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| Quarter | Site | Title | Description | |
|---|---|---|---|---|
| 05000369/FIN-2018012-01 | 2018Q3 | Mcguire McGuire | Failure to Translate Seismic Mounting Requirements for 125 VDC Vital Batteries into Installation and Replacement Procedure | The inspectors identified a Green finding and associated non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion III, Design Control, when the licensee failed to translate the mounting requirements for seismic qualification contained in NLI technical calculation C-017-074-2, Vital Instrumentation & Control Batteries & Racks Equipment Qualification Calculation, Rev. 0, into their battery replacement and installation procedure IP/0/A/3061/003, 125 Volt Vital Battery Maintenance and Repair, Rev. 23 |
| 05000287/FIN-2016003-02 | 2016Q3 | Oconee | Licensee-Identified Violation | Technical Specification (TS) 5.4.1., Procedures, states, in part, written procedures shall be established, implemented, and maintained covering activities described in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Procedure MP/0/A/3009/017, Visual PM Inspection and Electrical Motor Tests is used by the licensee during maintenance of electric motors. Contrary to the above, on April 25, 2016, the licensee did not adequately implement maintenance procedure MP/0/A/3009/017. Specifically, the licensee incorrectly wired the 3C RBCU motor control center contactor leads during maintenance causing 3C RBCU fan to operate in the reverse direction. On June 16, 2016, during an engineer walkdown, the engineer noted anomalies in the RBCU inlet temperature readings. On June 28, 2016, while investigating the temperature readings the licensee discovered that the 3C RBCU fan was operating in the reverse direction and declared the 3C RBCU inoperable. The 3C RBCU was inoperable when the plant entered Mode 4 on May 14, 2016 until June 28, 2016 when the 3C RBCU was repaired (approximately 45 days). Technical Specification 3.6.5, Reactor Building Spray and Cooling Systems, requires all three trains of RBCU operable while in Modes 1, 2, 3, and 4. On May 14, 2016, Unit 3 was starting-up from the refueling outage and entered Modes 4 through 1 with one train of RBCU inoperable. This action of changing modes with the 3C RBCU inoperable is prohibited by TS 3.0.4. The licensee entered this condition into their corrective action program as NCR 02041501. The licensee also restored 3C RBCU operability, trained/counseled technicians, and incorporated a procedure change which will enhance configuration control for the lifted leads aspect in the maintenance procedure for this activity. This finding was assessed using IMC 0609, Phase 1 screening worksheet of Attachment 4, Appendix A, and Appendix H, and was determined to be of very low safety significance (Green). |
| 05000269/FIN-2016003-01 | 2016Q3 | Oconee | Failure to Translate Design Requirements to Prevent the Effects of Waterhammer | The NRC identified a finding for the licensees failure to translate the limiting flow rate design requirement into station procedures used to start and operate the alternate reactor building cooling (RBC) system, in accordance with the Duke Energy Carolinas Topical Report, Quality Assurance Plan (QAP). Specifically, the licensee failed to translate the limiting flow rate of 170 gallons per minute (gpm) into Procedure AP/0/A/1700/051, Alternate Reactor Building Cooling, Revision (Rev.) 2, to ensure prevention of waterhammer on the A reactor building cooling unit (RBCU) or connecting low pressure service water (LPSW) lines when starting the RBCU Hale pump. The licensee entered this issue into their corrective action program as Action Request (AR) 02049903 and revised Procedure AP/0/A/1700/051 to limit the RBCU Hale pump discharge flow to each affected unit to an initial fill rate of 120 gpm or less. The performance deficiency was determined to be more than minor because it adversely affected the protection against external factors attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, opening the RBCU Hale pump discharge valve four turns, as specified in the procedure, would have resulted in filling the alternate RBC system at approximately 600-700 gpm and exceeding the design flow rate of 170 gpm established to prevent equipment and piping damage as a result of waterhammer. This provided a reasonable doubt that the alternate RBC system had the capability to reliably perform its intended safety function and, in turn, that the protected service water (PSW) system had the capability to meet its 30-day mission time during a turbine building fire that resulted in a loss of offsite power. The finding was determined to be of very low safety significance (Green) because the finding would not have resulted in a fire that caused secondary fires outside of the originating fire area due to circuit issues and did not affect the ability to reach and maintain a stable plant condition within the first 24-hours of a fire event. The inspectors determined the finding was indicative of present licensee performance and was associated with the cross-cutting aspect of design margin, in the area of human performance. Specifically, the licensee failed to operate and maintain the alternate RBC system equipment within design margins when they did not translate design requirements from Engineering Change (EC) 110008 and Calculation OSC-8107 into station procedures. |
| 05000414/FIN-2015003-01 | 2015Q3 | Catawba | Failure to Promptly Replace a Frequently Operated Sliding Link | An NRC identified non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, was identified for the licensees failure to promptly implement corrective actions to replace a frequently operated sliding link associated with the 2A train auxiliary feedwater (CA) control circuitry. As a result, the sliding link failed prior to replacement which affected the function to automatically swap from the normal source to the assured source (nuclear service water) on low suction pressure to the 2A motor driven CA pump. The licensee replaced the failed sliding link and entered the issue into their corrective action program. The inspectors determined that the licensees failure to promptly implement corrective actions for a previously identified vulnerability with frequently operated sliding link E-12 was a performance deficiency (PD). The PD was more than minor because it was associated with the equipment performance attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failed sliding link resulted in the inoperability of the 2A train of CA. The finding was determined to be of very low safety significance because of the multiple sources of water available to the CA pump before the assured source was needed, and the short duration that the steam generator injection lines valves were closed. This finding had a cross-cutting aspect of resolution (P.3), as described in the problem identification and resolution cross-cutting area as the licensee failed to replace sliding link E-12 in a timely manner commensurate with its safety significance. |
| 05000261/FIN-2014008-01 | 2014Q2 | Robinson | Failure to Take Adequate Corrective Action to Preclude Repetition of a Significant Condition Adverse to Quality Associated with the Steam Generator Tube Leak | The team identified a Green NCV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Actions, for the licensees failure to take adequate corrective action to prevent repetition of a significant condition adverse to quality regarding steam generator tube leakage due to poor maintenance practices. Specifically, on February 27, 2014, the C steam generator showed indications of a primary to secondary tube leak due to foreign material that was introduced during the fall 2013 refueling outage. As immediate corrective actions, on March 7, 2014, the licensee shutdown the plant and repaired the leak. This violation was entered into the licensees CAP as nuclear condition reports (NCRs) 683695, 683593, and 683591. The licensees failure to implement appropriate corrective actions to address poor worker practices to prevent recurrence of a steam generator tube leak was a performance deficiency. The finding was more than minor because it was associated with the initiating events cornerstone equipment performance attribute and it adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, foreign material entered the steam generator and damaged a steam generator tube, which increased the likelihood of a steam generator tube rupture. The inspectors screened this finding using IMC 0609, Appendix A, The Significant Determination Process (SDP) For Findings At-Power, dated June 19, 2012. The finding screened as Green per Section D of Exhibit 1, Initiating Events Screening Questions, because testing showed that the affected steam generator tube could sustain three times the differential pressure across the tube during normal full power and that the steam generator did not violate the accident leakage performance criterion. The performance deficiency does not have a cross cutting aspect because the last revision of the root cause evaluation was completed in 2011 and it is not indicative of current licensee performance. |
| 05000259/FIN-2013011-05 | 2013Q2 | Browns Ferry | Maintenance Personnel Not Following Clearance Procedure Violation | The team identified a Green non-cited violation (NCV) of Technical Specification (TS) 5.4.1, Procedures. The team determined that the maintenance Primary Authorized Employee (PAE) did not verify that all blocking points were danger tagged to ensure worker personal safety and equipment protection for the A2 RHRSW pump planned maintenance. The PAEs decision to only verify two of nine clearance components was a violation of TVA Corporate Procedure NPG-SPP-10.2, Rev. 5, Clearance Procedure to Safely Control Energy . The maintenance PAE did not ensure that the A2 RHRSW pump was isolated from an unexpected release of energy that could have resulted in personnel injury or pump damage. The PAE did not verify or recognize that the A2 RHRSW pump manual discharge valve was full open and not danger tagged closed on May, 6, 2013. This performance deficiency was reasonably within BFNs ability to foresee and correct. This Finding was more than minor because, if left uncorrected the BFN Maintenance Supervisors failure to follow the clearance and tagging procedure requirement to verify all danger tag blocking points, he only verified two of nine danger tags, for the A 2 RHRSW planned pump the performance deficiency would have the potential to lead to a more significant safety concern, such as more severe plant transients, engineered safeguard system malfunctions, and a higher probability of personnel injury. The team determined that this Finding was of very low safety significance (Green) because it did not represent an actual loss of safety function or safety systems out of service for greater than the TS allowed outage time. The team identified a cross-cutting aspect in the Work Practices component of the Human Performance area. Specifically, the licensee ensures supervisory and management oversight of work activities such that nuclear safety is supported. |
| 05000324/FIN-2013002-04 | 2013Q1 | Brunswick | Implementation of Enforcement Guidance (EGM) 11-003, Revision 1, Enforcement Guidance Memorandum on Dispositioning Boiling Water Reactor Licensee Noncompliance with Technical Specification Containment Requirements During Operations with a Potential for Draining the Reactor Vessel | A violation of TS 3.6.4.1 was identified. However, because the violation was identified during the discretion period described in EGM 11-003, Revision 1, the NRC is exercising enforcement discretion in accordance with Section 3.5, Violations Involving Special Circumstances, of the NRC Enforcement Policy and, therefore, will not issue enforcement action for this violation, subject to a timely license amendment request being submitted. |
| 05000324/FIN-2013002-01 | 2013Q1 | Brunswick | Failure to Follow Procedure for Variable Frequency Drive Reactor Recirculation Pump Design Modification | An NRC-identified Green finding was identified for the failure of the licensee to follow Procedure EGR-NGGC-0005, Engineering Change (EC), when performing the variable frequency drive (VFD) modification for the reactor recirculation pumps (RRPs). Specifically, between April 4, 2010 and the present, the licensee inappropriately used a Rapid Field Release (RFR) to revise the power supplies for the relays in the VFD system without re-evaluating the EC, the 10 CFR 50.59 Screen/Evaluation, and the Failure Modes and Effects Analysis (FMEA). This resulted in a new failure mode on a loss of the power supply causing a RRP runback and placing the plant in a flow transient, and a loss of cooling to the RRP seals. The licensee entered this issue into the corrective action program (CAP) as nuclear condition report (NCR) 581202. The performance deficiency associated with this finding was the failure of the licensee to follow Procedure EGR-NGGC-0005, Engineering Change (EC), when performing the VFD modification for the RRPs. The finding was more than minor because it was associated with the design control attribute of the Initiating Events Cornerstone and affects 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, the VFD modification inappropriately causes a RRP runback on a loss of 480 VAC and core flow instability, and a loss of cooling to the RRP seals. Using IMC 0609, Appendix A, issued June 19, 2012, The SDP for Findings At-Power, the inspectors determined the finding was of very low safety significance because as a transient initiator due to the RRP runback, 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. The inspectors determined the finding was also of very low safety significance because as a loss of coolant accident (LOCA) initiator, after a reasonable assessment of degradation, the finding would not result in exceeding the reactor coolant system leak rate for a small break LOCA or likely affect other systems used to mitigate a LOCA resulting in a total loss of their function. The finding has a cross-cutting aspect in the area of human performance associated with the work control attribute because the licensee did not appropriately coordinate work activities by incorporating actions to address the impact of changes to the work scope, associated with the VFD modification, on the plant. |
| 05000324/FIN-2013002-03 | 2013Q1 | Brunswick | Licensee-Identified Violation | The following violation of very low safety significance (Green) was identified by the licensee and is a violation of NRC requirements which meets the criteria of the NRC Enforcement Policy, for being dispositioned as a Non-Cited Violation. Technical Specification 5.7.1, High Radiation Area, requires posting and barricading of HRAs with dose rates not exceeding 1 Rem/hour at 30 centimeters from the radiation source or from any surface penetrated by the radiation. Contrary to this, on April 25, 2012, an unposted and unbarricaded HRA was identified by the licensee in the Unit 1 Reactor Building 80 elevation Reactor Water Clean-Up (RWCU) Precoat Tank area. During the previous shift, following a RWCU Back Wash Receiving Tank (BWRT) resin transfer drop to the Radwaste RWCU phase separators, a survey was performed and the area was downposted from HRA to RA. However, the survey failed to detect dose rates on the piping underneath the Unit 1 RWCU Precoat tank of 2.5 Rem/hour contact and 0.4 Rem/hour at 30 centimeters. The elevated dose rates were not found until a procedurally required follow-up survey was performed approximately 3.5 hours later by another HP technician. The technician took immediate corrective actions including posting and barricading the affected area. This finding was of very low safety significance (Green) because there was no substantial potential for overexposure. This was based on the fact that no workers entered the hotspot area underneath the Precoat tank during the brief period that the area was not properly controlled. In addition, the dose rates involved were not high enough to provide a substantial potential for overexposure. The licensee entered the issue into their CAP as NCR 532588. |
| 05000324/FIN-2013002-02 | 2013Q1 | Brunswick | Flood Impacts Due to Degraded Flood Protection Measures | The inspectors are opening a URI associated with the potential for flood intrusion into the service water building, reactor building, and emergency diesel generator building due to degraded flood protection measures to determine if a performance deficiency exists. From August through October, 2012, the licensee performed walkdowns of flood protection measures in accordance with Nuclear Energy Institutes 12-07 Walkdown Guidance. The licensee and inspectors identified degraded or missing flood protection measures in the service water building, reactor building, and emergency diesel generator building. The inspectors are opening a URI to review the licensees evaluation of these flood protection deficiencies and determine if a performance deficiency exists. The licensee entered these issues into the CAP as NCR 600850. This issue is being tracked as: URI 05000325/2013002-02 and 05000324/2013002-02, Flood Impacts due to Degraded Flood Protection Measures. |
| 05000269/FIN-2012004-01 | 2012Q3 | Oconee | Failure to Maintain Accurate Pre-Fire Plans | An NRC-identified non-cited violation of the Oconee Units 1, 2, and 3 renewed facility operating licenses, condition 3.D. was identified for the licensees failure to maintain accurate pre-fire plans in areas that contain safety related equipment. Discrepancies such as failure to identify compressed gas cylinder and chemical storage areas, fire extinguisher locations, and physical building characteristics were identified in 79 fire zone pre-fire plans. The licensee modified the pre-fire plans to correct the deficiencies. This violation was entered into the licensees corrective action program (CAP) as PIP O-12-10817. The performance deficiency (PD) was more than minor because it was associated with the Mitigating Systems Cornerstone Attribute of Protection Against External Events (Fire) and adversely affected the cornerstone objective in that inaccurate pre-fire plans could impact the fire brigades ability to effectively fight a fire. The inspectors determined that the finding was of very low safety significance (Green) because an alternate means of safe shutdown was available, the fire brigade consisted of plant personnel familiar with the plant layout and associated hazards, and appropriate firefighting equipment was available in each area. The cause of the PD was directly related to the aspect of complete, accurate, and up-to-date procedures of the Resources Component in the cross cutting area of Human Performance because the licensee failed to ensure that other personnel were assigned the responsibility to maintain the pre-fire plans. |
| 05000400/FIN-2012004-01 | 2012Q3 | Harris | Failure to Adequately Perform Containment Visual Inspection When Containment Integrity is Required | The inspectors identified a Green NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, when the licensee failed to adequately correct a previously identified issue associated with the performance of OST-1081, Containment Visual Inspection when Containment Integrity is Required. Specifically, on June 3, 2012 during an independent containment closeout inspection by the NRC resident inspectors, cables were identified as not having been analyzed for the impact on the operation of the containment sumps. The licensee did not identify or reconcile the unanalyzed cables in containment during the performance of OST-1081. The licensee removed a large portion of the cabling and then completed an operability evaluation, while in mode 3, on June 6, 2012 for the cables that remained. The evaluation concluded that the containment sump was fully operable, but with reduced margin because of the cables. The cables were further analyzed and recorded in Engineering Change 87249, with a similar conclusion. The issue was placed into the corrective action program (CAP) as action request (AR) #566201. The licensees failure to adequately identify and take prompt corrective actions to evaluate temporary cables in containment during OST-1081, which had not been previously analyzed was identified as a performance deficiency. The performance deficiency was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone and it adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, it could potentially cause one or more Residual Heat Removal (RHR), Containment Spray (CT) pumps, and associated Emergency Core Cooling Systems (ECCS) trains to be inoperable in the event that the containment sump became clogged and lost the required Net Positive Suction Head (NPSH) to the pump, during certain accidents. Using IMC 0609, Significance Determination Process, this finding was determined to be of very low safety significance because it was not a design or qualification deficiency, did not represent an actual loss of function of at least a single train for greater than the Allowed Out-of-service Time (AOT) or two separate safety systems out-of-service for greater than the AOT, did not result in a loss of safety function of one or more non-Technical Specification (TS) trains of equipment designated as risk significant for greater than 24 hours, and did not involve the loss or degradation of equipment or function specifically designed to mitigate a seismic, flooding, or severe weather initiating event (e.g., seismic snubbers, flooding barriers, tornado doors). The finding had a cross-cutting aspect of Evaluation of Identified Problems, as described in the Corrective Action component of the Problem Identification and Resolution cross-cutting area, because the licensee did not implement adequate corrective actions to prevent recurrence of unanalyzed material left in containment following the performance of OST-1081 |
| 05000400/FIN-2012004-02 | 2012Q3 | Harris | B Startup Transformer Lockout Due to Loss of Oil Filled Cable Pressure | A self-revealing Green NCV of Technical Specification (TS) 6.8.1, Procedures, was identified for the licensees failure to develop an adequate procedure for maintenance on an oil filled cable. Specifically, the licensee failed to provide adequate instructions to prevent causing additional damage to the cable which resulted in the lockout of the B Startup Transformer (SUT) on June 25, 2012. This also resulted in unavailability of the preferred power source for the B safety related equipment for over two days. As corrective actions, the licensee repaired the cable, restored oil pressure and returned the B SUT to its normal standby configuration. Additionally, the licensee performed an investigation which concluded that the cable had been damaged at the site of a previous repair when it was handled during maintenance. The issue was placed into the CAP as AR #545920. The licensees failure to develop an adequate procedure to ensure proper handling of the cable and prevent inadvertently causing damage was a performance deficiency. The performance deficiency was more than minor because it was associated with the Procedure Quality attribute of the Mitigating Systems cornerstone, and it affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, it resulted in the lockout of the B SUT and unavailability of the preferred power source for the B safety related equipment for over two days. Using IMC 0609, Significance Determination Process, this finding was determined to be of very low safety significance because it was not a design or qualification deficiency, did not represent an actual loss of function of at least a single train for greater than the TS AOT or two separate safety systems out-of-service for greater than the AOT, did not result in a loss of safety function of one or more non-TS trains of equipment designated as risk significant for greater than 24 hours, and did not involve the loss or degradation of equipment or function specifically designed to mitigate a seismic, flooding, or severe weather initiating event (e.g., seismic snubbers, flooding barriers, tornado doors). The finding had a crosscutting aspect of complete, accurate and up-to-date procedures, as described in the Resources component of the Human Performance cross-cutting area, because the licensee did not develop adequate procedures to prevent further damage while performing maintenance on the SUT cables |
| 05000400/FIN-2012007-02 | 2012Q2 | Harris | Failure to Notify the NRC of the EOF Loss of Emergency Assessment Capability | The inspectors identified an AV of 10 CFR Part 50.72(b)(3)(xiii), for the failure to report the loss of emergency assessment capability in the EOF. Specifically, the EOF was unavailable to perform its intended function for periods greater than seven days on several occasions from August 2009 to November 2011. This issue was entered into the licensees CAP as NCR 492707. The failure to report the loss of emergency assessment capability in the EOF as required by 10 CFR Part 50.72(b)(3)(xiii) was a performance deficiency. The finding was more than minor because it impacted the regulatory process which depends on plant activities being properly reported. The inspectors evaluated this finding against NRC IMC 0609 Appendix B, Emergency Preparedness Significance Determination Process Section 7.3. The inspectors determined that traditional enforcement is applicable. The licensee failed to report an occurrence of a major loss of emergency assessment capability. Specifically, the licensee failed to maintain a fully functional EOF when portions of the ventilation system were removed from service without compensatory measures, and the licensee failed to report the occurrence as required. As discussed in the Enforcement Policy, the severity level of a violation involving the failure to make a required report to the NRC will be based upon the significance of and the circumstances surrounding the matter that should have been reported. In this case, and as discussed above, the NRC concluded that the failure to provide the required report is associated with a preliminarily White finding for the failure to maintain a fully functional EOF. In addition, the licensees failure to report the condition of the EOF from August 2009 to November 2011, as required by 10 CFR 50.72, impeded the NRCs regulatory process. Had the licensee reported the incident as required, NRC review and follow-up inspection likely would have occurred, which may have prompted the licensee to adopt compensatory measures and/or corrective actions, thereby precluding the incidents that followed after August 4, 2009. Based on the above, the NRC determined the severity level of this apparent violation is preliminarily Severity Level III in accordance with the NRC Enforcement Policy. |
| 05000400/FIN-2012007-04 | 2012Q2 | Harris | Failure to Maintain an Adequate TSC to Support Emergency Response | The inspectors identified an AV of 10 CFR 50.54(q) for the licensees failure to provide a defensible technical basis for unfiltered air in-leakage, supported by sufficient experimental and empirical data for an input to a calculation used as the basis for TSC functionality. The compensatory measure established on February 16, 2012, was to issue a standing order (12-005) related to habitability and relocation of the TSC. The licensee has submitted an event notification (EN 47655), and entered this issue into their CAP as NCR 516120. The licensees failure to provide a defensible technical basis supported by sufficient experimental and empirical data for an input to the Alternate Source Term (AST) calculation, which was the basis for TSC functionality, was a performance deficiency. This failure resulted in the licensee being unable to meet the TSC habitability requirements as specified in the Harris Emergency Plan, PLP-201, Revision 57, section 3.3.1. The finding was more than minor because it affected the Emergency Preparedness Cornerstone objective of ensuring that the licensee was capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. Specifically, the ERO performance attribute was affected during the times when the TSC was not functional, and it did not meet 10 CFR 50.47(b)(8) Planning Standard program elements. The finding was assessed for significance in accordance with NRC IMC 0609, Appendix B, Emergency Preparedness Significance Determination Process. Attachment 2 of Appendix B, Failure to Comply Significance Logic is as follows: Failure to comply; Loss of Risk Significant Planning Standard Function (RSPS), NO; RSPS Degraded Function, NO; Loss of Planning Standard Function, YES; results in a White finding. The inspectors determined that this resulted in a preliminarily low to moderate safety significance finding (White). The inspectors did not identify a cross-cutting aspect associated with this finding because the performance deficiency occurred in 2001 and does not represent current licensee performance. |
| 05000261/FIN-2012007-02 | 2012Q2 | Robinson | Failure to Implement Trending Requirements Set Forth in Plant Procedures | An NRC identified finding was identified for the licensees failure to implement trending requirements set forth in CAP-NGGC-0206, Performance Assessment and Trending and EGR-NGGC-0010, System Component Trending Program and System Notebooks. Consequently the licensee missed opportunities to identify and enter adverse conditions into the CAP. The licensee entered these issues into the corrective action program as NCRs 535537 and 535926. The licensee has taken immediate corrective actions which include the generation of trend reports that were previously missed. The finding was more than minor because the licensees failure to correct trending program implementation deficiencies could have the potential to lead to a more significant safety concern. Specifically, these trending program implementation deficiencies leave the station vulnerable to not identifying less significant issues that may be providing precursor insights that could prevent a more significant condition adverse to quality. The finding was determined to affect the mitigating systems cornerstone objective of ensuring the availability, reliability, and capability of systems to respond to initiating events to prevent undesirable consequences. In accordance with NRC Inspection Manual Chapter 0609.04, Significant Determination Process Phase 1 screening, the finding was determined to be of very low safety significance (Green) because the finding did not result in a loss of system safety function or a loss of safety function of a single train for greater than allowed Technical Specification allowed outage time. This finding has a cross-cutting aspect in the area of problem identification and resolution associated with the corrective action program component. Specifically, the licensee failed to periodically trend and assesses information from the CAP and other assessments in the aggregate to identify programmatic and common cause problems |
| 05000261/FIN-2012007-01 | 2012Q2 | Robinson | Failure to Take Adequate Corrective Action to Preclude Repetition of a Significant Condition Adverse to Quality Associated with the Refueling Water Storage Tank Purification | A self-revealing Green NCV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, was identified for the licensees failure to take adequate corrective actions to prevent recurrence (CAPR) in response to a significant condition adverse to quality (SCAQ) associated with the purification of the Refueling Water Storage Tank (RWST). Specifically, on March 16, 2012, with the plant in Mode 4, the licensee aligned the non-seismically qualified Spent Fuel Pool Demineralizer to the seismically qualified boundary of the RWST to perform purification of the RWST. This action rendered the RWST inoperable. This issue was previously identified as a significant condition adverse to quality in May 2011, but the corrective actions taken failed to preclude repetition. The licensee entered this issue in the corrective action program as Nuclear Condition Report (NCR) 524619. As immediate corrective actions, the licensee removed the SFP purification system from service and replaced the caution tags on valves SFPC-805A, Refueling Water Purification Pump Suction from RWST and SFPC-805B, RWST Return, with a Clearance. The licensee plans to revise several operating procedures to correctly apply Technical Specifications implications into procedural steps and they also plan to implement Engineering Change (EC) 80584, to perform a seismic qualification of the spent fuel pool / RWST purification system to allow alignment to the RWST without affecting operability. The licensees failure to take adequate corrective actions to prevent recurrence of a SCAQ, aligning the non-seismically qualified spent fuel pool demineralizer system for purification of the safety related and seismically qualified RWST, was a performance deficiency. The finding was more than minor because if left uncorrected, it has the potential to lead to a more significant safety concern. The finding was determined to affect the mitigating systems cornerstone objective of ensuring the availability, reliability, and capability of systems to respond to initiating events to prevent undesirable consequences. Specifically, during a seismic event the purification piping could break and cause a loss of inventory in the RWST which is used in accident mitigation. Inspection Manual Chapter (IMC) 0609, Attachment 4, Table 4a, Phase 1 Initial Screening and Characterization of Findings, determined that this finding was within the mitigating systems (MS) cornerstone and was potentially risk significant due to a seismic external event and therefore required a Phase 3 SDP analysis. A phase 3 risk assessment was performed by a regional Senior Risk Analyst (SRA) using the NRC SPAR model. The analysis determined that the risk increase of the performance deficiency was an increase in core damage frequency less than 1E-6/year a GREEN finding of very low safety significance. The cross cutting aspect of the finding was directly related to the CAP component of the Problem Identification and Resolution area, because the licensee failed to take appropriate corrective actions to address safety issues. Specifically, the licensees corrective actions regarding the alignment of the purification system to the RWST were not adequate to solved the issue and prevent recurrence |
| 05000324/FIN-2012002-01 | 2012Q1 | Brunswick | Failure to Identify and Correct a Refrigerant Leak in the Instrument Air Dryer System | A self-revealing non-cited violation of 10 CFR 50 Appendix B, Criteria XVI, Corrective Action, was identified for the licensees failure to promptly identify and correct a condition adverse to quality related to the Control Room Air Conditioning (AC) system and the Control Room Emergency Ventilation (CREV) system. Specifically, the licensee failed to identify and correct a slow refrigerant leak in the instrument air dryer in the control building HVAC instrument air system, rendering both the control room AC and CREV systems inoperable. Upon discovery, the instrument air dryer was bypassed, air pressure was restored, and the control room AC and CREV systems were restored. The licensee entered this issue into the corrective action program as Action Request (AR) 502214. The failure to identify and correct the slowly lowering refrigerant pressure was a performance deficiency. This finding was more than minor because it was associated with the structure, system, and component (SSC) and barrier performance attribute of the Barrier Integrity Cornerstone. It also adversely affected the cornerstone objective of maintaining a radiological barrier for the control room. Specifically, the finding led to a loss of all air conditioning and filtering capability of control room air. The significance determination process was completed in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 Initial Screening and Characterization of Findings, Table 4a for the Barrier Integrity Cornerstone. The finding was determined to be of very low safety significance (Green) because it only affected the radiological barrier function of the control room, and does not represent a degradation of the smoke or toxic atmosphere barrier function of the control room. This finding has a cross-cutting aspect in the corrective action program component of the Problem Identification and Resolution area because the licensee did not identify the issue completely, accurately, and in a timely manner commensurate with its safety significance. |
| 05000259/FIN-2011011-04 | 2011Q3 | Browns Ferry | Inaccurate Information Provided Regarding Scoping of Motor Operated Valves in the Generic Letter 89-10 Program | An NRC-identified apparent violation of 10 CFR 50.9(a) requirements was identified when it was determined that the licensee provided information that was not complete and accurate in the letter dated January 6, 1997, Browns Ferry Nuclear Plant (BFN) Units 2 and 3 Generic Letter (GL) 89-10, Safety-Related Motor-Operated Valve (MOV) Testing and Surveillance, NRC Inspector Follow-up Item (IFI) 50-260, 296/95-19-01, Response to Request for Reevaluation Regarding Reduced Scope of MOVs. Additionally, TVA provided incomplete and inaccurate information to the NRC in a letter from T. E. Abney, Browns Ferry Nuclear Plant (BFN) Unit 1 Generic Letter 89-10 and Supplements 1 to 7, Safety-Related Motor-Operated Valve (MOV) Testing and Surveillance, dated May 5, 2004. This was an apparent violation of 10 CFR 50.9, Completeness and Accuracy of Information. The inspectors determined that the failure to provide complete and accurate information to the NRC was contrary to the requirements of 10 CFR 50.9, and was an apparent violation. Because violations of 10 CFR 50.9 are considered to be violations that potentially impede or impact the regulatory process, they are dispositioned using the traditional enforcement process. The regulatory significance was important because this information was material to the NRC because it was used, in part, as the basis for determining that valves FCV-74-52 and FCV-74-66 did not meet the conditions necessary that would require them to be in Browns Ferrys GL 89-10 MOV monitoring program. The issue was preliminarily determined to be an apparent violation of 10 CFR 50.9. |
| 05000400/FIN-2011003-01 | 2011Q2 | Harris | Offsite Power Supply Cables Submerged in Water | The inspectors identified the offsite power supply cables, connecting the switchyard to the startup transformers, were submerged in standing water in their underground bunkers. Additional inspection activities are needed to determine if the offsite power supply cables are suitable for operation while submerged in water. Pending the results of this additional inspection, an URI will be opened and designated as URI 05000400/2011003-01, Offsite Power Supply Cables Submerged in Water |
| 05000261/FIN-2010004-05 | 2010Q3 | Robinson | Failure to Correctly Implement a Systems Approach to Training for the Licensed Operator Requalification Program | (TBD) The inspectors identified an Apparent Violation (AV) of 10 CFR 55.59(c), Requalification program requirements , for the licensees failure to properly implement elements of a Commission approved program developed using a systems approach to training (SAT), that was implemented in lieu of meeting the requirements defined in 10 CFR 55.59 (c). The finding was entered into the licensees corrective action program as NCR-423232, NCR-423238, and NCR-423239. Corrective actions for this finding are still being evaluated. The licensees failure to properly implement elements of a Commission approved requalification program was a performance deficiency. The finding was determined to be more than minor because it was associated with the Initiating Events Cornerstone and affected the cornerstones 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 implement training requirements for Path-1 and perform adequate retraining of operators that demonstrated areas of weakness during operating tests contributed to operators failure to identify and implement actions to mitigate a loss of seal cooling to the reactor coolant pumps (RCPs) during the events of March 28, 2010. Contrary to Augmented Inspection Team Report 05000261/2010009, further inspection revealed that RCP seal injection was not adequate coincident with a loss of cooling to the thermal barrier heat exchanger to the B RCP. Using Manual Chapter Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, the inspectors determined the finding required a Phase 2 analysis because the finding could result in reactor coolant system (RCS) leakage exceeding Technical Specification limits. The Phase 2 analysis determined that this finding was potentially greater than green; therefore, a Phase 3 analysis is required by a regional senior reactor analyst due to an increase in the likelihood of an RCP seal LOCA. The significance of this finding is designated as To Be Determined (TBD) until the safety characterization has been completed. The cause of this finding was directly related to the cross cutting aspect of Personnel Training and Qualifications in the Resources component of the Human Performance area, in that the licensee failed to ensure the adequacy of the training provided to operators to assure nuclear safety. |
| 05000261/FIN-2010004-02 | 2010Q3 | Robinson | Failure to Design and Implement a Simulator Model that Demonstrated Reference Plant Response | A self-revealing Green NCV of 10 CFR 55.46(c), Simulation Facilities, was identified for a plant referenced simulator used for administration of operating tests not correctly modeling the reference plant. A loss of electrical power that resulted in a loss of component cooling water (CCW) to the reactor coolant pump seals was not properly modeled in the simulator. When power to safety-related 480 volt bus E-2 was transferred to the emergency diesel generator in the reference-plant, FCV-626, thermal barrier heat exchanger outlet isolation flow control valve, closed. The simulator modeled FCV-626 to respond to CCW flow through the valve and did not model the effect of a loss of power to the valve operator and associated control circuit. Consequently, with a loss of power to bus E-2, the simulator model allowed this valve to remain open. The licensee documented the issue in Significant Adverse Condition Investigation Report, 390095. As corrective action the licensee changed the simulator modeling to match the plant configuration. The inspectors determined that the failure of the simulator to accurately demonstrate reference plant response was a performance deficiency. This finding was more than minor because it affected the human performance attribute of the initiating events cornerstone in that the unexpected closure of FCV-626 raises the likelihood of human error in response to a loss and subsequent re-energization of the E-2 Bus. This could challenge reactor coolant pump seal cooling and result in reactor coolant pump seal failure. The finding was evaluated using the Operator Requalification Human Performance SDP (MC 0609, Appendix I) because it was a requalification training issue related to simulator fidelity. The finding was of very low safety significance (Green) because the discrepancy did not have an impact on operator actions resulting in a total loss of RCP seal cooling and subsequent increase in reactor coolant system (RCS) leakage. There is not a cross-cutting aspect associated with the finding because the performance deficiency involving the simulator modeling occurred over 3 years ago and does not reflect current licensee performance. |
| 05000261/FIN-2010004-03 | 2010Q3 | Robinson | Deficiencies in Non Safety-Related Cable Installation Result in Fire and Reactor Trip | A self-revealing Green finding was identified for the licensees failure to adequately follow guidance in a design change package for the installation of non safetyrelated 4kV cables. This resulted in cables with design features inappropriate for the application being installed and eventually led to a fire and a reactor trip. Specifically, the licensee failed to follow the cable vendor recommendations and a self-imposed administrative requirement/standard for cable installation contained in cable specification L2-E-035, Specification for 5,000 Volt Power Cable. The licensee entered this into the CAP as NCR 390095. As corrective actions, the licensee replaced the cable, conduit and other damaged equipment, including evaluation on damage to cables in overhead, and the feeder cables to station service transformer (SST) 2E and 4kV bus 5. The failure to follow the guidance in the design change package to install non safetyrelated cables between Bus 4 and Bus 5 in accordance with their design change program and vendor and cable installation specifications was a performance deficiency. This finding was determined to be more than minor because it affected the Initiating Events Cornerstone objective of limiting events that upset plant stability, and was related to the attribute of Design Control (i.e., Plant Modifications). Specifically, the inadequate cable modification was determined to be the root cause of the reactor trip that occurred on March 28, 2010. This deficiency also paralleled Inspection Manual Chapter 0612, Appendix E, Example 2.e, as the licensee did not follow their own administrative requirements and vendor recommendations for cable installation. The performance deficiency was screened using Phase 1 of Inspection Manual Chapter 0609, Significance Determination Process, which determined that because the finding increases the likelihood of a fire, a Phase 3 SDP analysis was required. A phase 3 SDP risk evaluation was performed by a regional senior reactor analyst in accordance with the guidance in IMC 0609 Appendix F utilizing the NRCs Robinson SPAR model. The Phase 3 analysis determined the finding to be of very low safety significance (Green) because the core damage frequency increase was less than 1E-6. There is not a crosscutting aspect associated with the finding because the performance deficiency involving the cable installation occurred greater than 20 years ago and does not reflect current licensee performance. |
| 05000261/FIN-2010004-04 | 2010Q3 | Robinson | Failure to Establish an Adequate PATH-1 Emergency Operating Procedure | (TBD) The inspectors identified an apparent violation (AV) of Technical Specifications (TS) 5.4.1, Procedures , for the licensees failure to establish and maintain an adequate emergency procedure that ensured reactor coolant pump (RCP) seal cooling was maintained following a reactor trip. The licensee has entered this into the CAP as nuclear condition report (NCR) 423147. Corrective actions for this finding are still being evaluated. The failure to establish and maintain an emergency procedure that would ensure adequate reactor coolant pump seal cooling, preventing seal degradation and a possible seal LOCA was a performance deficiency. The finding is more than minor because it is associated with 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, specifically a loss of seal cooling to prevent the initiation of a RCP seal loss of coolant accident (LOCA). Using Manual Chapter Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, the inspectors determined the finding required a Phase 2 analysis because the finding could result in RCS leakage exceeding Technical Specification limits. The Phase 2 analysis determined that this finding was potentially greater than green; therefore, a Phase 3 analysis is required by a regional senior reactor analyst due to an increase in the likely hood of an RCP seal LOCA. The significance of this finding is designated as To Be Determined (TBD) until the safety characterization has been completed. The cause of this finding had a cross-cutting aspect of Documentation, Procedures, and Component Labeling, in the Resources component of the cross-cutting area of Human Performance, in that the licensee failed to ensure procedures for emergency operations were adequate to assure nuclear safety. |
| 05000261/FIN-2010004-01 | 2010Q3 | Robinson | Failure to Have Adequate Work and Post Maintenance testing Instructions for the Volume Control Tank Comparator Module | A self revealing Green finding was identified for a failure to have adequate work orders to properly configure and post maintenance test the volume control tank (VCT) level comparator module. The licensees procedure ADM-NGGC-0104, Work Implementation and Completion, required that work orders contain all work activities necessary to perform all related work activities including Post Maintenance Testing (PMT). The licensees work orders for installing a jumper on the VCT level comparator module and for post maintenance testing failed to contain adequate instructions to properly configure (place jumper in correct location) and post maintenance test the volume control tank level comparator module. This resulted in the failure of the charging pump suction to automatically transfer from the volume control tank to the refueling water storage tank (RWST) when the auto transfer VCT low level setpoint was reached. The licensees identified corrective actions included repairing the subject VCT level module, reviewing the adequacy of other replacement NUS modules that have nonsafety control functions and revising the site specific PMT procedures to provide more specific guidance for ensuring that the control loop circuit is adequately tested. The failure to have adequate work order instructions to properly configure and post maintenance test the volume control tank level comparator module is a performance deficiency. This finding is greater than minor because the failure to auto transfer from the VCT to the RWST could cause a failure of the charging pump, resulting in the loss of seal injection which is a precursor to a seal LOCA. Using IMC 0609, Significance Determination Process, (SDP) Phase 1 Worksheet, the inspectors concluded that a Phase 2 evaluation was required since the finding could have likely affected other mitigation systems resulting in a total loss of their safety function. This issue was evaluated using IMC 0609, Appendix A (SDP Phase 2) as being potentially greater than green with loss of component cooling water (LOCCW) and loss of service water (LOSW) as the dominant sequences. A phase 3 SDP risk evaluation was performed by a regional senior reactor analyst in accordance with the guidance in IMC 0609 Appendix A utilizing the NRCs Robinson Standardized Plant Analysis Risk (SPAR) model. The VCT level comparator module performance deficiency resulted in a core damage frequency increase of less than 1E-6, Green. The risk was mitigated by the availability of the letdown and normal makeup charging pump suction sources, which would be available under certain conditions reducing the likelihood of an autoswap demand. Another factor which mitigated the risk is that the fire shutdown procedures for most fire areas specify use of a manual RWST supply valve. The performance deficiency is characterized as Green, a finding of very low safety significance. This issue has a cross-cutting aspect in the resources component of the human performance area because the licensee did not provide complete, accurate, and up-to-date work packages for the configuration and testing of the VCT comparator module. |
| 05000261/FIN-2010009-02 | 2010Q2 | Robinson | RCS Cooldown Rate Exceeds Technical Specification 3.4.3 limit | Through a review of plant data, the team determined that the crews response to the first event was not effective in stabilizing the plant. Through interviews and review of plant data, the team determined that the crew did not recognize the magnitude of the RCS cool down caused by an on-going steam demand. The RCS cool down rate exceeded the limit of 100o/hr in any one hour period as specified in Technical Specification (TS) 3.4.3, RCS Pressure and Temperature (P/T) Limits. The fact that the RCS cooldown rate exceeded the limiting value specified in TS 3.4.3, and the requirement to evaluate the actions contained in TS 3.4.3, was not recognized by the crew at any time during or after the cooldown. Based on interviews, the Reactor Operator (RO) and Control Room Supervisor (CRS) assessed the cool down rate as being consistent with what was experienced during simulator training for an RCP trip followed by a reactor trip. The RCS cool down continued until Instrument Bus 3 was inadvertently de-energized (approximately 33 minutes after the start of the first event), which caused the MSIVs to close, isolating the steam generators from the steam header. Based on the sequence of events, a review of plant data, and operator interviews, the team concluded that the crew did not recognize that VCT level was decreasing, a low VCT level alarm had annunciated, and automatic swapover of the charging pump suction from the VCT to the RWST failed to occur, until indicated level in the VCT had decreased to approximately 2-3 inches and charging flow had degraded. Once the crew identified this condition, the RO attempted to manually align the suction of the charging pumps to the RWST but made an error when performing the alignment. The error left the suction of the charging pumps aligned to the VCT. The Shift Technical Advisor (STA) determined the alignment was incorrect and the RO corrected the error. The crew did not reference APP-003-E3, VCT HI/LO LVL, which provided direction to manually transfer the charging pump suction to the RWST. RCP seal cooling was maintained because the crew reopened FCV-626 to restore CCW cooling to the RCP thermal barrier heat exchanger approximately 6 minutes before depletion of the VCT. However, high pump bearing temperature alarms were received on all three RCPs. The high temperature alarms subsequently cleared after operators reopened FCV-626. Based on operator interviews, the team concluded that, following implementation of Emergency Operating Procedures (EOPs), the operators did not complete a satisfactory review and evaluation of alarm conditions prior to the second event. Instead, the operating crew entered GP-004, Post Trip Stabilization, and attempted to reset the generator lockout relay without using the information in the Annunciator Panel Procedures (APPs) to completely and accurately assess abnormal electric plant status. GP-004 is a normal operating procedure and is written with the assumption that the plant is in a normal (undamaged) configuration. The crew was not aware that a sudden pressure fault signal from the UAT was still applied to the generator lockout circuit logic, as indicated by a locked in UAT fault trip alarm (APP-009-B6, AUX TRANSF FAULT TRIP). The attempted reset reenergized Bus 4 and caused a fault at breaker 52/24, initiating the sequence for the second fire. The team concluded that if the crew had performed a thorough control board walkdown, additional electric plant APPs and/or AOPs could have been identified and implemented before exiting to a normal operating procedure (GP-004). Additional review by the NRC will be required to determine if the licensees programs resulted in untimely identification and investigation of abnormal plant parameters and unexpected main control room alarms. This review will also determine whether the crews monitoring of plant parameters and alarms, and use of associated procedures, represents a performance deficiency. An Unresolved Item will be opened pending completion of this review. The URI is identified as 05000261/2010009-01, Monitoring of Plant Parameters and Alarms. Additionally, further review by the NRC will be required to determine if the RCS cooldown rate exceeding the limiting value specified in TS 3.4.3 represents a performance deficiency. An Unresolved Item will be opened pending completion of this review. The URI is identified as 05000261/2010009-02, RCS Cooldown Rate Exceeds Technical Specification 3.4.3 Limit. |
| 05000261/FIN-2010009-03 | 2010Q2 | Robinson | Utilization of operators During Events Requiring Use of Concurrent Procedures | Through interviews, the team determined that the Balance of Plant (BOP) operator concurrently performed Abnormal Operating Procedure (AOP)-041, Response to Fire Event, during the first event. The team observed that AOP-041 contains numerous steps to coordinate on-site and off-site fire brigade response and notifications. The team determined that having a licensed operator perform AOP-041, concurrent with the CRS and RO performing emergency operating procedures, is a licensee expectation in accordance with OMM-022, Emergency Operating Users Guide. Through interviews, the team determined that because the BOP operator was performing AOP-041, he was unavailable to assist the control room team in recognizing and diagnosing off-normal events and conditions for approximately the first 30 minutes of the first event. During interviews, the two operators responsible for panel operation (the RO and CRS) consistently noted the unavailability of a third person (the BOP licensed operator) to perform independent panel checks. The team noted that during conditions of minimum manning, using the BOP operator to concurrently perform certain AOPs may hinder or prevent him or her from assisting the CRS and RO in stabilizing the plant during events that challenge the control room crew. Additional review by the NRC will be needed to determine if the licensees utilization of operators, during conditions of minimum control room manning, is adequate during complex events. This review will also determine if this issue represents a performance deficiency. An Unresolved Item will be opened pending completion of this review. The issue will be identified as URI 05000261/2010009-03, Utilization of Operators During Events Requiring Use of Concurrent Procedures. |
| 05000261/FIN-2010009-04 | 2010Q2 | Robinson | Fidelity of Plant-Referenced Simulator | A review of simulator performance and event data by the team confirmed one simulation deficiency which had been identified by the licensee as part of their event review. When power to safety-related 480 volt Bus E-2 was transferred to the emergency diesel generator, FCV-626 (thermal barrier heat exchanger outlet isolation flow control valve) closed unexpectedly. As discussed in more detail in the Section 4.5, Unexpected Closure of FCV-626, the as-built plant configuration resulted in the valve closing on a loss of power. This response was not obtained in the simulator because the simulator modeling of FCV-626 was based solely on CCW flow through the valve and did not take into account power to the valve operator and associated control circuit. Consequently, in simulator scenarios which included a loss of power to Instrument Bus 4, this valve remained open. Because the plant reference simulator did not demonstrate expected plant response for a loss of Instrument Bus 4, the team identified the need for additional NRC review to determine the adequacy of fidelity of the plant reference simulator for conducting loss of component cooling system control manipulations and plant evolutions. This review will also determine if this issue represents a performance deficiency. An Unresolved Item will be opened pending completion of this review. The URI is identified as 05000261/2010009-04, Fidelity of Plant-Referenced Simulator. |
| 05000261/FIN-2010009-07 | 2010Q2 | Robinson | Loss of Seal Water Results in Failure of the A Main Condeser Vacuum Pump | The 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. |
| 05000261/FIN-2010009-08 | 2010Q2 | Robinson | Deficiencies in Non Safety-Related Cable Installation | To determine the circumstances surrounding the fault in the cable that led to the first electrical disturbance and subsequent reactor trip, the team performed the following activities: Determined details of the cable construction including conductor size, insulation thickness and material, and type of shielding using the manufacturers data sheet Compared the cable construction to system requirements and standard industry practice Reviewed relevant portions of the plant modification that installed the cable Viewed the site of the cable fault Reviewed cable records to determine where other similar cables are installed in the plant Interviewed engineering staff involved with the electrical distribution systems and components Reviewed the licensees causal analysis for the cable fault Evaluated the licensees proposed corrective actions The cable that faulted did not meet many of the specifications for the design change that installed the cable. This contributed to the cable failure. The cable, manufactured by the Rome Cable Corporation (Rome), was installed in 1986 when 4 kV Bus 5 was installed as an extension of Bus 4 per Plant Design Change Number DCN-851. The cable, identified as C21344A, served as the interconnection between 4 kV Buses 4 and 5 and was comprised of two conductors for each of three phases. The cable was installed in two steel conduits, with each conduit containing all three phases. As noted in Section 2.1, all 4 kV buses at Robinson are non safety-related. The Bill of Materials for DCN-851 indicated that the cable should be in accordance with Standard Specification L2-E-035 for 5,000 Volt Power Cable. However, the Bill of Materials did not indicate a purchase order number for the cable that faulted, as it did for other cables installed by the modification, such as 3/c No. 12 AWG cable. Records reviewed by the team indicated that the cable came from reel number HBR-13505. Differences between Standard Specification L2-E-035 and the actual installed Rome cable are listed below: L2-E-035 called for coated copper conductors. The installed cable had uncoated conductors. L2-E-035 called for all cables to be provided with an outer jacket. The installed cable did not have a jacket. L2-E-035 called for cable insulation and jacketing that was self-extinguishing and non-propagating with regard to fire as described in IEEE 383-1974, Type Test of Class 1E Electric Cables, Field Splices, and Connections for Nuclear Power Generating Stations. The Rome catalogue data made no claim as to fire propagation properties. The event demonstrated that the cable lacked fire propagation properties because 1) the cable ignited following the fault, 2) the cable did not self extinguish after the fault was denergized, and 3) flame was propagated along the cable. L2-E-035 called for 133 percent insulation level and insulation shielding if specified in the purchase order. The installed cable did not have either of these features. The cable consisted of single conductor 500 MCM uncoated copper with 130 mils of cross-linked polyethylene insulation rated for continuous operation at 5 kV and 90 degree Celsius. The insulation thickness was determined from the overall cable diameter and from the licensees measurement of conductor diameter. The manufacturers catalogue information (SPEC 7155 dated January 1, 1991) stated that an insulation thickness of 120 mils is suitable for applications requiring 100 percent insulation levels. However, due to the high-resistance grounding scheme used on the Robinson 4 kV electrical system, an insulation level of 133 percent or 173 percent was required, depending on how long a ground fault could remain on the system. The significance of not having adequate insulation thickness was that, should a single line to ground fault occur the voltage on the two un-faulted phases would exceed the rating of the insulation. The cable did not have a jacket. The significance of not having a jacket was that the cable insulation was more vulnerable to damage during installation. Also, the jacket, if installed, would have provided a buffer between the insulation and grounded metal parts, such as the conduit or bus enclosure. The cable did not have an insulation shield. When an insulation shield is not installed, the electric field will be partly in the insulation and partly in whatever lies between the insulation and ground. This situation could be conducive to corona if a thin layer of air lies between the insulator surface and ground, which can lead to insulation deterioration. IEEE 666-1991, Design Guide for Electric Power Service Systems for Generating Stations, Section 12.3.6 states: Power cables rated 5 kV and over should be equipped with insulation shield. The significance of not having a grounded insulation shield was that voltage stress on the insulation was not symmetrical and uniform around the circumference, but rather greater at points where the insulation contacted a grounded surface, such as a metal conduit, than at other points around the circumference. The following information indicated that shielded cable was originally intended for this cable: 1) Design Change Notice No. 6 to DCN-851 changed the termination detail from one depicting the grounding of shield wires to one with no shield wires, and 2) installation instruction 4.35 directed installation of a stress cone for cable C21344A, which would be needed only for a shielded cable. Cognizant licensee engineers stated that the Rome cable installed as part of the Bus 5 modification was different than other 4 kV cable installed at Robinson and was used only for the Bus 4 to Bus 5 connection and the feeder from Bus 5 to station service transformer 2E. During the inspection, the licensee did not present any documentation explaining or justifying why the installed cable for the Bus 5 modification was different than Standard Specification L2-E-035 and the typical cables installed in the plant. The team reviewed the 4 kV cables connected to Buses 1 through 5, and found this statement to be correct. All the 4 kV cables connected to Buses 1 through 5, except for the two cables mentioned above, met or exceeded standard specification L2-E-035, with at least 133 percent insulation and insulation shield. In addition to construction details of the faulted cable, the team reviewed various design considerations related to the cable. The ampacity of two 500 MCM, 90 degree Celsius, cables installed in conduit in free air is 954 amperes. The team estimated the maximum continuous load on Bus 5 as 493 amperes; 216 amperes for the 1750 HP Circulating Water Pump and 277 amperes for the 2000 kV station service transformer. The overcurrent relays were set at 1000 amperes. Therefore, the cables were not overloaded during normal operation. The conduits were the correct size for the cables installed within them. The number of bends in the conduits did not exceed the recommended maximum number of bends. Therefore, pulling tension limits should not have been exceeded during installation. This did not preclude the possibility that the three single conductors became twisted as the cable was pulled through three 90 degree bends. The licensees Event Review Team (ERT) visually examined the faulted cable and the station service transformer 2E feeder cable and determined the three single conductors were twisted. Twisting of one conductor around the other two conductors could result in jamming of the cables in the conduit since the combined diameter of the twisted cables would be greater than the inside diameter of the conduit. The twisting would have led to excessive pulling force being applied during cable installation. The required pulling force is proportional to the side wall pressure exerted on the cable at a bend. Because of the extensive damage resulting from the length of time the fault was energized, the failure mechanism could not be determined with absolute certainty. The licensees causal analysis determined with a fair degree of certainty that the initial fault occurred at a point where the conduits terminate at the top of Bus 5 switchgear. After consideration of the above facts and review of the licensees causal analysis, the team concluded that the failure mechanism probably involved one or more of the following factors: Degradation of the insulation at the surface of the cable due to corona Damage to the insulation due to inadvertent twisting of the three conductors during the pulling-in process resulting in excessive side-wall pressure at one or more of the three 90 degree bends in the conduit Rubbing of the cable against the conduit or switchgear top plate due to turbine building vibration A secondary fault at the Bus 4 cable compartment for circuit breaker 52/24 was caused by plasma gas migrating inside the conduit and through a hole in the conduit seal, along with terminations that were not taped. The ERT postulated that the hole was caused by pressure built up in the conduit as a result of the fault. The ERT further postulated that this secondary fault at circuit breaker 52/24 created permanent degradation of the insulation at that location. All of the cable within the compartment was completed destroyed when Bus 4 was reenergized about four hours after the initial fault was cleared. The licensee stated that corrective actions related to the cable failure would be to replace the Rome cable feeding station service transformer 2E before plant startup. The licensees Significant Adverse Condition Investigation Report for the event states that a search, using catalog identification numbers, was made across the Progress Energy fleet for this type of cable or similar cable and none was found. The licensee did not believe revisions were needed to the design control process because the process had been changed earlier to preclude the problems described herein, i.e. lack of proper control over purchasing and field changes. The team concluded that the apparent root cause of the initial cable failure and subsequent associated short-circuits was poor quality control over the non-safety-related modification process for installing the cable. A cable of lesser quality than other 5 kV cables installed throughout the plant was installed as a substitute during this modification. The cable terminations were not taped and the cable was not restrained to prevent rubbing. The consequence of the cable fault was a reactor trip. Because of the magnitude of the electrical fault, the reactor trip would have occurred regardless of whether bus tie circuit breaker 52/24 was fully functional. The resultant voltage transient decreased RCP speed which lowed RCS flow and initiated a reactor trip. This occurred faster than the time delay overcurrent protective relays associated with circuit breaker 52/24. Additional review by the NRC will be needed to determine whether the cable installation represents a performance deficiency. An Unresolved Item will be opened pending completion of this review. The issue will be identified as URI 05000261/2010009-08, Deficiencies in Non Safety-Related Cable Installation. |
| 05000261/FIN-2010009-09 | 2010Q2 | Robinson | Failure to Repair Circuit Breaker 52/24 Resulting in Breaker Being Unable to Operate | Circuit breaker 52/24 is the non safety-related tie circuit breaker between 4 kV Bus 4 and Bus 5. Following an electrical fault on cabling between this breaker and Bus 5 as described in Section 4.1, the breaker failed to open to clear the fault due to a lack of control power. The team reviewed equipment records related to circuit breaker 52/24 and determined that Work Request 357740 was written in November 2008 to repair the closed position indicating light located on the front of the circuit breaker. Because the closed position light would not illuminate after the light bulb was replaced, licensee personnel assumed the problem involved the socket for the bulb. Although the licensee had subsequently developed a work order to repair the socket, the licensee had not performed any additional repairs up to the time of the event. A number of opportunities existed to identify the source of the problem, including additional work requests and walkdowns by the system engineer. The additional work requests were canceled to the work order and the system engineer failed to recognize the potential impact of the failed indicating light regarding breaker operation. Following the event, the licensee determined that one of the control power fuses in the breaker trip circuit was failed. Laboratory examination by the licensee revealed that the fuse had a cracked internal element. The licensees ERT found that the overcurrent relays and the circuit breaker were fully functional. The failed fuse caused the breaker trip circuit to be deenergized, resulting in the indicating lamp being off and preventing the circuit breaker from tripping. Operations, Maintenance, and Engineering personnel did not fully understand the significance of the deenergized breaker indicating light. Operations personnel did not request an engineering assessment when they reviewed the work order. However, because station engineering was independently aware of the condition, it is not evident that a request for an engineering assessment would have resulted in a different outcome. The broken fuse, style LPN-RK-30SP, was manufactured by Bussman Division of Cooper Industries. As part of their corrective actions for this problem, the licensee checked the resistance of 16 fuses of the same style to determine whether any incipient degradation was taking place. The tested group included in-service fuses of various sizes as well as three new fuses. The licensee determined all the fuses had acceptable resistance readings. The licensee stated they would also provide training to appropriate plant personnel regarding this event and expectations for response to circuit breaker indicating lamps being off when they should be on. (Note: On April 14, 2010, the NRC issued Information Notice 2010-09, Importance of Understanding Circuit Breaker Control Power Indications, which described the problem with circuit breaker 52/24 control power). Section 4.1 states that, because of the high magnitude of the fault current, a reactor trip would have occurred as a result of the March 28 event, regardless of whether circuit breaker 52/24 was fully functional. However, for potential faults resulting in smaller currents, proper operation of circuit breaker 52/24 would prevent a reactor trip. The team concluded the licensee failed to understand the possible implications of circuit breaker 52/24 indicating light being off and should have pursued the issue in a timely manner. The problem existed for approximately 17 months until this event revealed the circuit breaker was unable to isolate a fault condition. Additional review by the NRC will be needed to determine whether the failure to correct, in a timely manner, a problem with the indicating light for circuit breaker 52/24 and the underlying problem with the control power fuse represents a performance deficiency. An Unresolved Item will be opened pending completion of this review. The issue will be identified as URI 05000261/2010009-09, Failure to Repair Circuit Breaker 52/24 Resulting in Breaker Being Unable to Operate. |
| 05000261/FIN-2010009-06 | 2010Q2 | Robinson | Adequacy of Emergency Operating Procedure Background Documents | From interviews, the team determined that the control room operators, in responding to the event, relied exclusively on actions and guidance explicitly described in EOPs. The operators did not consider mitigating actions that would have stabilized the plant that were not explicitly contained in these procedures, such as shutting the MSIVs. The emergency procedures being implemented centered on the Path-1 EOP. From a review of the plant procedures used by operators to respond to this event, the team determined that certain Path-1 procedure steps required operators to rely on their knowledge because these steps did not contain detailed (rule-based) guidance. The team observed that Path-1 is a flow diagram that assists with diagnostics but does not consistently provide acceptance criteria and alternate actions. The team determined that, in general, implementation of the Path-1 EOP relies more heavily on operator knowledge-based behavior versus the rule-based behavior emphasized in WOG Emergency Response Guidelines. The team noted that common industry practice among Westinghouse technology plants is to utilize a two-column page format for EOPs and to also provide more explicit detail regarding specific parameters to be checked and specific components to manipulate within each step. The team observed that EOPs did not contain explicit guidance to fully isolate ongoing steam flow in all cases. For example, End Path Procedure (EPP) Foldout A Step 6 MSR Isolation Criteria does not contain additional contingency actions in the event the specified action cannot be taken or is not effective (i.e. loss of power to MSR steam supply valves). During interviews, operators stated that they had been trained in the simulator to send local operators to close MSR valves as a contingency action. However, this action is not listed in the Foldout A procedure and no additional or alternate action that could be performed from the control boards, such as closing the MSIVs, is specified. Additionally, Path-1 Turbine Tripped does not contain additional steps that operators might be reasonably expected to take in order to accomplish the intent of the step, such as closing the MSIVs, in the event that the specified contingency actions of manually tripping the turbine and running back the turbine are not successful. The team also identified an inconsistency between the Path-1 Basis Document and the licensees emergency operating procedure users guide regarding the immediate operator action of SI Initiation. Path-1 EOP does not explicitly list parameters or conditions to be checked in order to determine if a safety injection is required (requiring both the operator performing the immediate action and the CRS who is reading the procedure to rely on their knowledge). However, the Path-1 Basis Document provides an interpretation of this step that states, in part, that a safety injection is required if RCS inventory is decreasing in an uncontrolled manner and exceeding all available makeup flow. OMM-022, Emergency Operating Procedures Users Guide Section 8.3.1, Item 10, lists parameters and values that operators are expected to check when performing this immediate action step. The team noted that this step in OMM-022 does not specify checking RCS parameters directly related to RCS inventory, such as pressurizer level, as described in the Path-1 basis document. The team reviewed plant data from the first event and determined that pressurizer level decreased off-scale. Based on interviews, the team also determined that operators did not recognize the magnitude and rate of the pressurizer level decrease caused by the ongoing RCS cool down. Consequently, the team identified the need for additional NRC review to determine the adequacy of OMM-022 with respect to the immediate operator action of checking whether a safety injection is required. This review will determine whether the inconsistency between the Emergency Operating Procedures Users Guide and the Path-1 Basis Document is a performance deficiency. An Unresolved Item will be opened pending completion of this review. The URI is identified as 05000216/2010009- 06, Adequacy of Emergency Operating Procedure Background Documents. |
| 05000261/FIN-2010009-01 | 2010Q2 | Robinson | Monitoring of Plant Parameters and Alarms | The team conducted an independent review of control room activities to determine if licensee staff responded properly during the events. With respect to operator awareness and decision making, the team was specifically focused on the effectiveness of control board monitoring, communications, technical decision making, and work practices of the operating crew. With respect to command and control, the team was specifically focused on actions taken by the control room leadership in managing the operating crews response to the event. The team performed the following activities in order to understand and/or confirm the control room operating teams actions to diagnose the event and implement corrective actions: Conducted interviews with control room operations personnel on shift during the event. Reviewed procedures, narrative logs, event recorder data, system drawings, and plant computer data. Observed a simulated plant response to this event as demonstrated on the plant reference simulator. Reviewed the crews implementation of emergency, abnormal, and alarm procedures as well as Technical Specifications. Reviewed Operations administrative procedures concerning shift manning and procedure use and coordination. Reviewed Operations procedures in use at the time of the second fire. The team determined that operators exhibited weaknesses in fundamental operator competencies when responding to the event. Specifically, the team determined that the operating crew did not identify important off-normal parameters and alarms in a timely manner, resulting in a failure to recognize an uncontrolled RCS cooldown and a potential challenge to RCP seal cooling. Additionally, the team determined that crew supervision did not exercise effective oversight of plant status, crew performance, or site resources. Through a review of plant data, the team determined that the crews response to the first event was not effective in stabilizing the plant. Through interviews and review of plant data, the team determined that the crew did not recognize the magnitude of the RCS cool down caused by an on-going steam demand. The RCS cool down rate exceeded the limit of 100o/hr in any one hour period as specified in Technical Specification (TS) 3.4.3, RCS Pressure and Temperature (P/T) Limits. The fact that the RCS cooldown rate exceeded the limiting value specified in TS 3.4.3, and the requirement to evaluate the actions contained in TS 3.4.3, was not recognized by the crew at any time during or after the cooldown. Based on interviews, the Reactor Operator (RO) and Control Room Supervisor (CRS) assessed the cool down rate as being consistent with what was experienced during simulator training for an RCP trip followed by a reactor trip. The RCS cool down continued until Instrument Bus 3 was inadvertently de-energized (approximately 33 minutes after the start of the first event), which caused the MSIVs to close, isolating the steam generators from the steam header. Based on the sequence of events, a review of plant data, and operator interviews, the team concluded that the crew did not recognize that VCT level was decreasing, a low VCT level alarm had annunciated, and automatic swapover of the charging pump suction from the VCT to the RWST failed to occur, until indicated level in the VCT had decreased to approximately 2-3 inches and charging flow had degraded. Once the crew identified this condition, the RO attempted to manually align the suction of the charging pumps to the RWST but made an error when performing the alignment. The error left the suction of the charging pumps aligned to the VCT. The Shift Technical Advisor (STA) determined the alignment was incorrect and the RO corrected the error. The crew did not reference APP-003-E3, VCT HI/LO LVL, which provided direction to manually transfer the charging pump suction to the RWST. RCP seal cooling was maintained because the crew reopened FCV-626 to restore CCW cooling to the RCP thermal barrier heat exchanger approximately 6 minutes before depletion of the VCT. However, high pump bearing temperature alarms were received on all three RCPs. The high temperature alarms subsequently cleared after operators reopened FCV-626. Based on operator interviews, the team concluded that, following implementation of Emergency Operating Procedures (EOPs), the operators did not complete a satisfactory review and evaluation of alarm conditions prior to the second event. Instead, the operating crew entered GP-004, Post Trip Stabilization, and attempted to reset the generator lockout relay without using the information in the Annunciator Panel Procedures (APPs) to completely and accurately assess abnormal electric plant status. GP-004 is a normal operating procedure and is written with the assumption that the plant is in a normal (undamaged) configuration. The crew was not aware that a sudden pressure fault signal from the UAT was still applied to the generator lockout circuit logic, as indicated by a locked in UAT fault trip alarm (APP-009-B6, AUX TRANSF FAULT TRIP). The attempted reset reenergized Bus 4 and caused a fault at breaker 52/24, initiating the sequence for the second fire. The team concluded that if the crew had performed a thorough control board walkdown, additional electric plant APPs and/or AOPs could have been identified and implemented before exiting to a normal operating procedure (GP-004). Additional review by the NRC will be required to determine if the licensees programs resulted in untimely identification and investigation of abnormal plant parameters and unexpected main control room alarms. This review will also determine whether the crews monitoring of plant parameters and alarms, and use of associated procedures, represents a performance deficiency. An Unresolved Item will be opened pending completion of this review. The URI is identified as 05000261/2010009-01, Monitoring of Plant Parameters and Alarms. Additionally, further review by the NRC will be required to determine if the RCS cooldown rate exceeding the limiting value specified in TS 3.4.3 represents a performance deficiency. An Unresolved Item will be opened pending completion of this review. The URI is identified as 05000261/2010009-02, RCS Cooldown Rate Exceeds Technical Specification 3.4.3 Limit. |
| 05000261/FIN-2010009-14 | 2010Q2 | Robinson | Unexpected Loss of Instrument Bus 3 for Two Minutes | The team reviewed the circumstances which resulted in an inadvertent de-energization of Instrument Bus 3. The team reviewed completed procedures, log entries, and system drawings. The team also interviewed personnel and performed a system walkdown. At 18:52 on March 28 the B battery charger de-energized due to loss of power to Bus E-2. Per Path-1, control room operators subsequently dispatched an Auxiliary Operator (AO) to restore the B battery charger. As the AO entered the battery room he made inadvertent contact with the handle for the B Inverter Supply Breaker 72/MCC-B (1K). The contact resulted in breaking the handle off of the breaker. Based on the timeframe when the AO entered the battery room and the time when Instrument Bus 3 was unexpectedly loss, the licensees ERT concluded the contact with the breaker caused the loss of Instrument Bus 3. The Auxiliary Operator recognized the damage to the breaker handle and continued to complete the restoration the B battery charger. The B battery charger was restored at 19:31. Upon exiting the battery room the AO verified the B inverter was operating correctly and reported the damage to the breaker handle. A review of plant data indicated Instrument Bus 3 was de-energized at 19:25 and reenergized at 19:27. The loss of Instrument Bus 3 power deenergized the High Steam Flow bistables in the Engineered Safety Features system. This condition, coincident with an RCS Low Tavg signal due to the RCS cooldown, generated a Main Steam Line Isolation signal, automatically closing all MSIVs and terminating the RCS cooldown. Based on interviews with the AO, no actions were performed to reset or reclose the B Inverter Supply Breaker. The licensee generated Work Order 01735191 to repair the broken breaker handle. The licensee performed troubleshooting activities to determine the cause of the two-minute interruption in instrument bus power, but was unable to detect any problems. The licensee was continuing to perform troubleshooting at the time this report was written. The licensee entered Condition Report 390070 into their corrective action program. Additional review by the NRC will be needed to assess the adequacy of the licensee troubleshooting efforts and evaluate any problems that may be identified. This review will also determine whether any performance deficiencies exist. An Unresolved Item will be opened pending completion of this review. The issue will be identified as URI 05000261/2010009-14, Unexpected Loss of Instrument Bus 3 for Two Minutes. |
| 05000261/FIN-2010009-13 | 2010Q2 | Robinson | Dedicated Shutdown Diesel Generator Failed to Start Due to Low Starting Air Pressure | The team reviewed the circumstances which resulted in a failure of the DSDG to start. The team reviewed completed procedures, log entries, system drawings and performed a system walkdown. At 18:52 on March 28, the DS bus was automatically de-energized, as designed, due to undervoltage on 4 kV Bus 3. As a result, the DSDG support equipment, such as the starting air system compressor and battery charger, lost power. Based in part on adequate starting air pressure, the licensee considered the DSDG available for the purpose of assessing on-line risk. The log reading normal minimum value for starting air pressure is 165 psig and operators were monitoring this parameter twice per day. At 14:41 on March 31 the licensee attempted to start the DSDG and re-energize the DS bus to maintain adequate DSDG support parameters such as starting air pressure and battery voltage. Starting air pressure had decreased to 100 psig and the DSDG did not start. The licensee successfully started the DSDG on April 1 at 13:40 by pressurizing the DSDG starting air receiver tank using high pressure air bottles. Both the E-1 and E-2 safety buses were energized during this time with Bus E-1 powered from off-site power and Bus E-2 supplied from EDG B. The licensee entered Condition Reports 390954 and 390958 into their corrective action program. Additional review by the NRC will be required to determine if the DSDG was available when credited in the licensees risk assessment during the plant cooldown to Mode 4. This review will also determine whether this issue represents a performance deficiency. An Unresolved Item will be opened pending completion of this review. The issue will be identified as URI 05000261/2010009-13, Dedicated Shutdown Diesel Generator Failed to Start Due to Low Starting Air Pressure. |
| 05000261/FIN-2010009-12 | 2010Q2 | Robinson | NUREG 0737 Response From Licensee to the NRC Describing the Behavior of RCP Seal Cooling Following a Loss of Offsite Power Event | Valve FCV-626 is located in the combined CCW return from the three RCP thermal barrier heat exchangers. In its normal open position it allows CCW flow to pass through the thermal barrier heat exchangers, providing backup cooling to the RCP seals in the event of a loss of the primary cooling flow (seal injection) from the charging pumps. There are two close functions for FCV-626: 1) closes on high flow in the return line which is indicative of a rupture of a thermal barrier heat exchanger (RCS to CCW system leak) and 2) closes in response to a Phase B containment isolation signal. The valve has no automatic opening functions. The valve closed when power to safety-related 480 volt Bus E-2 was transferred to the emergency diesel generator. The valve remained closed for approximately 39 minutes before the operators recognized the condition, reopened FCV-626, and restored CCW cooling to the RCP thermal barrier heat exchangers. Plant staff knew that FCV-626, a motor operated valve, was powered from Bus E-2 via MCC 6. However, plant staff, including operators, was unaware that FCV-626 would close on a momentary loss of power. Additionally, the simulator was modeled such that FCV-626 remained open when power to Bus E-2 was momentarily interrupted. The high flow closure function of FCV-626 is accomplished using flow orifice FE-626, which is located in the thermal barrier return line, and provides flow switch FIC-626 with a hydraulic input to operate high and low flow contacts. When the high flow contact opens, relay FIC-626X is de-energized and closes a contact in the closing circuit for the motor operator of FCV-626, thereby closing FCV-626. Plant procedure EDP-008, Instrument Buses, incorrectly indicated that the power source for the flow switch FIC-626 control circuit was from Instrument Bus 1. The power for the FIC-626 control circuit is from Instrument Bus 4. Instrument Bus 4 is fed from MCC-6, which also feeds motor operated valve FCV-626. When Bus E-2 transferred to the EDG, both valve FCV-626 and relay FIC-626X lost power for approximately 10 seconds. During this time interval, relay FIC-626X repositioned to its de-energized state, which closed a contact in the close circuit of valve FCV-626. When Bus E-2 reenergized, valve FCV-626 immediately began to close, which sealed in contacts to completely close the valve. The close circuit was sealed in before relay FIC-626X reset to its energized state. The team concluded that the most likely cause of the time delay for the relay to reset was a constant voltage transformer located between the relay and MCC-6. The safety significance of inadvertent shutoff of RCP thermal barrier cooling water is discussed in Section 1.1 of this report. The team reviewed historical data associated with the control circuit for valve FCV-626 and determined the licensee had at least two potential opportunities to discover the behavior of FCV-626 on a loss of power. The first opportunity was in 2005 while implementing Engineering Change (EC) 59456. While performing the EC, workers encountered wiring issues as documented in NCR168221. The licensee subsequently determined that flow switch FIC-626, which was previously thought to be powered from Instrument Bus 1, required no power to operate. As part of that investigation, it was noted that relay FIC-626X was powered from Instrument Bus 4. Wiring discrepancies existed in some of the associated drawings, but were either not noted or not pursued. 27 Enclosure 1 Additionally, the licensee did not update EDP-008, which continued to show Instrument Bus 1 Breaker 16 as the power source for the flow switch FIC-626 control circuit. The licensee has written NCR 391995 to correct these deficiencies. The second opportunity occurred in 2008 during the performance of OST-163, Safety Injection Test and Emergency Diesel Generator Auto Start on Loss of Power and Safety Injection (refueling). As part of the test, 480V safety-related Bus E-2 was transferred to the B EDG. Data recovered by the licensee indicated that FCV-626 closed at approximately the same time the B EDG re-energized Bus E-2. However, during the test, CCW system flow, which was being provided by the opposite train of power, was stable and RCPs were not running. Thus sufficient information was available to recognize that flow perturbations were not the cause for FCV-626 closing. About two hours later, the valve was reopened. The licensee either did not identify or did not pursue the unexpected behavior of FCV-626. The ERT entered the problems described in this section into the corrective action system. One corrective action will clarify the drawings associated with the control circuitry of FCV-626 and make some minor corrections to current drawings. Another corrective action will implement a modification to prevent inadvertent closure of valve FCV-626 for a momentary loss of power. The licensee stated the modification would be implemented prior to restart of the plant from the refueling outage. Additional review by the NRC will be needed to determine whether the design of FCV- 626, which caused the valve to close during a momentary loss of power, represents a performance deficiency. An Unresolved Item will be opened pending completion of this review. This issue is identified as URI 05000261/2010009-11, FCV 626, RCP Thermal Barrier Outlet Isolation CCW Valve, Unexpected Closure. In order to better understand the reason FCV-626 closed during a momentary loss of power, the team reviewed the licensing bases for the CCW system, including FCV-626. The team reviewed correspondence between the licensee and the NRC regarding NUREG 0737, Clarification of TMI Action Plan Requirements, Item II.K.3.25, Power on Pump Seals. This TMI item required the licensee to determine the consequences of a loss of RCP cooling due to a loss of offsite power lasting two hours. In their correspondence, the licensee stated that no modifications were necessary because the CCW system is still operable during a loss of offsite power (powered from the emergency buses) and provides flow to the RCP thermal barrier heat exchangers. They also stated that the B and C CCW pumps are automatically (requiring no operator action) started by a station blackout signal during a loss of offsite power event. Additional review by the NRC will be needed to determine if the behavior of RCP seal cooling following a loss of offsite power event is consistent with the description provided by the licensee in NUREG 0737 correspondence and if any differences represent a violation. An Unresolved Item will be opened pending completion of this review. The issue is identified as URI 05000261/2010009-12, NUREG 0737 Response From Licensee to the NRC Describing the Behavior of RCP Seal Cooling Following a Loss of Offsite Power Event. |
| 05000261/FIN-2010009-11 | 2010Q2 | Robinson | FCV 626, RCP Thermal Barrier Outlet Isolations CCW Valve, Unexpected Closure | Valve FCV-626 is located in the combined CCW return from the three RCP thermal barrier heat exchangers. In its normal open position it allows CCW flow to pass through the thermal barrier heat exchangers, providing backup cooling to the RCP seals in the event of a loss of the primary cooling flow (seal injection) from the charging pumps. There are two close functions for FCV-626: 1) closes on high flow in the return line which is indicative of a rupture of a thermal barrier heat exchanger (RCS to CCW system leak) and 2) closes in response to a Phase B containment isolation signal. The valve has no automatic opening functions. The valve closed when power to safety-related 480 volt Bus E-2 was transferred to the emergency diesel generator. The valve remained closed for approximately 39 minutes before the operators recognized the condition, reopened FCV-626, and restored CCW cooling to the RCP thermal barrier heat exchangers. Plant staff knew that FCV-626, a motor operated valve, was powered from Bus E-2 via MCC 6. However, plant staff, including operators, was unaware that FCV-626 would close on a momentary loss of power. Additionally, the simulator was modeled such that FCV-626 remained open when power to Bus E-2 was momentarily interrupted. The high flow closure function of FCV-626 is accomplished using flow orifice FE-626, which is located in the thermal barrier return line, and provides flow switch FIC-626 with a hydraulic input to operate high and low flow contacts. When the high flow contact opens, relay FIC-626X is de-energized and closes a contact in the closing circuit for the motor operator of FCV-626, thereby closing FCV-626. Plant procedure EDP-008, Instrument Buses, incorrectly indicated that the power source for the flow switch FIC-626 control circuit was from Instrument Bus 1. The power for the FIC-626 control circuit is from Instrument Bus 4. Instrument Bus 4 is fed from MCC-6, which also feeds motor operated valve FCV-626. When Bus E-2 transferred to the EDG, both valve FCV-626 and relay FIC-626X lost power for approximately 10 seconds. During this time interval, relay FIC-626X repositioned to its de-energized state, which closed a contact in the close circuit of valve FCV-626. When Bus E-2 reenergized, valve FCV-626 immediately began to close, which sealed in contacts to completely close the valve. The close circuit was sealed in before relay FIC-626X reset to its energized state. The team concluded that the most likely cause of the time delay for the relay to reset was a constant voltage transformer located between the relay and MCC-6. The safety significance of inadvertent shutoff of RCP thermal barrier cooling water is discussed in Section 1.1 of this report. The team reviewed historical data associated with the control circuit for valve FCV-626 and determined the licensee had at least two potential opportunities to discover the behavior of FCV-626 on a loss of power. The first opportunity was in 2005 while implementing Engineering Change (EC) 59456. While performing the EC, workers encountered wiring issues as documented in NCR168221. The licensee subsequently determined that flow switch FIC-626, which was previously thought to be powered from Instrument Bus 1, required no power to operate. As part of that investigation, it was noted that relay FIC-626X was powered from Instrument Bus 4. Wiring discrepancies existed in some of the associated drawings, but were either not noted or not pursued. 27 Enclosure 1 Additionally, the licensee did not update EDP-008, which continued to show Instrument Bus 1 Breaker 16 as the power source for the flow switch FIC-626 control circuit. The licensee has written NCR 391995 to correct these deficiencies. The second opportunity occurred in 2008 during the performance of OST-163, Safety Injection Test and Emergency Diesel Generator Auto Start on Loss of Power and Safety Injection (refueling). As part of the test, 480V safety-related Bus E-2 was transferred to the B EDG. Data recovered by the licensee indicated that FCV-626 closed at approximately the same time the B EDG re-energized Bus E-2. However, during the test, CCW system flow, which was being provided by the opposite train of power, was stable and RCPs were not running. Thus sufficient information was available to recognize that flow perturbations were not the cause for FCV-626 closing. About two hours later, the valve was reopened. The licensee either did not identify or did not pursue the unexpected behavior of FCV-626. The ERT entered the problems described in this section into the corrective action system. One corrective action will clarify the drawings associated with the control circuitry of FCV-626 and make some minor corrections to current drawings. Another corrective action will implement a modification to prevent inadvertent closure of valve FCV-626 for a momentary loss of power. The licensee stated the modification would be implemented prior to restart of the plant from the refueling outage. Additional review by the NRC will be needed to determine whether the design of FCV- 626, which caused the valve to close during a momentary loss of power, represents a performance deficiency. An Unresolved Item will be opened pending completion of this review. This issue is identified as URI 05000261/2010009-11, FCV 626, RCP Thermal Barrier Outlet Isolation CCW Valve, Unexpected Closure. In order to better understand the reason FCV-626 closed during a momentary loss of power, the team reviewed the licensing bases for the CCW system, including FCV-626. The team reviewed correspondence between the licensee and the NRC regarding NUREG 0737, Clarification of TMI Action Plan Requirements, Item II.K.3.25, Power on Pump Seals. This TMI item required the licensee to determine the consequences of a loss of RCP cooling due to a loss of offsite power lasting two hours. In their correspondence, the licensee stated that no modifications were necessary because the CCW system is still operable during a loss of offsite power (powered from the emergency buses) and provides flow to the RCP thermal barrier heat exchangers. They also stated that the B and C CCW pumps are automatically (requiring no operator action) started by a station blackout signal during a loss of offsite power event. Additional review by the NRC will be needed to determine if the behavior of RCP seal cooling following a loss of offsite power event is consistent with the description provided by the licensee in NUREG 0737 correspondence and if any differences represent a violation. An Unresolved Item will be opened pending completion of this review. The issue is identified as URI 05000261/2010009-12, NUREG 0737 Response From Licensee to the NRC Describing the Behavior of RCP Seal Cooling Following a Loss of Offsite Power Event. |
| 05000261/FIN-2010009-10 | 2010Q2 | Robinson | Failure of Charging Pump Suction Valves to Automatically Transfer Due to Errors in Implementing a Instrumentation Component Upgrade | Following the cable fault and resultant reactor trip, VCT level decreased and reached a low level set point that should have automatically transferred the suction source for the running charging pump to the RWST. The transfer did not take place as designed. The control circuitry which implements this transfer utilizes two VCT level transmitters. When each transmitter senses a low level, it energizes a relay via a comparator. When both relays are energized, and their contacts are closed, the circuit for opening the charging pump suction from RWST valve (LCV-115B) should be made up and the valve should open. Then, when LCV-115B opens, a signal is generated to close the VCT suction valve (LCV-115C.) One of the relays in the LCV-115B circuit was driven by an older style Hagan level comparator, and the other relay was driven by a newer style NUS comparator. Different NUS comparator configuration options, such as electromechanical relay or solid state output, can be made by placing plug-type jumpers at different locations on the circuit board. The licensees post-event troubleshooting revealed that the NUS comparator was not properly configured when it was installed in 2008. The NUS comparator should have been configured to have its output function operate in the solid state mode and energize the control relay when a low level was sensed. When the comparator was configured in 2008, the placement of jumpers resulted in an electromechanical relay output, which was only capable of de-energizing the control relay upon low level. As a result, the control relay driven by the NUS comparator was in the energized state when level in the VCT was normal. When level in the VCT decreased below the level at which the suction to the charging pumps should have transferred, the associated valves did not reposition because the relay driven by the NUS comparator was de-energized and the valve open circuit was not made up. The licensee did not detect the incorrect configuration of the NUS comparator after installation because of the limited scope of the post-installation testing. When the new comparator module was calibrated the bistable trip light responded as intended, satisfying the test acceptance criterion. The output contacts were not checked during the calibration and the licensee did not perform an integrated test, such as simulating a low VCT level, to confirm the two valves repositioned. The licensee replaced the VCT level Hagan comparator with an NUS comparator as part of a larger project to provide a replacement for obsolete Hagan comparators. Licensee engineers stated that about 80 percent of the Hagan comparators had been replaced with NUS comparators at the time of the AIT inspection. The team questioned the extent of condition for potential similar errors in replacement comparators, i.e. incorrect placement of jumpers and inadequate testing for detecting errors. The licensee noted that comparators used to perform reactor protection system functions, safety injection functions and certain other functions were subject to Technical Specification surveillance testing, which provided a check of the comparator output contacts. The licensee also pointed out that the circuit in question may have been unique in that only one of the comparators used in the two-out-of-two logic had been changed to the new NUS module. If two NUS modules had been installed, both containing the incorrect configuration for the jumpers, the transfer from VCT to RWST suction would have taken place with a normal VCT level and the problem would have been self revealing. The licensee stated that many control functions using the new NUS modules would alarm when the bistable actuates, making a similar problem self revealing. The licensee controlled the substitution of NUS comparators for Hagan comparators under the plant modification process using Engineering Evaluation EE-92-144. The licensee controlled component removal and installation within the maintenance process. The installation of the comparator for the charging pump suction transfer control circuit was accomplished under Work Order 011162348 in September 2008. Work order instructions directed an I&C technician to refer to the calibration procedure to determine the desired comparator configuration and refer to NUS instruction book EIP-M-DAM800 to determine the placement of jumpers necessary to implement that configuration. The placement and removal of jumpers was translated to work instructions which were reviewed and verified by an I&C system engineer. The licensee stated their planned corrective actions would include a review of all control circuits incorporating NUS comparators to confirm these circuits will operate properly. In cases where a review indicates proper operation cannot be assured, the licensee stated that appropriate testing will be performed. In addition, the process for implementing any future NUS comparator installations will be strengthened to preclude the problems described above. The team determined the failure of the suction for the charging pumps to automatically transfer from the VCT to the RWST upon low level in the VCT was caused by an error in the work instructions describing the placement of jumpers when a VCT level comparator was replaced. Additionally, the licensees post-maintenance testing was not adequate to detect the problem. Additional review by the NRC will be needed to determine whether these problems represent a performance deficiency. An Unresolved Item will be opened pending completion of this review. The issue is identified as URI 05000261/2010009-10, Failure of Charging Pump Suction Valves to Automatically Transfer Due to Errors in Implementing an Instrumentation Component Upgrade. |
| 05000261/FIN-2010009-05 | 2010Q2 | Robinson | Corrective Action for Operating Crew Performance Issues | To assess the extent of condition for the operator performance issues demonstrated during this event, the team reviewed a sample of simulator crew evaluation forms spanning the period of February 2008 to February 2010. The team identified multiple examples of operating crew weaknesses identified by training, relative to monitoring and control of major plant parameters. Of the six packages reviewed, four contained comments summarized as follows: February 27, 2008 unaware of steam dumps open; no attempt at RCS temperature control March 3, 2008 crew not clear if steam dumps actuated February 19, 2009 pressurizer level control post-trip was not anticipated; S/G level control needed improvement February 24, 2009 slow to identify steam dump malfunction; post- trip trends of associated parameters not provided The team noted that even though the evaluations highlighted the operators responsibility for monitoring and controlling major plant parameters, this emphasis was not effective in achieving the level of performance necessary to stabilize the plant following the uncontrolled cooldown that occurred during this event. The team concluded that additional inspection is warranted to determine if the licensees corrective action program is effective in capturing and addressing operating crew performance weaknesses. The team noted that the licensee also identified this issue regarding operating crew performance standards as part of their event investigation. This review will also determine if this issue represents a performance deficiency. An Unresolved Item will be opened pending completion of this review. The URI is identified as 05000261/2010009-05, Corrective Action for Operating Crew Performance Issues. |
| 05000261/FIN-2010002-02 | 2010Q1 | Robinson | A Emergency Diesel Generator Fuel Oil Transfer Pump Power Supply Cable Subjected to Continuous Submersion in Water Design Deficiency | The inspectors identified a NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, in that the licensee failed to maintain a safety-related cable in an environment for which it was designed. Specifically, the A Emergency Diesel (EDG) Fuel Oil Transfer Pump power supply cable was exposed to continuous submersion in water. The licensee removed the accumulated water from the hand hole, resealed, and reinstalled the hand hole cover. The licensee entered the issue into the corrective action program as AR 370343. Failure to maintain a safety related cable in an environment for which it was designed is a performance deficiency. The finding is more than minor in accordance with IMC 0612, Appendix B (Block 9, Figure 2), Issue Screening, because if left uncorrected, the performance deficiency has the potential to lead to a more significant safety concern. Specifically, subjecting the A EDG fuel oil transfer pump cable to continuous submersion could, over time degrade the cable and result in failure. In accordance with IMC 0609 (Table 4a), Phase 1 Initial Screening and Characterization of Findings, the finding was determined to be of very low safety significance (Green) because the finding was not a design or qualification deficiency which resulted in a loss of operability or functionality. The cause of the finding was directly related to the problem evaluation cross-cutting aspect in the corrective action program component of the Problem Identification and Resolution area because the licensee did not thoroughly evaluate the condition described in NRC Generic Letter 2007-01 Inaccessible or Underground Power Cable Failures that Disable Accident Mitigation Systems or Cause Plant Transients (P.1 (c) |
| 05000261/FIN-2010002-01 | 2010Q1 | Robinson | Inaccurate Drawings Result I Loss of RWST Level Indication Due to Freezing | A self-revealing non-cited violation of Technical Specification 5.4.1, Procedures, was identified in that the licensee used inaccurate drawings to hang clearances on freeze protection circuits which resulted in the Refueling Water Storage Tank (RWST) level instrument lines freezing. The licensee failed to properly translate the design of the freeze protection circuits to the drawings used in the clearances, causing the RWST level sensing line freeze protection to be unavailable. The licensee removed the clearance, re-energized the freeze protection and level indications were restored. The licensee entered the drawing discrepancy issue into the corrective action program as AR 374561 The disabling of the RWST level instrument freeze protection during the RHR pump work is a performance deficiency. The finding is more than minor because it affected the mitigating systems cornerstone objective to ensure the availability, reliability and capability of systems that respond to initiating events. Specifically, the RWST level instrument line freezing caused the required post accident instrumentation of the RWST to be inoperable. Using Appendix A of the Significance Process (SDP) described in IMC 0609, Mitigating System Cornerstone, this finding was determined to have very low safety significance (Green) because no loss of operability or functionality of the RWST resulted from the level sensing line freezing. There is no cross-cutting aspect of this NCV since the incorrect drawing that resulted in the inaccurate clearance was last revised in 1986 and is not indicative of current licensee performance. |