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05000313/FIN-2018003-06Arkansas Nuclear2018Q3Reactor Power Transient Caused by the Turbine Bypass Valve Failing OpenThe inspectors reviewed a self-revealed Green finding and associated non-cited violation of Arkansas Nuclear One, Unit 1, Technical Specifications 5.4.1.a, for the licensees failure to properly preplan maintenance that can affect the performance of safety-related equipment. Specifically, the licensee failed to properly pre-plan maintenance for the replacement of air supply tubing for turbine bypass valve CV-6687, which resulted in the failure of the air tubing, causing valve CV-6687 to fail open, which led to a manual reactor trip and a subsequent loss of the main condenser.
05000461/FIN-2017012-03Clinton2017Q4Evaluation of RCE 04082490, Reactor Scram from Trip of 1AP07EJ)Inspection Scope The inspectors held discussions with licensee personnel, reviewed the response of equipment and operations personnel, and reviewed historical corrective action program and maintenance related documents to evaluate whether a higher level of NRC response was needed to review this event. b. Discussion The inspectors did not identify any circumstances of the event that warranted escalation of the inspection to an Augmented Inspection Team. The event itself followed the anticipated sequence according to accident analysis and with a few non-consequential exceptions, plant equipment functioned as designed. While performing the preliminary risk analysis for the MD 8.3 Evaluation to determine the risk criteria, the Senior Reactor Analyst modeled the transient as a Loss of Condenser Heat Sink initiating event due to the manual reactor scram and closure of the inboard MSIVs. Direction to use the steam line drains to maintain the condenser as a heat sink when the MSIVs are closed was contained in site procedures. Procedure CPS (Clinton Power Station) EOP1; RPV Control, listed MSL drains as one of the systems to be used to control RPV pressure and cooldown rate. Procedure CPS 4100.01; Reactor Scram, directed the operator to use an appropriate cooldown method listed in CPS 9000.06, Unit Shutdown. In CPS 9000.06 Section 8.8, Cooldown With Main Condenser, MSL drain valves were one method listed and included a statement that it was OK to shut MSIVs when using this method. In this scenario, the control room supervisor stated that he considered using RCIC for pressure control, but determined that he did not need to because the 13 main condenser remained available and he was able to control the pressure/cooldown rate using the MSL drains to the main condenser. When the final MSIV closed and pressure started to rise, the crew started RCIC in the pressure control mode. The operating crew then continued to cooldown the reactor to Mode 4. The inspectors identified a concern that evaluation of the generic implications of the transformer failure could only be completed when the root cause of the transformer failure was known. Determination of the actual cause of the transformer failure to ground required an inspection of the damaged transformer at the ABB facility. The dry type transformer was built in 1980 and the design worst-case loading was 40 percent of the transformer rating. This type transformer was used in 29 480 VAC substations in the plant (only 5 of the 29 are safety-related). The safety-related transformers are inspected and megger tested at an 8 year frequency aligned with the safety-related bus outage schedule. The non-safety dry type transformers are inspected and megger tested at an 8 year frequency (some have been extended to 16 years based on performance). No degraded condition was found during the past preventative maintenance activities on the dry type transformers. However, operators at Clinton identified noises coming from one of the non-safety related dry type transformers in 2015. The transformer was removed from service and replaced. The transformer vendors evaluation identified degraded insulating material as the cause for the noise. Pending additional information from the inspection of the December 2017 transformer failure and the associated root cause investigation, the extent of condition and related activities were determined to be acceptable. c. Findings No findings were identified. During the review of the reactor scram and transformer failure that occurred on December 9, 2017, inspectors concluded that sufficient information was not available to identify generic implications or potential performance deficiencies with the design, manufacture or maintenance of the dry-type transformers pending completion of the licensees root cause analysis to be documented in RCE 04082490, Reactor Scram from Trip of 1AP07EJ. This issue is an unresolved item (URI) pending NRC evaluation of the additional information being developed by the licensee. (URI 05000461/201701203: Evaluation of RCE 04082490, Reactor Scram from Trip of 1AP07EJ)
05000219/FIN-2017003-01Oyster Creek2017Q3Inadequate Augmented Offgas System Procedure Resulted in a Manual ScramA self -revealing NCV of Technical Specification 6.8.1, Procedures and Programs, was identified because Exelon did not adequately establish and maintain the augmented offgas (AOG) system operation procedure as required by NRC Regulatory Guide 1.33, Quality Assurance Requirements (Operation), Appendix A, Section 7, Procedures for Control of Radioactivity. Specifically, Exelon procedure 350.1, Augmented Offgas System Operation, did not include adequate guidance for placing the AOG system into a recycle or shutdown configuration following a system trip. Without this guidance, Operations personnel failed to ensure the correct configuration of the AOG system following a partial trip of the system which resulted in degraded main condenser vacuum and a subsequent manual reactor scram on July 3, 2017. This issue was entered into the corrective action program as issue report 4028402. The corrective actions included placing the AOG system in the correct configuration and revising the AOG system operation procedure to provide guidance for verifying proper alignment of the AOG system when the system is in recycle or shutdown. The inspectors determined the performance deficiency was more than minor because it was associated with the Initiating Events cornerstone attribute of Procedure Quality 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. Specifically, the failure to establish an adequate procedure for verifying proper alignment of the AOG system following a full or partial trip of the system resulted in the AOG inlet valve being left in the open position, which allowed demineralized water to be siphoned from the flame arrestor tank and slowly fill the offgas hold- up pipe. This caused a degradation of main condenser vacuum and resulted in operators inserting a manual reactor scram on July 3, 2017. The inspectors evaluated the finding using IMC 0609, Attachment 4, Initial Screening and Characterization of Findings, and IMC 0609, Appendix A, Exhibit 1, Initiating Event Screening Questions. The inspectors determined the finding was a transient initiator that did not contribute to both the likelihood of a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of a trip to a stable shutdown condition, and therefore was of very low safety significance (Green). The finding had a cross- cutting aspect in the area of Human Performance, Avoid Complacency , because Exelon failed to recognize and plan for the possibility of mistakes or latent errors and implement appropriate error reduction tools by verifying the AOG system was properly aligned following a system trip ; instead , Operations personnel relied upon using a procedure that did not contain adequate guidance to place the AOG system in the correct configuration following a system trip (H. 12)
05000316/FIN-2016004-02Cook2016Q4Moisture Separator Reheater RuptureGreen. A self-revealed finding of very low safety significance (Green), occurred on July 6, 2016, when a portion of the Unit 2 Right Moisture Separator Reheater (MSR) B bellows assembly ruptured, causing a steam leak which damaged the adjacent turbine building wall. There were no associated violations of regulatory requirements since the piping was non-safety-related. Reacting to the rupture, operators tripped the reactor and isolated the leak by shutting the Main Steam Isolation Valves. While addressing a number of issues with the MSRs that occurred following a re-design of the internals in 2010, the licensee changed the design of the rods that hold the bellows assembly on each MSR pipe together. The design change called for tack welds to only be used on the end nuts of the rod. Contrary to the design change (EC51875), tack welds were placed on other nuts as well. The tack welds were determined to have changed the material properties of the rod in the vicinity of the welds, which caused cracking to initiate during operation. Eventually, the cracks grew to a point where two rods completely severed, causing the bellows to tear and rupture. Following the safe shutdown, the licensee repaired the bellows, inspected other rods, and restarted the plant. The issue was entered into their Corrective Action Program (CAP) as Action Request (AR)20167865. The issue was more than minor because it adversely affected the Design Control Attribute of the Initiating Events cornerstone because it resulted in a reactor trip and Unusual Event. Per the Significance Determination Process, a detailed risk evaluation was required because during the rupture operators had to close the Main Steam Isolation Valves, which isolated the main condenser (the preferred post-trip decay heat removal path). An NRC Regional Senior Reactor Analyst performed the evaluation and concluded the finding was of very low risk significance (Green). The inspectors determined the finding had an associated cross-cutting aspect in the Human Performance Area, specifically, H.12, Avoid Complacency. Specifically, site personnel did not plan for the possibility of mistakes, latent issues, and inherent risk, even while expecting successful outcomes.
05000277/FIN-2016002-03Peach Bottom2016Q2Human Performance Event Results in Emergent DownpowerA self-revealing finding of very low safety significance (Green) was identified for the failure of Exelon operators to use human performance error reduction tools during equipment manipulation in accordance with HU-AA-101, Human Performance Tools and Verification Practices. Specifically, on March 28, 2016, an equipment operator failed to use self-check (STAR) while removing a circuit breaker from service and incorrectly tripped the E-124 480 volt supply breaker which required a rapid manual power reduction to 80 percent rated thermal power (RTP) due to lowering main condenser vacuum and a partial loss of feedwater heating. Exelon entered the issue into their corrective action program (CAP) under issue report (IR) 2646772 and performed a root cause which identified corrective actions to address the adverse human performance behaviors at the station. The finding was more than minor because it was associated with 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, an equipment operator failed to adequately use human performance error reduction tools and opened an incorrect breaker which required a rapid downpower. The inspectors evaluated the finding in accordance with Exhibit 1 of IMC 0609, Appendix A, The SDP for Findings At-Power, dated June 19, 2012, and determined the finding was of very low safety significance (Green) because it did not result in a reactor trip and the loss of mitigation equipment relied upon for transition to a stable shutdown condition. This finding was determined to have a cross-cutting aspect in the area of Human Performance, Field Presence, because Exelon did not ensure that deviations from standards and expectations, which were identified by leaders, were corrected promptly. Specifically, Exelon identified that adverse human performance behaviors existed with certain equipment operators, however, those observations were not appropriately input into their performance management system, such that the behaviors could be addressed. Thus, these adverse behaviors were a primary contributor to this human performance error.
05000346/FIN-2016001-04Davis Besse2016Q1Less than Sufficient Work Package Documentation and Instructions Resulted in an Inadequate Part Being Installed into the Plants Integrated Control SystemA self-revealed finding of very low safety significance (Green) was identified for the licensees failure to include an adequate bench check for a replacement integrated control system (ICS) module that was installed into the system during the plants 2014 refueling outage (RFO) into the work package instructions for that activity. Specifically, a defeat switch on the replacement Module 528 for the ICS rapid feedwater reduction (RFR) circuit installed as preventative maintenance during the plants 18th RFO was incorrectly wired and not detected during pre-installation checks. The incorrectly wired module prevented the ICS RFR function from occurring during the unit trip on January 29, 2016, which contributed to the Steam Generator (SG) No. 1 high level condition and the resultant steam and feedwater rupture control system (SFRCS) actuation. This issue was entered into the licensees CAP. Corrective actions taken by the licensee included replacement of ICS Module 528 with a spare properly configured for the RFR defeat switch function. Additionally, a proper data package to enable bench checking ICS Module 528 to verify the capability of the module to perform its intended function was created. The licensee also created training and lessons learned from this event. This finding was of more than minor safety significance because it affected the design control and procedure quality attributes of the Mitigating Systems cornerstone of reactor safety, and adversely impacted the cornerstone objective of ensuring the availability, reliability, and capability of the units main feedwater (MFW) system and main condenser for decay heat removal. The finding was determined to be of very low safety significance because it did not represent a deficiency affecting the design or qualification of a mitigating system, structure, or component (SSC); it did not, in and of itself, represent a loss of system and/or function; it did not represent 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 being out-of-service for greater than their TS allowed outage times; and it did not represent an actual loss of function of one or more non-TS trains of equipment designated as high safety significant in accordance with the licensees maintenance rule program. The inspectors determined that the finding had a cross-cutting aspect in the area of human performance. The inspectors assigned the cross-cutting aspect of Documentation to the finding because the licensee had failed to ensure that the instructions and other work package guidance available to maintenance personnel performing the ICS Module 528 replacement had contained provisions for an adequate bench check of the module prior to its installation.
05000346/FIN-2016001-06Davis Besse2016Q1Less than Adequate Procedural Instructions for Restoring Main Feedwater Following a Reactor TripA self-revealed finding of very low safety significance (Green), and an associated NCV of TS 5.4.1(a) were identified for the licensees failure to establish and implement adequate procedural guidance for restoring MFW following a reactor trip. Specifically, the guidance in licensee procedure DBOP06910, Trip Recovery Procedure, for restoring MFW to the SGs using the motor-driven feedwater pump (MDFP) did not ensure that the MFW piping had been sufficiently re-pressurized prior to opening the MFW to SG isolation valves. This lack of satisfactory procedural guidance allowed control room operators to prematurely open the MFW to SG No. 1 isolation valve, which resulted in a SFRCS actuation on the reverse delta pressure (P) function. This issue was entered into the licensees CAP. Corrective actions planned by the licensee included changes to licensee procedure DBOP06910, Trip Recovery Procedure, to ensure that MFW header pressure is greater that SG pressure prior to opening the MFW to SG isolation valves. This finding was of more than minor safety significance because it affected the design control and procedure quality attributes of the Mitigating Systems cornerstone of reactor safety, and adversely impacted the cornerstone objective of ensuring the availability, reliability, and capability of the units MFW system and main condenser for decay heat removal. The finding was determined to be of very low safety significance based on the results of a detailed risk evaluation conducted by the NRC Region III Senior Reactor Analyst (SRA). The inspectors determined that the finding had a cross-cutting aspect in the area of human performance. The inspectors assigned the cross-cutting aspect of Resources to the finding because the licensee had failed to ensure that the procedural instructions and guidance available to plant operators restoring MFW during reactor trip recovery actions took into account all relevant technical details (e.g., the differences between MFW piping runs, the amount of time needed to re-pressurize MFW piping, etc.)
05000346/FIN-2016001-05Davis Besse2016Q1Lack of Software Change Controls and Inadequate Corrective Action for an Operator Workaround Contributes to Complications Experienced During a Reactor TripA self-revealed finding of very low safety significance (Green) was identified for the licensees failure to implement a technically correct software change associated with the SG / Reactor Demand ICS control station. Specifically, a known logic error within the plants ICS would cause the SG / Reactor Demand control station to trip to manual from automatic coincident with a reactor trip. The licensee had instituted compensatory operator actions for this condition, but removed these actions in December 2015 when they implemented a software change to rectify the problem. However, the corrective actions were inadequate and the SG / Reactor Demand ICS control station unexpectedly tripped to manual from automatic when the unit tripped on January 29, 2016. The unexpected control station mode of operation change, combined with the absence of any compensatory operator actions, contributed to the SG No. 1 high level condition and the resultant SFRCS actuation. This issue was entered into the licensees CAP. Corrective actions taken by the licensee included initiating work on a new software change to rectify the issue of the SG / Reactor Demand ICS control station tripping from automatic to manual coincident with a reactor trip; reestablishing the operator workaround and associated compensatory actions for control room operators; and revising applicable procedures to incorporate current industry standards for controlling software life cycle changes to certain categories of software that interface with plant systems. This finding was of more than minor safety significance because it affected the design control and procedure quality attributes of the Mitigating Systems cornerstone of reactor safety and adversely impacted the cornerstone objective of ensuring the availability, reliability, and capability of the units MFW system and main condenser for decay heat removal. The finding was determined to be of very low safety significance because it did not represent a deficiency affecting the design or qualification of a mitigating SSC; it did not, in and of itself, represent a loss of system and/or function; it did not represent an actual loss of function of at least a single train for greater than its TS allowed outage time, or two separate safety systems being out-of-service for greater than their TS allowed outage times; and it did not represent an actual loss of function of one or more non-TS trains of equipment designated as high safety significant in accordance with the licensees maintenance rule program. The inspectors determined that the finding had a cross-cutting aspect in the area of problem identification and resolution. The inspectors assigned the cross-cutting aspect of Evaluation to the finding because the licensee had failed to thoroughly evaluate the issue of the SG / Reactor Demand ICS control station unexpectedly tripping from automatic to manual to ensure that the software change intended to resolve the issue actually addressed its cause.
05000346/FIN-2015003-01Davis Besse2015Q3Flow Accelerated Corrosion Model Not Maintained In Accordance with Industry Standards and GuidanceA self-revealed finding of very low safety significance was identified for the licensees failure to maintain an adequate flow accelerated corrosion (FAC) program in accordance with station procedures and applicable industry guidance. Specifically, an incorrect restriction orifice size entered into the FAC program software in the late 1980s significantly underestimated the wear rate of a section of moisture separator reheater (MSR) piping that ultimately failed causing control room operators to conduct a rapid power reduction and manual reactor trip and declare an unusual event in accordance with the station's emergency plan. The failed section of piping had not been previously inspected in accordance with industry guidance and station procedures, and the incorrect FAC program software inputs had never been validated. This finding was associated with the Initiating Events Cornerstone of reactor safety and was of more than minor significance because it directly impacted 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. The inspectors evaluated the finding using IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power. Using Exhibit 1, which contains the screening questions for the Initiating Events Cornerstone of Reactor Safety, the inspectors determined a detailed risk evaluation was required because the finding was a transient initiator that resulted in both a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition (i.e., the loss of the main condenser as a heat sink and the loss of main feedwater). The inspectors contacted the NRC Region III Senior Reactor Analyst (SRA) to perform a detailed risk evaluation. The assumed core damage sequence used by the SRA was that the MSR pipe break occurs, followed by either main steam isolation valve (MSIV) failing to close, followed by any of four in-series main turbine stop valves (SVs) and control valves (CVs) failing to close. Mathematically, the change in core damage frequency (CDF) was estimated at: CDF = 1 (event occurs) x (9.51E-4 + 9.51E-4) x 4 x 1.5E-3 x 1.5E-3 = 1.71E-8/yr The SRA concluded the risk associated with this performance deficiency was, therefore, of very low safety significance (Green). Because the causes for the finding stemmed from deficiencies going back several years or more, the inspectors concluded that the finding represented a latent issue not necessarily indicative of present licensee performance. As a result, no cross cutting aspect was assigned to this finding.
05000293/FIN-2015010-01Pilgrim2015Q3Inadequate Procedures for Placing Main Turbine in ServiceThe inspectors identified a self-revealing Green non-cited violation of Technical Specification 5.4.1, Procedures, because Entergy did not provide adequate procedures in that appropriate operator actions to recover systems and components important to safety were not included within operating procedures 2.1.1, Startup from Shutdown, and 2.2.93, Main Condenser Vacuum System, as well as abnormal operating procedure 2.4.36, Decreasing Condenser Vacuum. Corrective actions include, in part, for Entergy engineers to establish operational limits for the offgas system, to include the factors of reactor power, air in-leakage, sea water system alignment, status of the augmented offgas system, status of the main turbine, and sea water inlet temperature, and to incorporate these limitations into site procedures. Entergy entered this issue into their corrective action program as condition report CR-PNP-2015-5197. This finding was more than minor because it was associated with the procedure quality attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Additionally, this performance deficiency is similar to example 4.b in IMC 0612, Appendix E, Examples of Minor Issues, in that it contributed to a reactor trip. The inspectors evaluated the finding using IMC 0609, Appendix A, Exhibit 1, Initiating Events Screening Questions. The inspectors determined this finding was of very low safety significance (Green) because it did not cause a loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. This finding had a cross-cutting aspect in the area of Human Performance, Design Margins, because Entergy did not operate equipment within design margins. Specifically, Entergy staffs lack of awareness of the limitations of offgas system during startup and while placing the main turbine in service resulted in operators establishing conditions that were outside those limitations.
05000352/FIN-2015002-01Limerick2015Q2Design Requirements Not Met for Installed Instrument Gas Tubing FittingA self-revealing Green NCV of 10 CFR 50, Appendix B, Criterion III, Design Control, was identified because Exelon failed to control the proper design configuration of installed plant equipment in Unit 1. Specifically, a fitting used in the safety-related primary containment instrument gas (PCIG) tubing supplying the 1C inboard main steam isolation valve (MSIV) was not installed in accordance with the specified quality standard and this deviation was not controlled. Subsequently, the fitting failed due to high cycle fatigue and caused a reactor trip. Exelons corrective actions included initiating condition report IR 2458005, installing approved tubing and fittings on February 24, 2015, on the 1C inboard MSIV which maintained wall thicknesses greater than original specifications, and verifying that current maintenance practice, training, and knowledge would preclude substitution of a different style fitting without further evaluation. This finding is more than minor because it is associated with the design control attribute of the initiating events cornerstone and affected the objective to limit the likelihood of events that upset plant stability during power operations. Specifically, the inadvertent closure of the 1C inboard MSIV resulted in a reactor trip. Using IMC 0609, Significance Determination Process, Appendix A, Exhibit 1, Initiating Events Screening Questions, the inspectors determined that this finding was of very low safety significance (Green) because the finding did not cause a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition (e.g. loss of condenser, loss of feedwater). Specifically, the finding caused the loss of one steam line to the main condenser but three steam lines remained available. The inspectors determined that the finding did not have cross-cutting aspect because the installation of the fitting that failed did not occur within the last three years, and the inspectors did not conclude that the causal factors represented present Exelon performance.
05000388/FIN-2015002-05Susquehanna2015Q2Loss of Main Condenser Vacuum When Transitioning Steam Seals to Auxiliary SteamA self-revealing finding of very low safety significance (Green) and associated NCV of SSES Unit 2 TS 5.4.1, Procedures, was identified because Susquehanna incorrectly implemented procedures for operation of the auxiliary steam and main turbine steam sealing systems. Specifically, on April 10, 2015, while Unit 2 was being shut down for a RFO, operators secured main turbine steam seals resulting in degraded main condenser vacuum. The degraded main condenser vacuum resulted in a main turbine trip, which caused an automatic reactor scram from approximately 37% power. Susquehanna restored main condenser vacuum by reestablishing steam seals, performed off-normal and emergency operating procedures to stabilize the plant post-scram and entered the issue into the corrective action program (CAP) as CR-2015-09890. The finding was more than minor because it was associated with the Human Performance attribute of the Initiating Events cornerstone and affected its objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, not understanding the impact of securing auxiliary steam to the main turbine steam seals resulted in the degradation of main condenser vacuum, automatic trip of the main turbine and associated reactor scram. The inspectors evaluated the finding in accordance with IMC 0609, Appendix A "The SDP for Findings At-Power," Exhibit 1, for the Initiating Events cornerstone, dated June 19, 2012. The inspectors determined the finding was of very low safety significance (Green) because it did not cause a reactor trip and the loss of mitigation equipment. Specifically, though a reactor scram occurred, operators were able to restore main condenser vacuum prior to MSIV closure and the main condenser and reactor feed pumps remained functional during the event. This finding has a cross-cutting aspect in the area of Human Performance, Avoid Complacency, because Susquehanna did not implement appropriate error reduction tools. Specifically, operators did not effectively implement human error prevention tools (e.g. pre-job briefing, stop-think-act-review) in accordance with station processes.
05000424/FIN-2014004-01Vogtle2014Q3Failure to Correctly Implement a Condensate and Feedwater Systems Procedure for StartupA self-revealing non-cited violation (NCV) of Technical Specification (TS) 5.4.1.a, Procedures, was identified for the licensees failure to implement system operating procedure (SOP) 13615-1, Condensate and Feedwater Systems, Version 84. Specifically, on July 30, 2014, the licensee conducted a power increase from Mode 2 (approximately 3 percent reactor power) to Mode 1 (approximately 8 percent reactor power) with main condenser hotwell level control in manual versus automatic as directed by procedure. This resulted in a main feedwater transient and a subsequent reactor shutdown. The licensee initiated an incident response team and entered this event into their corrective action program as condition report (CR) 847734. Additional corrective actions included revising the SOP to include specific instructions for the control of main condenser hotwell level with corresponding number of operating condensate pumps. The performance deficiency was more than minor because it was associated with the human performance attribute of the initiating events cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during power operations. Specifically, the performance deficiency was associated with a human error during implementation of SOP 13615-1, resulting in a main feedwater transient event (i.e. loss of condensate pump net positive suction head (NPSH) in the condenser hotwell resulting in lowering steam generator water levels), that subsequently upset plant stability. The inspectors evaluated the finding using IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, issued June 19, 2012. The finding screened as Green because it did not cause a reactor trip. The inspectors determined the finding had a cross-cutting aspect of procedure adherence in the human performance area because the unit operator did not implement SOP 13615-1 procedure Step 4.1.1.5, which required the UO to verify condenser hotwell control, 1LIC- 4415, is in auto maintaining normal level.
05000456/FIN-2014003-01Braidwood2014Q2Issues That Could Adversely Affect the UHSUnresolved Item: Issues That Could Adversely Affect the Ultimate Heat Sink Introduction: The inspectors identified four potential issues of concern after the licensee discovered that station procedures to address a failure of the Braidwood cooling lake dike did not include steps to secure nonsafety-related pumps, although the UFSAR stated and design calculations assumed that all circulating water pumps and nonsafety-related service water pumps would be secured.15. Description: Issue 1: TS 3.7.9, Ultimate Heat Sink, Limiting Condition for Operation Applicability After Identifying that a Non-Conforming Condition Could Challenge and/or Exceed the Associated Ultimate Heat Sink 30 Day Mission Time. The Braidwood cooling lake dike allows the ultimate heat sink (UHS) level to be maintained greater than the TS minimum level of 590. A failure of this nonsafety-related dike would cause a loss of level in the UHS to the 590 TS minimum level. During the inspection period, the licensee discovered that station procedures to address a failure of the Braidwood cooling lake dike did not include steps to secure nonsafety-related pumps, including circulating water pumps and service water pumps, that take a suction from the UHS and discharge to a location outside the UHS. As a result, and because the UFSAR stated and design calculations assumed that all nonsafety-related pumps, including circulating water pumps and service water pumps, would be secured to conserve UHS inventory following a dike failure, a non-conforming condition was identified. The licensee concluded that this non-conforming condition did not render the UHS inoperable as discussed in IR 1675291, Unanalyzed Condition Identified During IR 1674557, and IR 1676076, Discrepancy in the UFSAR Ultimate Heat Sink Description (Section 2.4.11.6), based upon the following: The issue was process-related and only concerned future planned actions for increasing the maximum UHS temperature; All TS 3.7.9, Ultimate Heat Sink, surveillance requirements were met; The Braidwood cooling lake did not actually reach the minimum TS level of 590; A cooling lake dike failure did not actually occur; and A statement in the UFSAR concerning the ability of the UHS to handle an assumed loss-of-coolant-accident coincident with a design basis seismic event that the licensee believed was erroneous. Specifically UFSAR Section 2.4.11.6, Ultimate Heat Sink Design Requirements included the following statement: ...The essential service water cooling pond (ESCP) is an excavated area located within the cooling pond designed to provide a sufficient volume to permit plant operation for a minimum 30-day period without requiring makeup water in accordance with Regulatory Guide 1.27. The ESCP has been reviewed to determine its ability to handle the total heat dissipation requirement of the station assuming a loss of coolant accident (LOCA) coincident with a loss of offsite power on one unit and a concurrent orderly shutdown and cooldown from maximum power to cold shutdown of the other unit using normal shutdown operating procedures, a single active failure, a coincident design basis seismic event... The inspectors noted that IR 1674557, Question on Ultimate Heat Sink License Amendment Request Impact on Pumps, documented that the licensee had preliminarily determined that operation of a single nonsafety-related service water pump at full flow would deplete the UHS in about 3.6 days and, as a result, the UHS would not be able to satisfy the 30-day post-accident volume requirements required by the plants design basis. The licensee concluded that even though procedural guidance did not 16 explicitly direct that nonsafety-related pumps be secured following a design basis accident, operators would recognize the problem and take actions to ensure that the UHS would still be able to perform its safety function and meet all design basis requirements. At the end of the inspection period, the licensee planned to more formally document the bases for UHS TS operability consistent with the definition of operability in the site-specific TSs and the licensees Operability Determination procedure. The licensee subsequently corrected this non-conforming condition by revising procedures to secure nonsafety-related pumps upon reaching a low lake level condition consistent with plant design calculations. Therefore, the inspectors did not have a current operability concern. Issue 1 will remain open pending the completion of the inspectors review of the licensees past operability determination. Issue 2: Timeliness of Actions to Inform the Shift Manager and/or Unit Supervisor of an Issue that May Affect Ultimate Heat Sink Operability On June 25, 2014, the inspectors reviewed IR 1674557, which documented that AOP BwOA ENV3, Braidwood Cooling Lake Low Level, did not direct nonsafety-related pumps that take a suction from the UHS and discharge outside of the UHS to be secured following a dike failure. In particular, although the Operability section of IR 1674557 was left blank, the Reviewed section concluded the following: There were no equipment deficiencies identified. This is a process issue regarding future planned actionsthere are no TS/Technical Requirements Manual/Offsite Dose Calculation Manual/GOCAR (General Operation Corrective Action Requirement) actions applicable; reportability criterion affected; or any SSC (structure, system and component) availability or functionality concerns raised by this issue. The inspectors determined that although the context of IR 1674557 suggested that this issue only impacted future planned actions that, in fact, the issue could affect the current operability of the UHS. Therefore, the inspectors promptly discussed this issue with the Operations Shift Manager who was not aware of any operability concerns associated with the issue or station actions to address the issue. Later that shift, the Shift Manager determined that the issue was reportable under 10 CFR 50.72(b)(3)(ii)(B), Unanalyzed Condition. At the end of the inspection period, it was not clear if the station had adhered to OPAA108115, Operability Determinations to inform the Shift Manager and/or Unit Supervisor of this issue in a timely manner. Issue 2 will remain open pending the licensees completion of a timeline of events and an inspector review of the station standards and implementation of those standards for this issue. Issue 3: Implementation of Operations Standing Order Upon Reaching a Low Lake Level Condition Without Performing a 10 CFR 50.59 and/or Generic Letter 8610 Review17. Upon discovery of the non-conforming and unanalyzed condition of the UHS, the licensee implemented an operations standing order that directed the nonsafety-related service water system, fire protection water system, and circulating water system to be secured following a cooling lake dike failure and low lake level of 590. This operations standing order augmented AOP BwOA ENV3, which did not direct any of these actions. In developing the subject standing order, the licensee did not perform a 10 CFR 50.59 evaluation and/or an associated review in accordance with Generic Letter 8610, Implementation of Fire Protection Requirements. At the end of the inspection period it was not clear if the licensees standing order process, or any other process, permitted this type of change without performing a 10 CFR 50.59 and/or associated Generic Letter 8610 evaluation. Additionally, it was not clear if the licensees temporary change was adequate (i.e. tripping both units, securing all circulating water and non-essential service water system pumps, and securing all running Fire Protection pumps just prior to reaching a low lake level of 590). Issue 3 will remain open pending the licensees completion of a timeline of events and additional inspector review. Issue 4: Safety Category II Structure, Systems and Component Interaction with the Ultimate Heat Sink The turbine building and a number of systems and components within the turbine building are designated as Safety Category II SSCs. The licensee defined Safety Category II SSCs as SSCs that were not designed to Safety Category I Standards. Specifically, Braidwood UFSAR Section 3.2.1.2 defined Safety Category II as follows: Those SSCs which are not designated as Safety Category I are designated as Safety Category II. This category has no public health or safety implication. Safety Category II structures, systems, and components are not specifically designed to remain functional in the event of the safe shutdown earthquake or other design-basis events (including tornado, probable maximum flood, operating basis earthquake, missile impact, or an accident internal to the plant). A reasonable margin of safety is, however, considered in the design as dictated by local requirements. Many Safety Category II items in Category I buildings are supported with seismically designed supports. These items and their supports are not Safety Category I or Seismic Category I as defined by Regulatory Guide 1.29. Structures and major components not listed in Table 3.2-1 as Safety Category I are Safety Category II. Safety Category II systems or portions of systems and components do not follow the requirements of Appendix B to 10 CFR 50. The quality assurance standards for these systems and components follow normal industrial standards and any other requirements deemed necessary by the Licensee. The licensee determined that a circulating water system line break and/or main condenser expansion joint rupture was not credible based on a review of postulated safe shutdown earthquake loads, and therefore a failure of this system following a design basis event such as a safe shutdown earthquake was not within the current licensing basis. The inspectors identified that a failure of the Safety Category II circulating water system could impact safety. For example the Braidwood cooling lake dike was also a Safety Category II structure. A failure of the cooling lake dike and establishment of the UHS18 level of 590 followed by a circulating water line break/expansion joint failure in the turbine building would result in a condition not currently evaluated (i.e., less useable UHS volume due to the displacement of a fraction of the UHS volume into the turbine building). At the end of the inspection period it was not clear how a Safety Category II SSC such as the circulating water system could be credited in a manner to not fail during a safe shutdown earthquake or other associated design basis event since, by definition, Safety Category II SSCs are not specifically designed to remain functional during these events. Additionally, the inspectors planned to review the Safety Category II Lake Screen House structure design to ensure that it could not adversely affect the intake in a manner that would prevent the UHS from performing its intended safety function. Issue 4 will remain open pending NRC review to ensure that the licensee is in compliance with their current licensing basis. (URI 05000456/201400301; 05000457/201400301, Issues That Could Adversely Affect the UHS)
05000341/FIN-2014002-03Fermi2014Q1Unacceptable Preconditioning of High Pressure Coolant Injection System Air-Operated Valve Prior to Stroke Time Test MeasurementThe inspectors identified a finding of very low safety significance with an associated non-cited violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings. The licensee failed to establish an adequate procedure to perform required stroke time testing for high pressure coolant injection turbine supply drain pot to main condenser drain line isolation valve E4100-F028. Specifically, the surveillance test procedure resulted in unacceptable preconditioning of the valve prior to the stroke time test measurement. The licensee entered this issue into its corrective action program for evaluation and initiated a corrective action to revise the test procedure. The finding was of more-than-minor significance since it was associated with the Procedure Quality attribute of the Barrier Integrity Cornerstone and adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Because the preconditioning altered the as-found condition of the air-operated valve, the data collected through the performance of the surveillance test were not fully indicative of the true valve performance trend. Therefore, this performance deficiency had a direct effect on the licensees ability to trend as-found data for the purpose of assessing the reliability of the valve. The finding was a licensee performance deficiency of very low safety significance because it did not involve an actual open pathway in the physical integrity of the Auxiliary Building. The inspectors concluded that because the valve testing sequence that unacceptably preconditioned E4100-F028 had existed in the surveillance test procedure for greater than three years and no opportunity reasonably existed during that time to identify and correct it, this issue would not be reflective of current licensee performance and no cross-cutting aspect was identified.
05000341/FIN-2014002-04Fermi2014Q1Failure to Perform Inservice Testing of High Pressure Coolant Injection and Reactor Core Isolation Cooling System ValvesThe inspectors identified a finding of very low safety significance with an associated non-cited violation of 10 CFR 50.55a. The licensee failed to perform required inservice testing of high pressure coolant injection and reactor core isolation cooling turbine supply drain pot to main condenser drain line isolation valves E4100-F029, E5150-F025, and E5150-F026. The licensee entered this issue into its corrective action program for evaluation, completed an immediate operability determination, and initiated a corrective action to revise applicable test procedures to incorporate inservice testing of the valves. The finding was of more-than-minor significance since it was associated with the Structures, Systems, and Components and Barrier Performance attribute of the Barrier Integrity Cornerstone and adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, the licensees failure to perform required inservice testing had a direct effect on its ability to trend as-found performance data for the purpose of assessing the reliability of the three isolation valves, which are required by design to isolate seismically qualified portions of the piping systems from non-seismically qualified portions. The finding was a licensee performance deficiency of very low safety significance because it did not involve an actual open pathway in the physical integrity of the Reactor and Auxiliary Buildings. The inspectors concluded that because the engineering evaluation that excluded the valves from inservice testing was completed in 1999 and no recent opportunity reasonably existed to identify and correct the error, this issue would not be reflective of current licensee performance and no cross-cutting aspect was identified.
05000298/FIN-2013005-05Cooper2013Q4Licensee-Identified ViolationTitle 10 CFR 50.65(a)(1), Requirements for monitoring the effectiveness of maintenance at nuclear power plants, requires, in part, that holders of an operating license shall monitor the performance or conditions of structures, systems, or components within the scope of the monitoring program against licensee established goals in a manner sufficient to provide reasonable assurance that such structures, systems, or components are capable of fulfilling their intended safety function. Contrary to the above, on November 6, 2013, the licensee identified that they failed to establish goals in a manner sufficient to provide reasonable assurance that structures, systems, or components were capable of fulfilling their intended safety function. Specifically, the licensee failed to establish goals for the main condenser when it was placed in an (a)(1) status. This performance deficiency was more than minor, and therefore a finding, because it was associated with the equipment performance attribute of the Initiating Events Cornerstone, and affected the associated cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) For Findings At-Power, inspector determined that the finding was of very low safety significance (Green) because th finding did not cause a reactor trip and the loss of mitigation equipment relied upon t transition the plant from the onset of the trip to a stable shutdown condition. This issu was entered into the licensees corrective action program as Condition Report CR-CNS-2013-07967 for resolution.
05000341/FIN-2013005-04Fermi2013Q4Evaluation of Apparent Unacceptable Preconditioning of High Pressure Coolant System Air Operated Valve Prior to Stroke Time TestingOn August 26, 2013, the inspectors observed portions of surveillance test procedure 24.202.01, HPCI Pump and Valve Operability Test at 1025 PSI (Pounds per Square Inch), and subsequently reviewed the test results. This surveillance test procedure was performed, in part, to satisfy the IST Program requirements in TS 5.5.6 and 10 CFR 50.55a, Paragraph f, Inservice testing requirements. The inspectors noted that the redundant HPCI turbine supply drain pot to main condenser drain line isolation valves (E4100-F028 and E4100-F029) automatically closed when the HPCI turbine was started. These two normally open valves were required by design to close upon HPCI turbine start to isolate seismically qualified portions of the piping system from non-seismically qualified portions. The valves were verified closed at step 5.1.49 of the test procedure after the HPCI turbine was started. After the HPCI turbine was secured, E4100- F028 and E4100-F029 were then reopened at steps 5.1.104 and 5.105, respectively. At step 5.1.109, E4100-F028 was then closed and its stroke time was measured. No stroke time testing of E4100-F029 was performed since the licensee excluded the valve from its IST Program because it concluded the valve does not perform a safety function in either the open or closed position. The inspectors questioned whether the test sequence inappropriately preconditioned E4100-F028 prior to its stroke time measurement since the valve closed when the HPCI turbine started and was then manually reopened after the HPCI turbine was secured. Cycling this AOV prior to measuring its stroke time masked the as-found condition and did not appear necessary to place the system in the configuration for testing. It appeared to the inspectors that a stroke time measurement could have been performed prior to running the HPCI turbine by manually cycling the valve closed and open. In addition, the inspectors questioned the exclusion of the redundant isolation valve (E4100-F029) from the licensees IST Program since it appeared to have the same design function as E4100-F028. The inspectors noted that Inspection Manual Technical Guidance Part 9900 defines unacceptable preconditioning, in part, as: The alteration, variation, manipulation, or adjustment of the physical condition of an SSC before or during TS surveillance or ASME (American Society of Mechanical Engineers) Code testing that will alter one or more of an SSCs operational parameters, which results in acceptable test results. Such changes could mask the actual as-found condition of the SSC and possibly result in an inability to verify the operability of the SSC. In addition, unacceptable preconditioning could make it difficult to determine whether the SSC would perform its intended function during an event in which the SSC might be needed. The Part 9900 Technical Guidance further states that influencing test outcome by performing valve stroking does not meet the intent of the as-found testing expectations described in NUREG-1482, Guidelines for Inservice Testing at Nuclear Power Plants, (April 1995), and may be unacceptable. The inspectors also noted that cycling an AOV prior to performing an as-found stroke time test measurement would not be in accordance with the licensees procedural guidance. MOP03, Operations Conduct Manual, Enclosure E, Position Paper Defining the Fermi 2 Policy on Preconditioning, Revision 35, states, in part, AOVs shall be stroke timed on the first stroke of a functional surveillance test .... Basis: Timing a stroke other than the first one constitutes preconditioning because the first stroke of an air operated valve after an extended period is typically longer than the following strokes. The Part 9900 Technical Guidance states that some types of preconditioning may be considered acceptable, but that this preconditioning should have been evaluated and documented in advance of the surveillance. Since the licensee had not performed an evaluation to justify preconditioning of the valve was acceptable prior to completing the testing, the inspectors have questioned whether the licensees surveillance testing sequence that cycled the valve prior to obtaining stroke time data constituted unacceptable preconditioning of the valve. The licensee initiated CARD 13-26877 to evaluate the apparent preconditioning concern. This issue is considered to be an Unresolved Item pending additional review by the Inspectors.
05000373/FIN-2013004-01LaSalle2013Q3Failure to Follow Procedure Led to Manual Scram with ComplicationsA self-revealed finding preliminarily determined to be of low-to-moderate safety significance was identified for the licensees failure to follow procedure LOP-CW-10, Dewatering the Circulating Water System, Revision 32, on Unit 2. Specifically, on April 25, 2013, with Unit 2 at 56 percent power, operators appointed to plan and execute the dewatering of the main condenser waterbox did so in a manner inconsistent with procedural guidance by manually adjusting the circulating water isolation valves while condenser manways were still open. The subsequent loss of isolation led to the flooding of the condenser pit and a resultant circulating water pump trip, loss of the normal heat sink, and a reactor scram. The licensee entered this issue into its corrective action program (CAP) as action report (AR) 1506809 and performed a root cause analysis to identify the root and contributing causes of the event, as well as to determine the appropriate corrective actions, such as providing training and revising procedures. The inspectors determined that the licensees failure to follow the prescribed steps of procedure LOP-CW-10 was a performance deficiency warranting a significance determination. The inspectors used Inspection Manual Chapter (IMC) 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 1, dated June 19, 2012, for the Initiating Events cornerstone. Because the finding caused a reactor trip AND the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition, a detailed risk evaluation was required. The Senior Reactor Analysts (SRAs) used the LaSalle Standardized Plant Analysis Risk (SPAR) model to perform the detailed risk evaluation. In accordance with Risk Assessment of Operational Events Handbook guidance, the initiating event Loss of Condenser Heat Sink was set to 1.0 using the events and condition assessment module of the Systems Analysis Program for Hands-On Integrated Reliability Evaluations (SAPHIRE), Version 8. The calculated conditional core damage probability for the event was 1.6E-6, which represents a finding of low-to-moderate safety significance (White). The finding had a cross-cutting aspect in the area of human performance, decision-making, because the licensee failed to use conservative assumptions when planning and executing the dewatering evolution. Specifically, the incorrect assumption that this evolution performed at-power could be treated the same as when performed during a shutdown condition enabled operators to stray from strict procedure adherence and into knowledge space.
05000250/FIN-2013004-03Turkey Point2013Q3Failure to Provide Adequate Instructions during Maintenance on the Gland Seal Steam SystemA self-revealing finding was identified due to the licensees failure to provide adequate work instructions for throttling the Unit 3 gland seal steam bypass valve. As a result of the licensees inadequate work instructions, an operator opened the spill bypass valve on the gland seal steam system until system steam pressure dropped and allowed air in-leakage through the turbine gland seals. This resulted in a reactor trip and the main condenser was unavailable for reactor decay heat removal until vacuum could be restored. The licensee entered this issue into their corrective action program as action request 1847369 and revised the system operating procedure to address operation of the bypass line around the spillover control valve. The inspectors determined the performance deficiency was more than minor because it was associated with the configuration control attribute of the initiating events cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during power operations. Specifically, the failure to provide adequate work instructions for the operation of the gland seal steam spillover bypass valve resulted in a reactor trip with the main condenser unavailable for reactor decay heat removal until vacuum could be restored. The inspectors screened the finding and determined that the finding was a transient initiator contributor which required a detailed risk analysis because the finding resulted in a reactor trip with a loss of condenser vacuum. A bounding analysis was performed by a regional Senior Reactor Analyst who concluded that the finding resulted in an increase in core damage frequency of less than 1E-6/year and, therefore, was a Green finding of very low safety significance. The finding was associated with a cross-cutting aspect in the work control component of the human performance area because the licensee did not adequately incorporate the need for planned contingencies, compensatory actions or abort criteria to ensure that throttling the gland seal steam spillover bypass valve would not result in a reactor trip and loss of the main condenser (H.3(a)).
05000254/FIN-2013003-02Quad Cities2013Q2Question Concerning Licensing Bases of the Ultimate Heat SinkThe inspectors identified an unresolved item (URI) concerning the current licensing bases with respect to failure of Lock and Dam No. 14 on the Mississippi River. The inspectors reviewed several documents to ascertain the current licensing bases for the UHS. The river serves as a source of raw water for the station as well as one of the heat sinks. The licensee designated the UHS as non-safety related and as described in UFSAR Sections 2.4.4 and 9.2.5.3, the UHS is required if the river can no longer support its functions. The inspectors noted the current UFSAR states the loss of river results from damage to the Lock; however, historical documents state the event promulgates from a loss of Dam No. 14. Specifically: Section 2.4 of the Final Safety Analysis Report (FSAR) states, in part, the following: The river level at the station is assumed to drop to elevation 561 feet 0 inches if Dam No. 14 were to fail (emphasis added). Elevation 561 feet, 0 inches is the normal river level downstream of Dam 14. The station design includes the feature that at the time that Dam 14 fails (emphasis added) the only systems requiring the use of river water would be the RHR service water pumps. If in the unlikely event the broken dam condition occurs (emphasis added), it is necessary to open the gate on the ice melting line to permit the discharged water to return to the intake flume. This procedure permits the use of the water impounded in the intake flume and discharge flume to be used as an evaporative heat sink. This technique will impound 3,960,000 gallons of water. The maximum amount of water required by the system at this stage will be approximately 7000 gpm, which means that without any recirculation, the impounded water will last a minimum of 9.4 hours. It will be necessary to make up water to the intake flume under this condition by portable pumping equipment which will move water from the main river channel to the plant. Pumps capable of pumping 7000 gpm water will be maintained on site and backup pumps available from the local fire stations. In a letter dated November 6, 1970, to the U.S. Atomic Energy Commission (now NRC), Commonwealth Edison (the licensee) addressed questions regarding the use of portable equipment to move water from the main river channel to the plant under frozen river conditions. In response to Question 2.8, the licensee stated the portable pumps would not be required under these conditions. In addition, the licensee afforded the opportunity to clarify some statements in Section 2.4 of the Final Safety Analysis Report (FSAR). Specifically, the licensee stated the portable pumps would not be needed for makeup under a loss of dam event because the evaporative losses were about 20 gpm, not 7000 gpm as written. Although not stated in the licensees response, the inspectors noted the original description in FSAR Section 2.4 did not account for the ice melt line used to recirculate water back to the UHS; hence stating the need for makeup to the closed volume of the UHS. The licensees clarification (the need for 20 gpm makeup) accurately reflects the actual losses that need to be replenished. In the safety evaluation dated August 25, 1971, Section 2.3 states, the facility is also designed to provide an adequate supply of cooling water to the plant by providing a reservoir of about 3.8 million gallons of water in the intake bay so that, even if the river level dropped below a level of 565 feet MSL due to an assumed failure of Dam 14 downstream of the site (emphasis added), the water trapped in the intake bay would supply an adequate source of water for safe cool-down of the reactor primary system. In 1989, the licensee determined the original evaporative losses cited in the November 6, 1970, letter did not account for the worst case conditions. The licensee performed a calculation assuming worst case summer conditions and determined the evaporative losses were about 54 gpm. The licensee concluded the two 2000 gpm portable pumps were more than sufficient to address these losses. In NRC Inspection Report 05000254/1998-201, 05000265/1998-201(ML9805180380), the NRC team identified errors with the 1989 calculation and the licensees approach. Specifically, the team determined that in an evaporative mode, the trapped volume of UHS would increase in temperature and during summer operation, could be driven well above the 95 degrees Fahrenheit design temperature established for the RHRSW system. The licensee performed a preliminary calculation assuming 1 hour cool-down time on the main condensers from dam failure to loss of contact with the river (emphasis added) and determined the UHS could reach 112 degrees Fahrenheit. The team noted this evaluation used a method of makeup different than the current UFSAR. The team initiated an Unresolved Item 05000254/1998-201-12, 05000265/1998-201-12 to determine the resolution of the dam failure effects on the UHS. In May 1998, the licensee completed 10 CFR 50.59 Safety Evaluation SE-98-068. The purpose of this evaluation was to assess proposed changes to the UFSAR to incorporate the results of the study and revised temperature calculations. It described the change from dam failure to Lock and Dam failure as a clarification of the event to include a timeline and credible failure modes for the Lock and Dam. The licensee concluded these changes did not constitute an un-reviewed safety question, was not a change to a license condition and did not require a TS change. In May 1998, the licensee revised the UFSAR to reference the study and include details on the expected timeline and actions associated with a transportation accident impacting the Lock. The revised UFSAR also reiterates the portable pumps are onsite with backup pumps provided from another facility or leasing facility. In November 1998, an inspection was conducted to follow up on the licensees actions to address this URI. As documented in NRC Inspection Report 05000254/1998-019, 05000265/1998-019 (ML9812290045), the NRC team noted the licensee performed a hydraulic study of the Mississippi River in April 1998. This study assessed the possible failure modes of Dam No.14 and concluded the most credible and reasonable worst case scenario involved a transportation accident whereby a river barge impacts the Lock and Dam. The study determined the time for the river to separate from the UHS was about 90 hours. The licensee used this information in Calculation QDC-3900-M-0692 to determine the cooling needs for the UHS. The calculation concluded three portable pumps delivering a total of 5100 gpm of cooler water were needed to ensure the inlet temperatures remained within design limits. A violation for the failure to assure the design basis information was consistent with actual plant design was issued. As described in Section 1R07.1b(3), in April 2001, the licensee completed a 10 CFR 50.59 Safety Evaluation Screening, QC-S-2001-0026, to assess removal of the portable pumps from onsite and relocating the pumps to an offsite leasing facility located a few hours away. The licensee revised the UFSAR and removed the portable pumps from the site. The inspectors noted the original FSAR did not provide the detail as to the cause of the dam failure or a time line for the loss of river event. The licensee stated their response to Question 2.8, (and as reiterated in the August 1971 Safety Evaluation) implies the loss is not immediate because water level would recede in the condenser box and the unit would be shutdown due to loss of condenser vacuum. The licensee contends the main condenser would remain functional following a dam failure up until the vacuum can no longer be maintained by the UHS supply. The inspectors noted the licensee had assumed 1-hour of such operation in their preliminary calculation performed in November 1998. The inspectors were concerned the licensee redefined the loss of river event from the original Section 2.4 of the FSAR description of an unlikely event of a broken dam to a transportation accident impacting the lock. Therefore, this issue is considered an Unresolved Item (URI 5000254/2013003-02; 05000265/2013003-02, Question Concerning Licensing Bases of the Ultimate Heat Sink) pending further consultation with the Office of Nuclear Reactor Regulation.
05000259/FIN-2013003-02Browns Ferry2013Q2LER 05000296/2013-003-00 and 05000259/2013-002-00Unresolved Item (URI). A self-revealing issue of concern was identified with the Unit 3 automatic reactor shutdown due to the turbine trip from loss of condenser vacuum on February 25, 2013 and the Unit 1 manual reactor shutdown due to a decreasing vacuum manual scram on March 19, 2013. On February 25, 2013, Unit 3 was operating at approximately 92 percent power following a forced midcycle outage for repairs on the condenser circulating water (CCW) system. At 1313 hours the unit automatically scrammed due to a turbine trip. The turbine trip was caused by low condenser vacuum as a result of a failure of a long cycle return line piping connection to the miscellaneous drain header which connects with the main condenser. Main steam isolation valves (MSIVs) were manually closed and main turbine bypass valves were unavailable due to the loss of condenser vacuum. During the transient all available mitigating equipment performed as designed. The licensee initiated PER 687732 to enter the event into the corrective action program. Licensee investigation revealed the failure of a feedwater long cycle return line connection to the miscellaneous drain header was a result of seat leakage from the reactor feedwater system long cycle return flow control valves (3-FCV-003-0071, 72, and 73). This seat leakage caused the water within the pipe to flash to steam which translated to excessive vibration on the pipe and resulted in fatigue failure of the connection between the 8 inch pipe and 24 inch miscellaneous drain header. On March 19, 2013, Unit 1 was operating at approximately 80 percent power. At 0402 hours the unit was manually scrammed due to decreasing main condenser vacuum. Following the manual scram condenser vacuum recovered and all available mitigating equipment was available and performed as designed. The vacuum degradation was caused by the separation of a 4 inch vent and drain pipe from a 24 inch miscellaneous drain header which connected to the main condenser. The separation was caused by vibration induced cyclic fatigue as a result of the combination of leaking drain valves and repeated operation of dump valves associated with feedwater heaters. The licensee initiated PER 698870 to enter the event into the corrective action program. Additional inspection of the maintenance history, service requests (SRs), problem evaluation reports (PERs), cause analyses and mitigating system responses concerning these two reactor trips are required to provide additional information into the issue. This unresolved item was tracked as URI 05000259, 260, 296/2013003-02.
05000272/FIN-2013003-06Salem2013Q2Failure to Follow the Loss of Main Condenser Vacuum ProcedureA self-revealing NCV of Technical Specification (TS) 6.8.1 Procedure and Programs, resulted from operators failure to implement the loss of condenser vacuum procedure. Specifically, operators failed to follow S1.OP-AB.COND-0001, Loss of Main Condenser Vacuum, which directed closure of the main steam isolation valves (MSIVs). This resulted in the inability to potentially recover the condenser as a heat sink, after the loss of circulating water (CW) pumps initiator was recovered, due to the actuation of the 11 low pressure (LP) turbine shell rupture disk. Corrective actions from the cause evaluation include developing additional abnormal operating procedure guidance to address a loss of all CW pumps, and designing simulator training scenarios to focus on secondary plant stabilization following reactor and turbine trips. The performance deficiency (PD) was determined to be more than minor because it was associated with the human performance attribute of the initiating events cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. The finding was considered associated with the initiating events cornerstone since it occurred during recovery actions after the reactor trip. The finding was determined to be of very low safety significance (Green) per IMC 0609, Significance Determination Process (SDP), Appendix A, Exhibit 1 Initiating Events, Section B, Transient Initiators, because the PD did not cause both a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. Specifically, the PD occurred after the reactor trip and resulted in the loss of one system (main condenser) of a number of available mitigation systems used to transition the plant to a stable shutdown condition. The PD did not cause the initiating event of a loss of condenser heat sink, but instead it only affected the ability to potentially recover the heat sink after CW was restored. This finding has a crosscutting aspect in the area of Human Performance, Resources, in that PSEG did not ensure that the crew was skilled in secondary plant stabilization and recovery. Specifically, PSEG did not ensure that the training program previously focused on the secondary plant stabilization and / or recovery post trip.
05000456/FIN-2013003-04Braidwood2013Q2Implementation of Lake Chemistry Management ProgramThe inspectors identified an URI associated with the licensees implementation of station procedural standards to notify Senior Site Management and Operations at the first sign of a lake softening event, and to implement AOP BwOA-ENV-7, Adverse Cooling Lake Conditions, when pre-determined calcium precipitation rate limits were exceeded on three occasions from March 2012 through April 2013. The licensees root cause analysis performed following a 2004 Braidwood Lake Precipitation Event (IR 199206, Lake Chemistry Trend Calcium Carbonate Issue, Assignment 13) identified that the Lake Chemistry Plan had not been formalized into operational procedures and, as a result, guidelines for administrative controls, actions limits and levels, and contingency actions had not been established for managing lake chemistry. As one of the corrective actions to address this issue, the licensee developed and implemented AOP BwOA-ENV-7, Adverse Cooling Lake Conditions, to address any future adverse lake precipitation event (IR 199206, Assignment #35). On November 10, 2004, BwOA-ENV-7, Adverse Cooling Lake Conditions, was approved, placed within the station procedures, and was required to be followed in accordance with station standards. This AOP stated that prompt actions may be required to minimize any adverse effects on plant operation. Procedure BwOA-ENV-7 required that several actions be performed to minimize the impact of a significant lake precipitation event. For example, the procedure directed numerous actions to determine whether there had been an adverse impact on plant systems. These actions included the observation of traveling screen operation, monitoring of safety-related and nonsafety-related service water system strainer performance, trending of main condenser pressure, and the monitoring of component cooling system heat exchanger performance, fire protection jockey pump performance, and reactor containment fan cooler service water flow. Upon the identification of any adverse impact, the procedure directed notification of the Braidwood Station Duty Team to ensure appropriate actions would be taken commensurate with safety. Additionally, immediately following entry, BwOA-ENV-7 required that the Emergency Director evaluate Emergency Plan conditions. The procedure also required that the licensee minimize SX and auxiliary feedwater pump, main control room chiller, and EDG operation to preclude chemical or biological fouling. Following issuance, BwOA-ENV-7 had been revised numerous times to modify the thresholds and standards for informing Senior Site Management and Operations of lake precipitation events and to specify the standards upon which Operations would be notified to implement the procedure. For the period of January 2012 through May 2013, CY-BR-120-412, Lake Chemistry Data Sheet, Revision 7 was in effect and required the following: At the first sign of a precipitation event or natural softening, NOTIFY Senior Site Management and Operations (Reference Section 3.5). COMPARE Calcium Hardness and Total Alkalinity trends to determine behavior of these parameters during period of softening and non-softening. (Reference Section 4.6.5) - REVIEW CW Makeup and blowdown flow history, as well as recent weather precipitation. - If lake softening rate exceeds 15 ppm (parts per million) Calcium Hardness in a 2-3 day period, NOTIFY Operations to enter BwOA-ENV-7. The inspectors reviewed Braidwood Lake chemistry data from January 2012 through April 2013. The inspectors identified that the licensee appeared to have not followed the standards discussed above for three of the five potential lake softening events during this period. Specifically, the inspectors identified that Senior Site Management and Operations notification and entry into procedure BwOA-ENV-7, Adverse Cooling Lake Conditions, was delayed for up to several days after the licensee had performed lake water sampling, had analyzed the sample, and had documented the results. The following specific examples were identified: 2012 First Lake Softening Event (BwOA-ENV-7 Entered on March 5, 2012 3 Days After Entry Conditions were Present Date Calcium Delta Between Prior Day Sample 2/29/2012 257 3/2/2012 231 (26) - 2012 Third Lake Softening Event (BwOA-ENV-7 Entered on April 15, 2012 2 Days After Entry Conditions were Present) Date Calcium Delta Between Prior Day Sample 4/11/2012 194 4/13/2012 167 (27) - 2013 Second Lake Softening Event (BwOA-ENV-7 Entered on April 4, 2012 1 Day After Entry Conditions were Present) Date Calcium Delta Between Prior Day Sample 4/1/2013 209 4/3/2013 191 (18) The inspectors determined through interviews with licensee personnel and through the review of Operations logs that the licensee had not notified Senior Management and Operations at the first signs of the listed lake softening events or had implemented BwOA-ENV-7 earlier than was documented in the Operations logs. As a result of not implementing BwOA-ENV-7, Adverse Cooling Lake Conditions, when required, the licensee did not appear to perform the actions required by the AOP in a time frame commensurate with station standards. Therefore, the licensee failed to meet the standards that they had originally developed and modified over the years to minimize the possible adverse effects of lake precipitation events. The inspectors discussed this issue of concern with licensee staff, management, and senior management who disagreed with the inspectors assessment. The main points of the disagreement were on the meaning of the term at the first sign and on the acceptability of allowing a sample to be taken and analyzed on one day but not reviewed by a supervisor through the Lake Chemistry Control Program until chemistry staff were available, potentially several days later. The inspectors inferred from the term at the first sign that actions were required to be performed without an undue delay and that these actions were not dependent upon readily available chemistry staff. In the past two lake precipitation events, plant equipment was adversely impacted relatively soon after the onset of the event. The inspectors recognized that the elevated differential calcium concentration samples identified during this inspection did not actually result in a lake precipitation event. As of the end of the inspection period, the licensee planned to determine the impact of a 2-3 day delay in implementing BwOA-ENV-7 on the ability to mitigate a lake softening event. Pending a review of this information, this issue is considered a URI. (URI 05000456/2013003-04; 05000457/2013003-04, Implementation of Lake Chemistry Management Program)
05000387/FIN-2013002-02Susquehanna2013Q1Inadequate Restoration from Clearance Order Results in Degradation of Main Condenser Vacuum and Plant DownpowerA self-revealing NCV of very low safety significance (Green) was identified when PPL incorrectly implemented the clearance order process while returning the common offgas recombiner to service after maintenance. NDAP-QA-0322, Energy Control Process, Revision 42, requires that upon completion of the (clearance order) restoration plan, the system should be restored to the design operating condition (e.g. running, automatic standby, etc.). Additionally, it requires the System Operating Representative (SOR) and Operations Supervision to ensure restoration of the clearance order prevents introduction of system or plant transients. Contrary to these requirements, on December 12, 2012, when restoring from a clearance order, a manual isolation valve for the common recombiner was incorrectly left in the closed position. This resulted in a degradation of main condenser vacuum when the common recombiner was subsequently placed in service on February 5, 2013, requiring operator action to decrease reactor power to maintain main condenser vacuum within limits. PPL entered the issue into the CAP as CR 1668013. The performance deficiency is more than minor because it was associated with the Configuration Control 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 power operations. Specifically, when PPL operators attempted to place the common recombiner in service on February 5, 2013, the closed manual isolation valve caused a loss of process flow to the recombiner and ultimately a degradation of main condenser vacuum. In responding to the reduction in vacuum, a recirculation pump runback was initiated and thermal power was rapidly reduced by approximately 32 percent. Additionally, the performance deficiency was similar to example 4.b in IMC 0612, Appendix E, Examples of Minor Issues, which states that a procedural error is more than minor if it caused a reactor trip or other transient. The inspectors evaluated the finding using IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, and determined the finding did not cause a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. Consequently, the finding is of very low safety significance (Green). The finding is related to the cross-cutting area of Human Performance, Work Practices in that PPL did not communicate human error prevention techniques such as self and peer checking to ensure work activities are performed safely. Specifically, both the SOR and Operations Supervision reviews were insufficient to ensure the manual steam isolation valve for the common recombiner was restored to the correct position during clearance order removal.
05000250/FIN-2012005-01Turkey Point2012Q4Failure to Verify 1B Feedwater Heater Drain Valve ClosedA self-revealing finding was identified when the licensee failed to follow procedure 0-ADM-222, Drain and Vent Rig Controls, while installing a temporary drain hose on Turkey Point Unit 4 in-service equipment. Operations and maintenance workers failed to verify a drain line flow path was isolated on the 1B feed water heater prior to removing a pipe valve cap that resulted in an unexpected lowering of condenser vacuum. Operators took action to close the open drain line isolation valve and terminate the plant transient. The licensee captured this condition in their corrective action program as AR 1819010. The licensees failure to verify the closed position of 1B feed water heater drain valve 4- 30-128, as required by procedure 0-ADM-222, prior to removing the pipe cap was a performance deficiency. The inspectors determined the performance deficiency was more than minor using IMC 0612, Appendix B, Issue Screening, because the performance deficiency was associated with the configuration control attribute of the initiating events cornerstone, and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during power operations. Specifically, the failure to verify the position of 4-30-128 resulted in lowering condenser vacuum that could have led to a reactor trip and the unavailability of the main condenser. The inspectors evaluated the finding using the significance determination process for findings at power of IMC 0609, Appendix A, Exhibit 1, Transient Initiators. The inspectors determined the finding was of very low safety significance (Green) because the finding did not result in a reactor trip and a loss of mitigation equipment relied upon to transition the plant to a stable shutdown condition. The finding was associated with a cross-cutting aspect in the work practices component of the human performance area because the licensee did not define and effectively communicate expectations, or follow the procedural requirement to physically verify valve position during the drain hose installation work.
05000458/FIN-2012009-06River Bend2012Q3Implementation of the Station Cable Reliability ProgramThe team identified an unresolved item associated with the licensees process for ensuring that underground non-safety related power cables whose failure could affect equipment in the scope of the Maintenance Rule were maintained as described in Procedure EN-DC-346, Cable Reliability Program, Revision 3. On May 21, 2012, non-vital 13.8 kV circuit breaker NPS-SWG1A ACB07, the supply breaker to circulating water area transformer STX-XS2A, tripped resulting in a loss of circulating water cooling to the main condenser and a subsequent reactor scram. The licensees investigation discovered that a fault in underground medium voltage cable 1NPSANJ322 had caused the trip of circuit breaker ACB07 and a fire in underground cable vault EMH1A. The licensee wrote Condition Report CR-RBS-2012- 3440 to document the event and the root cause analysis results. The licensees preliminary analysis identified the most probable cause of the cable fault as moisture intrusion at a spliced connection in cable 1NPSANJ322. The team reviewed the licensees root cause evaluation report, dated June 19, 2012. The cause evaluation concluded that the root cause of the cable failure was poor splice crimping and water intrusion at the splice causing accelerated cable insulation degradation. The team determined the report conclusions were appropriate. The NRC issued Generic Letter 2007-01, Inaccessible or Underground Power Cable Failures That Disable Accident Mitigation Systems or Cause Plant Transients, in February 2007. The generic letter required licensees to provide a description of the inspection, testing, and monitoring programs they used to detect the degradation of inaccessible or underground power cables that support systems that were within the scope of 10 CFR 50.65 (the Maintenance Rule). The Maintenance Rule required, in part, that licensees monitor the performance or condition of structures, systems, or components in a manner sufficient to provide reasonable assurance that such structures, systems, and components are capable of fulfilling their intended functions. The team determined that the licensee had established a cable monitoring program in December 2009 and had begun diagnostic cable testing in January 2011. Procedure EN-DC-346, Cable Reliability Program, Revision 3, required, in part, that underground power cables whose failure could affect Maintenance Rule equipment be monitored to establish the insulation condition using appropriate testing and evaluation of the test results. The licensee identified approximately 57 in-scope cables, fourteen of which had been tested before the May 21 failure. The licensee used a dielectric loss-dissipation factor test (tan a test) as their method of diagnosing problems in medium-voltage cables. The dielectric loss-dissipation factor test has the ability to detect thermally induced cracking, radiation-induced cracking, mechanical damage, water treeing, moisture intrusion, and surface contamination. Following replacement of the failed cable splice, the licensee performed diagnostic testing on cables 1NPSANJ303, 1NPSANJ304, and 1NPSANJ322 as part of post-maintenance testing and identified that cable 1NPSANJ304 did not have acceptable values for insulation resistance. The licensee cut open a splice on cable 1NPSANJ304 and found water between the cable jacket and insulation. The licensee initiated Condition Report CR-RBS-2012-03590 to document the water intrusion in cable 1NPSANJ304 in the corrective action program. The licensees cable reliability program established a cable risk factor for setting priorities for testing shielded medium voltage cables. The cable risk factor included the number of known splices in the cable and an adverse environment risk factor for cables subject to submergence. The program also included guidance for confirming that underground cable vault maintenance practices and water level trending were sufficient to keep the cables from submergence, if possible, to increase the longevity of the insulation system. The licensee had established a risk ranking for in-scope cables, but had not inspected the in-scope underground cable vaults to determine the number and location of cable splices. The presence of splices would change the ranking of cables. Cables 1NPSANJ304 and 1NPSANJ322 had not been tested before they failed at spliced connections in May 2012. The team identified that several different ranking formats were in use at the station and concluded that the cable ranking system for the scheduling of diagnostic tests was not clearly defined. The licensee performed visual inspections of other underground cable vaults searching for additional splices in the redundant non-safety-related train. No additional splices were found in the redundant train; however, other underground cable vaults needed to be dewatered because the cables were submerged and were not visible until the water had been removed. The team determined that prior to performing the cable vault inspections following the May 21 cable failure, the licensee did not have the information needed to effectively implement the guidance for developing the cable risk rankings described in procedure EN-DC-346, Cable Reliability Program, Revision 3. The root cause evaluation report stated that a testing schedule had been developed for the remaining in-scope cables such that initial dielectric loss-dissipation factor testing would be completed for all in-scope cables by the completion of Refueling Outage 18. The licensee initiated an additional action associated with the root cause evaluation to review the risk-ranking criteria for all in-scope cables. The team concluded further inspection was required to review the effectiveness of the licensees monitoring program for in-scope cables.
05000271/FIN-2012003-01Vermont Yankee2012Q2Inadequate Risk Assessment for Isolating the Condensate Pumps\' Minimum Flow Line\'S Automatic Flow Control ValveThe inspectors identified an NCV of 10 CFR 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, paragraph (a)(4), for Entergys failure to conduct an adequate risk assessment prior to isolating the condensate pumps minimum flow automatic control valve. Specifically, the inspectors identified that Entergy personnel had not analyzed the impact to plant risk with the condensate pumps minimum flow line to the main condenser isolated. Entergys corrective actions included declaring and announcing to site personnel the plant risk to be Orange, protecting further equipment, and initiating CR-VTY-2012-02074. The inspectors determined that the issue was more than minor because it is similar to IMC 0612, Power Reactor Inspection Reports, Appendix E, Examples of Minor Issues, example 7.e in that the overall elevated plant risk put the plant into a higher risk category established by Entergy. The inspectors determined the significance of the finding using IMC 0609, Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process. The finding was determined to be of very low safety significance (Green) because the Incremental Core Damage Probability Deficit for the timeframe that the condensate pumps were unavailable was less than 1E-6 (approximately 2E-7). The inspectors determined that the finding had a cross-cutting aspect in the Human Performance cross-cutting area, Resources component, because the equipment relied upon to perform the risk assessment, the equipment out of service software program (EOOS), did not include the condensate system automatic minimum flow control valve, which was not adequate to ensure nuclear safety.
05000416/FIN-2012003-08Grand Gulf2012Q2Failure of Hot-Work Fire Watch to Follow Procedural RequirementsThe inspectors reviewed a self-revealing non-cited violation of Technical Specifications 5.4.1(a), for failure of the hot-work fire watch to follow procedural requirements, which resulted in a fire in main condenser A. On April 11, 2012, at 6:11 p.m., hot-work was in progress inside the condenser A in the upper southeast corner at 150 foot elevation. Cutting was being performed by contract boilermakers using an oxy-acetylene torch, with ventilation exhaust and supply provided by nearby HEPA hoses. The torch cutting operation produced hot slag, which exited the barrier provided by the fire blankets and ignited the nearby HEPA hoses, air conditioning hoses, and eventually the acetylene hoses. Contract pipefitters in the area were able to extinguish the fire. The main control room was informed of the fire inside condenser A and dispatched the fire brigade to the scene. The operations shift manager declared a notice of unusual event at 6:26 p.m. due to a fire in the protected area lasting longer than 15 minutes. Members of the fire brigade entered the condenser bay at 6:42 p.m. and reported to the control room there was no fire present, only smoke. The notice of unusual event was exited at 7:00 p.m. Short term corrective actions included site management placing a stop work order on all hot-work until a complete investigation of the event could be performed. The licensee entered this issue into the corrective action program as Condition Report CR-GGN-2012-05418. The finding is more than minor because it is associated with the protection against external factors 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. The inspectors reviewed Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process, that states in the Assumptions and Limitations section, The Fire Protection SDP focuses on risks due to degraded conditions of the fire protection program during full power operation of a nuclear power plant. This tool does not address the potential risk significance of fire protection inspection findings in the context of other modes of plant operation (i.e., low power or shutdown). Therefore, the senior reactor analyst evaluated the finding in accordance with Manual Chapter 0609, Appendix G, Attachment 1, Shutdown Operations Significance Determination Process Phase 1 Operational Checklists for both PWRs and BWRs. The finding did not require a quantitative assessment because adequate mitigating equipment remained available; the finding did not increase the likelihood of a loss of reactor coolant system inventory; the finding did not degrade the ability to terminate a leak path or add reactor coolant system inventory; and the finding did not degrade the ability to recover decay heat removal if lost. Therefore, the finding screened as Green, having very low safety significance. The inspectors determined that the apparent cause of this finding was that site management did not ensure that hot-work supervisors were engaged in ensuring compliance with procedural requirements. This finding had a cross-cutting aspect in the area of human performance associated with work practices component because the licensee failed to ensure supervisory oversight of hot-work activities is performed within procedural requirements such that nuclear safety is supported.
05000440/FIN-2012002-01Perry2012Q1Reactor Manual Scram Associated With Inadequate Maintenance Risk EvaluationA self-revealed finding of very low safety significance (Green) and an associated NCV of 10 CFR 50.65(a)(4) was identified for failure to assess and manage risk associated with maintenance activities. Specifically, the licensee planned and conducted maintenance on a stator water cooling system pressure gauge on March 1, 2012, as a lower risk evolution than required, and conducted the maintenance online despite several decision points which indicated that this maintenance should have been conducted with the unit offline. When performed on line, the activity caused a reactor scram. The licensee entered the issue into the corrective action program as Condition Report 2012-03231. The finding was evaluated using IMC 0612, Appendix E, Examples of Minor Issues, and was determined to be more than minor because it is similar to Example 7.e and resulted in a reactor scram. Additionally, the performance deficiency impacted the Human Performance attribute of the Initiating Events Cornerstone, and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during power operations. In accordance with IMC 0609, Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process, a Region III Senior Reactor Analyst performed an analysis of the risk deficit for the unevaluated condition associated with work on a stator water system pressure gauge resulting in a reactor scram. The Perry Standardized Plant Analysis Risk (SPAR) model version 8.15 and SAPHIRE version 8.0.7.18 was used to calculate an Incremental Core Damage Probability Deficit (ICDPD). The result was an ICDPD of less than 7E-8. The dominant core damage sequences involved: (1) loss of the main condenser, failure of suppression pool cooling, failure of containment spray, failure of the power conversion system, failure of containment venting, and failure of late injection; and (2) failure of the reactor protection system to shutdown the reactor with failure of the recirculation pumps to trip. In accordance with IMC 0609, Appendix K, because the calculated ICDPD was not greater than 1E-6, the finding was determined to be of very low safety significance. This finding was associated with a cross-cutting aspect in the Work Planning (H.3(a)) component of the Human Performance cross-cutting area because the licensee did not incorporate appropriate risk insights into the development of the work package. Specifically, the licensee did not evaluate, during the planning phase of the work preparation, for the impact of re-installation of the pressure gauge and the potential for a pressure spike; a spike which caused a sustained runback of the main turbine generator with a resultant required action by the operators to manually scram the reactor.
05000397/FIN-2011005-01Columbia2011Q4Failure to Follow Work Instructions when Fabricating a Gagging Device for Main Condenser Hotwell Surge Bypass ValveThe inspectors reviewed a self-revealing finding for the licensee\\\'s failure to follow work instructions. Specifically, mechanics failed to properly implement Work Order 01188696, Task 7, when fabricating the gagging device used to maintain main condenser hotwell surge volume bypass valve closed during planned maintenance. As a result, on November 2, 2011, a rapid, unexpected rise in hotwell level and conductivity and a rapid drop in condensate storage tank level occurred. Subsequent review revealed that the gagging device installed on the main condenser hotwell surge volume bypass valve failed, which allowed a vacuum drag flow path of condensate storage tank water to the main condenser hotwell. Following identification, the licensee re-fabricated a gagging device in accordance with engineerings specifications. This issue was entered into the licensee\\\'s corrective action program as Action Request AR 00251720. The finding was more than minor because it affected the design control attribute of the Initiating Events 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 Inspection Manual Chapter 0609.04, Phase 1 Initial Screening and Characterization of Findings, the inspectors determined this finding to be of very low safety significance (Green) because the finding did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions will not be available. The inspectors determined that this finding had a cross-cutting aspect in the area of human performance associated with the decision making component because the licensee failed to implement roles and authorities as designed when fabricating the gagging device for COND-V-170 (H.1(a))
05000333/FIN-2011004-01FitzPatrick2011Q3Unplanned Power Reduction PI ReportingThe inspectors identified an unresolved item (URI) associated with FitzPatrick staff\\\'s interpretation of guidance for reporting unplanned power changes per 7,000 critical hours. Specifically, Entergy personnel did not report three power reductions during the second quarter of 2011 that the inspectors considered to have been reportable. The unplanned power changes per 7,000 critical hours performance indicator is defined as the number of unplanned changes in reactor power of greater than 20 percent of full-power, per 7,000 hours of critical operation excluding manual and automatic scrams. On January 11, 2011, FitzPatrick operators performed a power reduction to 55 percent to plug a leaking condenser tube. This power reduction was reported in the first quarter performance indicators as an unplanned power change. The root cause evaluation of this event determined that additional condenser tube leaks could occur. As a result, an operational decision-making issue (ODMI) action plan was developed by Entergy staff, which established four action levels for chemistry parameters (condensate demineralizer influent (COl) conductivity, reactor water conductivity, and reactor water chloride concentration). These action levels provide guidance for operators to perform a range of actions, such as a power reduction to support condenser tube plugging. The action plan was established on April 4, 2011. On May 6, 2011, operators observed indications of a rapid increase in hotwell conductivity and determined that COl conductivity increased to above action level 3. In accordance with the ODMI action plan operators reduced power to 55 percent later that day to identify and plug the leaking main condenser tube. The inspectors reviewed the guidance for reporting performance indicators in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. Concerning unplanned power reductions per 7,000 critical hours, the guidance states, This indicator captures changes in reactor power that are initiated following the discovery of an offnormal condition. If a condition is identified that is slowly degrading and the licensee prepares plans to reduce power when the condition reaches a predefined limit, and 72 hours have elapsed since the condition was first identified, the power change does not count. If, however, the condition suddenly degrades beyond the predefined limits and requires rapid response, this situation would count. In follow-up questions regarding the May 6 down power Entergy staff indicated that the down power was planned as a contingency action in the ODMI action plan and that, because the initial condition for which the action plan was written occurred greater than 72 hours prior to the down power, the down power should not be counted. The inspectors considered that notwithstanding an action plan, the condition was best described as a suddenly degrading condition that resulted in operators decreasing power the same day to address the condition. Therefore, it appeared to be appropriate to report the May 6 down power as unplanned. In addition, the inspectors determined that FitzPatrick operators performed two power reductions to 75 percent on June 7, and June 9, 2011, to support cleaning main condenser water boxes. This cleaning was necessary to address fouling that occurred during planned maintenance on the lake intake travelling screens. The fouling was the result of operation of circulating water system gates which caused sediment to be ingested by the circulating water system. The inspectors determined that FitzPatrick staff did not report these two down powers as unplanned in the second quarter PI. The inspectors reviewed the applicable guidance in NEI 99-02 which indicated that Anticipated power changes greater than 20 percent in response to expected environmental problems (such as accumulation of marine debris, biological contaminants, animal intrusion, environmental regulations, or frazil icing) may qualify for an exclusion from the indicator. The licensee is expected to take reasonable steps to prevent intrusion of animals, marine debris, or other biological growth from causing power reductions. Intrusion events that can be anticipated as a part of a maintenance activity or as part of a predictable cyclic behavior would normally be counted, unless the down power was planned 72 hours in advance ... FitzPatrick\\\'s staff indicated they considered this allowance to be applicable, in that they had taken reasonable steps to prevent intrusion by cleaning the lake water forebays prior to the maintenance. Because this activity had not been performed on line since the traveling screens had been replaced, station personnel also considered that they could not reasonably have anticipated the severity of the fouling that occurred. Finally, FitzPatrick staff included a contingency down power in the work week schedule, and noted in the applicable operating procedure that operation of the gates may require a power reduction to perform condenser cleaning. Notwithstanding an acknowledgement by FitzPatrick staff in their procedures and work week schedule as to the possibility of a need for a plant down power, the inspectors considered that these two down power conditions were anticipated as part of a maintenance activity and appeared to have not been planned 72 hours in advance. Therefore the inspectors had questions as to the appropriateness of not reporting the plant down powers on June 7, and June 9,2011. FitzPatrick staff initiated a review of these issues as part of the NRC and industry performance indicator frequently asked questions (FAQ) process. This item remains unresolved pending further information from the FAQ process. (URI 05000333/2011004-01, Unplanned Power Reduction PI Reporting)
05000219/FIN-2011003-02Oyster Creek2011Q2Difficulty in drawing a main condenser vacuum during plant startup due to water in 48 inch holdup lineAn unresolved item (URI) was identified to review the results of Exelon\\\'s investigation to identify the source of water that builds up in the 48 inch offgas header following a plant shutdown, an evaluation of the effect of that water on the inability to draw a vacuum in the turbine condenser on the subsequent startup, and to evaluate the effectiveness of the corrective actions taken following a similar event in 2006 to determine if a performance deficiency existed. The inspectors will review the results of Exelon\\\'s evaluation after it is completed, which had not occurred by the end of this inspection period. During the startup from the 1M26 outage in December 2010, Oyster Creek experienced a full reactor scram due to a main condenser low vacuum trip. Exelon performed a root cause evaluation, which was centered on operator performance issues, and documented the results in IR 1 155520. NRC inspectors reviewed the root cause report (RCR) in March 2011 and identified that the root cause evaluation did not address the issue of the difficulty of drawing a vacuum in the main condenser using the mechanical vacuum pump and three sets of air ejectors. Exelon generated IR 1 1931 10 to document the inspectors\\\' observation. During resident inspector follow-up of the issue, the inspectors identified that a similar event had taken place during the startup following the 1R21 outage in November 2006 and evaluated in an equipment apparent cause evaluation (EACE) documented in IR 556890. The inspectors identified that the source of the excess water found in the 48 inch hold up line was not identified in either the 2006 EACE or the 2010 RCR. Additionally, the inspectors questioned effectiveness of the corrective actions identified in the 2006 EACE due to the recurrence of the issue in 2010 which resulted in a reactor scram. The licensee documented the inspectors\\\' concerns in IR 1227974, which is currently being evaluated.
05000528/FIN-2011002-05Palo Verde2011Q1Inadequate Work Instructions for Condenser CoatingThe inspectors identified a self-revealing finding after Palo Verde Nuclear Generating Station failed to adequately perform maintenance activities associated with main condenser tube sheet coatings in Unit 3. As a result, a degraded tube was not replugged following coating and failed on January 15, 2011, resulting in high sodium levels in the condensate system. Operators entered the abnormal operating procedures for condenser tube rupture and reduced power to 40 percent power to facilitate troubleshooting and repairs. The licensee concluded that Work Order 3384533 and Procedure 31MT-9ZZ19, Tube Plugging of Secondary Heat Transfer Components, did not provide adequate instructions for the removal, accountability, and reinstallation of permanent plugs during maintenance. The licensee also concluded that engineering verification inspection practices were inadequate and no procedural guidance existed for the verification. The licensee completed repairs to the main condenser and returned Unit 3 to full power. The licensee entered the performance deficiency into the corrective action program as Palo Verde Action Request 3580739 and implemented immediate corrective actions to revise the pre-job brief checklist and maintenance work instructions for condenser tube plugging. The licensee has not completed all corrective actions for this issue. The inspectors determined that the performance deficiency is 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, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, the inspectors concluded that the finding is of very low safety significance (Green) because it did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions would not be available. This finding had a crosscutting aspect in the area of human performance associated with the resources component because the licensee failed to provide complete, accurate and up-to-date procedures and work packages for tube sheet coating, replugging and verification (H.2(c)).
05000387/FIN-2011002-05Susquehanna2011Q1lnadequate Maintenance Procedure Results in Steam Leak and Manual ScramA self-revealing finding of very low safety significance (Green) was identified when PPL personnel did not have adequate procedures to perform maintenance on a threaded connection on the \'5C\'feedwater heater (FWH) extraction steam bleeder trip valve, (BTVX 0245C. Specifically, existing maintenance procedures did not ensure that a threaded vent plug was reinstalled properly following maintenance. As a result, on January 25,2011, the threaded plug was ejeqted from the vent hole resulting in a steam leak that was un-isolable without removing thb main turbine from service. The steam leak caused malfunctions of non-safety-relatdd electrical systems and ultimately led to a manual reactor scram by control room operators. PPL entered this issue in their CAP as condition report CR 1346952. The finding was more than minor because thd finding was associated with the Initiating Events cornerstone attribute of Equipment Performance, and affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during power operatiofr. Specifically, failure of the pipe plug resulted in an un-isolable steam leak that ultirnately led to a manual scram. The inspectors evaluated the finding using IMC 0609, Attachment 4, lnitial Screening and Characterization of Findings, and determined the finding did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions would not be available. In this case, the main condenser was available as mitigation equipment once the turbine was tripped and the leak was isolated. Consequently, the finding is of very low safety significance This finding is related to the crosscutting area of Human Performance , because PPL did not ensure that personnel, equipment, procedures, and other resources were available and adequate to assure nuclear safety. Specifically, PPL did not ensure that complete, accurate and up to- date procedures were available to reinstall a threaded plug on a BTV in the FWH extraction steam line. (H.2(c))
05000458/FIN-2010005-05River Bend2010Q4Failure to Plug a Main Condenser Tube in Accordance with an Approved Work OrderThe performance deficiency was more than minor because it was associated with the human performance attribute of the Initiating Events Cornerstone and 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 power operations, in that the performance deficiency created a condition that upset plant stability by creating a condenser tube leak that prompted the plant to reduce power. The inspectors determined that the apparent cause of this finding was the licensees failure to use human performance error-prevention techniques to ensure that the tube plugging was performed correctly. This finding therefore has a crosscutting aspect in the work practices component of the human performance area because the licensee did not communicate and use human error prevention techniques commensurate with the risk of the assigned task, such that work activities are performed safely.
05000387/FIN-2010004-02Susquehanna2010Q3HPCI and RCIC CST Low-Level Suction Transfer Made Inoperable Due to Transfer of Water from Condenser Area to CST BermThe inspectors identified a Green NCV of Susquehanna Unit 1, TS 5.4.1, Procedures, for an inadequate procedure to transfer water from the condenser area to the condensate storage tank (CST) berm. Specifically, the procedure failed to include a maximum level in the CST berm that was acceptable to limit interactions with other safety-related equipment. The NCV was identified following the July 16, 2010, Unit 1 manual reactor scram due to a non-isolable circulating water leak in the main condenser area. Operations personnel commenced dewatering efforts by transferring water from the condenser area to the CST berm using a Liquid Radwaste Collection operating procedure as a guide. Water was transferred to the berm to a level sufficient to cause water intrusion into cable conduit and junction boxes containing High Pressure Coolant Injection system (HPCI) and Reactor Coolant Isolation Cooling system (RCIC) CST low level suction instrumentation which transfers HPCI and RCIC pump suction from the CST to the suppression pool. As a result, the low-level suction instrumentation became submerged affecting the reliability and capability of the HPCI and RCIC CST to suppression pool transfer function despite being required in Mode 3. The issue was entered into PPL\'s CAP (1297039). This performance deficiency is more than minor as it affected the equipment performance and procedural quality attributes of the corresponding Mitigating Systems cornerstone objective to ensure the reliability and capability of systems that respond to initiating events to prevent undesirable consequences (Le., core damage). Specifically, the low-level suction instrumentation was not designed for submergence. Transferring too much water from the condenser bay to the CST berm submerged the low-level suction instrumentation and affected the reliability and capability of the HPCI and RCIC CST to suppression pool transfer function. The finding was evaluated for significance using IMC 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings. Since the finding did not result in a loss of safety function or the loss of a train for greater than its TS allowed outage time, and was not potentially risk significant due to external event initiators, the finding was determined to be of very low safety significance (Green). This finding was determined to have a cross-cutting aspect in the area of Human Performance, Resources, because PPL did not ensure that procedures were adequate to assure nuclear safety. Specifically, operating procedure OP-169-004, Revision 17, did not specify a maximum level that could be transferred to the CST berm to limit interactions with safety-related, HPCI and RCIC low-level suction transfer instrumentation.
05000237/FIN-2010003-03Dresden2010Q2Undocumented Technical Basis for change to EOP ATWS Mitigation StrategyDuring the conduct of one of the dynamic simulator scenarios, the inspectors identified an unresolved item related to procedure implementation. 15 Enclosure During one of the dynamic simulator scenarios, conditions were simulated during an Anticipated Transient Without Scram (ATWS) that required the operating crew to lower reactor pressure vessel (RPV) water level in accordance with emergency operating procedure DEOP 400-5, Failure to SCRAM. The purpose of lowering RPV water level is to reduce core inlet sub-cooling and thus reduce the potential for power oscillations. DEOP 400-5, directs the operators to Terminate and Prevent all injection flow into the RPV except for flow from the CRD and Standby Liquid Control (Boron) systems. Contrary to the BWR Owners Group (BWROG) Emergency Procedure Guidelines (EPG) and Severe Accident Guidelines (Revision 2) which states that failure to completely stop RPV injection flow (with the exception of CRD, RCIC, and Standby Liquid Control) would delay the reduction in core inlet sub-cooling, thus increasing the potential for flux oscillations the crew was observed to implement this step in accordance with the licensees expectations, by decreasing the FWLC SETPOINT to -40 inches in incremental steps, such that the set point was always less than actual level. Using this method, feedwater flow was not actually stopped but level was dropped to -35 inches in approximately 1.5 minutes. When asked why the licensees procedural steps deviated from the BWROG EPG, the licensee stated that the deviation was necessary to prevent the loss of the Main Condenser heat sink (bypassing the Group 1 Isolation interlocks is performed in parallel and cannot be completed quick enough to prevent isolation of the Main Steam lines if flow is terminated completely). The BWROG EPG states that reducing reactor power and preventing power oscillations is of greater importance than preventing loss of the main condenser. Technical Specification 5.4.1 requires, in part, that written procedures/instructions be established, implemented, and maintained covering the emergency operating procedures required to implement the requirements of NUREG-0737, Clarification of TMI Action Plan Requirements, and NUREG-0737, Supplement 1, as stated in GenericLetter 82-33. NUREG-0737 and the associated Supplement 1 requires licensees to analyze transients and accidents, prepare emergency procedure technical guidelines, and develop symptom-based emergency operating procedures based on those technical guidelines. The BWROG EPG provides the technical basis for the development of the emergency operating procedures used by BWR licensees. Licensees are permitted to deviate from the BWROG guidelines provided they document the technical basis for the deviation. When asked to provide justification for the deviation from the BWROG EPG, the licensee was unable to do so. The licensee has initiated an engineering evaluation to provide the necessary basis for the deviation. This issue is an URI pending further NRC review and completion of the licensees actions to provide the necessary documentation to support the deviation: (URI 05000237/2010003-03; 05000249/2010003-03, Undocumented Technical Basis for Change to EOP ATWS Mitigation Strategy)
05000361/FIN-2010003-11San Onofre2010Q2Failure to Follow Station Procedures on Written Instruction Use and AdherenceThe inspectors identified a finding for the failure of the licensee to follow its procedures for written instruction use and adherence during a test to determine the impact on main condenser vacuum of a damaged feedwater heater. Specifically, on May 5, 2010, while performing a vacuum test on a sixth point feedwater heater, an operator failed to stop the activity, as required by Procedure SO123-XV-HU-3, Written Instruction Use and Adherence, Revision 3, when he encountered unclear and conflicting work instructions. This issue was entered into the licensees corrective action program as Nuclear Notification NN 200909706. The performance deficiency is more than minor because it affected the human performance attribute of the Initiating Events Cornerstone objective to limit the likelihood of those events that upset plant stability during power operations, and is therefore a finding. Using Manual Chapter 0609, Significance Determination Process, Phase 1 Worksheets, the finding is determined to have very low safety significance because it did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions would not be available. This finding has a crosscutting aspect in the area of human performance associated with the component of work practices because the licensee failed to communicate human error prevention techniques such that work activities were performed safely (H.4(a))
05000261/FIN-2010009-07Robinson2010Q2Loss of Seal Water Results in Failure of the A Main Condeser Vacuum PumpThe team observed that procedure GP-004 Post Trip Stabilization contained a step to reset the generator lockout relays but did not contain steps, cautions, or notes that prompt operators to ensure the inputs are clear prior to attempting a reset. Although AOP-024, Loss of Instrument Buses was not used, and was not required to be used per the licensees procedure use guidelines during this event, the team noted that the procedure does not address the effect of a loss of an instrument bus on the main steam flow channels that input into the Main Steam Line Isolation Signal. Additionally, AOP-024 does not address the loss of CCW flow to the RCP thermal barrier heat exchangers (FCV-626 closure). The team reviewed the circumstances which resulted in the fire in and subsequent failure of the A Main Condenser Vacuum Pump. The pump failed because seal water to the pump, which is supplied by demineralized water, was lost for approximately three and a half hours prior to the pump failure. The loss of power following the first fire caused the loss of demineralized water. The Main Condenser Vacuum Pump establishes and maintains condenser vacuum to provide a heat sink used for decay heat removal following a reactor trip. The team observed that the licensee does not have a procedure to address loss of seal water makeup to the main condenser vacuum pumps. Use of such a procedure could have prevented the fire and associated damage to this equipment. As a result of this observation, the team identified the need for additional NRC review to determine if procedures should have been available to address a sustained loss of seal water makeup to the main condenser vacuum pumps. Additional review by the NRC will be needed to determine whether the lack of a procedure for loss of seal water to the main condenser vacuum pumps is a performance deficiency. An Unresolved Item will be opened pending completion of this review. The URI is identified as 05000261/2010009-07, Loss of Seal Water Results in Failure of the A Main Condenser Vacuum Pump.
05000482/FIN-2010002-02Wolf Creek2010Q1Failure to Establish Goals and Monitor for a (1) Offgas Radiation Monitor GERE0092The inspectors identified a noncited violation of 10 CFR 50.65 for failure to establish goals per paragraph (a)(1) to monitor the performance of the main condenser offgas radiation Monitor GERE0092. Multiple failures occurred which exceeded the monitoring goals and the function was not moved to 50.65(a)(1) status for corrective action and goal setting. Wolf Creek engineering subsequently evaluated the issues and determined that the function should have been moved to a(1) for goal setting. The licensee entered this issue in their corrective action program as Condition Report 24423. This finding is more than minor because it is associated with the equipment performance attribute of the Mitigating Systems Cornerstone and affects the cornerstone objective to ensure the availability, reliability and capability of systems that respond to initiating events. The inspectors evaluated the significance of this finding using Inspection Manual Chapter 0609.04, Phase 1 Initial Screening and Characterization of Findings, and determined that this finding is of very low safety significance, Green. Specifically, the associated function (SP-04) to detect primary to secondary leakage and then isolate the steam generator blowdown flow path does not result in a loss of any safety function. The inspectors determined that this finding has a crosscutting aspect in the problem identification and resolution area associated with corrective action program because Wolf Creek failed to take appropriate corrective actions to address the system reliability issue and adverse radiation monitor performance trends in a timely manner, commensurate with safety significance and complexit
05000327/FIN-2009005-02Sequoyah2009Q4Reactor Trip due to Inadequate Transformer Bus Duct Maintenance ProcedureA self-revealing finding was identified for an inadequate maintenance procedure which was used to perform a periodic maintenance activity to clean and inspect the bus duct associated with the D common station service transformer (CSST). This resulted in the bus duct being left in a condition that allowed for water intrusion to occur, which led to a fault that caused a loss of one offsite power supply and an automatic reactor trip of both units with main feedwater unavailability. The licensee entered this issue into the corrective action program (CAP) as PER 166884. The finding was determined to be greater than minor because it was associated with the procedure quality 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. Specifically, the use of an inadequate procedure directly contributed to the loss of one offsite power supply and an automatic reactor trip of both units with main feedwater unavailability. Using Inspection IMC 0609, Significance Determination Process, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, the finding was determined to be applicable to a Phase 2 analysis since the finding contributed to both the likelihood of a reactor trip and the likelihood that mitigating systems will not be available. Using IMC 0609 Appendix A, Determining the Significance of Reactor Inspection Findings for At-Power Situations, a Phase 2 analysis was performed using the site specific risk-informed inspection notebook. The finding was assumed to affect the initiating event likelihood (IEL) of a Transient With Loss of Power Conversion System (TPCS), since power availability to the unit boards affects reactor coolant pump function as well as main condenser availability. A regional Senior Reactor Analyst performed a Phase 3 Significance Determination Process evaluation. The evaluation concluded the finding was of very low safety significance (Green) based on an assumed unavailability of the CSST B fast transfer function of 0.11/yr. No cross-cutting aspect was identified since the issue was not reflective of current licensee performance, in that the inadequate maintenance procedure was implemented in December 2006
05000483/FIN-2009005-01Callaway2009Q4Failure to Maintain an Adequate Flooding AnalysisThe inspectors identified a noncited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, after AmerenUE failed to provide adequate design control measures for verifying the adequacy of flooding analysis for the auxiliary feedwater pipe chase room 1206/1207. The revised calculation, performed on December 4, 2001, determined that the 10-inch piping from the condensate storage tank going to the main condenser was the limiting source of potential flooding. However several missing or incorrect assumptions challenged the basis for operability of safety related auxiliary feedwater pump related transmitters located in the room 22 inches above the floor level. On December 16, 2009, the licensee reperformed the flooding analysis calculation, M-FL-04, Revision 5, including the main condenser as an additional source of flooding. Although 984 gpm of margin was lost due to inclusion of the condenser as a source, the revised analysis supported an operability determination for the transmitters as operable. This finding was determined to be greater than minor because it impacted the Mitigating Systems Cornerstone attribute of design control and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using Manual Chapter 0609.04, Phase 1 Initial Screening and Characterization of Findings, this issue screened as very low safety significance because it was not a design or qualification deficiency that resulted in a loss of operability or functionality, did not create a loss of system safety function of a single train for greater than the technical specification allowed outage time, and did not increase the likelihood of a seismic, flooding, or severe weather initiating event. This finding was determined to not have a crosscutting aspect as the calculation of record was not reflective of current licensee performanc
05000440/FIN-2009004-05Perry2009Q3Licensee-Identified ViolationPerry TS 5.7.1 states, in part, that each high radiation area shall be barricaded and conspicuously posted as a high radiation area. Contrary to the above, on March 11, 2009, the reactor water reject line to the main condenser was identified to have dose rates up to 235 mRem/hr at 30cm thereby creating a high radiation area in the main condenser hotwell. A violation of regulatory requirements occurred when the area was not effectively barricaded, controlled, and conspicuously posted as a high radiation area. This was identified in the licensees CAP as CR 09-55159. Immediate corrective actions were to post and barricade the area in accordance with station procedures and applicable regulatory requirements. The finding was determined to be of very low safety significance because it was not an ALARA planning issue, there was no overexposure nor potential for overexposure, and the licensees ability to assess dose was not compromised
05000346/FIN-2008002-03Davis Besse2008Q1Unexpected Reactivity Excursion Due to Unidentified Valve Position During Post Repair Air Pressure TestingA self-revealing finding was identified for the failure of operators to maintain configuration control of valves during an air pressure test of a repair of a feedwater heater. Specifically, the operators left valve RD198 open during a pressure test of the extraction steam, or shell side, of feedwater heater 1-5 of the Main Feedwater System. This loss of configuration control gave testing air a path to the main condensers and led to degradation of the condenser vacuum, which then caused the Integrated Control System to raise reactor power unexpectedly. No violation occurred. Once the issue was identified, the licensee stopped the air pressure test and entered the finding into their corrective action program. The finding is greater than minor since it was associated with the configuration controloperating equipment lineup attribute of the Initiating Events Cornerstone and because it affected the associated cornerstone objective to limit the likelihood of those events that upset plant stability during power operations. The finding is of very low safety significance since it did not contribute to the likelihood of a primary or secondary system loss of coolant accident, did not contribute to both the likelihood of a reactor trip and the likelihood that mitigating equipment or functions would not be available, and did not increase the likelihood of a fire or internal/external flood. The finding was associated with the cross-cutting area of human performance in that work control and specifically the coordination of work activities did not properly record or assess the status of a valve in the test boundary and created a condition that had an operational impact (H.3(b)). (Section 4OA3
05000341/FIN-2007006-02Fermi2007Q4Undocumented Technical Basis for Change to EOPDuring one of the dynamic simulator scenarios, conditions were simulated during an Anticipated Transient Without Scram (ATWS) that required the operating crew to lower reactor pressure vessel (RPV) water level in accordance with emergency operating procedure (EOP) 29.100.01, Sheet 1A, RPV Control-ATWS. The purpose of lowering RPV water level is to reduce core inlet sub-cooling and thus reduce the potential for power oscillations. EOP 29.100.01, Sheet 1A, directs the operators to Terminate and Prevent all injection flow into the RPV except for flow from the CRD, Reactor Core Isolation Cooling (RCIC), and Standby Liquid Control (Boron) systems. Contrary to the BWR Owners Group (BWROG) Emergency Procedure Guidelines (EPG) and Severe Accident Guidelines (Revision 2) which states that failure to completely stop RPV injection flow (with the exception of CRD, RCIC, and Standby Liquid Control) would delay the reduction in core inlet sub-cooling, thus increasing the potential for flux oscillations the crew was observed to implement this step (FSL-10), in accordance with the licensees expectations, by turning OFF the low pressure Emergency Core Cooling Systems (ECCS) and Standby Feedwater pumps, reducing High Pressure Coolant Injection flow to 0 gpm, and reducing (i.e., NOT stopping) Feedwater system flow so that level decreased in a controlled manner. When asked why the licensees procedural steps deviated from the BWROG EPG, they stated that the deviation was necessary to allow time for bypassing of interlocks to prevent the loss of the Main Condenser heat sink, and to prevent dropping water level below the top of active fuel. The BWROG EPG states that reducing reactor power and preventing power oscillations is of greater importance than preventing loss of the main condenser. Technical Specification 5.4.1 requires, in part, that written procedures/instructions be established, implemented, and maintained covering the emergency operating procedures required to implement the requirements of NUREG-0737, Clarification of TMI Action Plan Requirements, and NUREG-0737, Supplement 1, as stated in Generic Letter 82-33. NUREG-0737 and the associated Supplement 1 required licensees to analyze transients and accidents, prepare emergency procedure technical guidelines, and develop symptom-based emergency operating procedures based on those technical guidelines. The BWROG EPG provides the technical basis for the development of the emergency operating procedures used by BWR licensees. Licensees are permitted to deviate from the BWROG guidelines provided they document the technical basis for the deviation. When asked to provide justification for the deviation from the BWROG EPG, the licensee was unable to do so. The licensee has initiated action (CARD 07-28195), through their corrective action program, to provide the necessary basis for the deviation. This issue is an Unresolved Item (URI) pending further NRC review and completion of the licensees actions to provide the necessary documentation to support the deviation: URI 05000341/2007006-02, Undocumented Technical Basis for Change to EOP ATWS Mitigation Strategy.
05000254/FIN-2007003-06Quad Cities2007Q2Review of Unit 1 4 kV Breaker FailuresOn May 7, 2007, the 1D residual heat removal pump breaker, a 4 kV Merlin Gerin AMHG model breaker, tripped open while operations personnel attempted to place the pump in service using QCOP 1000-10, Torus Water Transfer to the Main Condenser Via the Condensate Demineralizers. The licensee developed and implemented a detailed troubleshooting plan and was able to identify that the breaker cubicle mechanism operated cell switch linkage assembly cam follower rod length was slightly out of tolerance. This caused the attached cam follower to come in contact and apply a load to the breakers spring discharge roller. Strike marks (minor wear marks) were made on the cam follower due to contact with the breakers spring discharge roller. The spring discharge roller then applied a pre-load to the breakers trip paddle which made the breaker very susceptible to tripping during breaker movement. The licensees extent of condition review for Unit 1 included an inspection of all 48 4 kV Merlin Gerin AMHG model breaker cubicles before completion of the 2007 refueling outage. In addition, the licensee was in the process of implementing an inspection schedule for Unit 2 and had inspected 10 of the 47 4 kV breaker cubicles that contained the 4 kV Merlin Gerin AMHG model breakers by the conclusion of the inspection period. The inspectors noted that the licensee found strike marks on the 4 kV breaker cubicles cam followers for the Unit 12 emergency diesel generator feed to Bus 13-1, the 1A core spray pump, the 1B residual heat removal pump, the 1D residual heat removal service water, and the 1C condensate booster pump. Once identified, the licensee implemented a design change to remove a small portion (approximately 1/4 inch) of the cam follower in the location where strike marks were being found. This was implemented for cam followers in all breaker cubicles that had been inspected and for those that were to be inspected. The removal of the material will allow a larger gap between the cam follower and breakers spring discharge roller to add margin and prevent the breaker from tripping due to the physical contact between components. The inspectors consider the licensees corrective actions appropriate to prevent recurrence regarding this failure mode. At the conclusion of the inspection period, the inspectors had several unanswered questions regarding the causes of and contributors to the 4 kV Merlin Gerin breakers failure to remain in the closed condition. Based on the unanswered questions, the inspectors determined that this item should be unresolved pending review of the licensees final apparent cause evaluation report (URI 05000254/2007003-06; 05000265/2007003-06).
05000271/FIN-2000003-01Vermont Yankee2000Q2N/AThe team identified that the augmented off-gas building ventilation system failed a surveillance in May 1999. Subsequently, the licensee identified that the shutdown iodine filter for the mechanical vacuum pump for the main condenser failed a surveillance in March 1998. In both cases, a work request was initiated to repair the system; but no ER was written, as required by the ER procedure. The team identified a third example where a work request was initiated to resolve a discrepancy related to an alarm setpoint, but the request was canceled without resolving the problem. Nonetheless, the failure to initiate ERs for the first two issues is a violation of the VY Technical Specifications related to procedure implementation, and is being treated as a Non-Cited Violation. The violation was not assessed using the Significance Determination Process, as it did not impact one of the cornerstones; however, it provides substantive information relative to the cross cutting issue of problem identification and resolution. (Section 4OA2.1)
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