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05000348/FIN-2018011-0130 September 2018 23:59:59FarleyNRC identifiedFailure 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.
05000348/FIN-2018003-0130 September 2018 23:59:59FarleySelf-revealingUnit 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.
05000348/FIN-2018003-0230 September 2018 23:59:59FarleyLicensee-identifiedLicensee-Identified ViolationThis violation of very low safety significance was identified by the licensee and has been entered into the licensee corrective action program and is being treated as a Non-Cited Violation, consistent with Section 2.3.2 of the Enforcement Policy. Violation: Farley Unit 1 Operating License Condition 2.C.(4) and Unit 2 Operating License Condition 2.C.(6), Fire Protection, required in part that Plant Farley shall implement and maintain in effect all provisions of the approved fire protection program that comply with 10 CFR 50.48(c) and NFPA 805. NFPA 805 section 3.2.3 stated, in part, procedures to accomplish compensatory actions implemented when fire protection systems and other systems credited by the fire protection program and this standard cannot perform their intended function shall be established. Licensee procedure FNP-0-SOP-0.4, Fire Protection Operability and LCO Requirements section 4.0 establishes compensatory action when fire protection systems and other systems credited by the fire protection program cannot perform their intended functions. Contrary to the above, since January 16, 2018 through August 28, 2018, the licensee failed to establish compensatory measures (fire watches) as required by licensee procedure FNP-0-SOP-0.4 on thirteen occasions. The cause of the fire watch discrepancies were mainly because Farley Operations staff lacked an adequate understanding and ownership of the fire watch implementation process.
05000348/FIN-2018014-0230 June 2018 23:59:59FarleyNRC identifiedFailure 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-2018002-0430 June 2018 23:59:59FarleySelf-revealingFailure 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.
05000348/FIN-2018002-0530 June 2018 23:59:59FarleySelf-revealingFailure 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.
05000348/FIN-2018002-0630 June 2018 23:59:59FarleyLicensee-identifiedLicensee-Identified Violation

Violation: 10 CFR 50, Appendix B, Criterion XI, Test Control, required in part, a test program shall be established to assure that all testing required to demonstrate that structures, systems, and components will perform satisfactorily in service is identified and performed in accordance with written test procedures which incorporate the requirements and acceptance limits contained in all applicable design documents.

Contrary to the above, the Unit 1 pressurizer power operated relief valve (PORV) PCV-445A was not set up properly for testing and the written test procedures did not incorporate the acceptance limits in all applicable design documents. Specifically, the open and closed limit switches were not set up properly which would result in shorter stroke times during testing per licensee procedure FNP-1-STP-45.11, Miscellaneous Cold Shutdown Valves Inservice Test. Additionally, licensee procedure FNP-1-STP-201.28, Pressurizer Power Operated Relief Valves Position Indication and Relay Logic Contact Verification Q1B31PCV0444B and Q1B31PCV0445A, Ver. 14, allowed a minimum stroke length of 0.5 inches while a vendor evaluation in Request for Engineering Review (RER) 941414 stated a minimum stroke length of 0.56 inches was required.
05000348/FIN-2018002-0730 June 2018 23:59:59FarleyLicensee-identifiedLicensee-Identified Violation

Violation: Technical Specifications (TS) Limiting Condition of Operability (LCO) 3.3.1, Reactor Trip System (RTS) Instrumentation, required the RTS instrumentation for each Function in Table 3.3.1-1 to be operable. The over temperature delta-T (T) function listed in Table 3.3.1-1 required 3 channels to be operable in Modes 1 and 2. With one channel inoperable, the required actions of Condition E of LCO 3.3.1 are required to be performed within the completion time. LCO 3.0.3 required in part, when an LCO is not met and the associated actions are not met, an associated action is not provided, or if directed by the associated actions, the unit shall be placed in a mode or other specified condition in which the LCO is not applicable. Action shall be initiated within 1 hour to place the unit, as applicable, in: Mode 3 within 7 hours; Mode 4 within 13 hours; and Mode 5 within 37 hours.

Contrary to the above, since Unit 2 entered Mode 2 on Nov. 12, 2017, at 1138 with two channels of the OT delta T function inoperable until Nov. 13, 2017, at 0115 when one channel of the T function was restored, the licensee failed to place Unit 2 in Mode 3 within 7 hours and then Mode 4 within 13 hours as required by LCO 3.0.3. The time the two channels of the OTdelta T function was inoperable totaled 13 hours and 37 minutes. LCO 3.3.1 does not provide an associated action with two channels of the OT delta T function inoperable in Modes 1 and 2. The OT delta T trip function is provided to ensure that the design limit departure from nucleate boiling ratio (DNBR) is met. The inputs to the OT deltaT trip include pressure, coolant temperature, axial power distribution and reactor power as indicated by loop delta temperatures at full reactor coolant flow. Power range channel NI-42 provided the channel 2 input and pressurizer pressure instrument PT-457 provided the channel 3 input into the OT deltaT function. PT-457 was declared inoperable on Nov. 11, 2017, at 0522 and NI-42 was declared inoperable on Nov. 13, 2017, at 0136. Because NI-42 was found with a degraded center pin on high voltage cable connector, it was determined to be inoperable since Nov. 10, 2017. As a result, Unit 2 entered Mode 2 with two inoperable channels of OT delta T which is contrary to TS requirements.
05000348/FIN-2018002-0130 June 2018 23:59:59FarleySelf-revealingHigh 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.
05000348/FIN-2018014-0130 June 2018 23:59:59FarleyNRC identifiedFailure 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.
05000348/FIN-2018002-0830 June 2018 23:59:59FarleyLicensee-identifiedLicensee-Identified Violation

Violation: Farley Nuclear Plant Unit 2 Technical Specifications (TS) limiting condition for operation (LCO) 3.7.5, Auxiliary Feedwater System, required all three auxiliary feedwater (AFW) trains shall be operable in modes 1, 2, and 3. For Condition A, one steam supply to turbine driven AFW pump inoperable, the required action A.1 was to restore the affected equipment to operable status within the required completion time of 7 days. 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 and mode 4 within 12 hours. TS Surveillance Requirement (SR) 3.7.5.5 required verification that the turbine driven AFW pump steam admission valves open when air is supplied from their respective air accumulators.

Contrary to the above, the licensee determined the steam admission valve (Q2N12HV3235B) was inoperable longer than the required action completion time of 7 days between May 6, 2016 and October 15, 2017, while Unit 2 was in modes 1, 2, and 3. Unit 2 was not placed in mode 3 or 4 as required by condition C of TS LCO 3.7.5. On October 31, 2017, a turbine-driven auxiliary feedwater (TDAFW) pump steam admission valve (Q2N12HV3235B) was tested with a flow scan analysis device during a refueling outage, while the plant was in Mode 6. This valve is the B-train steam admission valve that supplies steam to the TDAFW pump from the 2C steam generator. There is a redundant A-train steam admission valve that supplies steam from the 2B steam generator. During valve flow scan testing of the valve actuator it was discovered that air was leaking past the actuator piston o-ring seal inside the valve air actuator. Air leakage was measured greater than 10 psig per minute which was significant enough that the valve would not meet surveillance requirement (SR) 3.7.5.5 when instrument air was supplied solely from the valves associated air accumulator. Although the valve would stroke open with air supplied only from the accumulator, the SR 2-hour acceptance criteria to maintain the valve open could not be met. Each steam admission valve has an air accumulator associated with it. The air accumulator is designed to provide a sufficient quantity of air to ensure operation of the valve during a loss of power event or other failure of the normal instrument air supply for a period of two hours. Also, the inspectors determined that the licensee missed an opportunity to determine the cause of the o-ring failure since the o-ring was discarded during actuator rework. Procedure NMP-ES-001, Equipment Reliability Process Description, requires the preservation of physical evidence when failures occur.
05000348/FIN-2018002-0230 June 2018 23:59:59FarleySelf-revealingFailure 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.
05000348/FIN-2018013-0130 June 2018 23:59:59FarleySelf-revealingInterference 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-2018002-0330 June 2018 23:59:59FarleyNRC identifiedFailure 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
05000364/FIN-2018001-0231 March 2018 23:59:59FarleyNRC identifiedEnforcement 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)
05000364/FIN-2018001-0331 March 2018 23:59:59FarleyNRC identifiedEnforcement 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
05000364/FIN-2018001-0131 March 2018 23:59:59FarleySelf-revealingFailure 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.
05000348/FIN-2017009-0131 December 2017 23:59:59FarleyNRC identifiedFailure to Report a Condition Which was Prohibited by Technical SpecificationsThe NRC identified a Severity Level IV (SL IV) non-cited violation of 10 CFR 50.73(a)(2)(i)(b) for failure to report plant operation prohibited by Technical Specification (TS) 3.3.2. Specifically, the licensee failed to perform a past operability evaluation and failed to recognize for having two steam flow channels on the 1 C steam generator inoperable longer than allowed by TS 3.3.2. Consequently, this condition was not discussed and reported on the Licensee Event Report (LER) 2016-007-00 or 2016-007-001. The issue was entered into the licensees CAP as condition report 10413856.This violation adversely affected the NRCs ability to perform its regulatory function; the NRC relies on licensees ability to identify and report conditions or events meeting the criteria specified in the regulations. The licensee did not evaluate past operability and failed to recognize, for the purpose of reportability, that the point of discovery occurred when the data was collected. Because this issue affected the NRC's ability to perform its regulatory function, it was evaluated using the traditional enforcement process. Consistent with the guidance in Section 6.9, Paragraph d.9, of the NRC Enforcement Policy and Guidance in Section 2.3.2.a, this finding was determined to be a Severity Level IV non-cited violation. This finding has no cross-cutting aspect as it was strictly associated with a traditional enforcement violation.
05000364/FIN-2017004-0131 December 2017 23:59:59FarleySelf-revealingFailure to Evaluate Impacts on the 2C RCP Oil Collection SystemA self-revealing finding was identified for the licensees failure to evaluate the impacts to the Unit 2 Reactor Coolant Pump (RCP) 2C oil collection system when a service water (SW) leak was identified on the Unit 2 RCP motor air coolers. As a result, a strategy was not implemented to prevent service water from collecting in the 2C RCP oil collection system drain tank which impacted its design function while the plant was in Mode 1. The licensees failure to evaluate the potential impacts to the Unit 2 RCP 2C oil collection system during the operability/functionality evaluation of the SW leak associated with RCP motor air coolers was a performance deficiency. The licensee initiated condition reports (CRs) 10420400 and 10422562 and replaced the 2C RCP motor and leaking air cooler.The finding was more than minor because it was associated with the protection against external factors (fires) and adversely affected the mitigating systems cornerstone objective to ensure the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, failure to maintain adequate capacity in the RCP 2C Oil Spillage Protection System (OSPS) oil collection tank presented a degradation of a fire confinement component which has a fire prevention function of not allowing an oil leak to reach hot surfaces. The significance of this finding was evaluated using IMC 0609, Appendix F, "Fire Protection Significance Determination Process, dated September 20, 2013, because the performance deficiency affected fire protection defense-in-depth strategies involving fire confinement. Using IMC 0609, Appendix F, Attachment 1, Fire Protection Significance Determination Process Worksheet, the inspectors determined that the finding was of very low safety significance (Green) because the exposed fire area contained no potential damage targets that are unique from those in the exposing fire area. The inspectors determined the finding had a cross-cutting aspect of Evaluation in the problem identification and resolution area because the licensee did not fully evaluate the impacts of the RCP motor air cooler SW leak on the Unit 2 RCP oil collection systems. (P.2)
05000364/FIN-2017004-0231 December 2017 23:59:59FarleyNRC identifiedFailure to maintainan operable Oil Collection System on RCP 2BAn NRC-identified NCV of 10 CFR 50.48(c) and National Fire Protection Association Standard 805 (NFPA 805), Section 3.3.12, was identified for the licensees failure to maintain the Unit 2 RCP 2B oil collection system in an operable condition to perform its design function. Specifically, the licensee failed to ensure that the RCP 2B OSPS oil lift system enclosure collected all oil leakage from all potential leakage sites, including the oil lift system. The licensees failure to maintain the Unit 2 RCP 2B oil collection system in an operable condition to perform its design function was a performance deficiency. The licensee initiated CR 10428611, and determined an oil leak was not active. Another CR was initiated (10446206) to inspect and, if needed, repair this area at the next available opportunity.The finding was more than minor because if left uncorrected, the performance deficiency would have the potential to become a more significant safety concern. Specifically, failing to ensure that the RCP 2B Oil Spillage Protection System oil lift system enclosure collected all oil leakage from all potential leakage sites, including the oil lift system,presented a degradation of a fire confinement component which has a fire prevention function of not allowing an oil leak to reach hot surfaces. The significance of this finding was evaluated using IMC 0609, Appendix F, "Fire Protection Significance Determination Process, dated September 20, 2013, because the performance deficiency affected fire protection defense-in-depth strategies involving fire confinement. Using IMC 0609, Appendix F, Attachment 1, Fire Protection Significance Determination Process Worksheet, the inspectors determined that the finding was of very low safety significance (Green) because the exposed fire area contains no potential damage targets that are unique from those in the exposing fire area. The inspectors determined the finding had a cross-cutting aspect of Design Margins in the human performance area because the licensee did not maintain fire protection defense-in-depth by ensuring the Unit 2 RCP 2B oil collection system was in an operable condition to perform its design function. (H.6)
05000348/FIN-2017009-0231 December 2017 23:59:59FarleyNRC identifiedFailure 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.
05000348/FIN-2017004-0431 December 2017 23:59:59FarleyLicensee-identifiedLicensee-Identified Violation10 CFR 50.55 (a)(b)(5)(i) required in part that licensees must apply the most recent version of ASME BPV Code cases listed in Regulatory Guide 1.147, Revision 17. Contrary to the above, the licensee failed to perform augmented re-examinations on a 30-day periodicity as required by ASME Code Case N-513-3. A through-wall pinhole leak on the Unit 2 Train A Service Water strainer backwash piping was documented in condition report (CR) 10234480 on June 10, 2016. The service water system provides a heat sink for the removal of process and operating heat from safety related components during a Design Basis Accident (DBA) or transient. The backwash piping is safety-related ASME Section III, Class 3 piping. An Immediate Determination of Operability Evaluation (IDO) was performed declaring the strainer operable but degraded non-conforming (OBDN). The licensee followed the guidance of ASME Code Case N-513-3, Evaluation Criteria for Temporary Acceptance of Flaws in Moderate Energy Class 2 or 3 Piping, Section XI, Division 1. The code case requires that an additional five similar susceptible locations be identified and inspected to ensure that another flaw does not exist. In addition to the expanded scope, the code case requires that frequent periodic inspections of no more than30-day intervals shall be used to determine if the flaws are growing to an unacceptable size. An additional CR (10236417) was initiated on June 15, 2016, to request work orders for inspection of these five locations. A total of three examinations were performed on a 30-day periodicity, the last being completed on August 22, 2016. CR 10416364 was initiated on October 5, 2017, documenting that no re-examinations on a 30-day periodicity were performed on the original leak location and the five additional locations since August 22, 2016. The ultrasonic examination was completed on October 5, 2017, and the degraded backwash piping was removed and replaced with new piping by WO SNC795917 on October 28, 2017. This finding was determined to be of very low safety significance (Green) because it was not a design or qualification deficiency, it did not represent a loss of system safety function of a single train for greater than its TS allowed outage time, and it did not screen as potentially risk significant due to seismic, flooding, or severe weather initiating events. This finding was entered into the licensees CAP as CR 10416364.
05000348/FIN-2017004-0331 December 2017 23:59:59FarleySelf-revealingFailure 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)
05000364/FIN-2017003-0130 September 2017 23:59:59FarleyNRC identifiedFailure to perform adequate corrective maintenance on the 2B EDGThe NRC identified a non-cited violation (NCV) of Technical Specification (TS) 5.4.1.a, Procedures, for the licensees failure to implement corrective maintenance work order instructions to identify and replace piping as necessary for a degraded threaded joint on the 2B emergency diesel generator (EDG) jacket water keep warm system piping. As a result, a leak occurred at this threaded pipe joint during surveillance testing which rendered the 2B EDG inoperable. The inspectors determined that the failure to follow work order instructions to replace degraded jacket water system piping during corrective maintenance on the 2B EDG on March 3, 2017, was a performance deficiency (PD). The finding was more than minor because it was associated with the equipment reliability attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. 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. Initial screening by the resident inspectors using the Saphire Farley 1 & 2 SPAR Model resulted in a potentially greater-than-green significance. Therefore, a detailed risk analysis was performed by a regional senior reactor analyst (SRA). The NRC Farley SPAR model was used for internal events, seismic and tornado/high winds risk estimates and the licensees Farley fire probabilistic risk assessment model was used for fire risk estimation. The major analysis assumptions included: a 51-day exposure period, EDG 2B operation at nominal failure to run probability until 8 hours when EDG assumed to fail due to the PD, PD treated as having common cause failure to run potential, no recovery of the 2B EDG was assumed, and no credit for FLEX equipment was assumed. The operation of the EDG for 8 hours prior to failure and remaining mitigating equipment limited the risk. The dominant sequence was a station blackout sequence consisting of a site-wide weather-related loss of offsite power, successful reactor shutdown, random failure to run of the 1/2A and 1C EDGs, failure of the 2B EDG due to the performance deficiency, failure to manually operate the turbine driven auxiliary feedwater pump long term, and failure to recover offsite power or an EDG leading to loss of core heat removal and core damage. The detailed risk evaluation (DRE) determined that the increase in core damage frequency due to the PD was <1.0 E-6 per year, a Green finding of very low safety significance. The finding had a cross-cutting aspect of Conservative Bias in the Human Performance area, because the decision to leave the diesel in a degraded condition following maintenance on March 3, 2017 was neither conservative nor prudent when additional action could have been taken to adequately repair or evaluate the threaded pipe joint (H.14).
05000348/FIN-2017007-0130 June 2017 23:59:59FarleyNRC identifiedFailure to Translate Design Basis Time Requirement into the Time Critical Operator Action Program ProcedureThe NRC identified a non-cited violation (NCV) of Title 10 Code of Federal Regulations (CFR) Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to translate the design basis time limit for the alignment of the emergency core cooling system (ECCS) to cold leg recirculation into their time critical operator action procedure. Specifically, the licensee failed to translate the ECCS to cold leg recirculation alignment activity time requirement of 9 minutes and 25 seconds from calculation SM-94-0452-001, RWST Depletion During Injection Mode with LOCA Until Switchover to Recirculation, Version 5.0, and UFSAR Table 6.3-4, into procedure NMP- OS-014-001, FNP Time Critical Operator Action Program, Version 4.0. The licensee entered this issue into their corrective action program as condition report 10365952 and determined that operability was not impacted due to conservatisms in the calculation and recent operating crew simulator performance. The performance deficiency was determined to be more than minor because it was associated with the procedure quality 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 licensees failure to translate the correct design basis time requirement into their acceptance criteria in procedure NMP-OS-014-001 resulted in several unidentified periodic time validation failures without remediation, therefore adversely affecting the licensees capability and reliability of aligning safety-related equipment needed during a loss of coolant accident within the established design basis time limits. The team determined the finding to be of very low safety significance (Green) because the finding was a deficiency affecting the design and qualification of a mitigating system, structure, or component (SSC), and the SSC maintained its operability. The team determined that no cross-cutting aspect was applicable because the finding did not reflect current licensee performance.
05000348/FIN-2017002-0230 June 2017 23:59:59FarleyNRC identifiedFailure to Follow Procedure Resulted in Inoperable PRF System BoundaryThe NRC identified a Green non-cited violation (NCV) of Technical Specification (TS) 5.4.1.a, Procedures, when inspectors found the 1A containment spray (CS) pump room door (door 106) open on May 12, 2017, without the required dedicated individual to close the door. As a result, the penetration room filtration (PRF) system boundary was inoperable which rendered both trains of the PRF system inoperable. Failure to follow section 19.0 of licensee procedure FNP-0-SOP-0.0, Version 163, was a performance deficiency. The performance deficiency was more than minor because it was associated with the structure, system, component and barrier performance attribute of the barrier integrity cornerstone and adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers protec t the public from radionuclide releases caused by accidents or events. Specifically, when door 106 was open, the PRF system boundary was inoperable, which caused both PRF trains to be inoperable. Without the dedicated individual to close the door as directed, the ability of the PRF system to perform its safety function was compromised. 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 of very low safety significance (Green) because the finding only represented a degradation of the radiological barrier function provided for the auxiliary building through the PRF system. The inspectors determined the finding had a cross-cutting aspect of Teamwork in the Human Performance area because maintenance did not effectively communicate and coordinate their activities with operations to ensure the requirements were met when door 106 was left open (H.4).
05000364/FIN-2017002-0330 June 2017 23:59:59FarleyNRC identifiedFailure to perform adequate corrective maintenance on the 2B EDGTo Be Determined (TBD). The NRC identified an apparent violation (AV) of Technical Specification (TS) 5.4.1.a, Procedures, for the licensees failure to implement corrective maintenance work order instructions to identify and replace a degraded jacket water fitting on the 2B emergency diesel generator (EDG) jacket water keep warm system piping. As a result, a leak occurred on the 2B EDG jacket water piping system during surveillance testing which rendered the EDG inoperable. 3 The inspectors determined that the failure to follow work order instructions to replace degraded jacket water system piping during corrective maintenance on the 2B DG on March 3, 2017, was a performance deficiency. The finding was more than minor because it was associated with the equipment reliability a ttribute of the mitigating systems cornerstone and adversely affected the cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. 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. Initial screening by the resident inspectors using the Sapphire Farley 1 & 2 SPAR Model resulted in a potentially greater-than-green significance. Therefore, a detailed risk analysis will be performed by a regional senior reactor analyst (SRA). The inspectors determined the finding had a cross-cutting aspect of Conservative Bias in the Human Performance area, because the decision to leave the diesel in a degraded condition following maintenance was neither conservative nor prudent when additional action could have been taken to adequately repair or evaluate the piping connection (H.14).
05000348/FIN-2017002-0130 June 2017 23:59:59FarleySelf-revealingFailure to Declare an Unusual Event During an Actual EventA self-revealing Green NCV of Title 10 of the Code of Federal Regulations (CFR) Part 50.54(q)(2), Part 50.47(b)(4), and Appendix E, Section IV.C.2, was identified for the failure to declare a Notification of Unusual Event (NOUE), during an actual event. Specifically, on November 1, 2016, Farley Unit 1 experienced conditions that met Emergency Action Level (EAL) HU3, Release of Toxic, Asphyxiant, or Flammable Gases Deemed Detrimental to Normal Operation of the Plant. The failure to declare a NOUE during an actual event was considered a performance deficiency. This finding was more than minor because it was associated with the Emergency Preparedness cornerstone attribute of Emergency Response Organization Performance (actual event response), and adversely affected the cornerstone objective of ensuring that a licensee is capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. Specifically, on November 1, 2016, Farley Unit 1 experienced conditions that met EAL HU3 for declaring a NOUE when toxic gas (ammonia) was detected in a vital area, which is also part of the owner controlled area. The performance deficiency is associated with the Emergency Classification Planning Standard 10 CFR 50.47(b)(4) and Appendix E Section IV.C.2, and is considered a Risk Significant Planning Standard (RSPS). The failure to declare a NOUE when directed by the EAL Matrix is considered a lost or degraded RSPS in accordance with Section 4 of Inspection Manual Chapter (IMC) 0609, Appendix B. Section 4.3.e of IMC 0609, Appendix B, provides the significance determination for a Failure to Implement, and the performance deficiency was determined to be of a low safety significance (Green). The finding was also determined to be associated with a cross-cutting aspect in the Training component of the Human Performance area because the organization did not provide adequate training to the various ERO members involved in this event to ensure knowledge transfer to maintain a knowledgeable, technically competent workforce, and instill nuclear safety values (H.9)
05000348/FIN-2017007-0230 June 2017 23:59:59FarleyNRC identifiedUntimely Corrective Actions for Check Valve Q2E21V0026The NRC identified a non-cited violation (NCV) of Title 10 Code of Federal Regulations (CFR) Part 50, Appendix B, Criterion XVI, Corrective Action, for the licensees failure to implement timely corre ctive actions to change the classification of check valve Q2E21V0026 (QV026) from cat egory C to category A/C in accordance with ASME OM Code-2001, Subsection ISTC -1300, Valve Categories. The licensee entered this issue into their corrective action program as condition report 10377744, reclassified the valve as category A/C in January 2017 to perform the leakage test during the next outage, and determined there was reasonable assurance the valve could perform its intended safety function until the outage. The performance deficiency was determined to be more than minor because it was associated with the structure, system, component, and barrier performance attribute of the Barriers 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 implement timely corrective actions resulted in the licensee not ensuring reverse flow to the refueling water storage tank (RWST) from the containment sump during the recirculation phase of safety injection (SI) would not exceed the plants dose rate limits. The team determined the finding to be of very low safety significance (Green) because the finding did not only represent a degradation of the radiological barrier function provided for the control room, auxiliary building, or spent fuel pool, and the finding did not represent a degradation of the barrier func tion of the control room against smoke or a toxic atmosphere. The team determined the finding was indicative of present licensee performance and was associated with the cross cutting aspect of Conservative Bias in the area of Human Performance because the licensee failed to use decision making practices that emphasize prudent choices over those that are simply allowable (H.14).
05000348/FIN-2017002-0430 June 2017 23:59:59FarleyNRC identifiedTornado Missile Vulnerabilities Result in Condition Prohibited by Technical SpecificationsOn December 7, 2016, licensee staff determined that the Unit 1 and 2 service water structure intake and exhaust ventilation hoods were not adequately protected from tornado generated missiles. On January 26, 2017, it was also identified that the emergency diesel generator fuel oil storage tank vents were not adequately protected from tornado generated missiles. Upon discovery, the on-shift Operations staff declared the service water pumps and emergency diesel generators inoperable and implemented Enforcement Guidance Memorandum (EGM) 15-002, Enforcement Discretion for Tornado-Generated Missile Protection Noncompliance. The licensee made a non-emergency report in accordance with 10 CFR 50.72(b)(3)(ii)(B) and 10 CFR 50.72(b)(3)(v)(D) via EN# 52414. These items were entered into the licensees CAP and discussed with the resident inspectors. The inspectors reviewed this LER, EGM 15-002 and verified the licensee implemented adequate compensatory measures 19 in accordance with interim staff guidance DSS-ISG-2016-01, Clarification of Licensee Actions in Receipt of Enforcement Discretion per Enforcement Guidance Memorandum EGM 15-002. Final corrective actions to resolve these issues are pending. On December 7, 2016, licensee determined that the Unit 1 and 2 service water structure intake and exhaust ventilation hoods were not adequately protected from tornado generated missiles. On January 26, 2017, the licensee also identified that the emergency diesel generator fuel oil storage tank vents were not adequately protected from tornado generated missiles. The licensee declared the service water pumps and emergency diesel generators inoperable, implemented compensatory measures and declared the affected equipment operable but nonconforming. These issues were entered into the licensees corrective action program and discussed with the resident inspectors. The inspectors reviewed the circumstances associated with the event report and verified the licensee implemented compensatory measures consistent with interim staff guidance DSS-ISG-2016-01, Clarification of Licensee Actions in Receipt of Enforcement Discretion per Enforcement Guidance Memorandum EGM 15-002, (ADAMS ML15348A202). Because this violation was identified during the discretion period covered by Enforcement Guidance Memorandum 15-002, Revision 1, Enforcement Discretion for Tornado Missile Protection non-compliance, (ADAMS ML16355A286) and because the licensee had implemented compensatory measures, the NRC is exercising discretion (EA-17-131) and not issuing enforcement action. The enforcement discretion was applied to the required shutdown actions of the following Technical Specification (TS) LCOs for both units: TS 3.7.8, Service Water System (SWS) TS 3.8.1, AC Sources Operating Final corrective actions to resolve these issues will be addressed by the licensees corrective action program. The licensee has entered this issue into the corrective action program as condition reports 10306023 and 10322897. This LER is closed.
05000348/FIN-2017001-0431 March 2017 23:59:59FarleyLicensee-identifiedLicensee-Identified Violation10 CFR 50.65 (a)(1) required, in part , that holders of an operating license shall monitor the performance or condition of structures, systems and components (SSCs) within the scope of the rule as defined by 10 CFR 50.65 (b), against licensee established goals, in a manner sufficient to provide reasonable assurance that such SSCs are capable of fulfilling their intended functions. Such goals shall be established commensurate with safety. When the performance or condition of a SSC does not meet established goals, appropriate corrective action s hall be taken. Contrary to the above, from October 22, 2015, the time that maintenance rule (MR) function P12 -F02, 1A reactor makeup water system was placed in (a)(1) status, the licensee did not take appropriate corrective actions when performance of the 1A reactor make up water system did not meet licensee established goals and did not repair the cause of previous 1A reactor makeup water pump failures. According to the MR (a)(1) plan EVAL- F-P12 -02947 dated October 22, 2015, work order SNC59263 to flows can pressure control valve (PCV) 510 and calibrate/replace pressure controller 510 was due on February 28, 2016. That work order was not completed on time as discussed in the (a)(1) plan and on June 28, 2016, CR10241662 requested a new work order to make the necessary repairs to PCV -510. As a result, a corrective maintenance work order SNC799691 was generated but was later cancelled. Further discussed in the (a)(1) plan from October 2015 was technical evaluation (TE) 915229. This TE documented the creation of work orders SNC55726 and SNC55728 as a completed corrective action. However, those corrective maintenance work orders were cancelled as part of a WO backlog reduction effort in September 2015. Preventive maintenance work order SNC59263 remained open, but was rescheduled for May 2018. CR10322037 was written by the system engineer and WO SNC59263 was rescheduled for July 2017. On February 8, 2017, CR10328144 identified degradation of PCV -510 and a corrective maintenance WO (SNC 844008) was approved t o repair this valve in April 2017. An equipment outage on the 1A reactor makeup water pump occurred during the week March 13, 2017, but the (a)(1) corrective action WO SNC59263 was not included in this equipment outage. This finding was determined be Green, very low safety significance, because the finding was not a deficiency affecting the design or qualification of a mitigating SSC, did not represent a loss of system and/or function, did not represent an actual loss of function of at least a single Train for longer its TS allowed outage time, and did not represent an actual loss of function of one or more non -TS trains of equipment designated as high safety -significant.
05000348/FIN-2017001-0231 March 2017 23:59:59FarleySelf-revealingPressurizer Safety Valve Setpoint Pressure Outside of Technical Specification Tolerance Banda. Inspection Scope This LER describes an issue with pressurizer safety valve Q1B13V0031B that was removed from service at Farley Nuclear Plant Unit 1 and tested at an offsite facility. As - found lift testing determined that the valve opened below the plant technical specification allowable lift pressure setting range. Firm evidence did not exist to identify when the failure to meet the lift setting occurred prior to the time of discovery at the test facility. The licensee stated in the LER that valve seat leakage was the most likely cause of the as-found lift pressure. During the period of time that the valve was in service, there were no control room indications of seat leakage. Upon disassembly of the valve at the testing facility following testing, there was a small amount of boric acid observed in the valve, indicating there was some seat leakage while the valve was in service. The inspectors reviewed the event, associated documents, and licensee corrective actions. The inspectors also evaluated the issue for any performance deficiencies. b. Findings Description: On October 13, 2016, pressurizer safety valve Q1B13V0031B, removed from service at Farley Nuclear Plant Unit 1, was tested at an offsite facility. As -found lift testing determined that the valve opened at 2443 psig steam pressure, which was low outside the plant technical specification allowable lift setting range of 2460 psig to 2510 psig. The valve was installed at Farley Nuclear Plant Unit 1 on May 27, 2015 , and remained in service during one fuel cycle until removal on October 11, 2016, when 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 i ts 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. Enforcement: Farley Nuclear Plant Unit 1 Technical Specifications limiting condition for operation (LCO) 3.4.10, Pressurizer Safety Valves, required three operable pressurizer safety valves with lift settings 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, A ction Statement, Condition B required that the unit be in mode 3 within 6 hours. Contrary to this, the licensee determined the pressurizer safety valve setting was outside the TS limits longer than 6 hours and 15 minutes during the operating cycle between May 27, 2015 and October 1, 2016, while the Unit was in modes 1, 2, and 3. TS compliance was restored by replacement of the pressurizer safety valve with an operable pressurizer safety valve prior to the beginning of operation for the next fuel cycle. The inspectors concluded that the violation was of very low safety significance (Green) and consistent with a Severity Level IV violation. 13 The NRC exercised enforcement discreti on (Enforcement Action EA -17- 041) for this violation in accordance with secti ons 2.2.4.d and 3.5 of the NRCs Enforcement Policy because the pressurizer safety valve as -found lift pressure was not within the licensees ability to foresee and correct beforehand. The inspectors reached this conclusion due to the fact that during the period of time that the valve was in service, there were no control room indications of seat leakage. 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 co ntinued to perform its reactor coolant system over -pressure protection function to prevent the system from exceeding the design pressure of 2485 psig. This issue was entered into the licensees corrective action program as condition report 10287017
05000348/FIN-2017001-0131 March 2017 23:59:59FarleySelf-revealingFailure to perform PM task resulted in MSIV closureGreen . A self -revealing finding was identified for the failure to maintain a preventive maintenance (PM) task to replace the main steam isolation valve (MS IV) test solenoid valves in accordance with the PM basis. As a result, test solenoid valve N1N11SV3369AG, which was installed for 13 years, failed and, combined with unknown additional air system leakage, led to an inadvertent closure of MSIV Q1N11HV3369A , resulting in a Unit 1 turbine trip/reactor trip with safety injection system actuation on Oct ober 1, 2016. The licensees failure to perform the PM task to replace the MSIV test solenoids in accordance with the PM basis as required by licensee procedure NMP -ES- 006, Preventive Maintenance Implementation and Continuing Equipment Reliability Improvement, Ver. 8.1, section 6.1.1 was a performance deficiency (PD). The PD was more than minor because it was associated with the equipment performance attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during power operations. This finding was of very low safety significance (Green) because the finding did not cause the loss of mitigation equipment relied upon to transition the plant to a stable shutdown condition following the reactor trip. The inspectors determined the finding had a cross - cutting aspect of Trending in the Problem Identification and Resolution (PI&R) area. Prior to this event, there were four documented failures of MSIV test solenoids valves in the last three years that did not get screened for programmatic or common cause issues (P.4).
05000348/FIN-2017001-0331 March 2017 23:59:59FarleyLicensee-identifiedLicensee-Identified Violation10 CFR Part 50, Appendix B, Criterion III, Design Control, required, in part, that measures be established for the selection and review for suitability of application of materials and parts that are essential to the safety -related functions of the structures, systems, and components. Contrary to those requirements, on October 20, 2016, the licensee discovered that an incorrect splice kit for the 1C containment cooler fan was installed on May 4, 2015. The design called for a bolted V splice, but the licensee installed a bolted in- line splice kit that was not suitable for use inside containment in accordance with Environment Qualification Package A -506152- 0029E, Rev. 2. This error resulted in the inoperability of the 1C containment cooler during periods of the Unit 1 operating cycle 27 (May 7, 2015 October 1, 2016). Specifically, there were four periods during applicable modes (modes 1 4) when the 1C containment cooler was the selected cooler for train B for a period greater than seven days, which exceeded the allowed completion time per TS 3.6.6. Upon discovery of the incorrect containment cooler splice kit in -use, the licensee removed and replaced the bolted in- line splice with an approved bolted V splice kit. The repairs were completed and tested on October 25, 2016. The finding was determined to be Green, very low safety significance, because the finding did not represent an actual open pathway in the physical integrity of the reactor containment, nor did it involve an actual reduction in function of the hydrogen igniters using the Barrier Integrity screening questions. The licensee entered this issue into the corrective action program as CRs 10288801 and 10317447
05000348/FIN-2016004-0131 December 2016 23:59:59FarleyNRC identifiedFailure to Adequately Install an Oil Collection System on Reactor Coolant Pump MotorsAn NRC-identified non-cited violation (NCV) of 10 CFR 50.48(c) and National Fire Protection Association Standard 805 (NFPA 805), Section 3.3.12, was identified for the licensees failure to comply with code requirements for design and installation of the Unit 1 Reactor Coolant Pump (RCP) oil collection system. The oil collection system did not include gaskets between the bolted joints on the RCP oil catch-basins, as required by the approved design for the Oil Spillage Protection System (OSPS). The licensees failure to install gaskets on the Unit 1 RCP oil collection systems was a performance deficiency. The licensee was informed of the inspector observation and initiated CR 10289565. Gasket material was installed on all three RCPs on October 23, 2016, as documented on WO SNC464660, SNC459614, and SNC406358. The performance deficiency was more than minor because if left uncorrected, the inadequate installation of the RCP oil collection system presented a degradation of a fire confinement function to prevent oil to leak onto hot surfaces. The significance of this finding was evaluated using IMC 0609, Appendix F, Fire Protection Significance Determination Process, dated September 20, 2013, because the performance deficiency affected fire protection defense-in-depth strategies involving fire confinement. Using IMC 0609, Appendix F, Attachment 1, Fire Protection Significance Determination Process Worksheet, the inspectors determined that the finding was of very low safety significance (Green) because the exposed fire area contains no potential damage targets that are unique from those in the exposing fire area. The inspectors determined the finding had a cross-cutting aspect of Procedure Adherence in the human performance area because the vendor installing the oil catch-basins did not follow the RCP reassembly procedure which required gaskets between all bolted joints. (H.8)
05000348/FIN-2016004-0231 December 2016 23:59:59FarleyNRC identifiedFailure to Perform Adequate NTTF Flooding WalkdownsAn NRC-identified non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion XVI, Corrective Actions, was identified because the licensee failed to identify and correct conditions adverse to quality associated with the flood protection design basis of the Unit 1 Auxiliary Building. Specifically, the licensee failed to identify missing condulet covers in electrical conduits that penetrate the Unit 1 auxiliary building below the flood protection design basis elevation of 154.5 feet (MSL). The inspectors determined that the failure to identify missing condulet covers in electrical conduits that penetrate the Unit 1 auxiliary building below the flood protection design basis elevation of 154.5 feet was a performance deficiency. The discovery of the missing condulet covers was captured in the licensees corrective action program with CR 10273516. The licensee implemented WO SNC815778 to replace missing condulet covers. Corrective actions to inspect the remaining below grade pipe trenches are being developed and scheduled. The performance deficiency 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 of ensuring availability, reliability, and capability of systems that respond to initiating events. Specifically, flood water could enter the Auxiliary Building Lower Equipment Room through unsealed electrical conduits and render the TDAFW Pump inoperable. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 2 of IMC 0609, Appendix A, The Significance Determination Process (SDP) For Findings At-Power, issued June 19, 2012, the inspectors utilized Section B, External Event Mitigation Systems (Seismic/Fire/Flood/Severe Weather Degraded), and Exhibit 4 of Appendix A and determined the finding did not involve a total loss of any safety function, identified through a PRA, IPEEE, or similar analysis, that contributes to external event initiated core damage accident sequences (i.e., initiated by a seismic, flooding, or severe weather event). The two motor driven AFW pumps are also located in the lower equipment room but are protected behind watertight doors and can satisfy the AFW safety function. Therefore, the finding screened to Green. The inspectors determined the finding had a cross-cutting aspect of Procedures in the human performance area because the licensee missed two opportunities to follow the NEI 12-07 guidance to evaluate the adequacy of the flood protection features below the design basis flood protection elevation.(H.8)
05000348/FIN-2016004-0331 December 2016 23:59:59FarleySelf-revealingFailure to Follow Procedure Resulted in Automatic Reactor Trip and Safety InjectionA self-revealing non-cited violation (NCV) of Technical Specification 5.4, Procedures, was identified on October 1, 2016, when the Unit 1 operations shift crew failed to comply with annunciator response procedure FNP-1-ARP-1.9, Ver. 50 for the JC4 annunciator. Conditions were met to trip the reactor, but the operations shift crew failed to do so. As a result, approximately 35 minutes later, MSIV 3369A closed which resulted in an automatic reactor trip and safety injection actuation. The failure of the operations shift crew to follow procedure FNP-1-ARP-1.9 was a performance deficiency (PD). This event was captured in the licensees corrective action program with condition report (CR) 10280729. The licensee established a root cause evaluation team, identified the root causes, and implemented corrective actions (CAR 266911). The PD was more than minor because it was associated with the human performance attribute of the Initiating Events cornerstone objective and adversely affected that objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during power operations. Specifically a manual reactor trip of Unit 1 as required by the ARP, would have prevented the automatic reactor trip and the automatic safety injection actuation. 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, while this issue resulted in a reactor trip, it did not cause the loss of mitigation equipment relied upon to transition the plant from the onset of a trip to a stable shutdown condition. The inspectors determined the finding had a cross-cutting aspect of Procedure Adherence in the Human Performance area, because the ARP was not followed and the operations crew did not trip the reactor as required by the procedure. (H.8)
05000348/FIN-2016004-0431 December 2016 23:59:59FarleyLicensee-identifiedLicensee-Identified Violation10 CFR 20.1501(a)(2) requires, in part, that licensees make surveys to evaluate the magnitude and extent of radiation levels and quantities of radioactive material. 10 CFR 20.1501(b) requires that the licensee shall ensure that instruments and equipment used for quantitative radiation measurements be calibrated periodically for the radiation measured. Contrary to this, on June 2, 2016, the licensee discovered that the surveillance procedure used to calibrate N1D21RE0001 and N2D21RE0001B (MCR Area Monitors) had been deleted and the monitors had not been calibrated for approximately six years. This condition was documented in CR 10231300. Upon re-calibration of N1D21RE0001, the low voltage power supply was found out of tolerance (CR 10256497), indicating that the radiation monitor might not have been able to perform its function of alerting MCR operators of changing radiological conditions. This condition was evaluated using IMC 0609, Appendix C, Occupational Radiation Safety SDP, and determined to be of very low safety significance (Green) because the finding is not related to ALARA dose planning, did not result in an overexposure or the substantial potential for overexposure, and the ability to assess dose was not compromised due to the use of appropriate personnel dosimetry.
05000348/FIN-2016003-0130 September 2016 23:59:59FarleyNRC identifiedFailure to Comply with NFPA-13 for Pre-action Fire Suppression System 1A-36 and Provide NRC Staff Complete and Accurate InformationAn NRC-identified Severity Level IV NCV of 10 CFR 50.9(a), Completeness and accuracy of information, and an associated Green NCV of 10 CFR 50.48(c) and National Fire Protection Association Standard (NFPA) 805, Section 3.9.1, was identified for the licensees failure to accurately evaluate and report non-compliance with code requirements for the design and installation of the Unit 1 pre-action sprinkler system 1A-36. The licensees failure to comply with code requirements for the design and installation of the Unit 1 pre-action sprinkler system, 1A-36 was a performance deficiency. The licensee entered the issue into their corrective action program (CR 10261278). The performance deficiency was more than minor because it was associated with the protection against external factors (i.e. fire) attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the inadequate design and installation of the sprinkler system represented a degradation of a fire suppression component which degraded the fire protection defense in depth element to rapidly detect and suppress fires that occur. The inspectors determined that the finding was of very low safety significance (Green) because the affected fixed fire suppression system would still be able to suppress a fire such that no additional equipment important to safety would be affected by a fire. The inspectors determined the cause of this finding was not associated with a cross-cutting area because it was not reflective of current licensee performance.
05000348/FIN-2016003-0230 September 2016 23:59:59FarleyNRC identifiedFailure to Maintain Requalification Examination IntegrityAn NRC-identified non-cited violation (NCV) of 10 CFR 55.49, Integrity of examinations and tests, was identified for the licensees failure to adhere to examination procedure standards that require the use of sequestering and examination security measures to prevent compromise when the same examination is administered to multiple crews on the same day. While observing simulator exam scenarios, the inspectors identified that neither of two crews scheduled to be evaluated on the same scenario that day were sequestered following completion of the first scenario. Both crews were in the same building and were not being monitored. The first crew was placed on the same Examination Security Agreement as examination developers and evaluators prior to participating in the scenario, as a means to prevent compromise of the examination. The licensee Examination Security Agreement Brief allows discussion of the exam with individuals that are on the Examination Security Agreement. The inspectors informed the licensee of this issue prior to the same scenario being administered to the second crew. The licensee subsequently administered a different scenario to the second crew to prevent any potential examination compromise and entered the issue into their corrective action program (CR 10271868). This performance deficiency was more than minor because it was associated with the Human 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 to prevent undesirable consequences. Specifically, the failure to adhere to examination security standards adversely affected the integrity of the administration of the operating exams, which tests licensed operator performance in order to ensure timely and correct mitigating actions after an event. Using the Licensed Operator Requalification Significance Determination Process, this finding was determined to be of very low safety significance (Green) because no known compromise of the examinations occurred. The inspectors determined the finding had a cross-cutting aspect of Resources in the cross-cutting area of Human Performance because the licensee failed to ensure that adequate training procedures were available to meet industry standards and ensure that the potential for the compromise of regulatory examinations did not exist. (H.1)
05000348/FIN-2016003-0430 September 2016 23:59:59FarleyLicensee-identifiedLicensee-Identified ViolationThe following Severity Level IV violation was identified by the licensee and was a violation of NRC requirements which met the criteria of the NRC Enforcement Policy, for being dispositioned as a non-cited violation. 10 CFR55.21, Medical examination, states, in part, that a licensee shall have a medical examination by a physician every two years. Contrary to the above, on August 30, 2016, the licensee identified that a licensed operator did not complete the required biennial NRC medical examination by May 2016, which was the two year due date. The due date for the licensed operators medical examination was incorrectly entered into the licensees learning management system (LMS) database when the operator received his previous physical while in the initial license training program to upgrade to a senior operator. The inspectors determined that the violation was consistent with a Severity Level IV violation because the licensed operator was not actively performing licensed duties in the control room. This issue was entered in the licensees corrective action program as CR 10267379.
05000348/FIN-2016003-0330 September 2016 23:59:59FarleyNRC identifiedFailure to Perform Adequate Preventive maintenance on Circuit Breaker Cell SwitchAn NRC-identified, non-cited violation of Technical Specification (TS) 3.8.9 Distribution Systems Operating, occurred when the shared 600 VAC 1-2R load center (LC) was inoperable for longer than allowed by technical specifications for Unit 1. The failure to perform adequate preventive maintenance on the ER05-2 circuit breaker cell switch in accordance with licensee procedure FNP-0-EMP-1322.01 was a performance deficiency. This event was entered in the licensees corrective action program as CR 10209365. The licensee cycled the ER05-2 cell switch which cleaned the electrical contact enough to establish continuity to power the closing circuit for the ER02-1 supply circuit breaker and reenergize the 1-2R 600VAC load center. An additional corrective action to replace the cell switch is pending. The 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 because inadequate preventive maintenance on the ER05-2 circuit breaker cell switch led to the inability to detect a degraded electrical contact which resulted in the inoperability of the 1-2R 600 VAC load center on April 13, 2016. This finding required a detailed risk evaluation because it represented an actual loss of function of a single train for greater than the TS allowed outage time. The inspectors used the NRC SPAR model for plant Farley to evaluate the significance of this finding. The regional senior reactor analyst reviewed this evaluation and determined that the increase in risk as a result of the performance deficiency was less than 1E-6 per year, a GREEN finding of very low safety significance. This finding was associated with the cross-cutting aspect of Field Presence in the Human Performance area because if deviations from standards and expectations were corrected promptly, the practice of checking a single electrical contact during the cell switch continuity verification would not have existed. (H.2)
05000364/FIN-2016002-0230 June 2016 23:59:59FarleyLicensee-identifiedLicensee-Identified ViolationTechnical Specifications 5.4.1, Procedures, required, in part, that written procedures shall be established, implemented and maintained covering activities recommended in Regulatory Guide (RG) 1.33, Revision 2, Appendix A. Section 3.f of RG 1.33 Appendix A recommended in part, that instructions for changing modes of operation should be prepared for containment. Licensee procedure FNP-2-STP-34.1, Containment Inspection (Post Maintenance), required in part no loose debris present in containment which could be transported to the containment sump. Contrary to the above, the licensee failed to adequately implement the procedure used to ensure the Unit 2 containment was free of loose material while in Mode 3. On May 7, 2016, the licensee identified approximately 145 square feet of loose debris in the Unit 2 containment following maintenance. These items were removed from containment. On May 10, 2016, the licensee evaluated the impacts on the Unit 2 containment sump and determined a margin of approximately six square feet remained before containment sump screen functionality would be impacted. This was based on a fraction of the material reaching the sump screens due size of loose materials, location of the material in containment relative to the location of the sump screens and the amount of obstructions along the postulated flow paths. The finding was determined to be Green, very low safety significance, because the finding did not represent an actual loss of function for greater than the TS allowed outage time. The licensee entered this issue into the corrective action program as CRs 10220077 and 10220301.
05000348/FIN-2016002-0430 June 2016 23:59:59FarleyNRC identifiedCondition Prohibited by Technical Specifications Due to Turbine Driven Auxiliary Feedwater Design IssueOn November 20, 2015, the Unit 1 TDAFW pump over sped and tripped on startup during surveillance testing. The licensee determined a previous design change that adjusted the MPU override timer setting from 10 seconds to 600 seconds resulted in a governor controller speed set point conflict that revealed itself during the performance of the test. The licensee implemented the set point change after consulting with the vendor as a corrective action to address previous issues with the setting of the MPU override timer. This new failure mode was not anticipated when the TDAFW pump governor controller MPU timer setpoint was changed in April 2015 on Unit 1, and January 2015 on Unit 2. After the modification was made on each unit, several successful starts were performed to validate the setpoint adjustment before the pumps were returned to service. Additionally, the TDAFW pumps had been successfully started 19 times on Unit 1 and 15 times on Unit 2 for surveillances, post-maintenance testing, and troubleshooting while the condition existed. Once discovered, the licensee implemented another design change to adjust the low idle speed setpoint to minimize the potential for turbine speed overshoot on startup. Enforcement: Farley Unit 1 and 2 Technical Specification (TS) limiting condition for operation (LCO) 3.7.5, Auxiliary Feedwater (AFW) System, required three operable AFW trains while the Unit is in modes 1, 2 or 3. With one AFW pump train inoperable, LCO 3.7.5. Condition B required restoration of the AFW train to operable status within 72 hours and within 10 days from discovery of failure to meet the LCO. Contrary to this requirement, Unit 1 operated from May 3, 2015, until November 22, 2015, with the Unit 1 turbine driven AFW inoperable. Unit 2 operated from January 10, 2015, until November 22, 2015, with the Unit 2 turbine driven AFW inoperable. A regional senior reactor analyst (SRA) performed a detailed risk evaluation to evaluate the risk increase associated with the condition. No failures occurred on Unit 2, therefore the condition did not result in a risk increase for Unit 2. The evaluation for Unit 1 was performed using the NRC Farley SPAR model with input from the licensees NFPA 805 Fire PRA model for the fire external event risk. The major analysis assumptions for Unit 1 included a 200 day exposure interval, recovery credit for local manual overspeed trip reset evaluated using the NRC SPAR-H human reliability analysis method, and an overspeed trip startup failure probability determined from plant specific data. The dominant risk sequence was a total loss of service water resulting in a plant trip and failure of the motor driven auxiliary feedwater (MDAFW) pumps, with failure of the turbine driven AFW pump due to the overspeed trip condition on startup with failure of the operator to accomplis overspeed trip reset which would lead to loss of core heat removal and core damage. The result of the detailed risk evaluation was an increase in risk due to the condition of <1.0 E-6/ year. The inspectors concluded that the violation was of very low safety significance (Green) and consistent with a Severity Level IV violation. The NRC exercised enforcement discretion (Enforcement Action EA-16-159) for this violation in accordance with sections 2.2.4.d and 3.5 of the NRCs Enforcement Policy because the impact of the design change was not within the licensees ability to foresee and correct beforehand. The inspectors reached this conclusion due to the number of successful TDAFW pump starts following implementation of the design change and the specific vendor recommendation to adjust the MPU override timer setting to greater than 30 seconds. This issue was entered into the licensees corrective action program as CR 10149716.
05000348/FIN-2016002-0130 June 2016 23:59:59FarleyNRC identifiedFailure to Perform TS Surveillance Requirements for Safety-Related BatteriesAn NRC-identified non-cited violation (NCV) of Technical Specification (TS) 5.4.1 Procedures, was identified with two examples. The licensee failed to implement and maintain surveillance test procedures for surveillance requirements (SR) 3.8.4.4 and SR 3.8.4.2. As a result, the licensee failed to perform actions to satisfy TS surveillance requirements and the battery terminal fasteners corroded and degraded over time. This event was entered into the licensees corrective action program as condition report (CR) 10206961. The licensee conducted the surveillance tests and implemented work order (WO) 777073 to remove visible terminal corrosion, replace corroded termination hardware, and verify battery cell-to-cell and terminal connections were coated with anti-corrosion material. The licensees failure to implement and maintain procedures used to satisfy surveillance requirements for the Unit 1 1B 125VDC auxiliary building battery was a performance deficiency. The performance deficiency was more than minor because, if left uncorrected, it had the potential to result in excessive corrosion buildup on the battery cell-to-cell and terminal connections which could have impacted the ability of the battery to perform its safety-related function. The significance of the finding was of very low safety significance (Green) because it was not a design or qualification deficiency, it did not represent a loss of system safety function of a single train for greater than its Technical Specification allowed outage time, and it did not screen as potentially risk significant due to seismic, flooding, or severe weather initiating events. The inspectors determined the finding had a cross-cutting aspect of Resources in the Human Performance area, because the licensee failed to ensure procedures used to conduct TS surveillance requirements for the 1B 125 VDC auxiliary building battery were adequate and implemented correctly. (H.1)
05000364/FIN-2016002-0330 June 2016 23:59:59FarleyLicensee-identifiedLicensee-Identified ViolationTechnical Specifications 3.4.15, RCS Leakage Detection Instrumentation, required that one containment atmosphere particulate radiation monitor, and one containment air cooler condensate level monitor (CCLM) or one containment atmosphere gaseous radiation monitor be operable in Modes 1 through 4. Contrary to those requirements, on August 7, 2015, Unit 2 was in Mode 1 when the licensee entered into a condition where all of the required monitors were inoperable, and failed to comply with the required actions of limiting condition for operation (LCO) 3.0.3. According to root cause report (CAR 261364), the licensee determined that CCLM system was inoperable on July 6, 2015, when the containment sump in leakage exceeded approximately one gallon per minute (gpm). On August 7, 2015, the licensee removed radiation detectors R-11 (particulate) and R-12 (gaseous) from service for maintenance. The radiation detectors in conjunction with all four containment cooler level indicators being inoperable met the entry conditions for Condition E of Technical Specifications 3.4.15, which required entry into LCO 3.0.3 immediately. This condition existed for 7 hours and 54 minutes, which exceeded the requirement of LCO 3.0.3 to be in Mode 3 within 7 hours. It was later confirmed that the A, B and D CCLMs were inoperable due to clogged drain lines and the C CCLM was tagged out for troubleshooting and repair on August 6, 2015. The inspectors determined that the licensee had previous opportunities to prevent the inoperability of the CCLM system due to the clogged drain lines. According to CAR 261706, a corrective action from February 2007 was not implemented which was a preventive maintenance task to clean and inspect the drain lines and level transmitter sensing lines. The finding was determined to be Green, very low safety significance, because the finding was not associated with loss of coolant accident (LOCA), plant transient, or support systems initiators. The licensee entered this issue into the corrective action program as CR 10155638.
05000348/FIN-2016008-0130 June 2016 23:59:59FarleyLicensee-identifiedInaccurate Training RecordsThe licensee identified a violation of 10 CFR 50.9(a) requirements and an associated finding of very low significance when it was determined that an employee deliberately completed requalification examinations for other employees without their knowledge or consent. Specifically, on three occasions the proctor took annual requalification exams of Fitness-for-Duty, radiation worker, and fire watch training for two other contract employees and made inaccurate entries in training records thereby falsely indicating that the employees actually attempted and passed the examinations. The records inaccurately showed that workers had successfully completed required annual requalification exams for fire watch, fitness for duty and radiation worker training. The licensee was notified about the incident through their employee concerns program and informed the NRC about the concern. Since the finding involved occupational radiation safety, the inspectors utilized IMC 0609, Appendix C, Occupational Radiation Safety Significance Determination Process, dated August 19, 2008, to assess its significance. The inspectors determined that the finding did not involve an overexposure; a substantial potential for an overexposure; a compromised ability to assess dose; or unplanned, unintended occupational collective dose. Consequently, the inspectors determined that the finding was of very low safety significance (Green). The inspectors determined that the finding has a cross-cutting aspect in the area of human performance, field presence, because the licensee did not ensure management oversight of contractor work activities (H.2). This issue was also dispositioned using traditional enforcement due to the willful aspects of the violation. Furthermore, the failure to provide complete and accurate information has the potential to impact the NRCs ability to perform its regulatory function. In accordance with the guidance of the Enforcement Policy and Enforcement Manual, this issue is considered a Severity Level IV violation because it involved information that the NRC required to be maintained by a licensee that was incomplete or inaccurate and of more than minor significance.
05000348/FIN-2016007-0131 March 2016 23:59:59FarleyNRC identifiedFailure to Verify Design Assumptions Associated With the Operation of the Atmospheric Relief Valves (ARVs)The NRC identified a non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for failure to verify design assumptions associated with the operation of the atmospheric relief valves (ARVs) following a steam generator tube rupture (SGTR). The licensee failed to verify that all credited methods of ARV operation as specified in procedure FNP-1-EEP-3, Steam Generator Tube Rupture, Rev. 27 could be performed within the FSAR specified time limit of 30 minutes. Upon identification of the issue, the licensee initiated Technical Evaluation 952125 and conducted two simulated scenarios using the two credited means of operating the ARVs following a SGTR. The licensee was able to show that the actions could be performed within the specified time, although the time results were marginal and did not account for operator error or repeatability. This issue has been entered into the licensees corrective action program as CR 10193323. The performance deficiency was more than minor because it was associated with the Design Control attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding was not greater than green because it affected the design or qualification of a mitigating structure, system, or component (SSC), but the SSC maintained its operability or functionality as documented in CR 10193323. This finding was not assigned a cross-cutting aspect because the issue did not reflect current licensee performance.
05000364/FIN-2016001-0131 March 2016 23:59:59FarleyLicensee-identifiedLicensee-Identified ViolationTechnical Specifications 5.4, Procedures, required, in part, that written procedures shall be established, implemented and maintained covering activities recommended in Regulatory Guide (RG) 1.33, Revision 2, Appendix A. Section 9.a of RG 1.33 recommended that maintenance that can affect the performance of safety-related equipment should be properly pre-planned and performed in accordance with written procedures, instructions, or drawings appropriate to the circumstances. Contrary to the above, the licensee failed to provide procedures that were appropriate to the circumstances for adding the proper amount of oil for the turbine connected to the Unit 2 turbine driven auxiliary feed water (TDAFW) pump. On February 4, 2016, the turbine oil system was overfilled because licensee procedure FNP-0-SOP-22.1, Auxiliary Feedwater Pump Lubrication Procedures, (Ver. 7) and work order SNC 759097 did not contain guidance to identify the proper oil level. The finding was determined to be of very low safety significance (Green) because there was not an actual loss of function for greater than the TS allowed outage time of 72 hours. The licensee entered this issue into the corrective action program as CR 10178550.
05000348/FIN-2015004-0231 December 2015 23:59:59FarleyLicensee-identifiedLicensee-Identified Violation10 CFR 50, Appendix B, Criterion III, Design Control, required in part, design control measures shall provide for verifying or checking the adequacy of design, such as by the performance of design reviews. Contrary to these requirements, the licensee failed to ensure the MPU override timer setting was documented and reviewed for impacts during the initial design implementation of the governor for the Unit 2 TDAFW pump in 2010 and during a subsequent design change that installed a parallel start circuit in 2011. This issue was documented in the licensees CAP as Condition Report (CR) 10009536. A detailed risk evaluation was performed in accordance with NRC IMC 0609 Appendix A using the Farley SPAR model and fire risk data from the licensees Farley Fire Probabilistic Risk Assessment model. The major analysis assumptions included: recovery credit for TDAFW pump restart, a short exposure interval, actual TDAFW pump failure data for Unit 2, and no credit for the reactor coolant pump shutdown seals. The dominant sequence was a loss of service water with a failure of the TDAFW pump and a failure to recover the pump leading to core damage. The result was a finding of very low safety significance (Green).