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05000324/FIN-2011004-032011Q3BrunswickInadequate Maintenance Results in Containment Isolation Valve FailureA self-revealing Green finding was identified for inadequate maintenance on the overload relay of the unit 2 reactor water cleanup (RWCU) system inlet isolation valve 2-G31-F001. As a result of the inadequate maintenance, the overload relay actuated during operation of the valve under normal conditions, and the valve failed to shut. This was revealed while operators were attempting to isolate the RWCU system on August 2, 2011. After the valve failed to fully shut on August 2, 2011, the licensee shut the valve in series with 2-G31-F001 (2-G31-F004), repaired the overload relay for the 2-G31-F001 valve by installing the correct fasteners, returned the 2-G31-F001 valve to service, and entered the issue into their corrective action program (AR #480063). The inadequate maintenance on the 2-G31-F001 valve overload relay was a performance deficiency. The finding was more than minor because it was associated with the Barrier Integrity cornerstone attribute of structure, system, and component (SSC) and Barrier Performance, and it affected the associated cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, the finding prevented a primary containment isolation valve from shutting. This finding was evaluated using Inspection Manual Chapter 0609, Significance Determination Process, Phase 1 Worksheet for Containment Barriers. The finding was determined to be of very low safety significance (Green) because the finding: 1) did not only represent a degradation of the radiological barrier function provided for the control room, auxiliary building, spent fuel pool, or the standby gas treatment system, 2) did not represent a degradation of the barrier function of the control room against smoke or a toxic atmosphere, and 3) did not represent an actual open pathway in the physical integrity of reactor containment. The cause of this finding has no cross-cutting aspect because the maintenance took place in 1992 and is not indicative of current licensee performance.
05000324/FIN-2011004-042011Q3BrunswickLicensee-Identified ViolationTechnical Specification 5.4.1, Procedures, requires that written procedures shall be implemented covering applicable procedures recommended in Regulatory Guide 1.33, Appendix A, November 1972 (Safety Guide 33, November 1972). Regulatory Guide 1.33, section I (Safety Guide 33, November 1972) requires written procedures for performing maintenance. Contrary to the above, the licensee identified that maintenance procedure 0CM-VFC500, Instructions for Repair, Reassembly, and Adjustment of the RCIC Terry Turbine Governor Valve, did not contain adequate guidance for assembling the unit 2 RCIC turbine governor valve. As a result, inadequate maintenance was performed on the unit 2 RCIC governor valve in 2009 in that proper spacing of the valve stem packing spacers was not maintained. This inadequate maintenance on the RCIC governor valve led to failure of the valve during quarterly surveillance testing on April 15, 2011. This finding was evaluated by the Regional Senior Reactor Analyst performing a Phase 3 significance analysis. The finding was determined to have a risk lower than 1E-6, and is GREEN. The short exposure time, and the availability of the severe accident mitigation alternative (SAMA) diesels for battery charging contributed to the low impact of the finding. The results were dominated by loss of the DC bus that powers HPCI, combined with automatic depressurization system (ADS) failures that could lead to high pressure core melt. External Events and Large Early Release Probability were found not to be major contributors to the risk of the finding. As corrective actions, the licensee revised the maintenance procedure and repaired the valve. This issue is in the licensees CAP as NCR #468283.
05000324/FIN-2011004-052011Q3BrunswickLicensee-Identified ViolationTechnical Specification (TS) 3.3.6.1, Primary Containment Isolation Instrumentation, requires that the RWCU high differential flow instrumentation be operable in modes 1, 2, or 3. If the instrumentation is not operable, then TS 3.3.6.1 requires that the RWCU penetration flow path be isolated within 1 hour. Contrary to the above, the licensee identified that the RWCU high differential flow instrumentation was not operable and the penetration flow path was not isolated when the unit entered mode 1 on April 16, 2011 until August 2, 2011, because the RWCU inlet flow sensing element was installed backwards, causing the flow sensing element to be inaccurate. The resulting inaccuracy caused the instrumentation to be unable to isolate within the required TS limit of less than or equal to 73 gallons per minute differential flow. The finding was determined to be of very low safety significance per Appendix A of Inspection Manual Chapter 0609, Significance Determination Process, because the finding: 1) did not only represent a degradation of the radiological barrier function provided for the control room, auxiliary building, spent fuel pool, or the standby gas treatment system, 2) did not represent a degradation of the barrier function of the control room against smoke or a toxic atmosphere, and 3) did not represent an actual open pathway in the physical integrity of reactor containment. Upon discovery of the condition, the licensee isolated the affected penetration flow path and installed the flow sensing element correctly. The issue is in the licensees CAP as NCR #479248.
05000335/FIN-2009004-012009Q3Saint LucieSeat leakage of Containment Spray Valves 2MV-07-3/4While reviewing condition report 2007-41688, the inspectors determined that seat leakage past containment spray system isolation valves 2-MV-07-3 and 2-MV-07-4 dates back to 1990. The valves are Pacific 12 inch gate valves with SB-0 Limitorque motor operators. Leakage has been as high as 3.37 gpm measured in 2004. Repairs on the valve seats and wedges have been ineffective. The repair activities have mainly consisted of lapping the valve seating surfaces and performing a satisfactory blue dye check. The valves are not containment isolation valves and require no periodic in-service test. The licensee has repeatedly planned replacement of the valve with an updated flexible wedge style valve during multiple refueling outages. However, as the refueling outages approach, the repair is cancelled due to scheduling conflicts or to further evaluate the condition. This has been noted by the inspectors during the last two refueling outages as the operator work around remains active. The inspectors determined that in 1996, the licensee developed a compensatory measure and procedure change to install a temporary hose from a drain valve downstream of 2-MV-07-3/4 to allow the seat leakage to drain to the floor drain system in the auxiliary building vice leaking into the containment spray system and discharging down into containment during shutdown cooling operations. Essentially, the licensee has created an operator work around that could have an adverse effect on shutdown cooling operations and reactor coolant system inventory while in midloop conditions which requires frequent makeup to the RCS to maintain reactor vessel inventory and adequate net positive suction head (NPSH) on the operating pump. This issue is unresolved pending completion of NRC review and analysis of licensee actions associated with the operator work around and is identified as Unresolved Item (URI) 05000389/2009-004-01, Seat Leakage of Containment Spray Valves 2 MV-07-3 and 2 MV-07-4
05000335/FIN-2009004-022009Q3Saint Lucie2B2Reactor Coolant Pump Failed Seal Injection LineOn July 8, 2009, during mid-shift operation, a Reactor Coolant System (RCS) Inventory Balance was performed and a 0.065 gpm RCS unidentified leak rate was calculated. Additionally, a Containment Atmosphere Particulate Radiation Monitor indicated an upward trend. The licensee performed a robotic inspection of containment in an attempt to identify any RCS leaks before shutting the unit down on July 13, 2009. Further investigation verified RCS pressure boundary leakage at the lower cavity piping J-groove weld of the 2B2 Reactor Coolant Pump (RCP). The licensee entered this issue into the Corrective Action Program (CAP) as CR 2009-19624. The licensees immediate corrective action included replacing seal packages to reset fatigue usage at the J-groove welds, flange removal, cutting and capping of the upper cavity lines and replacing middle cavity piping between the flange and next piping flange. To conduct repairs, the licensee entered into a higher risk Plant Operating Status (POS) of mid-loop configuration with reduced inventory. The inspectors noted that potentially similar weld failures took place in August 2007, on the 2B1 RCP pipe-to-elbow weld on the outboard side of the first flanged coupling of the 2B1 RCP seal injection 34 inch diameter line; in December 2007, on the 2B2 RCP weld connecting the 34 inch diameter seal injection line with the seal housing; and in January, 2009, on the 2B1 RCP pipe-to-flange weld on the outboard side of the first flanged coupling of the upper cavity pressure sensing line. The inspectors remained concerned whether licensee corrective actions associated with the previous weld failures were appropriate considering the repetitive failures. This issue is unresolved pending completion of NRC review and analysis of the final root cause evaluation and is identified as URI 05000389/2009004-02, Reactor Coolant Pump Failed Seal Injection Line. This LER is open
05000335/FIN-2009004-032009Q3Saint LucieFailure to take timely and effective corrective actions to prevent recurrence of EDG Day Tank level switch failures.A self-revealing Non-Cited Violation (NCV) of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, was identified for failure of the licensee to take timely and effective corrective actions to prevent recurrence of Unit 1 emergency diesel generator (EDG) day tank level switch failures following identification of Murphy switch reliability issues and issuance of NRC NCV 05000335/2009002-02. Specifically, on July 19, 2009, during functional testing of the 1B EDG day tank level switches, both the low and low-low level Murphy switches failed. The finding is more than minor because it is associated with the equipment performance attribute of the mitigating systems cornerstone. The finding was previously determined to have very low safety significance based on an SDP Phase 3 analysis. The analysis determined that the risk was less than 1E-6/year. This finding was related to the corrective action attribute of the problem identification and resolution cross-cutting area in the aspect of appropriate and timely corrective actions (IMC 0305 aspect P.1.d). (Section 4OA2.3
05000335/FIN-2010009-012010Q3Saint LucieFailure to adequately monitor performance of the 2b EDG and 1C AFW pump as required by 10 CFR 50.65The inspectors identified a non-cited violation of 10 CFR 50.65 (a)(2) for failure to demonstrate that the performance of the 2B Emergency Diesel Generator (EDG) and 1C Auxiliary Feedwater Pump (AFW) systems was effectively controlled by preventative maintenance (PM) such that these systems remained capable of performing their intended functions. The 2B EDG and the 1C AFW pump exceeded Maintenance Rule (a)(2) performance criteria since February 27 and May 30, 2010, respectively, and the goal setting and monitoring plans were not established as required by paragraph (a)(1) of the Maintenance Rule. This issue was entered into the licensees corrective action program as AR 581307. The finding was determined to be of greater than minor significance because it was associated with the Equipment Performance attribute of the Mitigating Systems Cornerstone, and adversely affected the cornerstone objective of ensuring availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. More specifically, the licensee failed to demonstrate that the performance of the 2B EDG and the 1C AFW pump was effectively controlled through appropriate PM. According to NRC Inspection Manual Chapter 0609, Attachment 4, Phase I, Initial Screening and Characterization of Findings, this finding was determined to be of very low safety significance because it did not lead to an actual loss of a safety system function or screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The cause of this finding was directly related to the cross-cutting aspect of Human Performance H.4(b) for the failure to follow the maintenance rule procedural requirements which resulted in the goal setting and monitoring plan not being established in a timely manner per 10 CFR part 50.65.
05000335/FIN-2011003-012011Q2Saint LucieFailure to Comply with Design Drawing Results in Main Steam Vent Line Failure and Subsequent TransientA self-revealing finding of very low safety significance was identified following a rapid downpower and manual reactor trip of Unit 2 on May 16, 2011. Specifically, the licensee failed to comply with an approved design drawing during installation of a one-inch vent line which resulted in a fatigue failure of the vent line. No violations of NRC requirements were identified because the location of the vent line was downstream of the main steam isolation valve and was classified as non-safety related. The licensee entered the issue into the Corrective Action Program as Action Request (AR) 1651817. The finding was more than minor because it resulted in a rapid downpower and manual reactor trip. The finding was associated with the Design Control attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as at power operations. Using NRC Inspection Manual Chapter 0609.04, Significance Determination Process (SDP) Phase 1 Initial Screening and Characterization of Findings, Table 4a for the Initiating Events Cornerstone, the finding was determined to be of very low safety significance (Green) because it was a transient initiator but did not increase the likelihood that mitigation equipment would not be available. This finding did not have a cross-cutting aspect because the performance deficiency was not indicative of current plant performance. Specifically, the performance deficiency occurred in 2005 or earlier
05000335/FIN-2012005-012012Q4Saint LucieFailure to Follow Seismic Restraining Procedures on Ladders Located Near SAFETY-RELATED EquipmentAn NRC identified non-cited violation (NCV) of Technical Specification 6.8.1, was identified which requires that written procedures be established, implemented, and maintained covering activities referenced in NRC Regulatory Guide 1.33, Revision 2, dated February 1978. The licensees procedures for seismic restraint of ladders: MA-AA- 100-1008, Station Housekeeping and Material Control; QI-13-PSL, Housekeeping and Cleanliness Controls Methods St. Lucie Plant; ADM-04.02, Industrial Safety Program; and ADM-27.11, Scaffold Control, were not implemented as written on ladders that were installed near safety-related equipment. The inspectors identified four examples of ladders not seismically restrained in accordance with the licensees procedures. During the licensees extent of condition review, 24 additional examples of ladders not in compliance with procedure requirements were identified. The licensees repeated failure to comply with procedures to seismically restrain ladders was a performance deficiency. Immediate corrective actions included completing a site-wide walk-down of the safety-related systems to identify and bring into procedural compliance any ladders that were not seismically restrained. The licensee entered this violation into the corrective action program as action request 1829233. The performance deficiency was determined to have more than minor significance because if left uncorrected, the failure to comply with station procedures to ensure adequate restraining of seismically controlled ladders, could lead to a more significant safety concern. Specifically, seismically unrestrained ladders could impact safety-related equipment during a design basis seismic event. The inspectors evaluated the risk of this finding using Manual Chapter 0609 Appendix A, Significance Determination Process for Findings At-Power, Exhibit 2- Mitigating Systems Screening questions. The inspectors determined that the finding was of very low safety significance because it did not require a quantitative assessment as determined in Exhibit 2. The finding involved the cross-cutting area of human performance, in the component of resources and the aspect of complete and accurate procedures (H.2.c) in that, the licensee failed to ensure complete, accurate, and up-to-date procedures were available for licensee personnel to ensure ladders were restrained to prevent seismic interaction with safety-related systems during a design basis seismic event.
05000335/FIN-2012005-022012Q4Saint LucieMissing Relay Cover Results in Inadvertent Emergency Diesel Generator ActuationA self-revealing, non-cited violation (NCV) of 10 CFR 50 Appendix B Criterion XVI Corrective Action was identified for failure to promptly identify and correct a missing cover on a safety-related under-voltage relay. The licensees failure to identify the missing relay cover on the 27X4 relay during the extent of condition review performed for condition report 406045 was a performance deficiency. Procedure PSL-01.05, Apparent Cause Evaluation (ACE) Handbook Section 7.6, dated July 30, 2008, provided the guidance for the required extent of condition review. The licensee added signage on the electrical cabinet door warning of the relay hazard, additional actions to determine the extent of condition and replace the relay cover is planned. The finding was determined to be more than minor because it affected the human performance attribute of the Initiating Events cornerstone and affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, without the relay cover installed, the relay was more vulnerable to actuation as a result of unintentional contact and a loss of the 1B3 vital 4 kV electrical bus occurred which required an unnecessary start and loading of the 1B EDG. The finding screened as Green because none of the attributes in the Manual Chapter 0609 Appendix G Attachment 1 Shutdown Operations Significance Determination Process Phase 1 Operational Checklist 3 were adversely impacted. The primary contributor to this conclusion was the licensees risk management controls which did not allow work in the train which was being relied upon for shutdown cooling. As a result, there was no loss of shutdown cooling for the event. There is no cross cutting aspect for the finding because the finding does not represent current licensee performance because the relay cover has been missing for several years.
05000335/FIN-2012005-032012Q4Saint LucieLicensee-Identified ViolationSt. Lucie Unit 1 Technical Specification 3.3.3.8, Accident Monitoring Instrumentation (with Table 3.3-11), requires, in part, that auxiliary feedwater flow instrumentation be operable in modes 1, 2, and 3. Action 7 of Table 3.3-11 requires inoperable auxiliary feedwater flow instrumentation to be returned to an operable condition within 72 hours or otherwise shutdown the unit to hot standby within six hours and to hot shutdown in 12 hours. Additionally, 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 May 10, 2012, the licensee did not implement adequate maintenance instructions that were appropriate to the circumstances in work order 40160852-01 to ensure that the safety-related square root extractor for auxiliary feedwater instrument FT-09-2A was wired correctly when it was installed in the plant and returned to service. As a result, FT-09-2A was inoperable from May 10, 2012, until discovery and correction of the wiring error on June 5, 2012 (27 days). The licensee entered this issue into their corrective action program as action requests 1773238 and 1828394. The failure to implement adequate work instructions in work order 40160852-01 to ensure that the square root extractor for FT-09-2A was wired correctly 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 inspectors evaluated significance of the issue using NRC Inspection Manual Chapter 0609.04, Initial Characterization of Findings; and Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process for Findings at Power, Exhibit 2. The inspectors determined the finding was of very low safety significance (Green) because the inoperable flow indication did not result in a loss of auxiliary feedwater heat removal safety function. Because this violation was of very low safety significance and was entered in the licensees corrective action program as action requests 1773238 and 1828394, this violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the NRC Enforcement Policy.
05000335/FIN-2012007-012012Q2Saint LucieFailure to Perform Preventive Maintenance on the 1B Condensate Pump Discharge Check ValveAn NRC identified finding was identified for the licensees failure to perform a preventive maintenance (PM) activity within its prescribed frequency on the 1B condensate pump discharge check valve. Consequently, the valve failed after a reactor trip and caused complications. No violations of NRC requirements were identified because the condensate pump discharge valve is non-safety related. The licensee entered this issue in the corrective action program as condition report 1755189. Corrective actions included revising the preventive maintenance procedure to initiate a condition report and require plant management approval prior to rescheduling a late PM. The finding was more than minor because it affected the equipment reliability attribute of the Initiating Events cornerstone and affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Using NRC manual Chapter 0609.04, Significant Determination Process Phase 1 screening, the finding was determined to be of very low safety significance (Green) because it was a transient initiator, but did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions will not be available. The finding involved the cross-cutting area of Human Performance with a work control aspect. Specifically, the licensee did not plan work activities to support long-term equipment reliability, and maintenance scheduling was more reactive than preventive.
05000335/FIN-2012007-022012Q2Saint LucieFailure to Correct a LPSI Pump Design DeficiencyAn NRC-identified Green NCV of 10 CFR Part 50 Appendix B, Criterion XVI, Corrective Actions was identified for the licensees failure to correct an identified condition adverse to quality associated with Low Pressure Safety Injection (LPSI) pump casing distortion. Specifically, the licensee failed to implement corrective actions to address an identified LPSI pump design deficiency, which resulted in failure of the 2A LPSI pump in March 2009. This issue was documented in the licensees corrective action program as condition report 2009-16124. This finding was more than minor because it was associated with the equipment reliability attribute of the Mitigating Cornerstone and it adversely affected the associated 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 failure to correct the LPSI pump design deficiency impacts the availability, reliability, and capability of the LPSI system to respond to plant events. In accordance with NRC Inspection Manual Chapter 0609.04, Significant Determination Process Phase 1 screening, the finding was determined to be of very low safety significance (Green) because the finding did not result in a loss of system safety function or a loss of safety function of a single train for greater than allowed Technical Specification allowed outage time. The finding did not represent an actual loss of safety function for greater than its technical specification allowed outage time. The finding had a cross-cutting aspect in the area of work practices, resources because the licensee failed to ensure that equipment is available and adequate to assure nuclear safety. Specifically, the licensee failed to maintain long term plant safety by minimizing longstanding LPSI pump design issues.
05000335/FIN-2012007-032012Q2Saint LucieFailure to Implement Timely Corrective Actions Resulted in a Plant TripA self-revealing finding was identified for the licensees failure to implement timely corrective actions. Specifically, after the overheating and failure of a Circulating Water Pump (CWP) motor resulted in an unplanned reactor down power, the licensee failed to implement timely corrective actions to monitor and trend motor stator temperatures using the installed RTDs. Consequently, a second CWP motor failed due to overheating that resulted in a reactor trip. No violations of NRC requirements were identified because the performance deficiency involved non-safely related equipment. The licensee entered this issue in the corrective action program as condition report 1697977. Corrective actions included immediately taking the motor stator RTD temperatures on both Units and using that data to monitor the CWP motors thermal performance for degradation. The finding was more than minor because it affected the equipment reliability attribute of the Initiating Events Cornerstone and affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Using NRC manual Chapter 0609.04, SDP Phase 1 screening, the finding was determined to be of very low safety significance (Green) because it was a transient initiator, but did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions will not be available. The finding involved the cross-cutting area of Problem Identification and Resolution with a corrective action program aspect. Specifically, the licensee did not take appropriate corrective actions to address safety issues and adverse trends in a timely manner, commensurate with their safety significance and complexity.
05000335/FIN-2012007-042012Q2Saint LucieFailure to Implement Vendor Technical Manual Recommendations to Inspect EDG Immersion HeatersA self-revealing potentially greater than Green AV of Technical Specification 6.8.1.a was identified for failure to establish adequate maintenance procedures associated with the emergency diesel generator (EDG) system. Specifically, station personnel failed to establish preventative maintenance inspections of diesel immersion heaters in accordance with vendor manual recommendations. As a result, the Unit 1 1A EDG was immediately rendered inoperable for 43.5 hours due to a failed immersion heater that resulted in a leak of the 1A2 EDG jacket water system. The licensee replaced the heater with an onsite spare. The finding was considered more than minor because it impacted the Reactor Safety Mitigating Systems Cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences and affected the cornerstone attribute of equipment performance. The issue was placed in the licensees corrective action program as condition report 1751214. The cause of this finding was related to the Work Control component of the Human Performance cross-cutting area due to the failure to plan work activities to ensure long term equipment availability. Specifically, maintenance scheduling was more reactive than preventative.
05000335/FIN-2012007-052012Q2Saint LucieFailure to Implement Vendor Described Preventive Maintenance on the Circulating Water Pump MotorsA self-revealing finding was identified for the licensees failure to implement vendor recommended preventive maintenance requirements to monitor and trend motor stator temperatures using the installed resistance temperature detector (RTDs) for the 1A2 Circulating Water Pump (CWP) motor. As a result of not trending 1A2 CWP motor performance, the pump was allowed to run to failure causing an unplanned reactor power transient. No violation of NRC regulatory requirements occurred. The inspectors determined that the finding did not represent a noncompliance because the performance deficiency involved non-safety related equipment. The licensee entered this issue in the corrective action program as condition report 1758355. Corrective actions included revising the circulating pump motor preventive maintenance procedure to include periodic monitoring and trending circulating water pump motor thermal performance using the installed stator Resistance Temperature Detectors (RTDs). The finding was more than minor because it affected the equipment reliability attribute of the Initiating Events cornerstone and affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Using NRC Manual Chapter 0609.04, SDP Phase 1 screening, the finding was determined to be of very low safety significance (Green) because it was a transient initiator, but did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions will not be available. The finding did not have a cross-cutting aspect because the performance deficiency was not indicative of current plant performance.
05000335/FIN-2012007-062012Q2Saint LucieLicensee-Identified ViolationTitle 10 of CFR Part 50, Appendix B Criterion XVI requires, in part, that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and non-conformances are promptly identified and corrected. Contrary to this, in 1999, the licensee documented (CR 99-1278) that the hot leg injection (HLI) methodology was not single failure proof, because a loss of an electrical bus would prevent both the primary and alternative HLI flow paths from being successful. The primary HLI injection flow path uses motor operated valves (MOVs), normally closed, fail-as-is, that are powered from train A and train B VAC buses. The alternate flow path uses solenoid operated valves that are powered by 125 VDC battery bus A and B. Valves in each HLI flow path are powered from the opposite train so that loss of electric power to train A or train B would render both flow paths inoperable. In 1999, the licensee determined that a HLI flow path could be restored by use of temporary jumpers to restore power to the MOVs affected by the loss of an electrical train. However, HLI procedures were not revised and were not fabricated at that time. In 2008, CR 2008-35069, documented that the previously identified jumpers and procedure changes were not implemented. CR 2008- 35069 developed new tracking actions for the required procedure changes and jumper fabrication. Subsequently, in 2011, the licensee identified that the procedure changes and jumper fabrication identified in the 1999 and 2008 CRs still had not been implemented. Currently the licensee has fabricated the required jumpers and procedure changes have been implemented thus restoring compliance. The inspectors determined that this finding was more than minor because it affected the Mitigating System cornerstone objective of ensuring the capability of the LPSI system to perform HLI, a required long term cooling safety function. The finding was evaluated in Phase 1 and determined to require a Phase 3 analysis due to the loss of system safety function. The condition was evaluated by a Regional SRA and determined to have very low safety significance (Green) based on the low likelihood of a large break LOCA and low likelihood of electrical failures requiring jumpers to be installed. This issue and corrective actions were documented in the licensees corrective action program as Action Request (AR) 1703137.
05000335/FIN-2013002-012013Q1Saint LucieFailure to Promptly Identify and Correct a Condition Adverse to Quality for Alignment of the SAFETY-RELATED Refueling Water Tank to a NON-SEISMIC Spent Fuel Pool Purification SystemAn NRC identified non-cited violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, was identified for the failure to promptly identify and correct a condition adverse to quality (CAQ) involving alignment of the safety-related refueling water tank (RWT) to a non-seismic spent fuel pool (SFP) purification system. Corrective actions included implementing administrative actions to preclude this alignment when the RWT is required to be operable. The finding was more than minor because it affected the configuration 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 alignment of the safety-related RWT to the nonseismic SFP purification system created a CAQ and rendered the RWT inoperable for greater than its allowed outage time. The inspectors evaluated the finding in accordance with NRC Inspection Manual Chapter 0609, Significant Determination Process, Attachment 4 and Appendix A and determined that the finding required a phase 3 evaluation by a senior reactor analyst. The analyst calculated the change in conditional core damage probability (ACCDP) due to the postulated loss of the RWT during an event, multiplied by the frequency of a seismic event that could require the use of the RWT (e.g., loss of coolant accident) and applied an exposure time factor (4 days/7 days). The dominant sequence was a steam generator tube rupture which proceeds to core damage due to a lack of high or low pressure injection water supply. The risk was mitigated by the low probability of a seismic event. The analysis determined that the risk increase of the performance deficiency was an increase in large early release frequency less than 1E-7/year which is a GREEN finding of very low safety significance. The cause of the finding involved the cross-cutting area of problem identification and resolution, the component of corrective action program, and the aspect of complete and thorough evaluation, P.1(c); because the licensee failed to properly evaluate for operability the practice of aligning a seismically qualified RWT to a non-seismic purification system.
05000335/FIN-2013002-022013Q1Saint LucieFailure to Ensure Reactor Auxiliary Building Penetrations Were Adequately Flood ProtectedAn NRC identified non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion III, Design Control, was identified for the licensees failure to ensure that all below grade Unit 1 and 2 reactor auxiliary building (RAB) penetrations were adequately sealed as required by the licensees design basis. The missing and degraded penetration seals were found during licensee inspections performed in response to a letter from the NRC to licensees, entitled Request for Information Pursuant to Title 10 of the Code of Federal Regulations 50.54(f) Regarding Recommendations 2.1, 2.3, and 9.3, of the Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident, dated March 12, 2012 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML12053A340). Corrective actions completed included restoring the degraded or missing seals to design basis requirements. The performance deficiency was determined to be more than minor because it affected the protection against external factors attribute of the mitigating system cornerstone, and affected the cornerstone objective of ensuring availability, reliability, and capability of systems that respond to initiating events. Using Manual Chapter 0609.04, Initial Characterization of Findings, Table 2, dated June 19, 2012, the finding was determined to affect an external event mitigation system and affected the mitigating system cornerstone. Although the finding existed with the units at power and during shutdown conditions since original plant construction, the risk was assessed using Manual Chapter 0609 Appendix G, Attachment 1 Shutdown Operations Significance Determination Process Phase 1 Operational Checklists for both PWRs and BWRs dated May 25, 2004 using Checklists 1 through 4. Appendix G was utilized since both units would have been shutdown prior to the probable maximum hurricane (PMH) event and associated external flood. Due to the accuracy of weather forecasting, there would be several days for the licensee to prepare for a PMH. The inspectors reviewed the finding with the regional senior reactor analyst and determined that the licensee would have adequate time to ensure that the mitigating capability of core heat removal, inventory control, emergency AC power, containment control, or reactivity control systems would have been available prior to the PMH affecting the site. The finding screened as Green because none of the attributes in the checklists were adversely impacted. No cross cutting aspects were assigned to the finding. The finding does not represent current licensee performance because the degraded and missing penetration seals have existed since original construction of the plant.
05000335/FIN-2013003-012013Q2Saint LucieFailure to Monitor Sscs Under 10 CFR 50.65(A)(1)The inspectors identified a non-cited violation associated with the licensees failure to follow the requirements of 10 CFR 50.65(a)(2), Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants. Corrective actions included the assignment of a fulltime maintenance rule coordinator to ensure the appropriate priority was assigned to maintenance rule activities, which included weekly meetings of the maintenance rule expert panel to allow evaluation of equipment failures. The performance deficiency was more than minor because it involved degraded system performance which, if left uncorrected, could become a more significant safety concern. Specifically, not addressing equipment issues under the maintenance rule could impact the reliability and unavailability of those systems, structures, and components important to safety. Using Manual Chapter 0609.04, Significance Determination Process Initial Characterization of Findings, the finding was determined to affect the Mitigating Systems Cornerstone and screened as Green because none of the logic questions under the cornerstone applied. Because the licensee had failed to utilize the corrective action program to associate and trend maintenance rule implementation issues in the aggregate to identify programmatic and common cause problems, the finding was associated with a cross-cutting aspect in the corrective action program component of the problem identification and resolution area
05000335/FIN-2013003-022013Q2Saint LucieInadequate MSIV Modification Installation and TestA self-revealing non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control was identified for the licensees failure to specify adequate modification installation and testing criteria to ensure the Unit 1 modified main steam isolation valves (MSIVs) were installed in accordance with design requirements. Corrective actions completed included restoring both MSIVs to design requirements, revising MSIV maintenance procedures, verifying the acceptability of all post-modification requirements associated with engineering changes provided by the MSIV contractor, and providing training of this event to maintenance and engineering personal. The performance deficiency was considered to be more than minor because it impacted the initiating events cornerstone objective of limiting the likelihood of events that upset plant stability and challenge critical safety functions and affected the cornerstone attribute of design control. Specifically the performance deficiency resulted in the inadvertent shutting of one MSIV and a plant trip. The performance deficiency also caused an increased probability of a loss of condenser heat sink due to a common cause failure of both MSIVs. The inspectors reviewed the finding in accordance with Inspection Manual Chapter 0609, Significance Determination Process, Attachment 4 and Appendix A and determined that the finding required a detailed risk evaluation by an NRC senior reactor analyst due to the increased probability of having a reactor trip with a loss of condenser heat sink. Using the NRC SPAR model, the analyst assumed a one year exposure period with no recovery credit. A loss of condenser heat sink was assumed with a probability of 1.0 though this would overestimate the risk significance because there was some probability the 1A MSIV would remain open during an event. The dominant sequence was a loss of condenser heat sink event where auxiliary feedwater and once-through steam generator cooling both fail. The risk was mitigated by the low probability of a common cause failure of both safety-related DC batteries. The analysis determined that the increase in risk due to the performance deficiency was a delta-core damage frequency (CDF) less than 1E-6/year, i.e., a Green finding of very low safety significance. Because the licensee failed to implement modification installation and test instructions that were adequate to ensure that the MSIVs could fully open, the finding was associated with the cross-cutting aspect of complete and accurate procedures in the resources component of the human performance area
05000335/FIN-2013003-032013Q2Saint LucieLicensee-Identified ViolationDuring plant operation in Modes 1 through 4, Unit 1 TS 3.7.7 limiting condition of operation (LCO) for the control room emergency ventilation system (CREVS) requires two air conditioning units. Unit 2 TS 3.7.7.1, LCO for the control room emergency air cleanup system (CREACS) requires two independent CREACS be operable with at least one air conditioning unit per system. Both units technical specifications allow continued operation with only one air conditioning unit operable as long as the second air conditioning unit is restored to operability within seven days. Otherwise, the unit must be placed in hot standby within the next six hours. For Modes 5 and 6 or during movement of irradiated fuel assemblies, Unit 1 TS requires that with only one air conditioning unit operable, restore at least two air conditioning units to operable status within seven days or suspend movement of irradiated fuel assemblies. Unit 2 TS requires immediate operation of the remaining operable CREACS in the recirculation mode or immediately suspend movement of irradiated fuel assemblies. Contrary to the above, since initial plant startup, design errors associated with the control circuitry for both units control room air conditioning systems resulted in plant operation with less than two operable control room air conditioning systems for greater than the time allowed by TS. If initially in service, both units swing air conditioning unit (3C) would not have automatically restarted after a postulated loss of offsite power (LOOP). Due to heat loading, the Unit 2 CREACS typically operated with only one air conditioning unit in service with another in standby. The licensee determined that the standby air conditioning unit would not have started after a LOOP no matter which train was in standby. A review of Unit 1 control room logs showed that the 3C swing CREVS was last in operation with this design error on August 22, 2012 for a period of approximately 14 days which exceeded the TS LCO. Since initial Unit 2 startup, the TS LCO was not met with just one air conditioning unit in service. The performance deficiency described above was more than minor because it was associated with the barrier performance attribute of the barrier integrity cornerstone objective and challenged the ability of the control room air conditioning systems to automatically perform their radiological barrier design function after a LOOP coincident with a design basis accident. The inspectors used IMC 0609, Attachment 4 and Appendix A and G, and determined the finding was of very low safety significance or Green, because (1) the finding only represented a degradation of the barrier function provided for the control room (Appendix A, Exhibit 3) and (2) the finding did not impact any equipment necessary to maintain the unit in a safe shutdown condition (Appendix G). This finding has been entered into the licensees CAP as AR 1796780. Additional information regarding this finding is documented in Section 4OA3.2 of this report.
05000335/FIN-2013004-012013Q3Saint LucieFailure to Request NRC Approval prior to implementation of an Alternative Repair Method for ASME Class 3 Piping in the Intake Cooling Water SystemAn NRC-identified Severity Level IV (SL-IV) non-cited violation (NCV) of 10 CFR 50.55a(a)(3) was identified for the failure to request approval from the NRC for a proposed alternative to the code requirements in Section XI of the American Society of Mechanical Engineers Boiler and Pressure Vessel Code applicable to the current Unit 1 in-service inspection interval. The licensee failed to request approval to use bolted patch plates for the permanent repair of degraded buried piping in several locations of the Unit 1 intake cooling water system prior to implementation. The licensee entered the issue in the corrective action program as AR 1809273 to address operability of the intake cooling water system and restore compliance with the applicable regulatory requirements. This performance deficiency was considered for traditional enforcement because the failure to request NRC approval prior to implementation of the repair activities impacted the NRCs ability to perform its regulatory function. This performance deficiency was determined to be a SL-IV violation in accordance with the violation examples in Section 6.1 of the NRC Enforcement Policy. Cross-cutting aspects are not assigned to traditional enforcement violations.
05000335/FIN-2013004-022013Q3Saint LuciePartial Loss of Offsite Power due to Non-segregated Bus FailureA self-revealing finding was identified for the licensees failure to establish adequate preventive maintenance (PM) activities for both units startup transformers (SUTs) 6.9kV non-segregated bus runs in accordance with site PM program requirements. As a result, external corrosion of the 2B SUT 6.9kV non-segregated bus run duct was allowed to degrade until a duct vent screen collapsed onto the energized bus causing a partial loss of offsite power to both units. This issue was placed in the licensees corrective action program as action request 1809273. Corrective actions included: repair of the corroded non-segregated bus duct vent associated with this event, updating the preventative maintenance program to address periodic maintenance of non-segregated bus duct vents, and completing inspections and repairs, as necessary, of both units outdoor bus duct vents for bus runs to the SUTs and auxiliary transformers. The performance deficiency was considered to be more than minor because it was associated with the equipment reliability attribute of the initiating events cornerstone and adversely affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, since 2003 when PM activities were established for SUTs (including 4.16kV non-segregated bus runs), the licensee failed to establish those same activities for both units SUT 6.9kV non-segregated bus runs. As a result, external corrosion of the 2B SUT 6.9kV non-segregated bus duct was allowed to degrade until a duct vent screen collapsed onto the energized bus causing a partial loss of offsite power to both units. The inspectors reviewed the finding in accordance with Inspection Manual Chapter 0609, Significance Determination Process, Attachment 4, Appendix A and Appendix G. Appendix A, The Significance Determination Process (SDP) for Findings At-Power, was used for both units because Unit 1 was operating and the failure could have reasonably occurred with Unit 2 operating prior to the fall 2012 outage. Appendix G, Shutdown Operations Significance Determination Process, was used for the time Unit 2 was in the 2012 outage. Appendix G required a detailed risk evaluation because the finding increased the likelihood of a loss of offsite power. A Senior Reactor Analyst subsequently performed an analysis of the risk impacts to both units while at-power and while the unit was shut down. The analyst determined that the risk significance of the issue was very low (i.e., Green). The dominant accident sequence was a Loss of Offsite Power during a shutdown condition, specifically when the RCS is vented such that: 1) the steam generators cannot sustain core heat removal, and 2) a sufficient vent path exists for feed and bleed. The remaining mitigation of such an accident was comprised of the Unit 2 EDGs and recovery of power from the opposite unit. The inspectors concluded that this finding did not have a cross-cutting aspect as this was not representative of present licensee performance.
05000335/FIN-2013004-032013Q3Saint LucieEmergency Diesel Generator Inoperable for a Period Greater Than the Allowed Outage TimeA self-revealing non-cited violation of Technical Specification (TS) 3.8.1.1.b was identified due to the licensee operating with an inoperable emergency diesel generator (EDG) for longer than the allowed outage time (AOT) of 14 days without taking the required TS actions. Specifically, during a relay replacement, the licensee installed a diode with a lead that had an un-insulated butt splice. This un-insulated butt splice caused an electrical short circuit resulting in a blown fuse in the 2A EDG start circuitry and was the cause of the EDG failing to start on March 13, and again on June 10, 2013. Consequently, the licensee operated with an inoperable EDG for a period longer than the AOT. Immediate corrective actions included insulating the diode butt splice to prevent a repeat electrical short. The relay assembly was subsequently replaced and a new diode that did not have a butt splice was installed. The issue was entered into the licensees corrective action program as action request 1880888. The performance deficiency was more than minor because it was associated with equipment performance attribute of the mitigating systems cornerstone and adversely affected the objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. 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 for Findings At-Power, Exhibit 2 Mitigating Systems Screening Questions, was used to further evaluate this finding. The finding required a detailed risk evaluation by an NRC senior reactor analyst due to an actual loss of function of at least a single Train for greater than its TS AOT. The analyst determined that the risk significance of the issue was very low (i.e., Green). The dominant accident sequence was a loss of offsite power followed by a series of electrical failures leading to station blackout and ultimately a reactor coolant pump seal loss of coolant accident and core damage. The remaining mitigation of such an accident was comprised of the Unit 1 EDGs and recovery of power from the opposite unit. This finding was associated with a cross cutting aspect in the resources component of the human performance area because the licensee had not provided complete, accurate, and up-to-date procedures and work packages to ensure that the EDG wiring butt splice was insulated in accordance with plant specifications during maintenance activities in May 2008 and again in September 2012 (H.2(c)).
05000335/FIN-2013004-042013Q3Saint LucieLicensee-Identified ViolationDuring plant operation in Modes 1 through 4, Unit 2 TS 3.6.3 limiting condition of operation (LCO) for containment isolation valves (CIVs) requires that CIVs shall be operable. The technical specification 3.6.3 action statement specifies with one or more containment isolation valve(s) inoperable, maintain at least one isolation valve operable in each affected penetration that is open and either: 1) Restore the inoperable valve to operable status within four hours; 2) isolate each affected penetration within four hours by use of at least one deactivated automatic valve secured in the isolation position; 3) isolate each affected penetration within four hours by use of at least closed manual valve or blind flange; or 4) be in hot standby within the next six hours and cold shutdown within the following 30 hours. Contrary to the above, on June 2, 2013, when a CIV associated with the 2A hydrogen analyzer became inoperable, the TS required actions above were not met until the CIV was de-energized approximately 13 hours later. The TS was violated when the unit was not placed in hot standby within ten hours of finding the CIV inoperable. The inspectors evaluated the finding using IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, (June 19, 2012). The inspectors used Exhibit 3 Barrier Integrity Screening Questions, for the reactor containment. The finding screened as very low safety significance (Green) because there was no actual open pathway in the physical integrity of reactor containment, containment isolation system, or heat removal components; and there was no impact on the hydrogen control function in containment. This finding has been entered into the licensees corrective action program as AR 1878888. Additional information regarding this finding can be found in Section 4OA3.1 of this report.
05000335/FIN-2013005-012013Q4Saint LucieFailure to Use Only NIOSH Certified Respiratory Protection EquipmentA self-revealing non-cited violation (NCV) of 10 CFR Part 20.1703(a) was identified for the use of respiratory protection equipment that had not been certified as safe by the National Institute for Occupational Safety and Health (NIOSH). The licensees use of respiratory protection equipment in a radiologically controlled area that had not been tested and certified by NIOSH or that had not obtained prior authorization from the NRC to use respiratory equipment not certified by NIOSH was a performance deficiency. The licensee discontinued use of the respiratory protection equipment and the issue was entered into the licensees corrective action program under action request (AR) 1719479. The finding was more than minor because it was associated with the Occupational Radiation Safety cornerstone attribute of Equipment and Instrumentation and adversely affected the cornerstone objective of protecting worker health and safety from exposure to radiation. When using non-NIOSH approved respirators in a radiologically controlled area, the potential existed to put workers in a situation that may be more hazardous than the radiological dangers that the respirator is meant to protect against (e.g. loss of air flow). The finding was determined to be of very low safety significance (Green) because it was not related to As Low As Reasonably Achievable (ALARA) planning, there was no overexposure nor potential for overexposure, and the licensees ability to assess dose was not compromised. A cross cutting aspect was not assigned because the performance characteristic was corrected and eliminated before the inspectors identified the issue and is therefore not reflective of present licensee performance.
05000335/FIN-2013005-022013Q4Saint LucieFailure to Identify and Implement Appropriate Corrective Actions for AFW System CorrosionThe inspectors identified a non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action. Specifically, the licensee failed to identify localized corrosion on the discharge piping for the 1C auxiliary feedwater pump that exceeded the licensees acceptance criteria for minimum pipe wall thickness. The licensee entered the issue into the corrective action program (CAP) as action request (AR) 1913575. Corrective actions included replacing the degraded sections of pipe and conducting analyses to verify past operability of the degraded piping. The performance deficiency was more than minor because if left uncorrected, it had the potential to lead to a more significant safety concern. Specifically, unmitigated corrosion of the AFW piping could result in through-wall leaks, affect structural integrity of the piping, and ultimately result in inoperability of the system. Using Table 2 of Manual Chapter 0609.04, Significance Determination Process (SDP) Initial Characterization of Findings dated June 19, 2012; the inspectors concluded the finding affected the mitigating systems cornerstone. The inspectors evaluated the finding using IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, Exhibit 2, dated June 19, 2012. The finding was determined to be of very low safety significance (Green) since the AFW system remained operable and was able to perform its function. The inspectors determined the cause of this finding was associated with a cross cutting aspect of minimizing longstanding equipment issues in the resources component of the human performance area. Specifically, the licensee had not provided adequate resources to address longstanding Unit 1 AFW system corrosion issues (H.2(a)).
05000335/FIN-2014002-022014Q1Saint LucieEvaluation of January 9, 2014 RAB FloodingThe inspectors identified an unresolved item concerning external flood water entering the RAB through conduits that did not have internal flood seals installed. On January 9, 2014, during a heavy rainfall event, the sites storm drain system reached capacity due to a partially blocked culvert. As a result, the storm water entered the Unit 1 component cooling water (CCW) area and then overflowed into the emergency core cooling system (ECCS) tunnel located adjacent to the reactor auxiliary building. The water entered two corroded electrical conduits in the tunnel and flowed into the Unit 1 reactor auxiliary building (RAB) -0.5 foot elevation. The licensee cycled drain valves to transfer the water to the ECCS room sump (RAB -10 foot elevation) and pumped the water to an internal storage tank. No safety-related equipment was affected as a result of the water intrusion into the RAB. Six conduits at RAB penetration P19, including the two degraded conduits that allowed water entry into the -0.5 foot elevation, were found not to have internal flood seals installed. A few days after the event, the licensee installed flood seals in the six non-safety-related conduits that penetrated the RAB at penetration P19. Additionally, the licensee initiated a root cause evaluation to determine the cause of the missing conduit flood seals. The issue is an unresolved item pending completion of the inspectors review of the licensees evaluation associated with this event (URI 05000335/2014002-02, Evaluation of January 9, 2014 RAB Flooding).
05000335/FIN-2014002-042014Q1Saint LucieLatent MV-08-03 Contactor Failure Results in Operation Prohibited by Tech SpecsOn December 20, 2013, the 1C AFW pump was declared inoperable in order to perform planned maintenance on the pumps trip and throttle valve (MV-08-03). After completion of the maintenance, MV-08-03 failed to open during post maintenance testing. The valve failed due to a stuck open contact in the auxiliary switch for the valves motor line contactor. The failure was unrelated to the valve maintenance. The licensee determined that the auxiliary switch contact failed to return to its standby position following the last successful operation of the valve on December 17, 2013. The licensee concluded that rubbing between the switch operating mechanism and the switch housing had degraded the operation of the auxiliary contact. The licensee properly installed and tested the switch in November 2013. The cause of the contact failure on December 20, 2013, had not previously been recognized as a failure mode for this type of switch. Additionally, there were no symptoms available to operators to indicate the contact had failed to return to its normal standby position. The inspectors concluded that there was no performance deficiency associated with the switch failure. The inspectors utilized available risk-informed tools to assess the safety significance of the 1C AFW pump inoperability. Based on the short amount of time that the 1C AFW pump was inoperable, the inspectors concluded this event was of very low safety significance. St. Lucie Unit 1 TS limiting condition for operation 3.7.1.2, Auxiliary Feedwater System, required at least three independent, operable AFW pumps in plant operating modes one through three. With one AFW pump inoperable, the inoperable pump must be returned to operable status within 72 hours or Unit 1 placed in hot standby within the next twelve hours. Contrary to the above, Unit 1 operated for 98 hours from December 17, 2013, until December 20, 2013, with the 1C AFW pump inoperable due to a failed auxiliary contact for the trip and throttle valve. Although a violation of 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 3.7.1.2 violation was not associated with a licensee performance deficiency. The inspectors concluded that the violation would normally be characterized as Severity Level IV based on its very low safety significance. The NRC exercised enforcement discretion (Enforcement Action (EA)-14-047) in accordance with Section 2.2.4.d of the Enforcement Policy because the violation was not associated with a licensee performance deficiency; and 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 1929130. Licensee corrective actions included: 1) installing and testing a new MV-08-03 auxiliary switch, 2) revision of AFW operating procedures to visually inspect the position of all auxiliary contactor switches of the same type following operation of the AFW system; and 3) modifying the contactor preventative maintenance procedure to check for binding of the switch and to verify tightness of the switch housing to prevent any misalignment between the switch and its housing. This LER is closed.
05000335/FIN-2014003-012014Q2Saint LucieFailure to Follow the Nuclear Design Control Procedure for Auxiliary Feedwater ValvesA self-revealing, non-cited violation (NCV) of Technical Specification (TS) 6.8.1, was identified which requires that written procedures be established, implemented, and maintained covering activities referenced in NRC Regulatory Guide 1.33, Revision 2, dated February 1978, including safety-related activities carried out during operation of the reactor plant. The licensee failed to comply with Quality Instruction ENG-QI 1.0, Nuclear Engineering Design Control, when an unauthorized modification was implemented during maintenance on two auxiliary feedwater (AFW) valves. Consequently, the unauthorized modification was the direct cause of the failure of one of the valve stems. Corrective actions included the proper installation of new stems in the valves. The licensees failure to comply with Quality Instruction ENG-QI 1.0, Nuclear Engineering Design Control, and modifying the AFW valve and plug assembly by drilling and pinning at a different location than what was specified on the maintenance assembly procedure was a performance deficiency. The performance deficiency was determined to have more than minor significance because if left uncorrected, the failure to comply with the engineering design control procedure to ensure adequate assembly of AFW valves could lead to a more significant safety concern. Specifically, failure of an AFW pump discharge valve could result in an inadequate steam generator heat sink during a design basis accident. Using Manual Chapter 0609.04, Significance Determination Process (SDP) Initial Characterization of Findings, Table 2, dated June 19, 2012, the finding was determined to affect the Mitigating Systems Cornerstone. The finding occurred while the Unit was at power. Manual Chapter 0609 Appendix A, Significance Determination 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 none of the logic questions under the cornerstone applied. The finding involved the cross-cutting area of Human Performance, in the aspect of Conservative Bias (H.14), in that, the licensee did not make a conservative decision to stop work when the maintenance procedure did not address installation of a used valve stem. Instead the licensee chose to move forward with the maintenance because the procedure did not specifically prohibit installation of a used stem.
05000335/FIN-2014004-022014Q3Saint LucieFailure to Establish a Reasonable Maintenance Effectiveness Demonstration for the ECCS Floor Drain Valve SystemAn 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-2014009-022014Q3Saint LucieInaccurate Information Concerning Flooding AnalysisThe 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.
05000335/FIN-2015001-012015Q1Saint LucieInadequate Risk Assessments on the Emergency Core Cooling SystemThe 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-2015001-022015Q1Saint LucieProcedural Non Compliances Relating To Temporarily Installed Ladders Located Near Safetyrelated SSCsThe 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-2015002-012015Q2Saint LucieFailure to Assess Potential Gaseous Effluents Released from Containment Equipment Hatch Openings during a Loss of Negative PressureThe 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.
05000335/FIN-2015002-042015Q2Saint LucieLicensee-Identified ViolationThe 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.
05000335/FIN-2015003-012015Q3Saint LucieUnsecured Utility Cart With An Unrestrained Operating Pedestal Fan Near Safety-related ECCS EquipmentAn 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-2015003-022015Q3Saint LuciePartial Loss of Unit 1 and Unit 2 Offsite Power Due to Unit 2 6.9 kV Non-Segregated Bus FaultThe 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.
05000335/FIN-2015003-042015Q3Saint LucieFailure to Follow Reactor Protection System Surveillance Procedure Resulting in Reactor Plant TripA 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-2015003-052015Q3Saint LucieUnit 2 Shutdown Due to Through Wall Crack and Leak in the 2B2 Safety Injection Tank Discharge PipeOn 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-2015004-012015Q4Saint LucieNRC Biennial Written Examinations Did Not Meet Qualitative StandardsAn 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-2015004-022015Q4Saint LucieNon-willful Compromise of a Remedial Examination Required by 10 CFR 55.59 Affected the Equitable and Consistent Administration of the ExamAn 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-2015004-032015Q4Saint LucieInadequate Corrective Actions to Prevent Fouling of the CCW HXsAn 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-2015004-042015Q4Saint LucieProcedural Non-compliances Relating to Installed Scaffold Located Near Safety-related SSCsAn 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-2015004-052015Q4Saint LucieFailure to Verify the Adequacy of the Unit 1 and Unit 2 Steam Generator Tube-to-Tubesheet Welds DesignAn 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-2015004-062015Q4Saint LucieLicensee-Identified Violation10 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-2015004-072015Q4Saint LucieLicensee-Identified ViolationContrary 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-2015007-032015Q1Saint LucieAdequacy of 10 CFR 50.59 Screening Performed for Unit 1 SGBD Maximum Flow Evaluation TestAn 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.
05000335/FIN-2016001-042016Q1Saint LucieLicensee-Identified ViolationLicensee Identified Violation (LIV) - T.S.6.8.1 requires written procedures be established, implemented, and maintained covering applicable procedures recommended in Appendix A 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.
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