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| Quarter | Site | Title | Description | |
|---|---|---|---|---|
| 05000389/FIN-2018003-01 | 2018Q3 | Saint Lucie | Failure to meet the Transient Combustible Requirements Specified by NFPA 805 | The 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-2018050-01 | 2018Q2 | Watts Bar | Licensee-Identified Violation | This 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-2018002-02 | 2018Q2 | Vogtle | High Vibrations on Unit 2 NSCW Pump No. 3 Result in Pump Inoperability | An 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. |
| 05000424/FIN-2018002-01 | 2018Q2 | Vogtle | Failure to Adequately Load Emergency Deisel Generator (EDG) During 24-Hour Endurance Test | An 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. |
| 05000335/FIN-2018001-01 | 2018Q1 | Saint Lucie | Improper Evaluation of LCV-9005 position setpoints Leads to AFAS | On 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 |
| 05000335/FIN-2017004-03 | 2017Q4 | Saint Lucie | Failure to Identify and Correct a Condition Adverse to Quality | The 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. |
| 05000389/FIN-2017004-02 | 2017Q4 | Saint Lucie | Failure to Follow Surveillance Maintenance Procedure Resulting in a Condition Prohibited by Technical Specifications | A 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. |
| 05000335/FIN-2017004-01 | 2017Q4 | Saint Lucie | Inadequate Reactor System Trip Process for Inoperable Channel Results in Operation in a Condition Prohibited by Technical Specifications | A 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-2017002-01 | 2017Q2 | Saint Lucie | Reactor Coolant Pressure Boundary Leak on the 1B2 Reactor Coolant Pump Lower Seal Heat Exchanger | On 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. |
| 05000250/FIN-2017002-02 | 2017Q2 | Turkey Point | Inadequate Foreign Materials Exclusion Controls for Thermo-Lag Activities Renders Electrical Equipment Inoperable and Results in a High Energy Arc Flash | Green: A self-revealing Green (NCV) of Technical Specification (TS) 6.8.1.a., Procedures and Programs, was identified for the failure to appropriately implement foreign material exclusion (FME) controls during Thermo-Lag fire barrier modifications. Specifically, maintenance procedure 0-GMP-102.21, Installation, Modification and Maintenance of Thermo-Lag Fire Barrier System, Rev. 0C, did not include instructions in sufficient detail to prevent foreign material used in the installation of Thermo-Lag fire barriers from entering nearby electrical equipment and was a performance deficiency (PD) which affected the operation of two redundant safety-related battery chargers and caused a high energy arc fault (HEAF) that damaged the 3A 4kV switchgear bus. After the HEAF, the licensee promptly ceased all Thermo-Lag installation activities. The licensee completed a root cause evaluation in Action Request (AR) 2192198 and revised the installation procedure to prevent foreign material from entering nearby electrical equipment. The PD was more than minor because it caused both a reactor trip and resulted in the unavailability of the 3A 4kV switchgear bus. The inspectors evaluated the significance of this finding by utilizing IMC 0609 Attachment 4, Initial Characterization of Findings, and IMC 0609 Appendix A, The Significance Determination Process for Findings At-Power, and determined the findings significance could not be screened to Green because it caused both a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. Therefore a detailed risk evaluation was required to complete the significance determination. Based upon the results of the evaluation the finding was considered to be Green, or equivalent to low safety significance. The cross-cutting aspect (CCA) that best corresponds to the root cause as described in IMC 0310, Aspects Within the Cross-Cutting Areas, was Resources; leaders ensure that personnel, equipment, procedures, and other resources are available and adequate to support nuclear safety (H.1). |
| 05000250/FIN-2017002-03 | 2017Q2 | Turkey Point | Failure to Implement Fire Detection | Green: A NRC-identified Green finding was identified for the licensees failure to follow plant procedure O-ADM-016, Fire Protection Program, Rev. 19. Specifically, the licensee failed to properly implement fire watches following a HEAF on the 3A 4kV switchgear bus. 3 The inspectors determined that the licensees failure to implement fire detection was a PD. This PD was more than minor because it was associated with the reactor safety mitigating systems cornerstone, and if a fire was not detected in the 3B 4kV switchgear room there was a potential for the B train of equipment to lose function which could have resulted in the unavailability of both the A and B trains of equipment post incident. The finding is not greater than Green because a risk analysis of the PD was performed and determined the risk increase in core damage frequency due to the PD was equivalent to a Green finding of very low safety significance due to the short exposure period. Because site personnel failed to reset fire detectors and implement fire watches in appropriate areas following the incident; and during interviews, inspectors identified that fire drills did not emphasize post incident activities, the inspectors concluded the finding had a CCA in the area of Human Performance associated with the Training; the organization provides training and ensures knowledge transfer to maintain a knowledgeable, technically competent workforce and instill nuclear safety values (H.9). |
| 05000250/FIN-2017002-01 | 2017Q2 | Turkey Point | Failure to Perform 100 Percent General Visual Examinations of Containment Moisture Barriers Associated with Containment Liner Leak Chase Test Connections | Green: A NRC-identified Green NCV of 10 CFR 50.55a, Codes and Standards, was identified for the failure to perform general visual examinations of moisture barrier materials in the reactor containment leak-chase channel test connections in accordance with the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel (BPV) Code, Section XI, Subsection IWE. The licensee performed the required examinations in Unit 3 during the April 2017, refueling outage and initiated corrective actions to revise the physical configuration of leak chase areas and review the In-service Inspection (ISI) Plan. This issue has been entered into the licensees corrective action program as AR 02196637. The failure to conduct the required visual examination of all moisture barriers in accordance with the ASME BPV Code requirements was a PD. The PD was more than minor significance per IMC 0612, Appendix B, Issue Screening, because the current Containment ISI Plan did not adequately implement the ASME BPV Code inspection requirements for the examination of moisture barriers, and if left uncorrected, had the potential to lead to a more significant concern. The finding was of very low safety significance, or Green, per IMC 0609 because it did not, based on inspections performed following discovery, represent an actual open pathway in the physical integrity of the reactor containment. Because the licensee did not effectively evaluate and appropriately implement the ASME BPV Code requirements in the Containment ISI Plan when a reasonable opportunity was available through the licensees review of NRC Information Notice (IN) 2014-07 and Regulatory Issue Summary (RIS) 2016-07, the inspectors determined the finding had a CCA in the operating experience component of the problem identification and resolution cross-cutting area, in that the organization systematically and effectively collects, evaluates, and implements relevant internal and external operating experience in a timely manner (P.5). |
| 05000335/FIN-2017001-01 | 2017Q1 | Saint Lucie | Inadequate Procedure Results in Adding an Incorrect Lubrication Oil to the 1B CS Motor Inboard Bearing | An 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). |
| 05000250/FIN-2017001-02 | 2017Q1 | Turkey Point | Failure of Vital Battery Chargers Due to Conductive Dust / Particulate Foreign Material Exclusion | Annual Sample: (Opened) Unresolved Item (URI): Failure of Battery Chargers Due To Conductive Dust / Particulate Foreign Material Exclusion 18 a. Inspection Scope: The inspectors performed an in-depth review of AR 2183537 that documented an equipment apparent cause evaluation (EACE) associated with three Unit 3 battery chargers that tripped while in service. Thermo-Lag was being installed in support of fire protection modifications for Turkey Points transition to a risk-informed fire protection program, i.e. NFPA 805. The inspectors reviewed the associated corrective actions to verify they were completed as prescribed and that open actions were scheduled to complete commensurate with the safety significance of the activity. The inspectors walked down the battery chargers to verify selected corrective actions were completed and walked down the modification to HVAC unit V78 that was installed to prevent air from blowing directly into the battery charger ventilation louvers. The inspectors reviewed ARs that were generated during the EACE and evaluated the licensees disposition of these ARs to verify the licensees actions were in accordance with licensee procedure, PI-AA-104-1000, Corrective Action. During this inspection, on March 18, 2017, in a separate location of the plant, the 3A 4kV switchgear bus arc flashed in the reactor coil cubicle causing the 3A 4kV switchgear bus protective relay circuits to automatically deenergize the bus. The inspectors attended the licensees RCE failure investigation team meetings on this issue to obtain updates and gather facts on the arc flash and failed switchgear. The licensees RCE related to the 3A 4kV switchgear failure was in process at the end of this inspection period. The 3A 4kV switchgear room was undergoing Thermo-Lag passive fire barrier installation which was similar to the work in the new electrical equipment room (NEER) that housed the battery chargers. Documents reviewed are listed in the Attachment. This inspection constitutes one sample. b. Findings: Introduction: A URI was opened to determine if there is a performance deficiency related to the battery charger trips in the NEER and failure of the 3A 4kV switchgear bus. Description: On February 2, 2017, the 3A2 vital battery charger input breaker and motor control center (MCC) supply breaker tripped. Four minutes later, the D51 battery charger input breaker tripped. Subsequently, on February 8, 2017, the 3B2 vital battery charger input breaker and MCC supply breaker tripped, and a loud bang and possible flash were reported to have occurred in the lower level near the 4D MCC which supplies 480 Vac to the 3B2 charger. On February 13, the 4A2 and 4B2 battery chargers had difficulty load sharing with redundant battery chargers operating on their associated battery busses. The ARs associated with these separate issues include: AR 2184506, AR 2183540, AR 2183773, and AR 2185218. The licensee initiated an EACE on these issues, AR 2183537. For the battery charger trips that occurred on February 2, the licensee noted that Thermo-Lag work was in progress near the chargers in the NEER. At the time of the breaker trips, several employees were in the NEER performing cleanup from the Thermo-Lag activities. The licensee discovered a notable level of dust on horizontal surfaces in the NEER as well as inside the 3A2 and D51 battery charger cabinets. The licensee concluded the dust was conductive. The 3A2, D51 and 3B2 chargers, which were all located near each other and in the same room elevation, were cleaned and returned to service. The 4A2 and 4B2 battery chargers were also cleaned but it was noted those 19 chargers were in the same room but at a lower elevation. On February 8, the 3B2 charger tripped, despite it having been previously cleaned. It was noted at the time of the 3B2 charger trip that there were several employees installing Thermo-Lag in the NEER. The licensee concluded that the apparent cause of the breaker trips was conductive dust/particulate that may have been created by Thermo-Lag passive fire barrier installation in the vicinity of the battery chargers. The dust/particulate became airborne and settled on charger components. Corrective actions included cleaning all the chargers in the room and installing a modification which provided a sheet metal barrier on top of the D51, 3A2 and 3B2 battery chargers to deflect air from HVAC Unit V78 being blown directly into the louvered charger electrical cabinets. On March 18, 2017, in a separate location of the plant, the Unit 3A 4kV switchgear room, the 3A 4kV switchgear bus arc flashed in the reactor coil cubicle. The arc flash resulted in an explosion and the 3A 4kV switchgear bus was automatically deenergized by protective relay circuits. Similar to the NEER that housed the battery chargers, the 3A 4kV switchgear room was undergoing Thermo-Lag passive fire barrier installation. The deenergized 3A 4kV switchgear bus resulted in a Unit 3 automatic reactor trip. This event and NRC follow-up is described in section 4OA3 of this report. The licensee promptly chartered an RCE team to investigate the failure of the 4kV bus. The licensee noted that prior to the arc flash there were several employees in the 3A 4kV switchgear room performing similar Thermo-Lag installation. As an immediate corrective action, the licensee stopped all Thermo-Lag installation work in the entire fleet. The licensees RCE plan included determining if there were any common causes with the battery charger trips and the 4KV switchgear failure due to Thermo-Lag installations. A URI was identified because additional review is needed to determine if there were any common causes between the battery charger trips and anomalies and the 3A 4kV switchgear bus arc flash and to determine if this issue of concern constitutes a violation. Specifically, the inspectors will review the licensees RCE of the failed 4kV switchgear to determine if there are causes and corrective actions which were not identified during the investigation of the battery charger trip EACE, and if corrective actions could have prevented the 3A 4kV switchgear bus arc flash. (URI 05000250/2017001-02, Failure of Vital Battery Chargers Due to Conductive Dust / Particulate Foreign Material) |
| 05000250/FIN-2017008-01 | 2017Q1 | Turkey Point | Potential Failure of Fire Detection Capability on Credited Train of Equipment Following High Energy Arc Flash Event | Inspection Scope The team reviewed the fire brigade response after an explosion and smoke was reported coming from the Unit 3 safety -related 3A 4kV switchgear to determine and assess whether : (1) the brigade response was adequately staffed ; (2) there was timely arrival of the required amount of dressed- out fire brigade members ; (3) the required firefighting equipment and communication equipment and procedures were taken to and or available at the scene to adequately plan and execute a fire fighting strategy; and (4) that the brigades fire -fighting actions and communications were appropriate in accordance with the established procedures and the licensees fire brigade program requirements. The team also reviewed whether the licensees fire brigade had requested assistance from the Miami -Dade Fire and Rescue Department , the basis for assistance and if Miami -Dade Fire and Rescue provided any firefighting assistance. The team interviewed the responsible fire brigade team leader and the SRO that responded to the switchgear room to obtain the details regarding the as found conditions and actions taken by the brigade to address the smoke and potential fire in the switchgear room . The team reviewed the licensees fire pre -plan to assess whether the licensee adequately ventilated the smoke from the Unit 3A switchgear given the circumstances. Specifically , the Unit 3 EDG had automatically started and was blowing high velocity air from the radiator exhaust into the direction of the 3A and 3B switchgear room door entrances. The team walked down the Unit 3 4kV switchgear rooms with the responsible SRO that had assisted in decision making to direct smoke ventilation during the incident, to understand the circumstances regarding the strategy used for ventilation. The team reviewed the licensees fire risk management actions implemented after the licensee identified the fire door had been damaged, including the establishment of a fire watch in the 3A 4kV switchgear room. The team reviewed the licensees fire brigade response report and CAP database to determine if the licensee was adequately addressing any unresolved issues identified during the fire brigade response. 12 b. Findings and Observations On March 18, 2017 , at approximately 11: 07 a.m. EDT , as a result of an arc f lash in switchgear room 3A, eleven out of eleven spot detectors and two out of two very early warning detectors activated in switchgear room 3B. The spot detectors activated spatially from the first detector closest to Fire Door D070- 3, which separates switchgear Room 3A and 3B , to the last spot detector activating closest to the exit door on the east side of the room. The licensee acknowledged the alarms at Fire Alarm Control Panel 3C286 after the incident; however, the licensee did not reactivate the smoke detectors until sixty two hours later on March 21, 2017 , at 12:51 a.m. EDT. The team confirmed with the licensee that the detectors would not have activated between the times they were acknowledged and reactivated. The 3B 4kV switchgear was the protected train after the arc f lash in the 3A 4kV switchgear. Procedure 0 -ADM -016, Fire Protection Program , Rev . 19, Table 5.6.3 -1, denotes Fire Zone 70 ( 3B 4kV switchgear) to include fire detection instruments in the maintenance rule (a)(4) monitored fire zone and specified required risk -informed interim compensatory actions for degraded equipment. Section 5.6.3.3. d outlined these compensatory actions as the following: ...all detection instruments must be in service when required to be functional. If any single detector instrument is declared out of service, within one hour, a continuous fire watch shall be established and maintained until the detection instrument is returned to service... Smoke removal activities immediately after the inc ident credits personnel in the switchgear room 3B for nearly four hours. Thereafter, based on the security access logs, at 2 :43 p.m. EDT, two maintenance personnel were placed on fire watch duty until 5:22 p.m. EDT . However, these individuals monitored switchgear room 3A and were not placed inside the room with the credited train, 3B. The following fire watch shift arrived at approximately 6:00 p.m. EDT and maintained presence outside of both switchgear rooms 3A and 3B with the entry doors closed. The licensee informed the team that the crew was fearful of the persistent odor that was emanating after the incident in switchgear 3A. Since this crew did not maintain logs nor access the doors, the licensee confirmed to the team they were present outside. AR 2194579 was generated to document fire watches located outside the room do not meet the intent of 0 -ADM -016.4, Fire Watch Program. The first documented log of a continuous fire watch occurred at 1:15 p.m. EDT on March 19, 2017. This log continues until the smoke detectors were reactivated at 12:51 a.m. EDT on March 21 , 2017 ; however these individuals were located in switchgear room 3A. The team interviewed fire watch personnel and determined that the individuals , which did not maintain fire watch logs and stationed themselves outside the switchgear rooms , were Florida Power and Light (FP&L) employees who recently started fire watch activities; whereas, the individuals that maintained logs and placed themselves inside switchgear room 3A were experienced contractors. The team did not have an opportunity to interview FP&L fire watch employees; the contractors that were interviewed were trained and experienced to sufficiently perform the duties. In addition, the single smoke detector in the 480V Load Center 3A, 3B room (Fire Zone 95) located directly above the switchgear rooms did activate during the incident and was not reactivated until 12: 51 a.m. EDT on March 21, 2017 . The detector is assumed to have activated by smoke travelling from switchgear room 3A to switchgear room 3B to 13 the fire door located on the second level of switchgear room 3B. According to 0- ADM - 016.4, Fire Watch Program, for a deactivated detector in the 480V Load Center 3A, 3B room, the following requirement applies: ...restore the non- functional instruments to functional status within 14 days or within the next 1 hour establish a fire watch patrol to inspect the zones with the non- functional instruments at least once per hour. The licensee maintained an hourly roving fire watch in switchgear rooms 3A, 3B and 3 A/B/C/D 480V Load Centers rooms before the incident that was temporarily suspended for the 11:00 a.m., 12:00 p.m., 1:00 p.m. & 2:00 p.m. hours on March 18, 2017, due to scene safety and subsequent investigation. The hourly rove was reinstated in switchgear rooms 3A, 3B and 3 A/B/C/D 480V Load Center rooms for the 3:00 p.m. hour. The team interviewed licensee fire managers regarding the fire response activities after the incident. The managers were cognizant of the issues and attributed them partly to the false fire alarms in other areas of the plant that occurred shortly after the event . AR 2194706 was generated to enhance fire procedures that would address functionality of suppression, detection and barriers; and consideration of compensatory measures post incident. Overall, the team concluded that the licensees fire brigade response and communications were adequate following the event. However, the team identified issues with regards to the establishment of a fire watch for the 4kV switchgear rooms following the event and therefore opened an Unresolved Item (URI) as documented below . URI 05000250, 251/ 2017008- 01, Potential Fai lure of Fire Detection Capability on Credited Train of Equipment Following High Energy Arc Flash Event Introduction: The team identified an URI associated with the licensees actions to implement fire watches following the 3A 4kV switchgear high energy arc flash . These actions potentially resulted in inadequate fire detection capability in the 3B 4kV switchgear room for a period of up to 58 hours following the event on March 18, 2017. Description : The arc flash in the 3A 4kV switchgear room activated all spot type and early warning smoke detectors in the 3A 4kV switchgear, 3B 4kV switchgear and 3/A/B 480V Load Center rooms. These detectors were not reactivated until 62 hours later on March 21, 2017, (58 hours following completion of smoke removal activities) . After the event , the 3B 4kV switchgear was the protected train of equipment. Due to the risk significance of switchgear room 3B, Procedure 0 -ADM -016.4, Fire Watch Program, require d a continuous fire watch with one smoke detector out of service. For the 3/A/B 480V Load Center, Procedure 0 -ADM -016.4 required an hourly fire rove for detectors out of service. The licensee had established an hourly fire rove before the incident for all the affected rooms that was temporarily suspended for scene safety and subsequent investigation. The licensee was unable to document a continuous fire watch for 58 hours following the smoke removal activities in switchgear room 3B until the detectors were reactivated. Fire watches were posted after the incident to cover switchgear room 3A , which was the non- credited train of equipment. In addition, for approximately 22 hours following smoke removal activities, the individuals covering switchgear room 3A did not keep fi re watch 14 logs and for a period of time the individuals stayed outside the room with the entry door closed. The team noted the cause of this deficiency was primarily due to lack of training and guidance for individuals performing the fire watches. As a result of inactive smoke detectors and no fire watches in switchgear room 3B, the credited train was without smoke detection for approximately 58 hours following smoke removal activities. Due to the risk significance of the room, licensee procedures required a continuous fire watch with one detector out of service. An URI has been opened for additional review to identify whether a performance deficiency existed related to the licensees fire watch actions following the arc flash event on March 18 . (URI 05000250, 251/2017008- 01, Potential Failure of Fire Detection Capability on Credited Train of Equipment Following High Energy Arc Flash Even |
| 05000250/FIN-2017008-03 | 2017Q1 | Turkey Point | Potential Failure to Implement Adequate Foreign Material Exclusion Control | Inspection Scope The team reviewed licensee documents, performed walk downs associated with the safety -related 3A 4kV switchgear located inside room 071, and interviewed licensee personnel to determine the conditions leading up to the internal bus fault event on the morning of March 18, 2017. The documents reviewed included procedures, work orders, drawings of floor plans, one line diagrams, specifications, correspondence, photographs, licensees NRC Inspection Team Briefing document, and Root Cause Charter description AR 02192198. b. Findings and Observations The team initiated the review by performing a walk down of the 3A 4kV switchgear room to establish an understanding of the conditions inside the room that may have affected the 3A 4kV switchgear. The room , which was significantly smaller than the 3B 4kV switchgear room, provided minimally adequate access around the equipment, such as the switchgear , motor control center s (MCC s), a sequencer panel, a sump pump, and floor mounted air handling units. The current limiting reactor (CLR) , or reactor coil, associated with the event was located in section 3AA06 of the 3A 4kV switchgear. The front of this section is across from a room air handler unit, which directs its air towards the ventilation louvers in the CLR section. The team interviewed members of the licensees failure investigation process team and determined their evaluation of the potential causes for the failure of the reactor coil included: Bus fault in reactor coil cubicle 3AA06 Failed insulator in cubicle 3AA06 19 Fault in reactor coil Bus fault external to the 3AA06 cubicle Load fault with failure to isolate Magnetic properties of the reactor coil interacting with erected scaffold. 3AA06 side panels pushed in from outside reducing air gap Foreign material from internal and/or external sources Bolts installed with nuts facing towards grounded surfaces. Large quantities of conductive dust suspended in air from sweeping prior to fault Each of the potential causes were dismissed for lack of any evidence with the exception of those issues that would have contributed to a reduction in the air gap between uninsulated busses and ground surfaces. The installation of the Thermo-Lag was in progress just prior to the bus fault and according to statements from the installing contractor personnel, they had just exited the room to prepare to go to lunch and had been cleaning up the space before leaving. One of the workers had gone back into the room to check on one last item when the bus fault occurred and suffered injuries as a result of the explosion. Based on interviews and photographs provided, it was determined that the mesh, used to make up the joining pieces of insulation, was conductive. That mesh material was also light weight and made out of carbon fiber. The protective relays operated as expected for almost all components , including the 174/TDO relay in the trip circuit that operated the lockout relay, which in turn opened all the breakers in the 3A 4kV switchgear bus. The lockout relay operation prevented the 3A EDG from closing in on the 3A 4kV switchgear bus. The loss of the bus initiated a loss of steam flow on the turbine. The Unit 3 turbine and generator were motoring for approximately 30 seconds with the transmission system experiencing power swings associated with the loss of the main generator. After 30 seconds, the Unit 3 generator 286/G3 lockout tripped followed by the switchyard breakers opening and isolating the generator in 1.8 cycles. The reactor coil separates the high and low sides of the 3A 4kV switchgear bus. The high side, which was upstream of the reactor coil, had a higher withstand capability for short circuits that the low side of the switchgear bus. There is a slight difference between the overcurrent relays for phases A and B compared to phase C. Tracings provided with the details of current and voltage conditions prior to, during , and after the bus fault reveal an increase in the fault current of phase C preceding the increase in phase A. Photographs of the effects of the bus fault indicated an initial arc located next to what appeared to be phase C bus. However, the target flags in the overcurrent relay s failed to indicate a phase C trip. The entire overcurrent protection system worked as expected except for the delay on the phase C components. The team reviewed procedures and methods prescribed by the licensee to control foreign material contamination. A number of the methods indicated included cutting the Thermo-Lag material outside the switchgear room approximately 15ft from the east door to the room. Some of the final cutting and trimming of the carbon fiber mesh was done inside the switchgear room on top of the scaffolding, which had been fitted with Grifflon net to protect from foreign material particles. In addition, a Pearl Weave material was 20 used to protect against falling objects to the space below. The team was able to confirm a number of these methods used by the conditions of the space during the walk down of the room and the interview transcripts provided by the licensee of the Thermo- Lag installation personnel. However, these methods appear to cover larger pieces of material that would be appropriately captured by the Pearl Weave or the Grifflon but not the smaller pieces of carbon fiber mesh that could become airborne and migrate around the room. The only apparent control provided for airborne particulate would be the air filter in the air handling unit. This would require the material to be at an elevation low enough to get sucked in by the air return at the bottom of the air handler. Any material suspended in air would be blown out from the air handler and potentially be blown through the louvers in the reactor coil cabinet. Overall, the team concluded that the licensee was taking appropriate actions to evaluate the potential causes for the failure of the 3A 4kV bus. The most likely potential causes of the event involve the introduction of foreign material into the switchgear as well as the configuration and design of the switchgear. Additional review of information related to these potential causes will be required following the conclusion of the licensees root cause evaluation, which had not yet been completed at the time of the inspection. Therefore the team opened two URI s as documented below. i. URI 05000250, 251/2017008- 03, Potential Failure to Implement Adequate Foreign Material Exclusion Controls Introduction: The team identified an URI associated with the licensees potential failure to properly control the spread of airborne particulates generated from the installation of the Thermo-Lag insulation material on cable trays and conduits inside the 3A switchgear room. Description : The documentation provided to install the Thermo-Lag insulation was prescribed in work order 40464284- 03, EC 283459 Install T -Lag of MCC -3B Power Cables in 3A SWGR , dated the 10th of March 2017. This work order refer red to procedure MA -AA- 101- 1000, Foreign Material Exclusion Procedure, for job supervisor to review and approve the foreign material exclusion ( FME ) controls under item 2.3. The supervisor signature was provided on the 17 th of October 2016 for this particular task. However, the signature date was prior to this work order issue date. Section 4.3 of the FME procedure in paragraph 10 stated that , Special precautions need to be taken when work activities (spray painting, sand blasting, grinding, cutting, welding, insulating, chemical cleaning etc.) may generate airborne dust, debris or chemical fumes that could be introduced into operating plant equipment such as motors, switchgear, control panels and electrical cabinets . In addition, section 4.5.1 , Electrical Cabinets , paragraph 1 , directed personnel to visually inspect the surrounding area, particularly overhead, for potential sources of foreign material and to note any nearby ventilation system that may introduce foreign material into the cabinet. In paragraph 2, it indicated that , Where practical, covers should be installed on open electrical enclosures, cabinets, and boxes required to be left open by procedure, plant operations, or maintenance . Section 4.5.2, Switchgear , directed the personnel to follow the measures identified above. In addition, the conductivity of this mesh may have played a significant factor in the resulting bus fault when it migrated into the reactor coil cabinet through the open louvers and formed a low impedance path from the exposed phase C bus to the metal enclosure of the cabinet. Pieces of the black mesh were discovered inside the reactor 21 coil insulated windings, which indicated an absence of screening material or a means to block foreign material migration into the inside of the reactor coil cabinet with its exposed busses. Procedure 0- GMP -102.21, Installation, Modification and Maintenance of Thermo-Lag Fire Barrier Systems , did not contain an engineering evaluation of the carbon fiber mesh used with the system installed inside the 3A 4kV switchgear room. Material safety data sheet (MSDS -0012821) from Cytec Engineered Materials with product name Thornel Pan Based Standard Modulus Carbon Fiber provided a hazard identification of Electrically Conductive Fibers Airborne fibers can short circuit electrical equipment . This URI was initiated to further review the environment created during the installation of the Thermo-Lag in 3A 4kV switchgear room. This environment may have contributed to a degraded isolation of exposed medium voltage bus bars inside the reactor coil cabinet . Following the completion of the licensees root cause evaluation, inspectors will determine whether performance deficiencies exist ed related to the licensees evaluation of the carbon fiber mesh and the foreign material exclusion controls in effect at the time of the event. (URI 05000250, 251/2017008- 03, Potential Failure to Implement Adequate Foreign Material Exclusion Controls) |
| 05000335/FIN-2016003-01 | 2016Q3 | Saint Lucie | Reactor Coolant System Leakage Technical Specification Violation | An 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-2016003-02 | 2016Q3 | Saint Lucie | Licensee-Identified Violation | Licensee 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. |
| 05000250/FIN-2016009-01 | 2016Q2 | Turkey Point | Inaccurate Fire Watch Logs | 10 CFR 50.9(a), Completeness and accuracy of information, states, in part, that information required by statute or by the Commissions regulations, orders, or license conditions to be maintained by...the licensee shall be complete and accurate in all material respects. NRC Licenses DPR-31 (Turkey Point Unit 3) and DPR-41 (Turkey Point Unit 4), License Condition D, Fire Protection, states, in part, that FP&L shall implement and maintain in effect all provisions of the approved Fire Protection Program as described in the Updated Final Safety Analysis Report (UFSAR) for Turkey Point Units 3 and 4. . . . Section 7.1 of Appendix 9.6A of the UFSAR for Turkey Point Units 3 and 4 states that (t)he Fire Protection Program was established by procedures (citing Procedure 0-ADM- 016). These procedures identify the various positions responsible for the fire protection program implementation, and outline requirements for fire prevention, detection, and suppression. Section 7.2 of Appendix 9.6A of the UFSAR states that Fire protection specifications are presented in the Fire Protection Program (Procedure 0-ADM-016). Section 3.13.1 of FP&L Procedure 0-ADM-016 states that The Fire Watch is responsible for being constantly alert and watchful for flames, smoke, the odor of burning materials, any safety hazards and/or poor housekeeping practices. Additional duties and responsibilities are described in 0-ADM-016.4, Fire Watch Program. Section 2.2.2 of Procedure 0-ADM-016.4 states that hourly fire watch logs and badge transaction reports are to be kept for one year following the origination date. Contrary to the above, on multiple occasions between November 2014 and April 2015, the licensee maintained records of hourly fire watch logs required by FP&L Procedure 0- ADM-016.4 that were not complete and accurate in all material respects. Specifically, Fire Watch Shift Supervisors (FWSS) initialed and signed hourly fire watch logs indicating that hourly fire watches had been completed, with all required areas checked, when on multiple occasions some areas had not been checked or hourly fire watches had not been performed at all. The hourly fire watch patrol records are material to the NRC because they provide evidence of compliance with regulatory requirements. |
| 05000389/FIN-2016001-02 | 2016Q1 | Saint Lucie | Failure to Provide Detailed Work Instructions Resulted in a Unit Transient | A 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-2016001-01 | 2016Q1 | Saint Lucie | Unauthorized Entry into a High Radiation Area | A 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. |
| 05000335/FIN-2016001-04 | 2016Q1 | Saint Lucie | Licensee-Identified Violation | Licensee Identified Violation (LIV) - T.S.6.8.1 requires written procedures be established, implemented, and maintained covering applicable procedures recommended in Appendix A in RG 1.33, Rev 2, 1978, section 7 c.(4) PWR Gaseous Effluent System Ventilation Air Monitoring. Specifically, procedure, 1-NOP-25.08, Unit 1 FHB Ventilation System Operation, step 4.5 provides instructions to stop (isolate) exhaust fan numbers HVE-15 & HVE-17 in order to discontinue gaseous effluent releases from the FHB when Unit 1 FHB gaseous effluent monitor (1RSC-26-4) is inoperable and 8-hour compensatory sampling has not been established as required by ODCM 3.3.3.10. Contrary to this, on October 7, 2014, with 1RSC-26-4 declared inoperable and without establishing 8-hour compensatory sampling as required by ODCM 3.3.3.10, the licensee failed to isolate FHB fans HVE-15 and HVE-17 as required by step 4.5 of -NOP-25.08, Unit 1 FHB Ventilation System Operation, and effluent releases continued via the FHB pathway for 16 hours. This violation was evaluated using the guidance in IMC 0609, Appendix D, Public Radiation Safety Significance Determination Process, and was determined to be of very low safety significance (Green) because it did not represent a substantial failure to implement the effluent release program and post-release data indicated that the release did not exceed 10 CFR 50 Appendix I dose values. |
| 05000389/FIN-2016001-03 | 2016Q1 | Saint Lucie | Inadequate Corrective Actions to Prevent Failure of the 2C ICW Pump Motor | A 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). |
| 05000335/FIN-2015004-01 | 2015Q4 | Saint Lucie | NRC Biennial Written Examinations Did Not Meet Qualitative Standards | An NRC-identified finding related to 10 CFR 55.59, Requalification, was identified based on a determination that greater than 20 percent of the 2014 biennial written exam question sampled for review were flawed. The finding did not involve a violation of NRC requirements. The inspectors determined that the finding was more than minor because it was associated with the Human Performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the finding adversely affected the quality and level of difficulty of biennial written examinations, which potentially impacted the facilitys ability to appropriately evaluate licensed operators. The risk importance of this issue was evaluated using IMC 0609, Appendix l, Licensed Operator Requalification Significance Determination Process (SDP). The qualitative standards used by the inspectors were defined in TR-AA-220-1004, Licensed Operator Continuing Training Annual Operating and Biennial Written Exams. Because more than 20 percent, but less than 40 percent, of the questions reviewed were flawed, Blocks 4 and 5 of Appendix I characterized the finding as having very low safety significance (Green). A review of the cross-cutting aspects was performed and no associated cross-cutting aspect was identified. |
| 05000335/FIN-2015004-02 | 2015Q4 | Saint Lucie | Non-willful Compromise of a Remedial Examination Required by 10 CFR 55.59 Affected the Equitable and Consistent Administration of the Exam | An NRC-identified severity level IV (SLIV) NCV of 10 CFR 55.49, Integrity of examinations and tests was identified based on a determination that a non-willful compromise of a remedial examination required by 10 CFR 55.59 affected the equitable and consistent administration of the examination. An associated finding of very low safety significance (Green) was also identified based on a determination that a biennial written remedial examination was not prepared and approved in accordance with licensee procedures. The licensees failure to develop and administer a remedial examination in accordance with TR-AA-220-1004, Licensed Operator Continuing Training Annual Operating and Biennial Written Exams, was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the Human Performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the performance deficiency caused an incident of exam compromise that affected the equitable and consistent administration of the exam and resulted in a licensed operator being authorized to resume licensed duties prior to the condition being corrected. Additionally, the finding adversely affected the integrity of a biennial written remedial examination, which impacted the facilitys ability to appropriately evaluate a licensed operator. The licensed operator subsequently passed another remedial examination that was one hundred percent different from his original exam and the previous remedial exam. The operator also demonstrated satisfactory performance while performing licensed operator duties and participating in the licensed operator requalification program. The traditional enforcement violation was evaluated using the NRC Enforcement Policy dated January 28, 2013, and revised February 4, 2015. The inspectors determined the violation was SLIV per Section 6.1.d.2 because the associated finding was evaluated by the SDP as having very low safety significance (i.e., Green). The finding was directly related to the cross-cutting aspect of procedure adherence of the cross-cutting area of Human Performance because the training staff did not follow applicable guidance for the preparation and approval of licensed operator biennial written remedial examinations. |
| 05000335/FIN-2015004-03 | 2015Q4 | Saint Lucie | Inadequate Corrective Actions to Prevent Fouling of the CCW HXs | An NRC-identified NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, was identified for the licensees failure to implement corrective actions to prevent fouling of the 2B component cooling water (CCW) heat exchanger (HX) that resulted in the number of blocked tubes exceeding the HXs maximum analyzed limit for plugged tubes. The licensees failure to implement adequate corrective actions was a performance deficiency and was within the licensees ability to prevent. Corrective actions included installing temporary equipment to ensure adequate continuous sodium hypochlorite (SH) is injected through the CCW HXs to prevent biological fouling. The licensee entered this issue into the CAP. The performance deficiency was more-than-minor because if left uncorrected, the performance deficiency had the potential to lead to a more significant safety concern. Specifically, inadequate SH injection may cause extensive fouling and can lead to a common mode failure of the CCW HXs preventing the required cooling of safety-related structures, systems, and components (SSCs) analyzed heat loads during a design basis accident (DBA). Using Manual Chapter 0609.04, Significance Determination Process Initial Characterization of Findings, Table 2 dated June 19, 2012, the finding was determined to affect the Mitigating Systems Cornerstone. Manual Chapter 0609 Appendix A, The Significance Determination Process (SDP) 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 did not represent either an actual loss of function of at least a single train for greater than its Technical Specification (TS) Allowed Outage Time, or two separate safety systems out-of-service (OOS) for greater than its TS Allowed Outage Time. The finding involved the cross-cutting area of the resolution component in Problem Identification and Resolution (PI&R) because the organization did not take effective corrective actions to address issues in a timely manner commensurate with the safety significance of the CCW HX, in that, even after the repeat fouling issue had been identified on the 2B CCW HX, the immediate resolution of inadequate SH injection remained unresolved until the inspectors addressed this issue with plant management. |
| 05000335/FIN-2015004-04 | 2015Q4 | Saint Lucie | Procedural Non-compliances Relating to Installed Scaffold Located Near Safety-related SSCs | An NRC-identified NCV of TS 6.8.1, Procedures and Programs, was identified for the licensees failure to properly implement written procedures covering activities referenced in NRC Regulatory Guide 1.33, Revision 2, dated February 1978. Specifically, the licensee routinely failed to complete engineering evaluations to determine the acceptability of scaffolds that did not meet the 2 inch clearance requirement of NextEra Nuclear Fleet Administrative Procedure MA-AA-100-1002, Scaffold Installation, Modification, and Removal Requests. The licensees failure to erect scaffold in compliance with the NextEra Nuclear Fleet Administrative Procedure was a performance deficiency. This issue has been entered into the licensees CAP. The performance deficiency was more-than-minor because it was associated with the Mitigating Systems Cornerstone Attribute of Protection against External Factors, Seismic, and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, routinely failing to complete engineering evaluations of scaffold clearance issues could lead to the continued use of inadequately installed scaffolds, ultimately posing a risk of rendering safety-related equipment inoperable during normal and adverse conditions, such as a design basis seismic event. Using Inspection Manual Chapter 0609, Attachment 4, Initial Characterization of Findings, Table 2, Cornerstones Affected by Degraded Condition or Programmatic Weakness, dated June 19, 2012, the inspectors determined the finding affected the Mitigating Systems Cornerstone. Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) 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 no was answered to all four screening questions, i.e. the finding did not represent an actual loss of function of any piece of plant equipment for any amount of time. The finding involved the cross-cutting area of PI&R in the aspect of resolution, in that the organization did not take effective corrective actions to address the scaffolding issues in a timely manner, as evidenced by a period of five months in which the inspectors continued to identify non-conformances with erected scaffold. |
| 05000335/FIN-2015004-05 | 2015Q4 | Saint Lucie | Failure to Verify the Adequacy of the Unit 1 and Unit 2 Steam Generator Tube-to-Tubesheet Welds Design | An NRC-identified, Non-cited Violation of 10 CFR Appendix B, Criterion III, Design Control, was identified for the failure to verify the adequacy of the Unit 1 and Unit 2 replacement steam generators (RSGs) design with respect to the requirements in the American Society of Mechanical Engineers Boiler Pressure Vessel Code (ASME Code), Section III, Article NB-3000, for the primary stress and fatigue analyses of the pressure-retaining tube-to-tubesheet welds. The licensee entered the issue in the corrective action program, and performed the required analyses for the Unit 1 and Unit 2 RSGs to demonstrate that the design met the ASME Code requirements. The inspectors used the guidance in NRC Inspector Manual Chapter (IMC) 0612, Appendix B, Issue Screening, and determined that the performance deficiency was more-than-minor because it was associated with the design control attribute of the Initiating Events Cornerstone, and adversely affected the cornerstone objective. Specifically, the failure to verify that the required stress and fatigue analyses were performed in accordance with the ASME Code did not support the objective of limiting the likelihood of primary-to-secondary leakage events that could upset plant stability and challenge critical safety functions during shutdown, as well as power operations. The inspectors evaluated this finding using NRC IMC 0609, Appendix A, Significance Determination Process for Findings At-Power, Exhibit 1 Initiating Events Screening Questions. The finding screened as Green because the stress calculations demonstrated that there was no degraded steam generator (SG) tube condition where one tube could not sustain three times the differential pressure across a tube during normal full power, and none of the SGs violated the accident leakage performance criterion. Additionally, the stress calculations demonstrated that the finding did not result in a condition that exceeded the reactor coolant system leak rate for a small loss of coolant accident (LOCA), or affected other systems used to mitigate a LOCA resulting in a total loss of their function (e.g., Interfacing System LOCA). The inspectors determined that no cross-cutting aspect was associated with this finding because the performance deficiency occurred more than 3 years ago, and it was not reflective of present performance. |
| 05000335/FIN-2015004-06 | 2015Q4 | Saint Lucie | Licensee-Identified Violation | 10 CFR55.49, Integrity of examinations and tests, states, Applicants, licensees, and facility licensees shall not engage in any activity that compromises the integrity of any application, test, or examination required by this part. The integrity of a test or examination is considered compromised if any activity, regardless of intent, affected, or, but for detection, would have affected the equitable and consistent administration of the test or examination. This includes activities related to the preparation and certification of license applications and all activities related to the preparation, administration, and grading of the tests and examinations required by this part. Contrary to the above, on August 18, 2015, the licensee identified that two licensed operators were administered a 2014 biennial requalification comprehensive written examination that contained five repeat questions from other versions of the biennial written examination that the individuals had either prepared or approved. The inspectors determined that the violation was not greater than very low safety significance (Green) because the licensed operators were not actively performing licensed duties in the control room. This issue was entered in the licensees corrective action program as CR 02067887. |
| 05000335/FIN-2015004-07 | 2015Q4 | Saint Lucie | Licensee-Identified Violation | Contrary to TS 6.8.1, Procedures and Programs, the licensee failed to implement the written procedures recommended in Appendix A of Regulatory Guide 1.33, Revision 2, dated February 1978, regarding PM of safety-related equipment. Specifically, Regulatory Guide 1.33 Appendix A Section 9.b states, in part, that system parts that have a specific lifetime should be replaced. The licensee implements this guidance in Regulatory Guide 1.33 by following the PM program, ER-AA-204, Preventive Maintenance Program Strategy, Revision 5, which details how PM should be developed and implemented for safety-related equipment. Section 3.2.9 of this procedure states, in part, that to ensure inclusion of vendor technical information, vendor maintenance recommendations should be included in PM bases and frequency requirements. The ESI-EMD owners group recommends a 10-year life for EDG speed switches based on electrolytic capacitor life expectancy. However, there is no evidence that the licensee considered vendor recommendations regarding the periodicity of EDG speed switch replacement when implementing its PM on the EDG. As a result, the existing PM for the speed switches was inadequate and led to the 1A EDG being rendered inoperable when the speed switch failed to function properly during manual local start of the EDG. This violation was associated with the Mitigating Systems Cornerstone and was determined to be of very low safety significance (Green) in accordance with Manual Chapter 0609 Appendix A, The Significance Determination Process (SDP) for Findings At-Power, because the finding did not result in a loss of system function or represent an actual loss of function of at least a single train for greater than its TS allowed outage time. The licensee entered this violation into its CAP as AR 2053060. |
| 05000335/FIN-2015003-01 | 2015Q3 | Saint Lucie | Unsecured Utility Cart With An Unrestrained Operating Pedestal Fan Near Safety-related ECCS Equipment | An NRC-identified, NCV of Technical Specification (TS) 6.8.1, Procedures and Programs, was identified for the licensees failure to implement written procedures covering activities referenced in NRC Regulatory Guide 1.33, Revision 2, dated February 1978. Specifically, the licensee failed to follow procedural requirements to properly secure a pedestal fan positioned on a wheeled cart to the extent required to prevent a potential for adverse interaction with safety-related systems, structures or components (SSCs) during a design basis seismic event. Failure to control equipment located near safety-related SSCs to prevent the equipment from interacting with safety-related SSCs during a design basis seismic event was a performance deficiency. Immediate corrective actions included removing the cart and fan assembly from the area and entering this issue into the corrective action program. The performance deficiency was more than minor because the issue was associated with the Mitigating Systems Cornerstone attribute of Protection Against External Factors (seismic) and affected the cornerstone objective of ensuring the availability, reliability, and capability of safety-related SSCs to respond to initiating events to prevent undesirable consequences. Specifically, during a design basis seismic event the unsecured cart and unrestrained fan could have damaged the emergency core cooling system low and high pressure safety injection flowrate transmitters causing control room operators to have a loss of safety injection flowrate indication and a small amount of system leakage during accident mitigation. Using Manual Chapter 0609.04, Significance Determination Process Initial Characterization of Findings, Table 2, dated June 19, 2012, the finding was determined to affect the Mitigating Systems Cornerstone. Manual Chapter 0609, Appendix A, Significance Determination Process (SDP) 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 inspectors answered No to all four screening questions. The finding involved the cross-cutting aspect in the area of human performance associated with training because the organization failed to provide training and ensure knowledge transfer to maintain a knowledgeable, technically competent workforce and instill nuclear safety values to ensure temporarily placed equipment located near safety-related SSCs was adequately secured to prevent interaction during a seismic event. |
| 05000335/FIN-2015003-05 | 2015Q3 | Saint Lucie | Unit 2 Shutdown Due to Through Wall Crack and Leak in the 2B2 Safety Injection Tank Discharge Pipe | On March 30, 2015 the operators reviewed the Unit 2 control room logs and identified increased leakage from the 2B2 SIT. On April 11, 2015, the 2B2 SIT was declared inoperable due to a through wall leak identified on the 12-inch diameter Class 2 piping of the discharge header. The licensee determined that the pipe failed due to a legacy support design from construction, which led to higher levels of stress in the supports weld. The licensee concluded through metallurgical analysis that the pipe flaw propagated through wall due to high cycle fatigue. Prior to the through-wall leak being identified, there were no indications that a flaw existed within the pipe support weld. Additionally, there were no examinations required to be performed on the support that would have recognized a flaw within the support weld. As a result, the inspectors concluded that there was no performance deficiency associated with the pipe failure. The inspectors utilized available risk-informed tools to assess the safety significance of the 2B2 SIT inoperability. Based on the fact that the through-wall leak did not preclude the 2B2 SIT from performing its design basis function while inoperable, the inspectors concluded this event was of very low safety significance. St. Lucie Unit 2 TS limiting condition for operation 3.5.1, Safety Injection Tanks (SIT), requires each RCS safety injection tank to be operable in plant operating Mode 1 through Mode 3. With one SIT inoperable, the inoperable SIT must be returned to operable status within 24 hours or Unit 2 placed in hot standby within the next six hours and hot shutdown within the following six hours. Contrary to the above, Unit 2 operated for approximately 13 days from March 30, 2015 to April 12, 2015, with the 2B2 SIT inoperable due to a through-wall leak identified on the 12-inch diameter class 2 piping of the discharge header. Although a violation of the TS occurred, the violation was not attributable to an equipment failure that was avoidable by reasonable licensee quality assurance measures or management controls. Therefore, the TS 3.5.1 violation was not associated with a licensee performance deficiency. The inspectors concluded that the violation would normally be characterized as a Severity Level IV violation based on its very low safety significance. The NRC exercised enforcement discretion in Enforcement Action (EA)-14-047, in accordance with Section 2.2.4.d and 3.5 of the Enforcement Policy because the violation was not associated with a licensee performance deficiency; therefore, it will not be considered in the assessment process or the NRCs Action Matrix. This issue was documented in the licensees corrective action program as AR 2039830. Licensee corrective actions included: replacing the leaking pipe spool piece with the through wall flaw (line I-12-SI-459), modifying the supports for line SI- 459, removing support SI-4203-44, revising procedure STD-C-010, Piping and Support Analysis Requirements St. Lucie Units 1 and 2, to include more detail related to weld attachments to specifically address avoiding extended lugs which develop a bending movement, and incorporating considerations associated with using weld attachments in an environment which involves cyclic loading. This LER is closed. |
| 05000335/FIN-2015003-02 | 2015Q3 | Saint Lucie | Partial Loss of Unit 1 and Unit 2 Offsite Power Due to Unit 2 6.9 kV Non-Segregated Bus Fault | The inspectors identified an unresolved item associated with the partial loss of offsite power as a result of a fault on the 2A1 6.9 kV non-safety bus. On September 17, 2015, a fault of the 2A1 6.9 kV bus connected to the 2A SUT resulted in the loss of power to both the 1A and 2A SUTs. 1A SUT was impacted since it shared a common power supply from the switchyard with the 2A SUT. The 2A1 6.9kV bus is of a bus bar design. The bus is made up of flat copper bars that are bolted together with all three phases contained in a metal enclosure. The phases are supported within the enclosure and insulated from each other using ceramic insulator plates that maintain the spacing between the phases and with the enclosure. Each bar is insulated between the bolted connections with Noryl insulation. Rubber insulating boots cover the bolted connections. The licensees inspection of the 6.9 kV bus determined that the fault occurred at a location where the bus transitions from a vertical to a horizontal orientation. The three insulating boots for this bolted transition were found lying on top of the ceramic insulators between the phases below in the vertical run. The boots had a coating of dust and corrosion products that had flaked off the enclosure. At the close of this inspection period, the licensees root cause evaluation and complete inspection of the 2A1 6.9 kV bus was in progress. The licensee entered this issue in the CAP as AR 2074774. This is an unresolved item pending review of the licensees root cause evaluation to determine whether or not a performance deficiency exists. The NRC will track this issue as an URI. |
| 05000389/FIN-2015003-03 | 2015Q3 | Saint Lucie | Untimely 10 CFR50.72 Notification | The 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. |
| 05000335/FIN-2015003-04 | 2015Q3 | Saint Lucie | Failure to Follow Reactor Protection System Surveillance Procedure Resulting in Reactor Plant Trip | A Green, self-revealing, NCV of TS 6.8.1 was identified for the licensees failure to adequately implement surveillance procedures during reactor protection system (RPS) testing. Specifically, the licensee failed to implement as-written operations surveillance procedure 1-OSP-63.01, RPS Logic Matrix Test, when operators failed to close two trip circuit breakers (TCBs) prior to proceeding to the next section of the procedure. This resulted in an unplanned automatic reactor trip when a second pair of TCBs were opened. Corrective actions completed for this event included a human performance review that was conducted by the shift manager, operations director and plant general manager, initially implementing around the clock management oversite, and revising the RPS logic matrix test procedure to change it from a reader/doer procedure to a procedure with more concurrent verification steps. The licensee entered this issue into their corrective action program as AR 2065821. The licensees failure to follow procedure 1-OSP-63.01, RPS Logic Matrix Test, as written is a performance deficiency. This performance deficiency was more than minor because it was associated with the human performance attribute of the Initiating Events Cornerstone and it adversely affected the associated cornerstone objective of limiting the likelihood of events that upset plant stability and challenge critical safety functions and resulted in an actual plant trip. The inspectors evaluated the risk of this finding using IMC 0609, Significance Determination Process, Attachment 4, Initial Characterization of Findings and IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power. The inspectors determined that the finding was of very low safety significance because it did not result in both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions would not be available. 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 logic matrix test to ensure procedure steps were completed as required. |
| 05000335/FIN-2015002-01 | 2015Q2 | Saint Lucie | Failure to Assess Potential Gaseous Effluents Released from Containment Equipment Hatch Openings during a Loss of Negative Pressure | The inspectors identified a Green non-cited violation of Technical Specification 6.8.1 for the failure to implement procedures for the monitoring, evaluating, and reporting of gaseous effluents in accordance with the methodology in the Off-Site Dose Calculation Manual. Specifically, there was no program in place to assess potential effluent releases from containment equipment hatch openings during periods when negative pressure was lost. The licensee took immediate corrective actions including placement of a low-volume air sampler near the Unit 1 Reactor Containment Building equipment hatch, and entered the issue into their corrective action program as AR 02037629. The performance deficiency was more than minor because it was associated with the Public Radiation Safety cornerstone attribute of Programs and Processes and adversely affects the cornerstone objective of ensuring adequate protection of public health and safety from exposure to radioactive materials released into the public domain as a result of routine civilian nuclear reactor operation. The finding was assessed using the Public Radiation Safety Significance Determination Process. Based on the fact that routine (i.e. nonaccident) effluents released from an equipment hatch are unlikely to contribute significantly to public dose, this finding does not represent a substantial failure to implement the effluent program and was determined to be of very low safety significance (Green). This finding has a crosscutting aspect of Operating Experience (P.5) because the licensee failed to recognize the applicability of regulatory issues experienced by other plants regarding equipment hatch monitoring. |
| 05000389/FIN-2015002-02 | 2015Q2 | Saint Lucie | Failure to Comply with Technical Specification 3.0.3 | The 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. |
| 05000335/FIN-2015002-04 | 2015Q2 | Saint Lucie | Licensee-Identified Violation | The St. Lucie Unit 1 Technical Specification 6.8.1(a) states, in part, that the licensee shall establish, implement, and maintain the applicable procedures recommended in Appendix A of Regulatory Guide 1.33, Rev. 2, 1978. Section 9(a) of Appendix A to Regulatory Guide 1.33, Rev.2, states, in part, that maintenance that can affect the quality 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 the above requirements, on April 12, 2015, the licensee did not implement adequate maintenance instructions that were appropriate to the circumstances as specified by WO 40296976 to ensure that the 1C AFW pump was correctly aligned and returned to service. Specifically, the work order instructions required Attachment 10 of procedure 1-PMM-09.04, Auxiliary Feedwater Turbine Mechanical and Electrical Over speed Trip Tests, to be completed as part of the pump restoration. Attachment 10 of procedure 1-PMM-09.04 included a step to position valve V08385 to the open position, and this step was not completed. The licensee entered this issue into the CAP as AR 02042311. The failure to adequately implement the work instructions in WO 40296976 requiring completion of Attachment 10 of procedure 1-PMM-09.04, to ensure the valve was correctly aligned was a performance deficiency. The performance deficiency was more than minor because it was associated with the equipment performance attribute of the mitigating systems cornerstone and adversely impacted the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events. The finding was of very low safety significance (Green) because the inspector answered No to all of the associated Mitigating Systems screening questions within IMC 0609, Attachment 4, Initial Characterization of Findings. 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 o f the NRC Enforcement Policy. |
| 05000389/FIN-2015002-05 | 2015Q2 | Saint Lucie | Licensee-Identified Violation | Technical 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-2015002-03 | 2015Q2 | Saint Lucie | Problem with LER Reporting | The 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. |
| 05000335/FIN-2015001-01 | 2015Q1 | Saint Lucie | Inadequate Risk Assessments on the Emergency Core Cooling System | The inspectors identified a Green non-cited violation of 10 CFR 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, paragraph (a)(4), for the licensees failure to conduct adequate risk assessments prior to performing surveillance testing on the emergency core cooling system (ECCS). Consequently, ECCS surveillance testing was completed while the unit was in a Green online risk configuration when the risk should have been elevated to Yellow. Corrective actions completed included implementing instructions via an Operations Standing Order to declare any system, structure or component unavailable when it is declared inoperable unless an assessment is completed to show that operator actions can restore the safety function before it is needed. The licensees failure to implement the online risk assessment program as required by ADM- 17.16, Implementation of the Configuration Risk Management Program, was a performance deficiency (PD). Specifically, in each of the three examples identified by the inspectors, the plants online risk was reclassified from Green to Yellow when properly assessed as established by the licensees online risk monitor (OLRM). The inspectors determined that the PD was more than minor because it adversely affected the equipment performance attribute of the Mitigating Systems Cornerstone. Specifically, the failure to identify increases in operational risk and implement risk management actions adversely affected the reliability of those systems relied upon to respond to plant events. The finding was determined to be of very low safety significance (Green) because for each instance, the Incremental Core Damage Probability Deficit for the timeframe the ECCS was unavailable was less than 1E-6. The inspectors determined that the finding had a cross-cutting aspect of Training in the Human Performance area, because the control room operators did not have adequate risk insight guidance and an adequate understanding regarding use of operator actions to take credit for safety function availability, causing incorrect application of the on-line risk monitoring tool (H.9). |
| 05000335/FIN-2015001-02 | 2015Q1 | Saint Lucie | Procedural Non Compliances Relating To Temporarily Installed Ladders Located Near Safetyrelated SSCs | The NRC identified a Green, non-cited violation of Technical Specification (TS) 6.8.1, Procedures and Programs, 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 licensee failed to track, inspect and evaluate the placement of temporarily installed ladders (TILs) that were touching or placed near safety-related Structures, Systems, and Components (SSCs) with the potential to interact with the SSCs during a design basis seismic event. Corrective actions completed included removing TILs that were no longer being used and entering the remaining ladders into the corrective action program (CAP) for tracking and inspection, and reviewing whether any ladder required an engineering evaluation. The licensees repeated failure to track, inspect, or complete an engineering evaluation on TILs located near safety-related SSCs as required by licensee procedures ADM-27-21 and MA-AA-100-1008 was a performance deficiency. The performance deficiency was more than minor because if left uncorrected, the performance deficiency had the potential to lead to a more significant safety concern. Specifically, routinely not tracking, inspecting or completing engineering evaluations of TILs that are touching or located near safety-related SSC could allow ladders to be installed, which interact with safety-related equipment resulting in equipment rendered inoperable during a design basis seismic event. The finding screened as green because the finding did not represent an actual loss of function of at least a single Train for > its TS Allowed Outage Time OR two separate safety systems out-of-service for > its TS Allowed Outage Time. The finding involved the crosscutting area of Problem Identification and Resolution, in the aspect of Identification, in that non-compliances associated with TILs had been long-term issues, which the licensee had failed to identify and enter into the CAP. As a result, the ladder issues remained unnoticed and unaddressed in the CAP until identified by the inspectors (P.1) |
| 05000335/FIN-2015007-03 | 2015Q1 | Saint Lucie | Adequacy of 10 CFR 50.59 Screening Performed for Unit 1 SGBD Maximum Flow Evaluation Test | An unresolved item (URI) was identified regarding the adequacy of a 10 CFR 50.59 screening that was completed for the performance of a test on the Unit 1 SGBD system. A violation of 10 CFR 50.59(d)(1) was identified for the licensees failure to perform a full written 10 CFR 50.59 evaluation which provided the basis that the test or experiment did not require a license amendment. Specifically, the test introduced operating conditions that were inconsistent with the analyses described in the stations UFSAR, and a full 10 CFR 50.59 evaluation was not performed. The URI is being opened to provide for additional inspection of the licensees past operability evaluation of the test conditions, and corresponding event re-analyses, to determine if the violation of 10 CFR 50.59 was more than minor. On November 11, 2011, the licensee performed a test using procedure 1-LOI-23.01, Steam Generator Blowdown Maximum Flow Evaluation Test, Rev. 1. During the test, SGBD flow was increased to 160 gpm on each steam generator. Prior to the performance of the test, a 10 CFR 50.59 screening was performed for the activity, which determined that the proposed activity did not involve a test or experiment not described in the UFSAR, where an SSC is utilized or controlled in a manner that is outside the reference bounds of the design for that SSC or is inconsistent with analyses or descriptions in the UFSAR. The inspectors determined that at the time the 10 CFR 50.59 screen was completed, Chapter 15 of the UFSAR identified that the assumed SGBD flow rate during the loss of normal feedwater event was 40 gpm per steam generator. Another event involving a loss of feedwater with no AFW flow, described in UFSAR Chapter 10, identified that the SGBD flow rate was assumed to be 35 gpm. The inspectors determined that the SGBD flow rate of 160 gpm allowed by 1-LOI-23.01 was inconsistent with the UFSAR analyses assumptions for the SGBD system. Following the inspectors identification of the discrepancy, the licensee planned to evaluate the test conditions to determine if analysis acceptance criteria could be met when the SGBD flow rate input was increased to values allowed during the test. Additional inspection of this re-analysis is needed to determine if the full 10 CFR 50.59 evaluation, had it been performed, would have concluded that a license amendment should have been pursued prior to implementing the activity. This issue will be identified as URI 05000335/2015007-03, Adequacy of 10 CFR 50.59 Screening Performed for Unit 1 SGBD Maximum Flow Evaluation Test. |
| 05000389/FIN-2014005-01 | 2014Q4 | Saint Lucie | Failure to Follow Work Instructions during Installation of Unit 2 Vent Valve V3811 | The 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-2014005-02 | 2014Q4 | Saint Lucie | Design Basis Review for Unit 2 Steam Generator Tube-to-Tubesheet Joint | The 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. |
| 05000269/FIN-2014005-01 | 2014Q4 | Oconee | Failure to Update FSAR for Mode 4 LOCA | An NRC identified Severity Level IV violation of 10 CFR 50.71(e), "Maintenance of Records, Making of Reports," was identified for the licensees failure to update the final safety analysis report (FSAR) after the licensee adopted the improved technical specifications (ITS). The licensee adoption of ITS introduced the possibility of a Mode 4 loss of cooling accident (LOCA), which was an accident of a different type than previously evaluated in the FSAR. The licensee initiated PIP O-15-00260 in order to determine future corrective actions. Continued non-compliance does not present an immediate safety concern because the inspectors assessed this as a very low safety significant issue. The licensees failure to update the FSAR as required by 10 CFR 50.71(e) was a performance deficiency. The performance deficiency impacted the ability of the NRC to perform its regulatory oversight function and was dispositioned using traditional enforcement. Specifically, a failure to update the UFSAR challenges the regulatory process because it serves as a reference document used, in part, for recurring safety analyses, evaluating license amendment requests, and in preparation for and conduct of inspection activities. This violation was determined to be a Severity Level IV violation per Section 6.1.d.3 of the NRC Enforcement Policy, revised July 9, 2013, because the lack of up-to-date information has not resulted in any unacceptable change to the facility or procedures. The NRC Enforcement Policy also requires disposition of findings in the significance determination process, which determined the finding was not more than minor. Since this issue was dispositioned using traditional enforcement, there was no cross-cutting aspect associated with this violation. |
| 05000269/FIN-2014005-02 | 2014Q4 | Oconee | Keowee Hydro Unit 2 Inoperable for Longer Than Allowed TS Outage Time | A self-revealing Green NCV of Oconee Nuclear Station Technical Specification (TS) 3.8.1, AC Sources Operating, was identified for Keowee Hydro Unit 2 being inoperable for longer than allowed TS outage time. The licensee modified Keowee Hydro Unit 2 electrical protection circuitry with a faster response relay which was susceptible to an existing degraded system condition and ultimately caused Keowee Hydro Unit 2 to be inoperable. The licensee implemented engineering change (EC111358) which moved the 86E2X relay to another cabinet which was not susceptible to the vibration from the governor oil system. The licensee entered this issue in their corrective action program (CAP) as PIP-O-13-09152. The licensees failure to properly evaluate a modification to the electrical control circuit of the governor oil system, which resulted in Keowee Hydro Unit 2 being inoperable for longer than allowed TS outage time, was a performance deficiency. The issue is more than minor because it was associated with the equipment performance attribute of the mitigating system 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 (i.e., core damage). Specifically, the modification of the governor oil system, including the addition of the 86E2X governor TXS catastrophic relay, resulted in Keowee Hydro Unit 2 being inoperable for longer than allowed TS outage time. The finding was screened in accordance with NRC IMC 0609, Significance Determination Process (SDP), Attachment 4 and Attachment A and determined to require a detailed risk evaluation. A regional Senior Reactor Analyst performed a risk analysis of the performance deficiency which was found to be Green (CDF < 1E-6/year). The dominant accident sequence was a loss of offsite power where Keowee Unit 1 fails independently and unrelated to the performance deficiency and power is not successfully restored by Oconee operators. The influential factors in the Green result were the limited exposure time (19 days) and the ability to quickly restore power to the unit via the Lee Station gas turbines via the Fant Line. This finding was determined to have a cross-cutting aspect in the problem identification and resolution cross cutting area because the licensees organization failed to take effective corrective actions to address the issue in a timely manner commensurate with its safety significance. Specifically, the licensee failed to take effective corrective actions to address system interactions (i.e. high vibrations) which ultimately had an adverse effect upon modifications to the governor oil system of the Keowee Hydro Unit 2. |
| 05000389/FIN-2014004-01 | 2014Q3 | Saint Lucie | Failure to Follow Foreign Material Exclusion Requirements in Reactor Vessel Maintenance Procedures | A 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. |
| 05000335/FIN-2014004-02 | 2014Q3 | Saint Lucie | Failure to Establish a Reasonable Maintenance Effectiveness Demonstration for the ECCS Floor Drain Valve System | An NRC-identified non-cited violation (NCV) of 10 CFR 50.65(a)(2), Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, resulted from the licensees failure to establish a technically justifiable and reasonable maintenance effectiveness demonstration for the emergency core cooling system (ECCS) floor drain valve system. Corrective actions included a revision to the maintenance rule (MR) system function and the reliability performance criteria, the completion of a 3-year extent of condition review to identify all missed functional failures, entering the valve actuators into the licensees air-operated valve program, and monitoring the performance of the Unit 1 ECCS floor drain valve system as required by 10 CFR 50.65(a)(1). This issue was entered into the licensees corrective action program as action request 1936612. The performance deficiency was more than minor because it involved degraded system performance which, if left uncorrected, could become a more significant safety concern. The inspectors evaluated the significance of the finding under the mitigating systems cornerstone using Table 2 of Attachment 4 (dated June 19, 2012) and Exhibit 2 of Appendix A (dated June 19, 2012) to Inspection Manual Chapter 0609, Significance Determination Process, (dated June 2, 2011). The inspectors determined the finding was of very low safety significance (i.e., Green) because the exhibit criteria did not screen the finding to a detailed risk assessment. The inspectors concluded the finding was associated with the cross-cutting aspect of trending (P.4) in the problem identification and resolution area because the licensee had failed to utilize the corrective action program to associate and identify an adverse trend related to repeated system failures in the aggregate to identify common cause and programmatic issues. |
| 05000335/FIN-2014009-02 | 2014Q3 | Saint Lucie | Inaccurate Information Concerning Flooding Analysis | The licensee identified an apparent violation (AV) of 10 CFR 50.9(a), Completeness and Accuracy of Information, for the failure to provide the NRC with complete and accurate information regarding the safety significance of degraded and missing penetration seals that were identified on electrical conduits and piping that passed through exterior walls of the Unit 1 and Unit 2 reactor auxiliary buildings (RABs). Specifically, the licensee failed to identify missing flood barriers on the Unit 1 RAB and the licensee underestimated the volume of water that would have entered the Unit 1 and Unit 2 RABs during a design basis flood event and challenge the operability of safety-related equipment. The licensee entered this issue into the corrective action program as action requests (AR) 1932213 and AR 1943185 and completed corrective actions to repair and replace the degraded and missing flood penetration seals. The apparent violation had the potential to impede or impact the regulatory process, and was therefore subject to traditional enforcement as described in the NRC Enforcement Policy, dated July 9, 2013. 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 AV should be considered for escalated enforcement action. In particular, had this information been complete and accurate, it may have caused the NRC to reconsider a regulatory position or undertake a substantial further inquiry. Because the apparent violation involved the traditional enforcement process with no underlying technical violation that would be considered more than minor in accordance with Inspection Manual Chapter (IMC) 0612, a cross-cutting aspect was not assigned to this violation. |