minor because, if left uncorrected, it could potentially lead to a more significant safety concern during Appendix R fire events.
05000348/FIN-2018002-0530 June 2018 23:59:59FarleyFailure of a Main Steam Isolation Valve on the C Steam LineA green self-revealed NCV of Technical Specifications 5.4.1, Procedures was identified for the failure of the licensee to provide adequate procedural guidance in FNP-0-MP-39.0, Main Steam Isolation Valve Disassembly and Reassembly to maintenance personnel for assembling the main steam isolation valve (MSIV) disc arm to the disc. As a result, MSIV 3370C failed, which resulted in partial blockage of the C steam line on March 25, 2018, while the plant was operating at approximately full rated power. The valve disc in the swing-type MSIV separated from the disc arm and fell into the steam flow path. Specifically, the four bolts holding the disc to the arm broke, due to disc to disc arm fluttering, as a result of improper assembly.
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.
05000400/FIN-2018002-0730 June 2018 23:59:59HarrisMinor ViolationA minor, self-revealing violation of TS 6.8.1.a, Procedures and Programs,was identified for failure to follow procedure AD-OP-ALL-0200, Clearance and Tagging. On April 7, 2018, while the plant was in Mode 3 at 0 percent power, the licensee isolated breaker DP-1A-1 circuit 28 in accordance with clearance OPS-1-18-5015-DEH MODS-0093. Isolating this breaker caused an unexpected auto start signal for both motor driven auxiliary feedwater (MDAFW) pumps for a loss of last running main feed pump despite the 1B main feedwater pump still being in operation. Both MDAFWs started and operators manually secured the 1B main feedwater pump to maintain proper feedwater flow to the steam generators. TS 6.8.1.a, requires, in part, that written procedures be implemented covering activities referenced in Regulatory Guide 1.33, Revision 2, dated February 1978, including safety-related activities carried out during operation of the reactor plant. Procedure AD-OP-ALL-0200, Section 5.5, step 4, states Clearance impacts must be evaluated to ensure that effects on systems and components outside of the boundary are identified and are acceptable, or properly dispositioned. Contrary to this requirement, the licensee did not identify that the isolation of breaker DP-1A-1 circuit 28 would cause the MDAFWs to auto start in Mode 3 when developing clearance OPS-1-18-5015-DEH MODS-0093. Screening: The violation is minor because the impact to the plant was minimal; the unit was in Mode 3 throughout the event, the reactor remained subcritical, and feedwater flow to the steam generators was not lost. Enforcement: Because the performance deficiency is minor, it will not be subject to enforcement action in accordance with the NRCs Enforcement Policy. The licensee entered this issue into their CAP as NCR 02196873. The associated LER is closed.
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-2018002-0130 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-2018013-0130 June 2018 23:59:59FarleyInterference with the operation of a respiratorA self-revealing, Green, Finding and associated Severity Level IV Notice of Violation (NOV) of 10 CFR 20.1703 (a), (b) and (e) and plant Technical Specification (TS) 5.4.1, was identified when licensee personnel altered respiratory protective equipment in such a way that its function was inhibited when worn by a worker. Specifically, on September 8, 2016, a Southern Nuclear Corporation (SNC) Corporate Fleet Radiation Protection (RP) Manager, a SNC Corporate Lead Health Physicist, and a Farley Nuclear Plant (FNP) RP Supervisor willfully directed RP technicians to place a cover over the power switch of a Powered Air-Purifying Respirator (PAPR) in violation of the SNC procedure and NRC regulation.
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-2018002-0230 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.
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
05000280/FIN-2018010-0131 March 2018 23:59:59SurryFailure to implement the 10 CFR, Part 50, Appendix R, III.G.3 requirements consistent with fire protection license condition 3I.The NRC identified a Green finding and associated non-cited violation (NCV) of the requirements consistent with license condition 3.I, Surry Units 1 and Unit 2. Specifically, the licensee failed to adequately protect fiberglass pipe that is susceptible to fire damage and required for safe shutdown. By not protecting the pipe, the licensee did not ensure the alternative shutdown methodology was implemented with the independence as defined by the 10 CFR 50 Appendix R section III.G.3 requirements.
05000395/FIN-2018010-0131 March 2018 23:59:59SummerFailure to Justify Activation Energy for Valcor SOV XVX06050AThe qualification of the Valcor SOVs, completed in 1979, used the 10oC rule to determine the accelerated aging rate, which was equivalent to a 0.831 eV activation energy derived for Valcors ethylene propylene rubber (EPR). The inspectors determined that 0.831 eV for EPR, although realistic, it was not the most limiting identified for EPR. Valcor originally qualified the SOVs for 40 years at 120oF, however many of the valves are normally energized and will see temperatures exceeding 120oF. The SOV, XVX06050A, is a normally energized open valve that de-energizes to close on a containment isolation phase A signal and opened post-accident for hydrogen analyzing in the reactor building. In 1988, Impell Corporation, the licensees contractor, reanalyzed the qualification and determined that DuPont Tefzel insulation was the most limiting component instead of EPR and that a 50% loss of tensile strength was the limiting failure mechanism at 0.95 eV activation energy. To extrapolate a new activation energy, Impell estimated data points from a rudimentary log life plot that did not have any actual test data points. Impell obtained the plots from a DuPont Tefzel design handbook which also contained the log life plot for the elongation to break failure parameter of Tefzel, which appeared more limiting than tensile strength. Because the new activation energy extrapolation did not use actual test data, the extrapolation of that data was less limiting than the original qualification activation energy, and the elongation to break failure parameter was not evaluated, the team determined the new activation energy was not justified. 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. Section C.5.c of the RG 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. The licensee did not find the original qualification activation energy to be in error or non-conservative. The licensee chose to develop an activation energy from less limiting log life plots, which was non-conservative. In addition, without actual data for the log life plots, the licensee was unable to demonstrate acceptable margins for uncertainty. The team determined that the valve would have exceeded its qualification based on the original qualification and unjustified use of the new activation energy. Corrective Actions: On February 19, 2018, the licensee entered this issue into their corrective action program as CR 18-00754 and performed an immediate determination of operability to verify that the valve could still perform its intended safety function. Corrective Action Reference: CR 18-00754 6 EnclosurePerformance Assessment: The failure to justify the basis upon which the activation energy of Valcor SOV XVX06050A was established in accordance with RG 1.89 Section C.5.c was a performance deficiency (PD). The PD was determined to be more than minor because it adversely affected the SSC and Barrier Performance 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 justify the activation energy used for Tefzel adversely affected the reliability of the solenoid to maintain its qualification over the entire 40 year qualified life of the plant. 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 in 1988, the team determined that no crosscutting aspect was applicable because the finding was not indicative of current licensee performance. Enforcement: Title 10 CFR 50.49 (e)(5) states Equipment qualified by test must be preconditioned by natural or artificial (accelerated) aging to its end-of-installed life condition. Consideration must be given to all significant types of degradation which can have an effect on the functional capability of the equipment. If preconditioning to an end-of-installed life condition is not practicable, the equipment may be preconditioned to a shorter designated life. The equipment must be replaced or refurbished at the end of this designated life unless ongoing qualification demonstrates that the item has additional life. Contrary to the above, since August 30, 1988, the licensee failed to age Valcor SOV XVX06050A to its end of life condition and to replace the equipment at the end of its designated life. This violation is being treated as an NCV, consistent Section 2.3.2 of the Enforcement Policy.
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.
05000334/FIN-2018403-0331 March 2018 23:59:59Beaver ValleySecurity
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.
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-2018001-0131 March 2018 23:59:59Beaver ValleyInadequate Procedure AdherenceA self-revealed Green finding was identified when the licensee failed to adequately implement procedure NOP-WM-1001, Order Planning Process. Specifically, FENOC personnel that made a change to work order testing requirements did not receive concurrence from a Unit 1 Senior Reactor Operator nor did they ensure that the original scope and/or intent of the test was met.
05000395/FIN-2018010-0331 March 2018 23:59:59SummerInadequate Radiation Harsh Environmental Qualification of Reactor Building Spray Pump ADuring the review of EQDP-H-MO1-G03 for RB spray Pump A, the team noted that the pump was qualified for a maximum harsh environment of 1x106 radiation absorbed dose (rad); however, the total integrated dose (TID) was expected to be greater than 6.1x106rad TID over its 40 year life. Tab F1 of the EQDP, containing the equipment qualification report of the motors dated June 1977, stated that the maximum integrated radiation dose justified by the report over the 40 year operating life of the motor was 1x106 rads. The EQDP stated that component data shows that all components are suitable for the rated 1x106 rads integrated dose with the exception of (a) unfilled polyester resin and (b) the Dacron felt. In all cases, the polyester resins are filled to various degrees with glass or similar products. Such filling of the resin results in a significant increase in the radiation resistance of the combination -- as high as 9x108 rads. The Dacron felt by itself, at a threshold resistance of 8.6x105 rads, approaches the required radiation resistance but the felt is designed to be saturated with the impregnating epoxy resin and occurs only in this state. No specific data is available on the radiation resistance of the combination (Dacron filled epoxy), but the evidence indicates that the combination will exceed the required 1x106 rads. The team noted that the expected TID dose over the 40 year life of the RB spray pump A motor exceeded the original qualification provided in this test report. In order to ensure the pump was qualified for its radiation environment, the licensee had Impell Corporation perform Calculation 0980-036-030, Qualified Radiation Levels for GE Motors, Rev. 0, in August 31, 1988, which concluded that the motor was qualified for 1.5x107rads. The re-analysis was not based on partial type testing of the motor or a similar motor in accordance with NUREG-0588, but only reinterpreted the same material information previously provided by GE. The team noted that the reanalysis made different assumptions than GE did on the material characteristics of an unknown polyester resin fill material and Dacron felt. For the polyester resin, Impell could not determine what the fill material was or how much fill was used, but determined that it had a higher radiation resistance. For the Dacron felt, Impell assumed that the Dacron would not be a weak link in radiation resistance because of the epoxy. These assumptions were used to justify increasing the radiation qualification of the RB spray pump motor. The team determined that the original qualification of 1x106 rads was appropriate and was not proven to be inadequate by Impell because of the uncertainties documented by GE, and the lack of actual type testing information for the motor to support the Impell assumptions. FSAR Section 3.11.2 states that the licensee is committed to NUREG 588 Category II requirements. Section 2.1.2 of NUREG 588 states The choice of the methods selected is largely a matter of technical judgment and availability of information that supports the conclusions reached. Experience has shown that qualification of equipment subjected to an accident environment without test data is not adequate to demonstrate functional operability. In general, the staff will not accept analysis in lieu of test data unless (a) testing of the component is impractical due to size limitations, and (b) partial type test data is provided to support the analytical assumptions and conclusions reached. Section 2.1(3)(a) of NUREG 588 states Equipment that must function in order to mitigate any accident should be qualified by test to demonstrate its operability for the time required in the environmental conditions resulting from that accident. The team determined that the basis for raising the radiation qualification was not justified and that the qualification test report did not demonstrate that RB spray pump A was qualified over its 40 year operating life. Corrective Actions: On February 16, 2018, the licensee entered this issue into their corrective action program as CR 18-00707 and performed an immediate determination of operability to verify that the pump could still perform its intended safety function. 9 EnclosureCorrective Action Reference: CR 18-00707 Performance Assessment: The licensees failure to justify that RB spray pump A could perform its function under the radiation conditions expected during an accident in accordance with Section 2.1(3)(a) of NUREG 588 was a PD. The PD was determined to be more than minor because it adversely affected the Equipment Performance 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. Specifically, the failure to qualify the pump to expected radiation conditions adversely affects the pumps capability to perform its intended safety function during a design basis accident. The team used inspection manual chapter (IMC) 0609, Att. 4, Initial Characterization of Findings, issued December 7, 2016, for mitigating systems, 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 was a deficiency affecting the qualification of a mitigating structure, system, and component (SSC), and the SSC maintained its operability. Since the underlying cause of the issue occurred on August 31, 1988, the team determined that no crosscutting aspect was applicable because the finding was not indicative of current licensee performance. Enforcement: Title 10 CFR 50.49 (e)(4) requires, in part, that the electric equipment qualification program must include and be based on radiation, and the radiation environment must be based on the type of radiation, the total dose expected during normal operation over the installed life of the equipment, and the radiation environment associated with the most severe design basis accident during or following which the equipment is required to remain functional, including the radiation resulting from recirculating fluids for equipment located near the recirculating lines and including dose-rate effects. Contrary to the above, since August 31, 1988, the licensee failed to qualify RB spray pump A to the total dose expected during normal operation over the installed life of the pump and during the most severe DBA. This violation is being treated as an NCV, consistent Section 2.3.2 of the Enforcement Policy
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
05000338/FIN-2018001-0131 March 2018 23:59:59North AnnaFailure to Assure Service Water Pump Sheds from Emergency Bus upon LOOP or SBOA self-revealing Greennon-cited violation (NCV) of Technical Specification (TS)5.4.1.a, was identified for the licensees failure to have adequate written procedures for assuring proper configuration control in areas affected by maintenance or plant modifications. Specifically, the licensee failed to detect and correct a disconnected lead from contact C1 on 1-SW-62-1SWEB03. This directly led to the failure of the 1B service water (SW) pump to shed from the 1J emergency bus during performance of maintenance procedure 1-PT-83.2 on March 11, 2018.
05000364/FIN-2018001-0131 March 2018 23:59:59FarleyFailure to conduct an In-Service Testing (IST)surveillance on the 2B charging pump discharge check valveA Green self-revealed NCV of 10 CFR 50, Appendix B, Criterion XI, Test Control, was identified for the failure to test the 2B charging pump discharge check valve, Q2VE21V122B, in accordance with IST requirements. Specifically, licensee procedure FNP-2-STP-4.2, 2B Charging Pump Quarterly In-service Test was improperly signed off as complete in November 2017, without the required test being conducted. As a result, this was a missed opportunity to identify the degraded check valve which was later declared inoperable when it did not meet the surveillance test acceptance criteria on January 30, 2018.
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-2018410-0131 March 2018 23:59:59HarrisSecurity
05000334/FIN-2018010-0131 March 2018 23:59:59Beaver ValleyInadequate Diesel Fuel Oil Temperature ProtectionThe team identified a finding of very low safety significance (Green) for the failure to ensure that diesel powered Diverse and Flexible Coping Strategies (FLEX) equipment would be reliable to mitigate postulated beyond-design basis external events during very low temperature conditions. Specifically, at temperatures below the site fuel cloud point (4 degrees Fahrenheit (F) to -7 degrees F), portable FLEX equipment, such as emergency diesel powered pumps, were susceptible to conditions in which their capability of starting and operating would be impacted due to fuel crystallizing or gelling and subsequent coating of fuel filter elements.
05000395/FIN-2018010-0531 March 2018 23:59:59SummerPotential High Radiation Dose Areas with Unqualified ComponentsThe NRC opened a URI to determine if a performance deficiency exists. The licensee did not perform analysis to determine the radiation exposure to shielded components adjacent to electrical and blank penetrations on the outboard side through containment. As a result, many mild environment components may be adversely affected. The inboard side of the penetrations is exposed to rad levels approaching 9X107 rads and the out board side is shielded by thin steel plates with electrical pass-thru holes. The inspectors noted that there were many areas of the plant identified as mild environments with unanalyzed penetrations. For example, the inspectors observed that the two trains for the plant service water were adjacent to unanalyzed penetrations. The components adjacent to the outboard side of the penetrations may be unqualified for service conditions expected during the most severe DBA as required by 10 CFR 50.49(e)(4). NUREG-0588 Section 1.4 "Radiation Conditions Inside and Outside Containment," required, in part, that "(8) Shielded components need be qualified only to the gamma radiation levels required..." and that "(12) Equipment that may be exposed to radiation doses below 104 rads should not be considered to be exempt from radiation qualification, unless analysis supported by test data is provided to verify that these levels will not degrade the operability of the equipment below acceptable values. The licensee provided a white paper for this issue that asserts that consideration of radiation streaming was not part of their licensing basis, thus enforcement would be addressed through a backfit analysis in accordance with 10 CFR 50.109. The team must determine whether the site licensing basis required consideration of radiation streaming and whether a backfit analysis would be appropriate in lieu of enforcement. The licensee captured this issue in their corrective action program as CR-18-00684 and determined that the process for qualification of equipment used was found acceptable per the VCS SER. Further evaluation will be performed under this CR but currently all components are qualified to their expected operating conditions and will perform their design functions. At worst, the EQ life of components may be reduced. All equipment in penetration areas are operable.
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.
05000334/FIN-2018403-0231 March 2018 23:59:59Beaver ValleySecurity
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)
05000334/FIN-2018403-0131 March 2018 23:59:59Beaver ValleySecurity