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05000348/FIN-2018002-082018Q2FarleyLicensee-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-2018002-072018Q2FarleyLicensee-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-2018002-062018Q2FarleyLicensee-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.
05000259/FIN-2018002-042018Q2Browns FerryLicensee Identified Non-Cited Violation

LER 05000259, 260, 296/2018-003-00 identified a violation of 10 CFR 50.48(c)(4)(iii). This 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: 10 CFR 50.48(c)(4)(iii) Fire Protection required, in part, that the licensee maintain fire protection defense in depth (post-fire safe shutdown capability). Contrary to the above, from October 28, 2015 until March 10, 2018, the C3 Emergency Equipment Cooling Water (EECW) pump did not have the Fire Protection Plan required backup control panel function. Significance/Severity: Using IMC 0609 Appendix F, the violation was screened to green following a risk analysis performed by the licensee that a NRC Senior Risk Analyst reviewed and agreed was correctly performed. Corrective Action Reference(s): CR 1394604
05000348/FIN-2018002-042018Q2FarleyFailure 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.
05000259/FIN-2018002-032018Q2Browns FerryFailure to analyze for a Water Hammer event due to Spurious Operation of Residual Heat Removal Service Water (RHRSW) Valves during a Fire EventAn Apparent Violation (AV) of 10 CFR 50.48(c)(3)(ii) was identified for the failure to perform a required analysis using the methodology in Chapter 2 of NFPA 805 for the RHRSW piping as a result of a postulated fire scenario.
05000348/FIN-2018002-032018Q2FarleyFailure 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
05000296/FIN-2018002-022018Q2Browns FerryInoperable Residual Heat Removal (RHR) Pump Results in Condition Prohibited by Technical SpecificationsA self-revealed SL IV NCV of TS 3.5.1 and 3.6.2.3 was identified when the licensee discovered that the 3A RHR pump was inoperable for longer than the allowed outage time and follow on action completion time.
05000321/FIN-2018002-012018Q2HatchEnforcement Action (EA)-18-100: Unanalyzed Conditions for a Postulated Fire Discovered During NFPA 805 TransitionOn April 3, 2017, the licensee submitted Licensee Event Report (LER) 05000321, 366/2017-001-00: Unanalyzed Conditions for a Postulated Fire Discovered During NFPA 805 Transition documenting the discovery of a condition of non-compliance with the sites fire protection program (FPP). In preparation for transiting the fire protection licensing basis from 10 CFR 50.48(b) (Appendix R) to 10 CFR 50.48(c) (NFPA 805), a weak-link and operator manual action analysis was completed for Information Notice 92-18 type hot shorts on motor operated valves (MOV). The licensees examination of their Appendix R Safe Shutdown Analysis identified circuit configurations in multiple fire areas where an Appendix R postulated fire could impact the ability to achieve safe shutdown conditions. The licensee failed to protect MOV cables associated with the RHR and RCIC emergency cooling systems in fire areas 0024 (Main Control Room), 1203F (Unit 1 Reactor Building), 1205F (Unit 1 Reactor Building), and 2203F (Unit 2 Reactor Building). Specifically, the licensee failed to ensure that fire induced cable impacts cannot bypass the limit and torque switches and result in physical damage to the MOVs, thus preventing the MOVs from being operated from the Main Control Room, Remote Shutdown Panel, or locally. This condition could prevent operators from achieving and maintaining safe shutdown (SSD) of the plant in the case of a postulated fire. A licensee-identified non-compliance with 10 CFR Part 50, Appendix R, Section III.G.2, was identified for the licensees failure to protect one of the redundant trains of equipment needed to achieve post-fire SSD from fire damage. Specifically, the licensee failed to use one of the means described in Appendix R, Section III.G.2.a, b, or c to ensure that one of the redundant trains of equipment necessary to achieve and maintain hot shutdown conditions was protected from fire damage. The inspectors performed a detailed review of the information and documents related to the LER and discussed the condition with the licensee to assess the adequacy of the licensees compensatory measures and corrective actions. Corrective Action(s): Hourly fire watches and Fire Action Statements were initiated to address the postulated condition for the identified MOVs. Additionally, the licensee committed to completing physical plant modifications to the impacted MOVs during the next Unit 1 and Unit 2 plant refueling outages to rectify the issue of potential spurious operation of the associated MOVs associated with this LER. Corrective Action Reference(s): The licensee entered this issue into their Corrective Action Program (CAP) as condition reports (CRs) 10326399, 10326401, 10326402, 10326404, and 10326405. Enforcement: Violation: 10 CFR Part 50.48(b)(1) requires that all nuclear power plants licensed to operate prior to January 1, 1979, must satisfy the applicable requirements of 10 CFR Part 50, Appendix R, Section III.G. 10 CFR 50, Appendix R, Section III.G.2, states, in part, that where cables or equipment, that could prevent operation or cause mal-operation due to hot shorts, open circuits, or shorts to ground, of redundant trains of systems necessary to achieve and maintain hot shutdown conditions are located within the same fire area outside of primary containment, one of the following means of ensuring that one of the redundant trains is free of fire damage shall be provided: (a) separation of cables and equipment by a fire barrier having a 3-hour rating, (b) separation of cables and equipment by a horizontal distance of more than 20 feet with no intervening combustibles or fire hazards and with fire detectors and an automatic fire suppression system in the fire area, or (c) enclosure of cables and equipment in a fire barrier having a 1-hour rating and with fire detectors and an automatic fire suppression system in the fire area. Contrary to the above, the licensee failed to use one of the means described in Appendix R, Section III.G.2.a, b, or c to ensure that one of the redundant trains of equipment necessary to achieve and maintain hot shutdown conditions was protected from fire damage. Specifically from October 1974 to April 2017, the licensee had not met the requirements of 10 CFR Part 50.48(b) to identify and protect cabling of 51 Unit 1 and Unit 2 RHR and RCIC emergency cooling system MOVs in fire areas 0024 (Main Control Room), 1203F (Unit 1 Reactor Building), 1205F (Unit 1 Reactor Building), and 2203F (Unit 2 Reactor Building). On April 3, 2017, the licensee identified the failure to protect equipment that was required to mitigate fire events and determined that fire damage could cause mal-operation of the affected MOVs, potentially leading to fire induced cable impacts which bypass the limit and torque switches and result in physical damage to the MOVs, thus preventing the MOVs from being operated from the Main Control Room, Remote Shutdown Panel, or locally. A fire-induced failure could have caused the loss of the required Safe Shutdown components. Severity/Significance: Failure to protect one train of cables and equipment necessary to achieve post-fire SSD from fire damage for fire areas designated in the Fire Protection Program (FPP) as meeting Appendix R, Section III.G.2, was a performance deficiency. This finding was more than minor because it was associated with the reactor safety mitigating system cornerstone attribute of protection against external events (i.e., fire). Specifically, failure to protect safe shutdown cables and equipment from fire damage negatively affected the reactor safety mitigating systems cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Because this issue relates to fire protection and this non-compliance was identified as a part of the sites transition to NFPA 805, this issue is being dispositioned in accordance with Section 9.1, Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48) of the NRC Enforcement Policy. The significance of this licensee-identified non-compliance with 10 CFR Part 50, Appendix R, Section III.G.2, was determined by the results of the IMC 0609, Appendix F, Fire Protection Significance Determination Process, Phase III Quantitative Screening Approach. The quantitative screening approach performed by a Region II Senior Risk Analyst resulted in a calculated delta core damage frequency (CDF) of less than 1E-04, which screens this noncompliance to less-than-red significance. Additionally, in order to verify that this noncompliance was not associated with a finding of high safety significance (Red), inspectors reviewed qualitative and quantitative risk analyses performed by the licensee. These risk evaluations took ignition source and target information from the ongoing HNP fire PRA to demonstrate that the significance of the non-compliances were less-thanthan 1E-4/year). The inspectors also performed walk-downs to verify key assumptions were applicable. Based on the ignition frequency of fire sources in the affected areas, inspectors determined that the significance of this non-compliance was less-than-red. The inspectors also noted that the values in the licensees quantitative analysis were conservative, in that they used screening values instead of more detailed values. This provided additional confidence that this non-compliance was not associated with a finding of high safety significance (Red). The inspectors determined that no cross cutting aspect was applicable to this performance deficiency because this finding was not indicative of current licensee performance. Basis for Discretion: The NRC exercised enforcement discretion in accordance with Enforcement Policy, Section 9.1, Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48), a Confirmatory Order (ML16223A467) which extended the period for discretion, and Inspection Manual Chapter 0305. On April 4, 2018 (ML18096A955), the licensee submitted a license amendment request to adopt NFPA 805 and change their fire protection licensing bases to comply with 10 CFR 50.48(c). The inspectors reached this conclusion due to the fact that this issue was licensee-identified and will be addressed during the licensees transition to NFPA 805, it was entered into the licensees corrective action program, immediate corrective action and compensatory measures were taken, it was not likely to have been previously identified by routine licensee efforts, it was not willful, and it was not associated with a finding of high safety significance (Red).
05000348/FIN-2018002-052018Q2FarleyFailure 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-2018002-022018Q2FarleyFailure 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-2018002-012018Q2FarleyHigh 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.
05000259/FIN-2018002-012018Q2Browns FerryHPCI System Over Pressurization due to Failure to Maintain ProcedureA self-revealed, Green, NCV of 10 CFR 50, Appendix B, Criterion V Instructions, Procedures, and Drawings was identified for failure to maintain procedure 2-SR-3.8.4.3(MB-2) Revision 11, Main Bank 2 Battery Service Test. Specifically, the licensee failed to evaluate the impact of an emergent, Unit 2 procedure revision to a step intended to mitigate over pressurizing Unit 1 High Pressure Coolant Injection (HPCI) system
05000414/FIN-2018002-032018Q2CatawbaNotice of Enforcement Discretion Granted from Technical Specifications Related to the Failure of the 2A EDG During Post-Maintenance TestAs required by Inspection Manual Chapter 0410 Section 06.03.c, an unresolved item is being opened associated with a Notice of Enforcement Discretion 18-2-001 related to approval to not comply with TS requirements associated with the failure of the 2A emergency diesel generator during post-maintenance testing on June 11, 2018. On the basis of the staffs evaluation of the licensees request, the NRC concluded that granting the NOED was consistent with the NRCs Enforcement Policy and had no adverse impact on public health and safety or the environment. Therefore, as communicated orally to the Duke staff on June 14, 2018, the NRC exercised enforcement discretion to not enforce compliance with TS LCO 3.8.1 Condition G requirements that Catawba Nuclear Station, Units 2, be in Mode 2 by 10:08 a.m. EDT on June 14, 2018. Unit 2, Mode 3 entry was extended by 48 hours, to allow completion of repair on the 2A emergency diesel generator. Planned Closure Action: Inspectors will review the licensees cause evaluation for this issue.Licensee Actions: Duke completed repairs to the 2A emergency diesel generator such that the condition causing the need for the NOED was corrected at 9:06 p.m. EDT on June 14, 2018. Corrective Action Reference: CR 2212222
05000413/FIN-2018002-022018Q2CatawbaFailure to Promptly Identify and Correct a Condition Adverse to QualityThe inspectors identified a Green NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, for the licensees failure to promptly identify and correct a condition adverse to quality associated with low resistance readings for core exit thermocouples (CET) identified during testing on January 30, 2018. Specifically, the licensee failed to declare two CETs inoperable when resistance readings were outside of the acceptance criteria until April 9, 2018.
05000414/FIN-2018002-012018Q2CatawbaFailure to Identify and Correct CAQ Associated with Failure of the 2B Seal Water Injection Filter O-ringA self-revealed Green NCV of 10 CFR Part 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 failure of 2B seal water injection filter (SWIF) O-ring on May 13, 2018. Specifically, the licensees failure to implement corrective actions for the first failure of the O-ring on 2B SWIF on March 12, 2018, led to a second failure of 2B SWIF O-ring on May 13, 2018.
05000348/FIN-2018013-012018Q2FarleyInterference 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.
05000321/FIN-2018001-022018Q1HatchLicensee-Identified ViolationThis violation of very low safety significant 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: Hatch Nuclear Plant Technical Specification (TS) 5.7.2 states in part, areas with radiation levels greater than 1000 mRem/hr, measured at 30 cm from the radiation source or from any surface the radiation penetrates, but less than 500 Rads in 1 hour measured at 1 meter from the radiation source or from any surface that the radiation penetrates, shall be provided with locked or continuously guarded doors to prevent unauthorized entry.Contrary to the above, February 6, 2018, the licensee identified dose rates of 72 Rem/hr on contact, and 3.9 Rem/hr at 30 cm on the U-1 bottom head drain valve located in the 127 foot elevation of the Subpile room, in the Unit 1 Drywell. For approximately 4 hours, the entrance to the room was not locked or continuously guarded to prevent unauthorized entry as required by TS 5.7.2. Significance/Severity: The finding was of very low safety significance (Green) because it was not an as low as reasonably achievable (ALARA) planning issue, there was no overexposure nor potential for an overexposure, and the licensees ability to assess dose was not compromised.Corrective Action Reference(s):The licensee identified and documented the failure to control access to the Lock High Radiation Area (LHRA) in Condition Report 10458608.
05000321/FIN-2018001-012018Q1HatchFailure to comply with Type B shipping container Certificate of Compliance (CoC) requirements.An NRC Identified Green NCV of 10 Code of Federal Regulations (CFR)71.17, General license: NRC-approved package, was identified for the licensees failure to comply with the Type B shipping container Certificate of Compliance (CoC) requirements. 10 CFR 71.17(c)(2)states, in part, that a holder of a General license to utilize an NRC-approved package shall comply with the terms and conditions of the license, certificate, or other approval, as applicable, and the applicable requirements of subparts A, G, and H of this part. Specifically, on several occasions the licensee placed in transit Type B containers which did not pass the CoC leak test requirement(s).
05000335/FIN-2018001-012018Q1Saint LucieImproper Evaluation of LCV-9005 position setpoints Leads to AFASOn November 19, 2013, during reactor startup activities, feedwater bypass valves, A (LCV-9005) and B (LCV-9006), were found to be operating at different throttle positions while maintaining their respective steam generator water levels. Valves LCV-9005 and 9006 were both originally installed in April 1978. LCV-9005 was replaced in 1994, with an equivalent valve, due to obsolescence. The original valve had a full open stroke length of 1.5 inches (in.), while the new equivalent valve had a full open stroke length of 2 in. to provide the same flow as the original valve. When installed, LCV-9005 was set up to limit its stroke length to 1.5 in., matching the replaced valve, and the associated drawings were never revised to show that the new valve had a full 2 in. open stroke length. In 2009, the distributed control system (DCS) was installed utilizing these drawings and was setup under the assumption that both valves, LCV-9005 and LCV-9006, were the same model valves and stroke lengths.The DCS system was designed to provide a signal to throttle the feedwater bypass valves following a reactor trip to 20 percent open to provide approximately 5 percent feed flow in order to recover steam generator water levels utilizing main feedwater. During Unit 2 startup activities in November 2013, the licensee noted a discrepancy in the valve positions for LCV-9006 and LCV-9005 when they were providing steam generator water level control. The licensee placed the issue in the corrective action program under Action Request (AR) 1921720 and determined that it was necessary to evaluate a revision of the LCV-9005 DCS setpoint, which was accomplished by an engineering condition evaluation under AR 1925428. The engineering condition evaluation was inadequate in that it failed to recognize the differences in the two different model valves, and therefore failed to provide adequate corrective actions to address performance issues associated with these differences.The final recommendation from AR 1925428 was that the current LCV-9005 setting did not impose any risk to the plant operation, as the 2A steam generator level had been within acceptable range with no control room alarm observed. Therefore, no setpoint change was required at that point.On October 26, 2017, following a Unit 2 trip, LCV-9005 was sent a digital DCS demand signal to be 20 percent open. Since the valve was locally set to have a maximum stroke of 1.5 in. instead of 2 in. open, the actual flow through the valve was less than 5 percent. This resulted in flow lower than needed to maintain 2A steam generator level, and caused level to lower, which eventually resulted in an actuation of the A train auxiliary feedwater actuation system (AFAS). Corrective Action(s):The licensee implemented corrective actions to: 1) properly set up LCV-9005 in order for it to have a full stroke length of 2 inches so that it could provide the required feedwater flow and, 2) update associated drawings to include correct stroke lengths.Corrective Action Reference(s): This issue was entered into the licensees CAP as AR 2232869
05000348/FIN-2017004-042017Q4FarleyLicensee-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-2017004-032017Q4FarleyFailure 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-2017004-022017Q4FarleyFailure 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)
05000364/FIN-2017004-012017Q4FarleyFailure 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)
05000424/FIN-2017003-052017Q3VogtleLicensee-Identified Violation10 CFR 20.1501 requires that each licensee make or cause to be made surveys that may be necessary for the licensee to comply with the regulations in Part 20 and that are reasonable under the circumstances to evaluate the extent of radiation levels, concentrations or quantities of radioactive materials, and the potential radiological hazards that could be present. Contrary to the above, on June 28, 2017, the licensee failed to evaluate radiological conditions in room 1- AB -C-94, Back flushable Filter Crud Tank Pump Room, following the tank being placed in recirculation by Operations. On July 2, 2017, during a routine survey of room 1- AB- C-94, general area dose rates in the area were found to be as high as 600 mrem/hr. On the previous survey, conducted on June 19, 2017, maximum dose rates were found to be as high as 60 mrem/hr. This finding was evaluated using IMC 0609, Appendix C, Occupational Radiation Safety SDP, and was 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. Therefore, the inspectors determined the finding to be of very low safety significance (Green). This issue was entered into the licensees corrective action program as CR 10383067.
05000424/FIN-2017003-042017Q3VogtleLicensee-Identified Violation10 CFR 50, Appendix B, Criterion XI, Test Control stated, in part, that test programs shall be established to assure that all testing required to demonstrate that structures, systems and components will perform satisfactorily in service. UFSAR Section 8.1.4.3.C.2 stated that the onsite electrical system was designed in accordance with IEEE 308 -1974, Criteria for Class 1E Power System at Nuclear Generating Stations. IEEE 308 -1974 Section 6.3 recommended periodic tests be performed at scheduled intervals to detect deterioration of equipment to demonstrate operability of the components that are not exercised during normal operation. Contrary to the above, the licensee did not establish adequate test control measures to assure that the protective function of all 1E lockout relays were periodically verified. Specifically, there was no preventative maintenance to test the 1E lockout relays for non- MSPI loads. This condition has existed since plant initial operation and was identified during a licensee Nuclear Oversight audit on July 13, 2017. The inspectors determined this finding was of very low safety significance (Green) because the inspectors found no documented history of in- service failures of 1E lockout relays rendering safety -related equipment inoperative. This issue was documented in the licensees corrective action program as CR 10381797.
05000424/FIN-2017003-012017Q3VogtleFailure to Implement and Establish Appropriate Work Instructions Affecting Safety-Related ChillerA Self -Revealing, Green, non- cited violation (NCV) of Technical Specifications (TS) 5.4.1.a, Procedures, was identified for the licensees failure to implement maintenance work instructions and establish appropriate procedures concerning the use of flow measurement and test equipment (M&TE) in support of essential safety features (ESF) chilled water pumps in- service testing (IST). As a result, the Unit 1 A train safety -related chiller was inadvertently rendered inoperable when technicians isolated a flow transmitter associated with the chillers auto -start control logic when installing and removing M&TE in support of the IST. The licensee entered this issue into their corrective action program (CAP) under condition report (CR) 10390340 and corrective action report 270610 and planned to revise the procedure. Failure to implement maintenance work instructions and establish appropriate procedures concerning the use of flow M&TE in support of ESF chilled water pumps IST, which can affect ESF chiller performance, as required by Regulatory Guide (RG) 1.33, Quality Assurance Program Requirements, of February 1978, was a performance deficiency (PD). 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 to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding was determined to be of very low safety significance (Green) because while the unit 1 A train ESF chiller was rendered inoperable, it did not represent a loss of function of the train for greater than its TS Allowed Outage Time. The finding was assigned a cross cutting aspect of Challenge the Unknown because questions and risks regarding the use of flow M&TE for the test were not properly evaluated and managed before proceeding. (H.11)
05000338/FIN-2017003-012017Q3North AnnaLicensee-Identified ViolationTS 5.4.1 requires, that Written procedures shall be established, implemented, and maintained covering the following activities: a. The applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Regulatory Guide (RG) 1.33, Appendix A, identifies Access control to radiation areas, including a Radiation Work Permit (RWP) system as one of the areas requiring procedural controls. Additionally, procedure VPAP-2101, Radiation Protection Program, Revision 35, Attachment 1, RCA Work Practices, identifies what workers should know prior to entering the RCA (minimum requirements). Attachment 1 states, in part, All workers entering the RCA are required to: 1) Notify RP prior to entering the RCA. Contrary to the above requirements, on September 15, 2017, two maintenance workers entered U2 Containment, a posted High Radiation Area (HRA), while signed in on an incorrect RWP, and without checking in at the Health Physics Shift Supervisor window prior to entering containment. The workers signed in on the RWP they had used earlier in the day which did not allow entry into a HRA. The containment building had been posted as a HRA in preparation for lifting the reactor head while the workers were out of containment. HP personnel in the remote monitoring facility identified that the individuals were on an incorrect RWP, informed HP personnel in containment, and the workers exited containment prior to the head lift. This finding was of very low safety significance (Green) because there was no substantial potential for overexposure and the licensees ability to assess dose was not compromised. The immediate corrective actions were documented in CR 1078223. Corrective actions included a human performance review, coaching of the individuals by RP Management, and distribution of a site-wide message discussing the incident and reminding site personnel to remain aware of radiological safety.
05000425/FIN-2017003-032017Q3VogtleFailure to Maintain Cleanliness of Motor Operated Valve Limit Switch CompartmentA Self -Revealing , Green, NCV of TS 5.4.1.a, Procedures, was identified for the licensees failure to perform an adequate cleanliness inspection of the Unit 2 nuclear service cooling water (NSCW) system pump no. 6 discharge motor -operated -valve (MOV) limit switch compartment, as required by the maintenance procedure. As result , the valve failed to operate when demanded and rendered the NSCW pump inoperable. The failure to perform an adequate cleanliness inspection of NSCW pump no. 6 discharge MOV limit switch compartment following preventive maintenance, as required by maintenance procedure NMP -ES- 017- 008, was a performance deficiency (PD). The licensee cleaned affected MOV sub -components, verified proper operation, and restored operability of the pump. This issue was entered into the licensees CAP as CR10399054 . The 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 to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage). The finding was determined to be of very low safety significance (Green) because although the performance deficiency affected the qualification and operability of the NSCW pump, it did not represent a loss of function of an NSCW train for greater than its TS Allowed Outage Time . The finding was assigned a cross cutting aspect of Avoid Complacency, because maintenance technicians did not recognize the possibility of making mistakes when performing routine tasks of inspecting and manipulating grease containing components inside the limit switch compartment. (H.12)
05000425/FIN-2017003-022017Q3VogtleFailure to Maintain ECCS Flow Balance and Check Valve Inservice Test ProcedureAn NRC- Identified, Green, NCV of TS 5.4.1.a, Procedures, was identified for the licensees failure to maintain a Unit 2 surveillance procedure that demonstrated satisfactory performance of the forward flow safety function of emergency core cooling system ( ECCS ) check valves. The licensee revised and performed the test to verify satisfactory valve performance. This issue was entered into the licensees CAP as CR10410794. The failure to maintain procedure 14721D -2 to ensure test conditions that adequately demonstrated satisfactory performance of ECCS check valves 2- 1205- U6 -001/00 2, as required by Regulatory Guide (RG) 1.33, Quality Assurance Program Requirements, of February 1978, was a performance deficiency (PD ). The performance deficiency was more than minor because if left uncorrected, it could result in degradation of ECCS check valves to go undetected. The finding was associated with the mitigating system cornerstone. The finding was determined to be of very low safety significance (Green) because the performance deficiency did not result in a loss of operability or functionality of ECCS check valves. The finding was assigned a cross cutting aspect of Resources, because the licensee did not ensure that an ECCS surveillance procedure was adequate to support nuclear safety . (H.1)
05000400/FIN-2017003-022017Q3HarrisReview of Removal of the Technical Support Center (TSC) Temporary Diesel GeneratorThe inspectors conducted a detailed review of NCR 02123373, Emergency Action Level Document Calculation Assumptions. The inspectors chose the sample because the EAL issue initially appeared to be potentially more significant than finally determined. The inspectors evaluated the following attributes of the licensees actions: complete and accurate identification of the problem in a timely manner evaluation and disposition of operability and reportability issues consideration of extent of condition, generic implications, common cause, and previous occurrences classification and prioritization of the problem identification of root and contributing causes of the problem 19 identification of any additional condition reports completion of corrective actions in a timely manner 2. The inspectors conducted a detailed review of NCR 00520918, Loss of Offsite Power Impact on Technical Support Center (TSC). The inspectors chose the sample because it was discovered that on July 17, 2017, the licensee had removed a temporary diesel generator that was intended to provide a back -up reliable power source to the TSC until a permanent solution was implemented. The inspectors evaluated the following attributes of the licensees actions: complete and accurate identification of the problem in a timely manner evaluation and disposition of operability and reportability issues consideration of extent of condition, generic implications, common cause, and previous occurrences classification and prioritization of the problem identification of root and contributing causes of the problem identification of any additional condition reports completion of corrective actions in a timely manner b. Findings 1. Incomplete and Inaccurate Emergency Action Level Submittals Introduction: The NRC identified a Severity Level IV NCV of 10 CFR 50.9 , Completeness and accuracy of information, for failure to provide complete and accurate information for prior approval of a new EAL scheme. The documents submitted to the NRC were, Shearon Harris Nuclear Power Plant, Unit 1 Changes to the Emergency Action Level Scheme, dated April 25, 2010, and License Amendment Request to Adopt Emergency Action Level Scheme Pursuant to NEI 99- 01, Revision 6, dated April 30, 2015. The first submittal to the NRC in 2010 was not complete and accurate in all material respects , and the submittal in 2015 was a missed opportunity to identify the errors made in the first submittal in 2010. Description : On May 10, 2017, Shearon Harris identified the hot operating mode EAL thresholds were calculated incorrectly using a NUREG -0654 methodology vice the required NEI 99- 01 Rev. 6 method, as specified in the current facility licensing basis. When employing the NUREG -0654 methodology to calculate the EAL threshold values, the reactor coolant system (RCS) inventory was assumed to be released at a 50 gallons per minute (gpm) RCS leak rate and activity of 300 micro -Curies per gram (ci/gm) dose equivalent iodine (DEI), over a six -hour period of time. In comparison, when employing the NEI 99- 01 Rev. 6 methodology, the assumption as part of calculating the EAL threshold values was that the entire RCS inventory was released instantaneously at an activity of 300ci/gm DEI. Both of the licensees submittals to the NRC, specified the licensee s EAL scheme for Category F Fission Product Barrier EAL, contained declaration EAL threshold values for the containment high range radiation monitor for loss of fuel clad barrier and potential loss of containment , that were significantly lower than the correct values , due to use of the improper calculation methodology. The submittal dated April 30, 2015, was submitted to provide a complete change to the EAL scheme. This submittal was a missed opportunity by the licensee to identify that the wrong methodology to calculate the EAL threshold values had been used. 20 These submittals were not correct in material content and impacted the NRC s regulatory processes. The NRC evaluated the licensees failure to provide complete and accurate information to determine if there were any unresolved issues. The inspectors concluded that the incomplete and inaccurate information in the license submittal was material to the NRC because, had the NRC staff known the actual methodology used was inaccurate, the staff would have required the licensee to modify the EAL threshold values . The licensee appropriately revised the EAL threshold values utilizing the correct calculation methodology. The licensee issued NC R 02123373, dated May 10, 2017, for EAL thresholds that were calculated without using the correct methodology described in the facility licensing basis. The licensee implemented compensatory corrective actions by issuing Standing Instruction 2017- 017 to inform operators and emergency response organization decision - makers of the proper application of the EAL scheme and revised threshold values to be implemented until a permanent change is made to the license. Additionally, the licensee issued NCR 02155272, dated October 3, 2017, for the incomplete and inaccurate EAL submittal, specifically addressing and resolving the completeness and accuracy issues identified by the inspectors. The final significance determination of the underlying technical issue for the licensees failure to maintain the effectiveness of its emergency plan was documented in NRC Inspection Report 05000400/2017003, Section 4OA7, as a Green LIV. Analysis : The inspectors evaluated the underlying technical issue and determined that the licensees failure to maintain the effectiveness of its emergency plan was a performance deficiency. The issue was documented as a Green LIV in Section 4OA7 of this report. The ROPs significance determination process does not specifically consider the regulatory process impact in its assessment of licensee performance. Therefore, it was necessary to address this violation which impeded the NRCs ability to regulate, using traditional enforcement to adequately deter non- compliance. Using the NRC Enforcement Policy, Section 2.3.11, Inaccurate and Incomplete Information, and Section 6.9, Inaccurate and Incomplete Information or Failure to Make a Required Report , this issue was determined to be a SL IV violation. Though the NRC would have questioned the issue with a request for additional information, it would not have resulted in substantial further inquiry. Additionally, the associated technical violation was determined to be of very low safety significance. Traditional enforcement violations are not assessed for cross -cutting aspects . Enforcement : Section 50.9 of 10 CFR states, in part, that, information provided to the Commission by a licensee shall be complete and accurate in all material respects. Contrary to the above, on April 25, 2010, and on April 30, 2015 , information was submitted by the licensee to the NRC that was not complete and accurate in all material respects. Specifically, the submitted documents specified the licensee s EAL scheme for Category F Fission Product Barrier EAL, contained EAL declaration threshold values for the containment high range radiation monitor , that were lower than the actual correct values , due to use of an improper calculation methodology. This was not in accordance with the license. It was used to calculate the loss of fuel clad barrier and potential loss of containment thresholds values. The licensee implemented compensatory corrective actions by issuing Standing Instruction 2017 -017 to inform operators and emergency response organization decision -makers of the proper application of the EAL scheme and appropriate threshold values to be implemented. Additionally, the licensee plans to submit a license amendment request to update the 21 EAL scheme. Because this violation was not repetitive or willful, and was entered into the licensees CAP as NC R 02155272, it is being treated as a SL IV NCV, consistent with Section 2.3.2 .a of the NRC Enforcement Policy. ( NCV 05000400/2017003- 01, Incomplete and Inaccurate Emergency Action Level Submittal s) 2. Adequacy of Process for Removal of the TSC Temporary Diesel Generator Introduction: The inspectors opened an Unresolved Item (URI) to complete a review of the licensees removal of a temporary diesel generator on July 17, 2017, that was previously installed to provide reliable backup power to the TSC in the event of a Loss of Offsite Power (LOOP) coincident with a Loss of Coolant Accident (LOCA) event. This temporary diesel generator was originally intended to be installed until a reliable backup power source could be implemented under a permanent modification. Description : The licensee initiated NCR 00520918 on March 1, 2012, to address the consequences of a LOOP/LOCA event on the T SC functionality. Since the TSC is designed with two sources of electrical power, both from offsite power sources, it was recognized that a complete loss of offsite power to the TSC could result in long term TSC operational concerns. Specifically, with t he loss of both offsite power sources, the TSC emergency ventilation system, which provides required radiation protection for event response personnel, would be non- functional, as well as other critical TSC equipment following the loss of short -term (~1 -2 hour s) back -up battery power supplies. The inspectors noted that the operability/functionality section of NCR 00520918 stated that the TSC was functional based on the (current) availability of both of the offsite power sources; however, should a LOOP event occur, then the TSC would be considered non -functional since offsite power would be rendered non -functional. This statement demonstrated the licensees understanding of the vulnerability of continued TSC functionality during a LOOP event. In recognition of this vulnerability, the NCR implemented a short -term solution for procuring and installing a temporary diesel generator in late 2012 under modification EC 85350. The inspectors noted that an emergency preparedness change review evaluation was conducted in accordance with 10 CFR 50.54(q) under action request 00568695. This change request stated that it was necessary to provide the infrastructure for an additional reliable power source for the TSC habitability systems. NCR 00520918 stated that the long- term solution was to provide a permanent backup power supply to the TSC , at which time the temporary diesel generator would be removed. While an action item was initiated to install this TSC permanent backup power source under modification EC 85145, the modification was later revised, removing the intended implementation of a permanent backup power source to the TSC. The inspectors were concerned that the TSC could have equipment and habitability issues during design basis LOOP/LOCA events when the normal TSC offsite power would be non- functional. In addition, the inspectors determined that the TSC temporary diesel generator was removed from the site on July 17, 2017, without implementing the originally intended reliable permanent backup power to the TSC and without conducting a 10 CFR 50.54(q) evaluation specific to its removal to demonstrate that this action did not reduce the effectiveness of implementing the emergency plan. The inspectors requested additional information from the licensee related to the documentation, basis, and process used for the removal of the TSC temporary diesel generator, and evidence that the TSC facility would still be capable of performing all of its intended functions during a LOOP/LOCA event. This issue of concern requires more information to 22 determine if a performance deficiency exists, and if the performance deficiency potentially constitutes a violation of regulatory requirements . Pending review of additional information from the licensee, this issue is identified a s URI 05000400/2017003 -02, Review of Removal of the Technical Support Center ( TSC ) Temporary Diesel Generator.
05000400/FIN-2017003-012017Q3HarrisIncomplete and Inaccurate Emergency Action Level SubmittalsThe NRC identified a Severity Level (SL ) IV non- cited violation (NCV) of 10 CFR 50.9, Completeness and accuracy of information, for failure to provide complete and accurate information for prior approval of a new emergency action level (EAL) scheme. The documents submitted to the NRC were, Shearon Harris Nuclear Power Plant, Unit 1 Changes to the Emergency Action Level Scheme, dated April 25, 2010, and License Amendment Request to Adopt Emergency Action Level Scheme Pursuant to NEI 99- 01, Revision 6, dated April 30, 2015. The submit ted documents specified the licensee s EAL scheme for Category F Fission Product Barrier EAL, which contained declaration EAL threshold values for the containment high range radiation monitor that were lower than the correct values due to use of a n improper calculation methodology. The calculation methodology that was used was not in accordance with the license. It was used to calculate the loss of fuel clad barrier and potential loss of containment threshold values. The licensee implemented compensatory corrective actions by issuing Standing Instruction 2017 -017 to inform operators and emergency response organization decision- makers of the proper application of the EAL scheme and appropriate threshold values to be implemented. Additionally, the licensee plans to submit a license amendment request to update the EAL scheme. The licensee entered this violation into their corrective action program (CAP) as nuclear condition report (NCR) 02155272. The inspectors evaluated the underlying technical issue and determined that the licensees failure to maintain the effectiveness of its emergency plan was a performance deficiency. The issue was documented as a Green licensee- identified violation (LIV) in Section 4OA7 of this report. The reactor oversight process (ROP) , significance determination process , does not specifically consider the regulatory process impact in its assessment of licensee performance. Therefore, it was necessary to address this violation which impeded the NRCs ability to regulate, using traditional enforcement to adequately deter non- compliance. Using the NRC Enforcement Policy, Section 2.3.11, Inaccurate and Incomplete Information, and Section 6.9, Inaccurate and Incomplete Information or Failure to Make a Required Report, this issue was determined to be a SL IV violation. Though the NRC would have questioned the issue with a request for additional information, it would not have resulted in substantial further inquiry. 3 Additionally, the associated technical violation was determined to be of very low safety significance. Traditional enforcement violations are not assessed for cross -cutting aspects
05000400/FIN-2017003-032017Q3HarrisLicensee-Identified ViolationSection 50.54(q)(2) of 10 CFR requires, in part, that a licensee shall follow and maintain the effectiveness of an emergency plan which meets the planning standards of 10 CFR 50.47(b) and the requirements of 10 CFR Part 50, Appendix E . Section 50.47(b)(4) of 10 CFR requires that a standard emergency classification and action level scheme, the bases of which include facility system and effluent parameters, is in use by nuclear facility licensee, and State and local response plans call for reliance on information provided by facility licensees for determinations of minimum initial offsite response measures. Contrary to the above, from April 2010 to May 2017, the licensee failed to maintain the effectiveness of its emergency plan. Specifically, the licensee's emergency classification scheme action levels for Category F Fission Product Barrier EAL , contained declaration threshold values for the containment high range radiation monitor , which were lower than the correct values due to an improper methodology used in calculating the loss of fuel clad barrier and potential loss of containment barrier threshold values and rendered the EALs ineffective. The licensee implemented compensatory actions by issuing Standing Instruction 2017- 017 to inform operators and emergency response organization decision- makers of the proper application of the EAL scheme and appropriate threshold values to be implemented until a permanent change can be made to the license. The issue was entered into the licensees CAP as NCR 02123373. The inspectors evaluated this issue as an ineffective EAL per IMC 0609, Appendix B, Emergency Preparedness Significance Determination Process , Figure 5.4 -1. The inspectors concluded that the violation was of very low safety significance (Green). Although the incorrect EAL would alone render an early EAL classification of a General Emergency (GE) based upon the specific radiation monitor, other EALs would provide a GE classification in an accurate and timely manner aligned with the incorrect threshold values of the containment high range radiation monitor .
05000364/FIN-2017003-012017Q3FarleyFailure 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).
05000369/FIN-2017002-012017Q2Mcguire
McGuire		Inadequate Survey Results in Unposted HRAGreen . A self -revealing Green non- cited violation (NCV) of 10 CFR 20.1501(a)(2) was identified for the licensees failure to conduct an adequate area radiation survey in Room 619 of the auxiliary building (waste gas decay tank (WGDT) room). Specifically, on April 19, 2016 , a high radiation area (HRA) was identifi ed near WGDT A in the WGDT room when a worker entering the area received a dose rate alarm on his electronic dosimeter (ED) and follow -up surveys revealed dose rates as high as 110 mrem/hr at 30cm. Also, as a result of the licensees failure to perform a survey, the area was not barricaded and posted in accordance with plant Technical Specification (TS) 5.7.1, High Radiation Area. The licensee immediately barricaded and posted the area as an HRA, performed an apparent cause evaluation to determine additional long term actions and entered the issue into their corrective action program as Nuclear Condition Report (NCR) 02021742. The licensees failure to conduct an area radiation survey to evaluate the magnitude and extent of radiation levels near WGDT A was a performance deficiency. This finding was determined to be more than minor because it was associated with the occupational radiation safety cornerstone attribute of human performance and adversely affected the cornerstone objective of ensuring adequate protection of worker health and safety from exposure to radiation from radioactive material during routine civilian nuclear reactor operation. Specifically, failure to identify, post and control HRAs could allow workers to enter HRAs without knowledge of the radiological conditions in the area and receive unintended occupational exposure. The finding was evaluated using Inspection Manual Chapter (IMC) 0609 Appendix C, Occupational Radiation Safety Significance Determination Process. The finding was not related to the a s low as reasonably achievable (ALARA) planning, did not involve an overexposure or substantial potential for overexposure, and the ability to assess dose was not compromised. Therefore, the inspectors determined the finding to be of very low safety significance (Green). This finding involved the cross -cutting aspect of avoid complacency in the area of human performance because the possibility of significant dose rate changes in the WGDT room during startup was a latent issue for which the licensee failed to recognize and plan. (H.12)
05000364/FIN-2017002-032017Q2FarleyFailure 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).
05000366/FIN-2017001-012017Q1HatchFailure to Identify Abnormal Condition on 2C EDG Cross Drive AssemblyGreen . A self -revealing non- cited violation (NCV) of Hatch Unit 2 Technical Specification 5.4.1 was identified when technicians performing maintenance on the 2C emergency diesel generator observed pitting on the lower crank component gears and did not initiate a condition report as required by procedure 52SV -R43 -001- 0, Diesel, Alternator, and Accessories Inspection. The licensees failure to initiate a condition report, as required by 52SV -R43 -001- 0 Diesel, Alternator, and Accessories Inspection, for the pitting observed on the lower crank component gears was a performance deficiency. The violation of regulatory requirement occurred on or about November 2015 until the licensee replaced the 2C EDG cross drive assembly and restored compliance on August 25, 2016. The violation was entered into the licensees corrective action program as CR 10263236. The performance deficiency was more than minor because if left uncorrected, the failure to evaluate gear pitting would allow progression of a degradation mechanism to the point of EDG inoperability. The inspectors screened this finding using IMC 0609, Appendix A, The Significant Determination Process (SDP) For Findings At -Power, dated June 19, 2012. Because all four questions in Section A of Exhibit 2, Mitigating Systems Screening Questions, were answered no, the finding screened as Green. The inspectors determined that this finding had a cross -cutting aspect in the Resources aspect of the human performance area, because the licensee did not ensure adequate procedural guidance to recognize the difference between normal and destructive pitting. (H .1)
05000321/FIN-2017001-022017Q1HatchLicensee-Identified ViolationUnit 2 Technical Specification 3.6.1.3 requires each PCIV be operable in Mode 1. With one PCIV inoperable, the affected penetration flow path must be isolated by use of at least one closed and de -activated automatic valve, closed manual valve, blind flange, or check valve with flow through the valve secured. Contrary to the above, on November 6, 2016 at 21:51 operators tagged valve 2E41F111, a PCIV, open with the breaker off. Subsequently, a licensed operator performing a main control room board walk down noted the PCIV was inoperable and, on November 8 at 0151, operators closed and de -activated an automatic valve in the line to rest ore compliance. Inspectors screened the finding in accordance with IMC 609 Appendix A The Significance Determination Process (SDP) for Findings at -Power. The finding screened as very low safety significance (Green) because the questions in Appendix A E xhibit 3 for reactor containment were answered no. This issue was documented in the licensees corrective action program as CR 10295889. (Section 4OA3.2)
05000321/FIN-2017001-032017Q1HatchLicensee-Identified ViolationTechnical Specification 5.7.1 requires, in part, entrances into areas in which the intensity of r adiation is > 100 mrem/hr but < 1000 mrem/hr, measured at 30 cm from the radiation source or from any surface the radiation penetrates, to be controlled by requiring issuance of a Radiation Work Permit (RWP). Contrary to this, On September 9, 2016, two in dividuals entered a High Radiation Area in the Unit 2 SE Diagonal 87' elevation to calibrate an RHR Service water transmitter without the proper briefing or RWP. The individuals were briefed and permitted to enter the HPCI Room area instead of this area. This finding was of very low safety significance (Green) because there was no substantial potential for overexposure and the licensees ability to assess dose was not compromised. The immediate corrective actions were documented in CR 10271667. The long term corrective actions include continuing training suc h that all craft personnel are exposed to the remediation scenario. (Section 2RS1 )
05000260/FIN-2017001-012017Q1Browns FerryFailure to Take Corrective Actions to Preclude a Repeat Failure of a Containment Isolation ValveGreen. An NRC identified non-cited violation (NCV) of 10 Code of Federal Regulations (CFR) 50, Appendix B, Criterion XVI, Corrective Action, was identified for the licensees inadequate corrective actions to preclude repetition (CAPR) of a significant condition adverse to quality (SCAQ). The licensees failure to take appropriate CAPRs for a SCAQ that resulted in an inoperable RCIC containment isolation check valve was a performance deficiency. The licensee entered the condition into their corrective action plan as condition report (CR) 1265552, performed repairs to the valve, and initiated a new root cause analysis. This performance deficiency was more than minor, because it was associated with the configuration control attribute of the Barrier Integrity cornerstone and adversely affected the cornerstone objective because the misalignment of the stem to disc for 2-CKV-71-14 resulted in a loss of reliability. The finding screened as Green because the RCIC subsystem remained operable. The finding was not assigned a cross-cutting aspect because the cause was not related to current licensee performance.
05000259/FIN-2017001-022017Q1Browns FerryUnauthorized Entry into a High Radiation AreaGreen. A self-revealing NCV of Technical Specifications (TS) 5.7.1 was identified for a worker who entered a High Radiation Area (HRA) (Unit 1 reactor building steam tunnel) without proper authorization. This performance deficiency was determined to be greater than minor because it was associated with the Occupational Radiation Safety Cornerstone attribute of Human Performance and adversely affected the cornerstone objective of ensuring adequate protection of worker health and safety from exposure to radiation from radioactive material during routine civilian nuclear reactor operation. The inspectors determined the finding to be of very low safety significance (Green). The licensee entered the issue into their Corrective Action Program (CAP) as CR 1219539 and took immediate corrective actions including restricting Radiologically Controlled Area (RCA) access for the individuals involved and performing confirmatory surveys of the area. This finding involved the cross-cutting aspect of Human Performance, Teamwork, (H.4), because a significant contributor to this event was poor communication between different work groups (workers entering the reactor building steam tunnel and RP personnel at the control point). (Section 2RS1)
05000259/FIN-2017001-032017Q1Browns FerryFailure to Perform Airborne Radioactivity SurveysGreen. An inspector-identified NCV of TS 5.4.1 was identified for the licensees failure to obtain an air sample while performing work in an area with smearable contamination levels greater than 50,000 disintegrations per minute (DPM) per 100cm2. This performance deficiency was determined to be greater than minor because it was associated with the Occupational Radiation Safety Cornerstone attribute of Human Performance and adversely affected the cornerstone objective of ensuring adequate protection of worker health and safety from exposure to radiation from radioactive material during routine civilian nuclear reactor operation. The inspectors determined the finding to be of very low safety significance (Green). The licensee entered the issue into their CAP (CR 1219539) and, since the work created airborne radioactivity in the area, performed in-vivo monitoring on the affected workers to assess doses from the intake of radioactive material. This finding involved the cross-cutting aspect of Human Performance, Avoid Complacency, (H.12), because, considering the contamination levels present, RP staff underestimated the risk for potential airborne radioactive material in the area
05000259/FIN-2017001-042017Q1Browns FerryFailure to Control the Issuance of Instructions and Drawings for Transformer ReplacementsGreen. An NRC identified NCV of 10 CFR Part 50, Appendix B, Criterion VI, Document Control, was identified after maintenance on safety-related 4kv to 480 volt transformers TS1A and TS1B (Unit 1) resulted in the windings tap setting being misconfigured. The licensees failure to develop work instructions to change TS1A and TS1B transformer configuration was a performance deficiency. This performance deficiency was more than minor because it impacted the Mitigating Systems cornerstone attribute of configuration control in that the loads supplied by 480 volt shutdown boards 1A and 1B were challenged by this misconfiguration. The finding screened as Green because the electrical system remained operable. The licensee entered the condition into their corrective action plan as CR 1221265 and corrected the tap setting. The finding was not assigned a cross-cutting aspect because the cause was not related to current licensee performance.
05000259/FIN-2017001-052017Q1Browns FerryLicensee-Identified Violation10 CFR 50 Appendix B, Criterion III, Design Control required, in part, that measures be established to assure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions. Contrary to the above, between July 17, 2014, and January 8, 2017, the licensee failed to correctly translate into applicable drawings as required by their NPG-SPP-9.3 Nuclear Plant Modifications and Engineering Change Control procedure the changes associated with DCN 70491 to the EDG D output breaker. This resulted in two separate modifications using the same terminal point that caused a short circuit when the breaker was manually closed. This violation is documented in the licensees CAP as CR 1248939. This violation screened as Green because it was determined that the EDG D was operable during this entire period.
05000348/FIN-2016004-012016Q4FarleyFailure 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-2016004-022016Q4FarleyFailure 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-2016004-032016Q4FarleyFailure 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-2016004-042016Q4FarleyLicensee-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.
05000280/FIN-2016004-012016Q4SurryChange of Surveillance Frequency Caused the Charging Service Water Header to Become Biologically FouledA self-revealing NCV of 10 CFR 50, Appendix B, Criterion XVI was identified because the surveillance procedure frequency used to flush the service water (SW) piping in Mechanical Equipment Room (MER)-3 and MER-4 was changed from two weeks to four weeks without sufficiently considering the effects of river conditions on biological growth and without getting management permission to change the periodicity. As a result of the periodicity change, the B charging (CH) and main control room (MCR) SW header became blocked with biological growth and was declared inoperable on September 22, 2016, during the performance of 0-OSP-VS-012, High Flow Flush of SW Strainers and Piping in MER 3 and MER 4. As immediate corrective action, the licensee cleaned the clogged SW strainer and completed the backflushing of the SW header. The SW flushing periodicity was restored to a two week frequency to be seasonally and risk assessed and reduced as heavy fouling season ends. This issue was documented in the licensees corrective action program (CAP) as CR 1048251. The inspectors reviewed Inspection Manual Chapter (IMC) 0612, Appendix B, Issue Screening, dated September 7, 2012, and determined the performance deficiency (PD) was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone, and it adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using IMC 0609.04, Initial Characterization of Findings, Table 2, dated June 19, 2012, the finding was determined to affect the Mitigating Systems Cornerstone. The inspectors screened the finding using IMC 0609, Appendix A, Significance Determination Process (SDP) for Findings at-Power, dated June 19, 2012, and determined that it screened as Green because the deficiency did not affect the design or qualification of the charging pump service water pump system and it did not represent a loss of system safety function. This finding has a cross-cutting aspect in conservative bias aspect of the human performance area, H.14, because the licensee did not use decision making-practices that emphasize prudent choices over those that are simply allowed.
05000281/FIN-2016004-022016Q4SurryInadequate Design Change Post Maintenance Testing Causes Water Intrusion into Station Service Transformer and a Reactor TripA self-revealing finding was identified because the test requirements section of the station service transformer (SST) design change (DC) was not comprehensive in that it did not test that the isolated phase bus ducting terminal boxes were constructed to prevent water intrusion into the boxes. This was discovered during a significant rainfall event partially caused by Hurricane Matthew, which filled up the A SST terminal box with water and eventually shorted the A phase of the main generator causing a Unit 2 main generator, main turbine, and subsequent reactor trip on October 9, 2016. As corrective action, sealant was applied to the SST terminal boxes on all seams and bolt holes; and weep holes with drain assemblies were installed on each box. This issue was documented in the licensees CAP as CR 1049987. The inspectors reviewed Inspection Manual Chapter (IMC) 0612, Appendix B, Issue Screening, dated September 7, 2012, and determined the PD was more than minor because it was associated with the design control attribute of the Initiating Events Cornerstone, and it adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Using IMC 0609.04, Initial Characterization of Findings, Table 2, dated October 7, 2016, the finding was determined to affect the Initiating Events Cornerstone. The inspectors screened the finding using Manual Chapter 0609, Appendix A, SDP for Findings at-Power, dated June 19, 2012, and determined that it screened as Green because although the deficiency did cause a reactor trip, it did not cause a loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. This finding has a cross-cutting aspect in the Operating Experience aspect of the Problem Identification and Resolution area, P.5, because the licensee did not evaluate and implement relevant external operating experience.
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