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05000335/FIN-2016003-012016Q3Saint LucieReactor Coolant System Leakage Technical Specification ViolationAn NRC-identified Green non-cited violation (NCV) of Unit 1 Technical Specification 3.4.6.2 Reactor Coolant System Leakage was identified. Specifically, the licensee failed to enter TS 3.4.6.2 Action c for reactor coolant system pressure isolation valve (V3217) when the valve experienced operational seat leakage of approximately 30 gpm during flushing and cooling the shutdown cooling system. Immediate corrective actions were not required since the valve was later determined to be inoperable and repaired. The licensee entered this issue into the licensees corrective action program. The licensees failure to recognize that gross seat leakage from check valve V3217 indicated of a major problem with valve seat alignment and that higher differential pressure would not help seat the valve was a performance deficiency (PD). The performance deficiency is more than minor because it is associated with the barrier integrity cornerstone attribute of human performance and adversely affected the cornerstone objective of providing reasonable assurance that physical barriers such as the containment, protected the public from radionuclide releases caused by accidents or events. The PD resulted in 46 additional hours of operation with V3217 seat leakage outside of TS acceptance criteria which required the unit to be in cold shutdown. The finding involved the cross-cutting area of human performance and specifically within that area was associated with conservative bias because the operability evaluation did not demonstrate it was safe to proceed with valve V3217 experiencing gross seat leakage (H.14).
05000335/FIN-2016003-022016Q3Saint LucieLicensee-Identified ViolationLicensee identified violation (LIV) - T.S.6.8.1 requires written procedures be established, implemented, and maintained covering applicable procedures recommended in Appendix A of Regulatory Guide 1.33, Rev 2, 1978. Appendix A, Section 9, Procedures for Performing Maintenance, states, in part, that maintenance that can affect the performance of safety-related equipment should be properly preplanned and performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances. Contrary to this, Unit 1 Pressure Isolation Valve (PIV) V3217 was rebuilt in October 2013, using Licensee procedure 0-GMM-80.22, Swing Check Valve Inspections. 0-GMM-80.22 did not provide specific detail to ensure consistency and first time work quality and directly resulted in V3217 being reassembled incorrectly. Specifically the disc arm bushings were installed backwards, as well as no spacers in the bushing bores. The period of concern was from the achievement of Mode 4 on August 5, 2016 at 09:43 hours, to declaration of entry into the TS action statement and entry into Mode 5 on August 4, 2016 at 20:03 hours, resulting in 82 hours of operation with V3217 seat leakage outside of TS acceptance criteria. The inspectors characterized the safety significance of the issue utilizing Manual Chapter 0609.04, Significance Determination Process Initial Characterization of Findings, and determined the issue affected the barriers cornerstone due to leakage past an isolation valve. Manual Chapter 0609 Appendix A, The significance determination process (SDP) for Findings At-Power, Exhibit 3 was used to further evaluate this finding which screened as Green because the finding represented neither an actual open pathway in the physical integrity of the reactor containment and does not involve an actual reduction in the function of the hydrogen igniters in the reactor containment. This issue has been entered into the licensees CAP as AR 2148252.
05000335/FIN-2017001-012017Q1Saint LucieInadequate Procedure Results in Adding an Incorrect Lubrication Oil to the 1B CS Motor Inboard BearingAn NRC-identified Green, non-cited violation (NCV) of Technical Specification (TS) 6.8.1, Procedures and Programs, was identified for the licensees failure to establish, implement, and maintain written procedures covering activities referenced in NRC Regulatory Guide 1.33, Revision 2, dated February 1978. Specifically, the licensees failure to maintain a plant lubrication manual with correct lubrication oil specifications for the 1B containment spray (CS) pump motor resulted in adding unacceptably low viscosity lubrication oil to the inboard bearing of the 1B CS pump motor. Immediate corrective actions included restoring the 1B CS pump inboard bearing with the correct lubrication oil and placing the issue in the licensees corrective action program.The licensees failure to correctly specify the 1B CS pump motor inboard bearing lubrication requirements in licensee general maintenance procedure GMP-22 was a performance deficiency (PD). The PD was more than minor because it was associated with the procedure quality 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). Specifically, the inadequate procedure resulted in adding the incorrect lubrication oil to the 1B CS pump motor bearing, causing the pump to be declared inoperable for approximately 56.5 hours. The finding screened to Green because the failure did not: (1) affect the design or qualification of the systems, structures and components, (2) represent an actual loss of function, and (3) represent an actual loss of function of at least a single train for greater than its TS allowed outage time. The finding involved the cross-cutting area of human performance, in the aspect of avoid complacency, in that, the individuals involved with the procedure revision did not implement appropriate error reduction tools to ensure the procedure was appropriately changed to reflect the new lubrication oil requirement (H.12).
05000335/FIN-2017002-012017Q2Saint LucieReactor Coolant Pressure Boundary Leak on the 1B2 Reactor Coolant Pump Lower Seal Heat ExchangerOn January 31, 2017, Unit 1 was shutdown to investigate and repair the source of RCS leakage in the vicinity of the 1B2 RCP seal package. The unidentified leakage rate measured was 0.17 gallons per minute (gpm), which is well below the TS limit of 1 gpm of unidentified leakage. Typical RCS unidentified leak rates are in the range of 0.05 - 0.07 gpm. The licensees investigation revealed the source of the leakage as RCS pressure boundary leakage from the RCP lower seal cooler. St. Lucie Unit 1 TS 3.4.6.2, Reactor Coolant System Operational Leakage, Action a was entered and the unit was placed in cold shutdown (Mode 5, less than 200 degrees F) in accordance with the TS. The 1B2 RCP rotating assembly and pump cover with the integral lower seal heat exchanger were replaced during the fall refueling outage which occurred between September 26 and November 8, of 2016. The RCP integral lower seal heat exchanger was a tube-in-tube heat exchanger that was permanently attached to the pump cover. The inner tube contained high pressure RCS water and the outer tube contained low pressure CCW. The heat exchanger was connected to the CCW supply and return piping utilizing flanges with the flange nuts torqued to 225-230 foot-pounds (ft-lbs,) as specified by the manufacturer. The manufacturer specified a change in the torque requirements in 2015 from a previous value of 125 ft-lbs when it was identified that the 125 ft-lbs specification was not the proper torque value for the size of the flange used. The leakage emanated from a crack in the inner tube material near the toe of a weld where the inner tube exits from the outer tube. The location was in the vicinity of a CCW system connection flange. Based on a review of containment atmospheric particulate monitor data and reactor cavity leakage flow instrument data, the licensee determined that the RCS pressure boundary leak started on November 9, 2016 or shortly thereafter. This was approximately one week after the RCP was started near the conclusion of the refueling outage.The licensee determined that the most probable cause of the cracked seal cooler tubing was due to a deficiency in the lower seal heat exchanger design that allowed stresses to approach or exceed the yield strength of the tubing when the flanges were torqued to connect the CCW piping to the cooler. The resultant plastic deformation of the tubing and associated flaw formation allowed low stress; high cycle fatigue from normal RCP operation, to propagate the flaw until it was through-wall, causing the pressure boundary leakage. A finite element analysis model, developed by an outside engineering firm for the RCP seal cooler, was used to support this conclusion. The finite element analysis model determined that when the CCW flange connection was torqued to 230 ft-lbs, a tensile stress was imparted that approached or exceeded the minimum yield strength of the lower seal heat exchanger tubing and possibly caused plastic deformation and subsequently an outside diameter surface flaw in the failure region. A counter torque could not reasonably be applied during installation due to the design of the CCW flange connection.This issue was documented in the licensees corrective action program as AR 2182938. Licensee corrective actions included; 1) removing the 1B2 RCP seal cooler heat exchanger flaw and completing a weld repair of the heat exchanger outlet tubing; 2) visually inspecting all Unit 1 and Unit 2 RCP lower seal heat exchangers to identify any leakage and the presence of any outer diameter surface flaws, and; 3) determining whether a lower torque value can be used when connecting CCW to the seal cooler heat exchanger, or by implementing a different method of torqueing the CCW flanges that would reduce the stress on the tubing to an acceptable level. Enforcement: St. Lucie Unit 1 TS limiting condition for operation 3.4.6.2, Reactor Coolant System Operational Leakage, required, in part, that RCS operational leakage shall be limited to no pressure boundary leakage during plant operations in Mode 1 through 4. With any pressure boundary leakage, Unit 1 had to be placed in hot standby (Mode 3) within 6 hours, and in cold shutdown (Mode 5) within the following 30 hours. Contrary to the above, Unit 1 experienced RCS pressure boundary leakage from approximately November 9, 2016, until the unit was shut down on January 31, 2017, and later cooled down to Mode 5 on February 1, 2017. The inspectors utilized the enforcement policy examples of Section 6.1, and available ris k- informed tools to assess the safety significance of the RCS pressure boundary leakage and related violation. Based on the fact that the through-wall crack leak rate was stable, was within the capacity of the charging system, and would not impact other systems used to mitigate a loss of coolant accident, the inspectors concluded the safety significance of the violation was very low and consistent with Severity Level IV. Additionally, the risk aspects were discussed and confirmed with a regional Senior Risk Analyst. This issue was documented in the licensees corrective action program as AR 2182938.The NRC exercised enforcement discretion in Enforcement Action (EA)-2017-117, in accordance with Section 3.10 of the Enforcement Policy because the violation was not associated with a licensee performance deficiency. Specifically, the violation was not attributable to an equipment failure that was avoidable by reasonable licensee quality assurance measures or management controls and therefore inspectors concluded that there was no performance deficiency associated with the RCS boundary leakage. The RCP cover with its integrated lower seal cooler was replaced with a new component and installed in accordance with vendor instructions. This enforcement discretion will not be considered in the assessment process or the NRCs Action Matrix. This LER is closed.
05000335/FIN-2017004-012017Q4Saint LucieInadequate Reactor System Trip Process for Inoperable Channel Results in Operation in a Condition Prohibited by Technical SpecificationsA Green, self-revealing NCV of 10 Code of Federal Regulations (CFR) Part 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, was identified for the licensees failure to have an adequate procedure for reducing the trip setpoint of the B channel of the reactor protection system (RPS) high startup rate (HSUR) bistable. The licensees failure to establish an adequate procedure, as required by 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, to place the "B" channel wide range nuclear instrument in a tripped condition was a performance deficiency (PD). This deficiency resulted in a violation of Technical Specification (TS) Limiting Condition for Operation (LCO) 3.3.1.1. Following discovery of the condition, the licensee initiated immediate corrective actions to place the B channel RPS HSUR in trip, meeting the TS requirement. The inspectors determined that the finding was more than minor because it was associated with the Mitigating Systems cornerstone attribute of procedural quality and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, there was no procedure to perform the setpoint reduction method as identified in 1-AOP-99.01. The only direction was to Contact I&C in the step. The Instrumentation and Control (I&C) processes used to implement the HSUR reduced setpoint reduction method were inadequate, in that, they did not evaluate all potential failure conditions when setting the HSUR bistable. The finding did not screen as greater than Green because while the degradation affected a single RPS trip signal, it did not affect the function of other redundant trips; and the finding did not involve control manipulations that unintentionally added positive reactivity; and finally the finding did not result in a mismanagement of reactivity by operators. Using IMC 0310, Aspects Within the Cross-Cutting Areas, the inspectors determined that the finding had a cross-cutting aspect in the area of human performance. Specifically, the cross- cutting aspect of resources (H.1) was assigned to the finding because the licensee did not ensure an adequate procedure was available to implement the HSUR setpoint reduction.
05000335/FIN-2017004-032017Q4Saint LucieFailure to Identify and Correct a Condition Adverse to QualityThe NRC-identified a Green non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Actions, for failure to identify and correct a condition adverse to quality. The licensee failed to identify that their procedures lacked actions to install control power jumpers that are required to defeat the reactor coolant systems (RCS) pressure interlocks for the shutdown cooling (SDC) suction line motor operated valves (MOVs) when aligning the plant for hot leg injection (HLI) and then correct the condition. Following the identification of this procedural vulnerability, the licensee fabricated control power jumpers and revised procedure 1-GME-100.03, Installation and Removal of Temporary Power Jumpers for MOV V3481, V3652, V3432 AND V3444, to provide direction for installation of power jumpers. In addition, the licensee performed a more detailed failure modes and effects analysis to ensure that the revised procedures accounted for all possible single failures. This issue has been entered into the licensees corrective action program (CAP) as CR 2217631.The PD was more than minor because it was associated with the Design Control attribute of the Mitigating System cornerstone objective of ensuring the capability of the low pressure safety injection (LPSI) system to perform its required long term cooling safety function (HLI). The condition was evaluated by a Regional Senior Reactor Analyst and determined to have very low safety significance (Green) based on the low likelihood of a loss of coolant accident (LOCA) and low likelihood of electrical failures requiring jumpers to be installed. This issue and corrective actions were documented in the licensees CAP as Action Request (AR) 2217631. This finding was not assigned a cross-cutting aspect because the underlying cause was a legacy issue and not indicative of current performance.
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-2010003-012010Q2FarleyFailure to perform adequate surveys to identify potential radiological hazards during reactor cavity drain downA self-revealing non-cited violation (NCV) of 10 CFR Part 20.1501(a) was identified for failure to perform adequate surveys to identify rising radiation levels during the lowering of water level in the reactor cavity. This resulted in an uncontrolled High Radiation Area (HRA) in a worker-occupied area of the refueling floor near the edge of the reactor cavity. The immediate corrective actions were to post the affected areas as required by licensee procedures and re-flood the cavity. The licensee entered the issue into their corrective action program as condition report (CR) 2010105943. This finding is more than minor because it was associated with the Occupational Radiation Safety Cornerstone attribute of Program and Process (Monitoring and Radiation Protection Controls) and adversely affects the cornerstone objective of ensuring adequate protection of worker health and safety from exposure to radiation from radioactive material during routine nuclear reactor operation. The finding was evaluated using the Occupational Radiation Safety Significance Determination Process (SDP) and was determined to be of very low safety significance (Green) because it was not related to As Low As Reasonably Achievable (ALARA) Planning and the ability to assess dose was not compromised. In addition, it did not involve overexposure or substantial potential for overexposure because the lower cavity was inaccessible at the time of the event. The cause of this finding was directly related to the cross-cutting aspect of radiological safety in the Work Control component of the Human Performance area because the potential job site conditions (radiological hazards) associated with reduction of water shielding following underwater cutting of significant radiation sources were not adequately identified (H.3(a)).
05000348/FIN-2010003-022010Q2FarleyFailure to maintain safety-related cables in a non-submerged environmentAn NRC-identified Green NCV of 10 CFR 50, Appendix B, Criterion III, Design Control, was identified for the licensees failure to implement measures to assure that safety-related cables remained in an environment for which they were certified. Safetyrelated cables purchased and installed in underground electrical pull boxes at Farley Nuclear Plant have been subjected to submergence, a condition for which they are not designed. To address this issue, the licensee has performed the immediate corrective action of increasing the frequency of measuring water level in the pull boxes and removing excess water to ensure cables are not submerged. The licensee entered the issue into their corrective action program as CR 2010100512. Failure to maintain safety-related electrical cables in a physical environment for which the cables are designed to operate is a performance deficiency. This performance deficiency is more than minor because it is associated with the Design Control attribute of the Mitigating Events cornerstone, and adversely affected the cornerstone objective to ensure the reliability of systems responding to initiating events to prevent undesirable consequences. Specifically; because 1) testing of these cables has not been performed, 2) the cables have not been maintained within the parameters they are designed, and 3) there have been documented failures of cables throughout the nuclear industry due to degradation caused by submergence in water. The significance of this finding was screened using the Phase 1 of the SDP in accordance with NRC Inspection Manual Chapter 0609 Attachment 4. The finding screened as Green, because the finding is a design or qualification deficiency confirmed not to result in loss of operability or functionality. The inspectors determined the inadequate assessment of available information in the CAP caused the licensee to fail to aggregate the programmatic and common cause problems reflective of cross-cutting aspect P.1(b).
05000348/FIN-2010003-032010Q2FarleyLicensee-Identified ViolationTS 3.6.3, Containment Isolation Valves requires, each containment isolation valve shall be operable with the unit in Modes 1, 2, 3, and 4. A note attached to the Limited Condition for Operation allows penetration flow path(s) except for 48-inch purge valve flow paths, which may be un-isolated intermittently under administrative controls. Contrary to the above, the licensee declared prerequisites for entering Mode 4 were met on May 13, 2010 at 2:19 a.m., and entered Mode 4 at 2:26 a.m. with containment isolation valve Q2P18V001 unlocked and open. Q2P18V001, is the service air outboard containment isolation valve and was discovered open by the licensee during the performance of a surveillance test on June 2, 2010. The licensee immediately closed and locked the valve restoring compliance with the TS. The licensee also entered the discovery into its CAP as CR 2010107407. This finding was assessed using IMC 0609, Phase 1 screening worksheets of Attachment 4 and H relating to Containment Barrier Integrity, and determined to be of very low safety significance (Green) because the open penetration would not have allowed the entire volume to exit through the opening within a 24 hour period.
05000389/FIN-2006002-042006Q1Saint LucieNotice of Enforcement Discretion for Containment Ventilation System Purge Valve FailureOn February 14, 2006, at 4:10 p.m; the licensee entered a 24 hour required action statement per Technical Specification 3.6.1.7 Action c, Containment Ventilation System, for a failed measured local leak rate test (LLRT) of the containment purge supply inboard isolation valve FCV-25-36. The surveillance being performed was required by TS surveillance 4.6.1.7.4. The required action was to restore the valve to an operable status within 24 hours or be in hot standby within the next 6 hours and in cold shutdown within the following 30 hours. The licensee determined the valve could not be restored within 24 hours and requested enforcement discretion to allow the use of a blind flange in place of closing valve FCV-25-36 to satisfy TS 3.6.1.7 Action c. On February 15, 2006, at 7:20 a.m; the licensee removed valve FCV-25-36 from the system and replaced it with an engineered blind flange. The post installation LLRT was completed satisfactorily at 10:50 a.m. on February 15, 2006. On February 15, 2006, at 2:00 p.m; the NRC verbally granted discretion from TS 3.6.1.7 Action c. The installation of the blind flange ensured the penetration was capable of performing its passive pressure retaining safety function. The licensee initiated condition report 2006-4378 to document the noncompliance. At the close of this inspection period the inspectors had not yet completed all inspection activities associated with this NOED. Therefore this item is identified as unresolved item, URI 05000389/2006-02-04, Notice of Enforcement Discretion for Containment Ventilation System Purge Valve Failure.
05000389/FIN-2014002-012014Q1Saint LucieNoncompliance with Barricading and Posting RequirementsA self-revealing non-cited violation (NCV) of 10 CFR 20.1501(a) and Technical Specification (TS) 6.12.1 was identified for failure to perform radiological surveys to ensure that the potential radiological hazards and extent of radiation levels were evaluated for an equipment transfer box being removed from the Unit 2 upper reactor cavity. This failure resulted in dose rates greater than 100 millirem per hour (mrem/hr) at 30 centimeters (cm) from a high efficiency particulate air (HEPA) vacuum cleaner, and was discovered by two workers who received electronic dosimeter (ED) dose rate alarms of 108 and 84 mrem/hr when working near the HEPA vacuum cleaner. Dose rates of the HEPA vacuum cleaner were found to be 850 mrem/hr at 30 cm. Upon identification, the licensee posted and controlled access to the equipment transfer box and placed the HEPA vacuum cleaner into a shielded container. This condition has been placed into the licensees CAP under ARs 01946341 and 01946351. The finding was determined to be more than minor because it is associated with the Program and Process attribute of the Occupational Radiation Safety cornerstone, and adversely affected the cornerstone objective of ensuring adequate protection of worker health and safety from exposure to radiation, in that the workers were unnecessarily exposed to high radiation area conditions. The finding was evaluated in accordance with Inspection Manual Chapter (IMC) 0609, Appendix C (August 19, 2008), and was determined to be Green because it did not involve as low as reasonably achievable (ALARA) planning or work controls, was not an overexposure, did not present a substantial potential for an overexposure, and the ability to assess dose was not compromised. The inspectors determined that this issue had a field presence crosscutting aspect in the human performance area (H.2) because supervisors did not oversee work activities by observing and reinforcing standards and expectations.
05000389/FIN-2014002-032014Q1Saint LucieFailure to Provide Detailed Work Instructions Resulted in Degraded Debris Filter System Performance and resulted in a Manual Reactor TripA self-revealing finding was identified for the licensees failure to provide adequate work instructions. The maintenance work instructions for a debris filter system (DFS) backwash valve motor operator did not contain adequate details to ensure the motor operator was installed correctly. The incorrectly installed motor operator prevented the DFS from mitigating an influx of algae into the circulating water system and ultimately resulted in the need for operators to manually trip the reactor. The licensee entered this issue into the corrective action program (CAP) as action requests (ARs) 1878615 and 1911638. Corrective actions included properly installing the DFS backwash valve motor operator. The performance deficiency was more than minor because it was associated with the equipment reliability attribute of the initiating events cornerstone and adversely affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during power operations. Specifically, the 1A2 DFS backwash valve was installed incorrectly in August 2012. This degraded the components ability to mitigate an algae intrusion event on May 31, 2013, and resulted in a manual reactor trip. The finding was determined to be of very low safety significance (Green) based on Exhibit 1, Initiating Events Screening Questions, found in Inspection Manual Chapter 0609, Significance Determination Process, Appendix A, SDP for Findings At- Power (June 19, 2012). This was due to the fact that the finding 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. The cause of this finding was associated with a cross-cutting aspect of providing complete and accurate documentation in the documentation component of the human performance area. Specifically, the licensee did not provide work instructions with enough detail to properly reinstall the1A2 backwash valve motor operator (H.7).
05000389/FIN-2014003-022014Q2Saint LucieFailure to Design the Emergency Diesel Generators to Operate Under Worst Case Environmental ConditionsAn NRC-identified non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion III, Design Control, was identified. The licensees failure to translate design control measures to ensure operation of Unit 2 emergency diesel generators (EDGs) under worstcase environmental conditions was a performance deficiency. Specifically, since initial licensed operation in 1983, the licensee failed to ensure the Unit 2 EDGs were designed and built to operate under worst case high wind conditions. As a result, sustained high winds from specific directions could have impacted EDG radiator performance resulting in the unavailability of both Unit 2 EDGs. Corrective actions included modification of the EDG building to allow EDG operation under all postulated high wind conditions. The performance deficiency was more than minor because it affected the design control attribute of the mitigating system cornerstone, and affected the cornerstone objective of ensuring availability, reliability, and capability of systems that respond to initiating events. Specifically, the performance deficiency could have resulted in the inoperability of both Unit 2 EDGs during sustained high wind conditions. Using Table 2 of Inspection Manual Chapter (IMC) 0609.04, Significance Determination Process Initial Characterization of Findings dated June 19, 2012; the inspectors concluded the finding affected the mitigating system cornerstone. The inspectors evaluated the finding using IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, Exhibit 2, dated June 19, 2012. The finding was determined to require a detailed risk evaluation by an NRC senior reactor analyst since the finding represented a loss of function. The regional senior reactor analyst performed a Phase 3 SDP analysis for the finding. The EDG impact would only occur in response to a Loss of Offsite Power (LOOP). The analysis considered the impact of the finding on an independent LOOP, by calculating the likelihood that the site wind conditions, absent a Hurricane, would occur at the same time as an independent LOOP event. In addition, the coincident or dependent LOOP was considered, by assuming the hurricane winds would impact the EDGs and would occur with a hurricane induced LOOP. Wind data was taken from National Weather Service records at Palm Beach International airport, which is the closest station to have both wind speed and direction historical records to determine the likelihood for non-hurricane high winds. Hurricane frequency data was taken for the Landfalling Hurricane Probability Project for St Lucie County. The Conditional Core Damage Probability was determined through the use of the NRCs plant risk models. EDG recovery, because the winds would not be likely sustained (both speed and direction) for greater than 6 hours, and the ability to crosstie Unit 2 emergency power to Unit 1 were major factors in the outcome. The screening analysis resulted in a combined risk which, even with conservative assumptions, was low enough for the finding to be characterized as Green. A cross-cutting aspect was not assigned to the finding since the finding does not represent current licensee performance. The condition existed since original construction of the plant.
05000389/FIN-2014004-012014Q3Saint LucieFailure to Follow Foreign Material Exclusion Requirements in Reactor Vessel Maintenance ProceduresA self-revealing non-cited violation (NCV) of Unit 2 Technical Specification 6.8.1.a was identified for the licensees failure to follow the requirements in reactor vessel maintenance procedures, to exclude foreign material from the reactor coolant system (RCS) during refueling outage activities. The licensee entered the issue in the corrective action program as action request 1957565. Corrective actions included evaluation of the foreign object damage, and revision of foreign material exclusion (FME) controls in outage maintenance procedures. The performance deficiency was more than minor because if left uncorrected, it had the potential to lead to more significant safety concerns. Specifically, the failure to follow FME controls in maintenance procedures had the potential to lead to the introduction of foreign material in the RCS, which could result in degradation of RCS components, such as the fuel cladding, RCS pressure boundary cladding, and steam generator (SG) tubes. The inspectors screened this finding utilizing IMC 0609 Attachment 4, Initial Characterization of Findings, dated June 19, 2012, and IMC 0609 Appendix A, The Significance Determination Process for Findings at Power, dated June 19, 2012. The finding screened as Green using Exhibit 1, Section D, Initiating Events Screening Questions, screening question 2, because the finding did not result in a condition where one or more SGs violated accident leakage performance criterion (i.e., did not involve degradation that would exceed the accident leakage performance criterion under design basis accident conditions). The inspectors determined this performance deficiency had a resources crosscutting aspect (H.1) in the human performance area, because the licensees administrative procedure for FME practices, MA-AA-101-100, was inadequate to support nuclear safety, in that it allowed for a less conservative approach to FME in the reactor cavity.
05000389/FIN-2014005-012014Q4Saint LucieFailure to Follow Work Instructions during Installation of Unit 2 Vent Valve V3811The licensee identified a finding of very low safety significance (Green) and associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, which requires, in part, that activities affecting quality shall be accomplished in accordance with instructions, procedures, and drawings. During the performance of WO 40118062, on breaker B52DB50078, the licensee failed to correctly perform the steps in section 5.4.5 of procedure RMP 9303, DB50 Breaker Routine Maintenance. Procedure RMP 9303 inspected and bent as necessary, the control relay contacts for the breaker to obtain the proper contact alignment. The breaker was subsequently installed and used in the P32C SW pump breaker cubicle, 1B5220C, and failed to close on May 29, 2014, during surveillance testing. The licensee concluded that oxide buildup on the control relay contacts had prevented them from making up, which prevented the breaker from closing. The oxide buildup was the result of improper contact alignment, which inhibited the proper wiping action needed to clean the contacts each time they were cycled. The licensee concluded, based on the contact arms being rigid, that the misalignment was present since the new control relay was installed and RMP 9303 performed in July 2012. Title 10 CFR Part 50, Appendix B, Criterion V, requires, in part, that activities affecting quality shall be accomplished in accordance with instructions, procedures, and drawings. RMP 9303 is the licensees procedure containing instructions for the inspection and adjustment of safety-related control relay contacts, an activity affecting quality. Contrary to the above, between July 11, 2012 and July 24, 2012, the licensee failed to properly complete RMP 9303 Section 5.4.5, which required the licensee to inspect and adjust contacts to ensure that the contacts had the appropriate gap, contacted in the appropriate sequence, and contacted in the approximate center. The inspectors determined that this issue was more than minor as it impacted the equipment performance attribute of the Mitigation Systems Cornerstone. The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, dated June 19, 2012, and Appendix A, The Significance Determination Process for Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, dated June 19, 2012. Since the breaker operated successfully on May 7 and failed to operate on May 29, the inspectors answered "Yes" to the mitigating systems screening question number 3, and consulted regional senior risk analysts to perform a detailed risk evaluation. The senior risk analysts performed a detailed risk evaluation for the finding as described below. Since the time of actual failure of the breaker for the P32C SW pump cannot be determined, a T/2 evaluation provides an exposure time of 11 days (i.e., 22 days from May 7, 2014 to May 29, 2014 divided by 2 or 11 days). The T/2 exposure time is appropriate based on Risk Assessment Standardization Project manual guidance. The Point Beach Standardized Plant Analysis Risk model version 8.22, Systems Analysis Programs for Hands-on Integrated Reliability Evaluations (SAPHIRE) version 8.1.2 software, and the Support System Initiating Event (SSIE) methodology that is incorporated into the Standardized Plant Analysis Risk model was used to obtain a CDF of 1.29E7/yr for internal events for the failure-to-start of the P32C SW pump due to the breaker failure. The dominant core damage sequences involve a loss-of-offsite-power (LOOP) with the failure of AFW and the failure of high pressure recirculation. Since the total estimated change in core damage frequency was greater than 1.0E7/yr, an evaluation was performed for external event delta risk contributions. The total CDF was found to be the sum of the CDF contributions from internal events, fire, and seismic or 4.46E7/yr (i.e., 1.29E7/yr + 3.21E7/yr + 8.4E11/yr = 4.50E7/yr). Large Early Release Frequency - Since the total estimated change in core damage frequency was greater than 1.0E7/yr, IMC 0609 Appendix H, Containment Integrity Significance Determination Process was used to determine the potential risk contribution due to large early release frequency. Each Point Beach Unit is a 2-loop Westinghouse Pressurized Water Reactor with a large dry containment. Sequences important to large early release frequency include steam generator tube rupture events and inter-system loss-of-coolant-accident events. These were not the dominant core damage sequences for this finding. Based on the Detailed Risk Evaluation, the inspectors determined that the finding was of very low safety-significance (Green). This issue was entered into the CAP as AR 01968602 and AR 02020073.
05000389/FIN-2014005-022014Q4Saint LucieDesign Basis Review for Unit 2 Steam Generator Tube-to-Tubesheet JointThe inspectors identified an unresolved item (URI) associated with the design of the tube-to-tubesheet joint for the Unit 2 replacement SGs. In April 2014, the channel head of Unit 2 SG-2B experienced impingement damage in the hot leg side, due to a foreign object in the reactor coolant system. The extent of the damage included impingement marks on the tube-to-tubesheet welds. The licensee entered the issue in the CAP as AR 01955927. The inspectors reviewed the licensees one-cycle operability evaluation for this condition (Areva Report 51-9222481- 000) to verify that the licensee provided adequate technical justification demonstrating that the SG would be capable of performing its design function, particularly to maintain tube integrity, during the current cycle. The inspectors did not identify an issue of concern with the licensees operability conclusions, but issued a URI to determine if the foreign material intrusion issue constituted a performance deficiency and/or a violation of NRC requirements. In October 2014, the NRC closed the URI with a non-cited violation for the failure to follow the requirements in reactor vessel maintenance procedures. The inspectors review and disposition of this issue was documented in NRC Inspection Report 05000389/2014004 (ADAMS Accession Number ML14293A668). From October to December 2014, the inspectors had further discussions with the licensee, and reviewed the planned corrective actions to address Unit 2 SG-2B operability for future plant operating cycles. In their review, the inspectors identified an issue of concern related to the design approach for the tube-to-tubesheet welds in the Unit 2 replacement SGs. Specifically, the licensees operability evaluation addressing the impingement damage for the current cycle described the weld at the end of each tube as a seal weld, without further discussion about the structural function of the weld. The inspectors determined that it was necessary to confirm whether the Unit 2 SG tube end welds were credited in the structural analysis of the tube-to-tubesheet joint under design basis loads. The inspectors determined that additional information from the SG vendor was needed to understand the design approach and qualification for the tube-totubesheet joint, including the welds. This issue of concern with the tube-to-tubesheet welds did not adversely affect the licensees operability conclusions for the current cycle. The operability evaluation for SG-2B contained technical data from the vendor to demonstrate that the tube structural integrity and primary-to-secondary leakage criteria would not be challenged due to the performance of the mechanically expanded portion of the tube inside the tubesheet. The licensee provided sufficient information about the tube-to-tubesheet joint design to provide reasonable assurance that the joint, considering the impingement damage to the tube end welds, would meet the performance criteria for SG tube integrity required in the plants Technical Specifications.
05000389/FIN-2015002-022015Q2Saint LucieFailure to Comply with Technical Specification 3.0.3The NRC identified a non-cited violation of Technical Specification (TS) 3.0.3 for the licensees failure to take the required actions to shut down the plant in a timely manner. The licensees failure to perform an adequate operability evaluation in accordance with the requirements of EN-AA-203-1001, Operability Determinations / Functional Assessments, was a performance deficiency. Specifically, the licensee failed to identify in an Immediate Operability Determination that through-wall leakage on the ASME Class 1 pipe riser for vent valve V3811 rendered both Emergency Core Coolig Systems (ECCS) subsystems inoperable, requiring entry into TS LCO 3.0.3 and performance of the applicable action statements. The licensee entered this into their corrective action program as AR 02021204. The performance deficiency 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 the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors determined the finding was associated with the mitigating systems cornerstone and required a detailed risk evaluation because the finding represented a loss of function on the high pressure safety injection system. A detailed risk evaluation determined the significance of the finding was Green. The inspectors determined the finding was related to the crosscutting aspect of Evaluation (P.2) of the Problem Identification and Resolution area because the licensees failure to thoroughly evaluate the issue commensurate with its safety significance led to the licensee failing to perform an appropriate operability evaluation.
05000389/FIN-2015002-032015Q2Saint LucieProblem with LER ReportingThe NRC identified multiple non-cited violations of regulatory requirements that it has decided to group into an example of a problem associated with the licensees reporting program. This problem includes violations of 10 CFR 50.73, Licensee Event Report System, for the licensees failure to address all the applicable reporting criteria and 10 CFR 50.9, Completeness and Accuracy of Information, for the licensees failure to submit complete and accurate information to the Commission, as part of Licensee Event Report (LER) 050000389/2014-001 dated September 22, 2014 . These violations were material to the NRC because the failure to include the appropriate reporting criteria and provide complete and accurate information had the potential to impede or impact the regulatory process and, therefore, is subject to traditional enforcement as described in the NRC Enforcement Policy. The inspectors used the examples provided in Section 6.9, Inaccurate and Incomplete Information or Failure to Make a Required Report, of the NRC Enforcement Policy, and concluded that this problem was appropriately categorized as Severity Level (SL) IV. The licensee placed these issues into their corrective action program as AR 02021204 and has submitted a revised LER.
05000389/FIN-2015002-052015Q2Saint LucieLicensee-Identified ViolationTechnical Specification 6.12.1 requires an area with dose rates greater than 100 millirem per hour (mrem/hr) at 30 centimeters (cm) to be barricaded and conspicuously posted as an HRA. Contrary to this, on January 31, 2015, the licensee identified dose rates in excess of 100 mrem/hr at 30 cm on a five gallon bucket containing drain hoses in a Radiation Area within the U2 Pipe Tunnel, which was not barricaded or posted as a High Radiation Area (HRA). A survey of the bucket identified dose rates of up to 120 mrem/hr at 30 cm. Immediate corrective actions included relocating the bucket to a locked location in a designated HRA. This condition was documented in AR 02022248. This violation was evaluated using the guidance in IMC 0609, Appendix C, Occupational Radiation Safety Significance Determination Process, and was determined to be of very low safety significance (Green) because there was no substantial potential for overexposure and the licensees ability to assess dose was not compromised. Because this violation was of very low safety significance and was entered CAP, this violation is being treated as a NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy.
05000389/FIN-2015003-032015Q3Saint LucieUntimely 10 CFR50.72 NotificationThe NRC identified an NCV of 10 CFR 50.72(b)(3)(iv)(A) for the licensees failure to notify the NRC within 8 hours of an event that was not part of a preplanned sequence which resulted in a valid actuation of an emergency AC electrical power system. During Unit 2s refueling outage with Unit 2 in Mode 5 and the 2A emergency diesel generator (EDG) properly tagged out of service for pre-planned maintenance, a phase-to-phase fault on the 6.9kV non-segregated bus from the 2A startup transformer (SUT) to the non-safety related 2A1 bus caused the 1A and 2A SUTs supply breakers to open. The safety related 4.16kV 2A3 bus experienced an under voltage condition which generated a valid actuation signal for the 2A EDG. The licensee failed to recognize this event as reportable pursuant to 10 CFR 50.72(b)(3)(iv)(A). The licensee generated corrective actions (AR 2075703) which included restoring compliance within a reasonable period of time after the violation was identified, and training the appropriate personnel to understand why the situation was reportable pursuant to 10 CFR 50.72. The inspectors determined that the failure to report required plant events or conditions to the NRC had the potential to impede or impact the regulatory process. As a result, the NRC dispositioned this violation of 10 CFR 50.72 using the traditional enforcement process instead of the SDP. The inspectors determined that this issue was more than minor because it is similar to a Severity Level IV example provided in Section 6.9 of the NRC Enforcement Policy. Cross-cutting aspects are not assigned to traditional enforcement violations.
05000389/FIN-2016001-012016Q1Saint LucieUnauthorized Entry into a High Radiation AreaA self-revealing, NCV of TS 6.12.1.b occurred when a worker entered a high radiation area (HRA) without being made knowledgeable of dose rates in the area prior to entry. Specifically, on November 10, 2015, a worker performing a plant surveillance under radiation work permit (RWP) 15-004, Clearance Tags, Surveillances and Inspections, climbed into overhead in the Unit 2 Pipe Penetration room and received an electronic dosimeter (ED) dose rate alarm. The licensee entered this issue into the CAP as AR 02090225 and took immediate corrective actions which included restricting the operators access to the radiological control area (RCA), performing followup surveys and convening a human performance review board to examine causal factors for the purpose of determining corrective actions. This PD was determined to be more than minor because it is associated with the Occupational Radiation Safety Cornerstone attribute of Human Performance and adversely affects 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. Workers permitted entry into HRAs with inadequate knowledge of current radiological conditions could receive unintended occupational exposures. The finding was evaluated using the Occupational Radiation Safety SDP. The finding was not related to as low as reasonably achievable (ALARA) planning, nor did it 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). The inspectors noted that the operator responded properly to the ED dose rate alarm thereby limiting his potential for unintended exposure. This finding involved the cross cutting aspect of (H8) procedure adherence because the individual understood the RWP requirements but failed to comply with them.
05000389/FIN-2016001-022016Q1Saint LucieFailure to Provide Detailed Work Instructions Resulted in a Unit TransientA self-revealing finding was identified for the licensees failure to provide adequate work instructions for the circulating water system 1B1 traveling water screen drive motor replacement. Specifically, the inadequate work instructions resulted in a plant transient in order to remove the associated circulating water pump (CWP) from service. This issue was placed in the licensees corrective action program (CAP) as action request (AR) 2095560. The licensee completed the following corrective actions: (1) Counsel all maintenance supervisors in regard to having a questioning attitude and to seek guidance if unsure; (2) Rewire the 1B1 traveling screen drive motor for the proper rotation; (3) Install labels indicating the proper rotation for all eight traveling screen drive motors; (4) Submit document change requests to update the total equipment database; (5) Update all work orders (WO) for the remaining screen drive starter replacements to provide motor rotation direction and mark the post-maintenance test (PMT) step as a critical step, and; (6) Change clearance requests for traveling screen work to include directions to have electricians on station prior to returning the control switch to automatic. The failure to provide adequate work instructions for replacement of the 1B1 traveling screen motor was a performance deficiency (PD). The PD was more than minor because it was associated with the procedure quality attribute of the initiating events cornerstone and adversely affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during power operations. Specifically, the inadequate WO instructions resulted in installing the 1B1 traveling screen drive motor incorrectly on December 4, 2015. After the maintenance, the system automatically started and the screen rotated backwards. The backward rotation allowed accumulated debris to be transported to the 1B1 debris filter system (DFS) filter and caused it to overload. The resulting high differential pressure (DP) on the DFS filter necessitated the need to lower unit power (plant transient) and required removal of the 1B1 CWP from service. The finding was determined to be of very low safety significance (Green) based on Exhibit 1, Initiating Events Screening Questions, found in IMC 0609, Significance Determination Process, Appendix A, Significance Determination Process (SDP) for Findings At-Power (June 19, 2012). This was due to the fact that the finding 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. The inspectors determined the cause of this finding was associated with a cross-cutting aspect of ensuring risks are evaluated and managed before proceeding in the Challenge the Unknown component of the human performance area. Specifically, the licensee did not have a healthy questioning attitude and did not recognize the need to seek guidance when installing a new circulating water system traveling screen motor (H.11).
05000389/FIN-2016001-032016Q1Saint LucieInadequate Corrective Actions to Prevent Failure of the 2C ICW Pump MotorA self-revealing, NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, was identified for the licensees failure to implement corrective actions to prevent failure of the 2C intake cooling water (ICW) pump. The failure was a result of several air box baffle bolt-heads breaking off due to corrosion and impacting the motor stator winding, which caused an electrical ground on the winding. Corrosion of the bolts was attributed to not having functional motor heater elements. Corrective actions included repairing the motor heater elements on the 2A and 2C ICW pump motors. This issue was entered into the licensees CAP as AR 02077661. The licensees failure to implement adequate corrective actions to prevent the Unit 2C ICW pump motor winding failure that resulted from extensive corrosion of the baffle bolts was a PD and was within the licensees ability to prevent. The PD was more-than-minor because if left uncorrected, the PD has the potential to lead to a more significant safety concern. Specifically, not repairing a degraded or non-functioning motor winding heater in a timely manner prohibits protection against the humid salt water environment which the motor windings are exposed to during standby operational conditions and creates an environment for accelerated corrosion on the baffle bolts and motor winding leading to premature failure of the motor. Manual Chapter 0609 Appendix A, The Significance Determination (SDP) Process for Findings At-Power, Exhibit 2 Mitigating Systems Screening Questions. dated June 19, 2012, was used to further evaluate this finding. The finding screened as Green because the finding represented neither an actual loss of function of at least a single train for greater than its technical specification (TS) Allowed Outage Time, nor two separate safety systems out of service (OOS) for greater than its TS Allowed Outage Time. Manual Chapter 0609, Appendix G, Attachment 1, Shutdown Operations Significance Determination Process Phase 1 Initial Screening and Characterization of Findings, dated May 9, 2014, was used to further evaluate the shutdown safety significance of this finding. The finding screened to Green because the inspectors answered no to all the screening questions listed under Exhibit 3 - Mitigation System Screening Questions. The finding involved the cross-cutting area of the evaluation component in problem identification and resolution (PI&R) because the organization did not thoroughly evaluate the function of the motor winding heater to ensure that resolutions address causes and extent of conditions commensurate with the long term operability of the ICW pump motors. Specifically, after identifying that the motor winding heater on the 2C ICW pump motor was not functioning, the licensee entered this issue into the CAP but did not adequately evaluate the significance of having a non-functional heater on the motor winding and instead deferred the heater repairs to be completed at the next motor overhaul which was scheduled to be performed in four years (P.2).
05000389/FIN-2017004-022017Q4Saint LucieFailure to Follow Surveillance Maintenance Procedure Resulting in a Condition Prohibited by Technical SpecificationsA Green, self-revealing, NCV of TS 6.8.1 was identified for the licensees failure to adequately implement a maintenance procedure during a monthly flow channel check for the 2C Auxiliary Feedwater (AFW) pump. Specifically, the licensee failed to implement as-written surveillance maintenance procedure 2-SMI-09.05C, 2C Auxiliary Feedwater Pump Flow Channel Check, when performing the channel checks for both 2C AFW pump flow transmitters. The licensees failure to follow surveillance maintenance procedure 2-SMI-09.05C, was a PD. Upon discovery, the flow transmitters were declared inoperable and subsequently, the condition was promptly restored to normal. The PD was more than minor because it was associated with the Human Performance attribute of the Mitigating Systems cornerstone and it adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The PD adversely affected the licensees ability to monitor 2C AFW flow during a design basis accident. The inspectors determined that the finding was not greater than Green because it did not represent a deficiency affecting the design or qualification of a mitigating system; it did not represent a loss of system and/or function; it did not represent an actual loss of function for at least a single train for more than its TS allowed outage time; and it did not represent an actual loss of function of one or more non-TS trains of equipment designated as high safety-significant in accordance with the licensees maintenance rule program. The finding involved the cross-cutting area of human performance, with an aspect of avoiding complacency (H.12), in that, the licensee failed to ensure that personnel effectively used human performance tools during the AFW pump flow channel check to ensure procedure steps were completed as required.
05000389/FIN-2018003-012018Q3Saint LucieFailure to meet the Transient Combustible Requirements Specified by NFPA 805The inspectors identified a Green non-cited violation (NCV) of 10 CFR 50.48(c), National Fire Protection Standard NFPA 805, requirements. Specifically, the licensee failed to comply with transient combustible control requirements in high risk fire zones as required by NFPA 805 and implemented by licensee procedure ADM-19.03, Transient Combustible Control.
05000390/FIN-2003002-022003Q2Watts BarNoncompliance of the Unit 2 Layup Process to10 CFR 50, Appendix BThe inspectors identified that the applicant had initiated an unapproved reduction in equipment preservation to the Unit 2 lay-up process. The applicant had elected to cease performing preventive maintenance on many components An inspector-identified, non-cited violation of 10 CFR 50, Appendix B, Criteria XIII, Identification and Control of Materials, Parts, and Components, was identified. This finding satisfied a traditional enforcement criterion of failure to receive NRC approval for a change in licensee activity In accordance with the NRC Enforcement Policy, the finding was characterized as a Severity Level IV NCV involving a failure to receive prior NRC approval for a change in licensee activity (Section 4OA5).
05000390/FIN-2018050-012018Q2Watts BarLicensee-Identified ViolationThis violation of very low safety significance (Green)was identified by the licensee and has been entered into the licensees corrective action program and is being treated as a Non-CitedViolation, consistent with Section 2.3.2 of the Enforcement Policy.Violation: Title 10 of the Code of Federal Regulations(10 CFR) Part 50 (10 CFR 50), Appendix B, Criterion III, Design Control, requires the licensee to effectively implement design control measures for piping analysis calculations* associated with the Unit 1 and Unit 2 emergency core cooling systems (ECCS).Contrary to the above, since initial operation of Unit 1 in 1996 and Unit 2 in 2016, Tennessee Valley Authority failed to ensure the proper hydraulic time history was utilized in TVAs TPIPE special purpose computer program used to determine static and dynamic linear elastic analyses for the ECCS including the effects of pipe voiding. This resulted in non-conservative voiding design acceptance criteria for the RHR and SI systems of both units. This performance deficiency was more than minor because it was associated with the Design Control attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to utilize proper hydraulic time history in the licensees TPIPE computer model resulted in developing non-conservative voiding acceptance criteria that was used during operation that could challenge ECCS functionality. The finding was determined to be of very low safety significance since additional analysis determined with reasonable assurance that the systems remained operable but non-conforming and would have performed their safety function.Significance/Severity Level: Green. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, the inspectors determined that this finding was of very low safety significance (Green) because the finding affected the design or qualification of mitigating systems; however, the mitigating systems maintained their operability. Corrective Action Reference:CR 1407257
05000424/FIN-2018002-012018Q2VogtleFailure to Adequately Load Emergency Deisel Generator (EDG) During 24-Hour Endurance TestAn NRC-identified Green NCV of Vogtle Nuclear Station TS, Section 5.4.1.a, Procedures, was identified for the licensees failure to implement the EDG 24-hour endurance surveillance procedure 14668A-1, Train A Diesel Generator Operability Test, revision 7.2, to operate the EDG as close as practicable to 3390 kVAR. Specifically, the licensee failed to carry out procedure steps and provisions that would assist in loading the EDG closer to the TS value of 3390 kVAR. The failure to follow procedure 14668A-1 and get as close as practicable to 3390 kVAR was a performance deficiency.
05000424/FIN-2018002-022018Q2VogtleHigh Vibrations on Unit 2 NSCW Pump No. 3 Result in Pump InoperabilityAn NRC-identified Green NCV of 10 CFR 50 Appendix B, Criterion III, Design Control, was identified for the licensees failure to ensure that design control measures for the Unit 2 train A (2A) nuclear service cooling water (NSCW) pump no. 3 motor replacement, conducted in May 2015, adequately evaluated and addressed structural resonance of the pump, commensurate with the original pumps. As a result, the pump operated at higher than desired vibrations, since installation, causing accelerated bearing wear and premature failure of the motor in February 2018. The licensees failure to ensure that design control measures for the 2A NSCW pump no. 3 motor replacement adequately evaluated and addressed structural resonance of the pump, commensurate with the original pumps was a performance deficiency.
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