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| Quarter | Site | Title | Description | |
|---|---|---|---|---|
| 05000259/FIN-2009007-01 | 2009Q2 | Browns Ferry | Suppression Pool Initial Temperature Assumed in the Appendix R Thermo-Hydraulic Analysis May not be the Most Limiting Value | The team identified a URI involving a postulated fire scenario in which the initial suppression pool temperature assumed in the licensees Appendix R thermohydraulic analysis may not be the most limiting value for a postulated fire in certain FAs.The licensees Appendix R thermo-hydraulic analysis was based on specific initial plant conditions at the time of entry into the SSIs. During review, the team noted that a fire induced single spurious equipment operation could result in plant parameters being outside the initial conditions assumed in the thermo-hydraulic analysis and SSA prior to entry into the SSIs. This was corroborated by a simulator exercise for a postulated fire in FA 9, which demonstrated the effect on suppression pool temperature of a single main steam safety relief valve (MSRV) spuriously opening at the onset of a fire. During the simulator exercise, suppression pool temperature quickly rose above the 95 degrees Fahrenheit (o F) value assumed in the thermo-hydraulic analysis. Suppression pool temperature above the analyzed value could impact the net positive suction head (NPSH) required for the low pressure coolant injection (LPCI) pumps, which were credited for providing core cooling (if high pressure systems were not available) and suppression pool cooling. This issue was discussed with licensee personnel who initiated problem evaluation report (PER) 169488 to assess the basis for the suppression pool temperature assumed in the Appendix R analysis. The licensee had hourly roving fire watches in place (which were implemented as additional compensatory measures to address the existing noncompliant OMAs) while this issue was being evaluated. This issue is unresolved pending the NRCs review of the licensees assessment of the suppression pool temperature basis during the fall 2009 triennial fire protection inspection (TFPI). This issue is identified as URI 05000259, 260, 296/2009007-01, Suppression Pool Initial Temperature Assumed in the Appendix R Thermo-Hydraulic Analysis May not be the Most Limiting Value |
| 05000259/FIN-2009007-02 | 2009Q2 | Browns Ferry | Containment Isolation Valves not Included in the Appendix R Separation Analysis | The team identified a URI concerning whether the containment isolation valves (CIVs) were included and properly analyzed for availability in the Appendix R separation analysis to ensure closure to support COP and NPSH requirements for postulated fires in certain FAs. TVA submitted a letter to the NRC dated November 15, 2007, Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 - Technical Specifications (TS) Changes TS-431 and TS-418 - Extended Power Uprate (EPU) - Response to Round 13 Request for Additional Information (RAI) - Containment Overpressure APLA-35/37. In that letter, TVA indicated that the analysis for Appendix R showed that credit for COP was needed during certain fire scenarios to ensure adequate NPSH for the residual heat removal (RHR) pump operating in the alternate shutdown cooling mode for a postulated worst case fire event. However, fire damage to circuits of CIVs could cause failure to close or spurious opening of the CIVs which could result in the depressurization of the primary containment. The TVA letter further stated that the FAs in which COP would be needed were reviewed and TVA concluded from the review that none of the CIV cables that could cause spurious opening (downstream of the MCR hand switches) were located in the FAs of concern. However, during this inspection, TVA personnel informed the team that the CIVs were not included in the Appendix R separation analysis and may not have been analyzed for fire induced spurious actuations in the FAs of concern where COP was needed to ensure adequate NPSH. The information discussed with the team during this inspection regarding the CIVs did not appear to be consistent with the information provided in the licensees November 15, 2007, letter to the NRC. The team questioned the adequacy of the SSA (i.e., were the CIV cables sufficiently analyzed for spurious actuation in the FAs where COP was needed) in that the CIVs were not included as minimum SSD system equipment necessary for COP for the alternate shutdown cooling mode. The licensee initiated PER 169484 to review the Appendix R separation analysis to determine if the CIVs needed to be included in the analysis. The team noted that the licensees EPU license amendment request submittals were being reviewed by NRR and questions had been raised regarding the COP needed to ensure adequate NPSH requirements for the available RHR pump. The team discussed the CIV issue with the NRR licensing project manager for BFN to ensure NRR awareness and consideration of the issue during review of the licensees EPU license amendment request. This issue is unresolved pending further NRR review of the licensees analysis of the CIV cables for potential impact on the COP and NPSH concerns associated with the EPU. This CIV issue is identified as URI 05000259, 260, 296/2009007-02, Containment Isolation Valves not Included in the Appendix R Separation Analysis |
| 05000259/FIN-2009007-03 | 2009Q2 | Browns Ferry | Operator Manual Actions to Isolate Main Steam Safety Relief Valves for a Unit 2 Appendix R Fire Event | The team identified a URI related to the concern that the Unit 2 SSIs were different from the Units 1 and 3 SSIs, in that the Unit 2 SSIs did not include OMAs to address closure of an MSRV if the valve were to spuriously open due to a postulated fire. During review/walkdown of selected SSIs, the team noted that the Unit 1 and Unit 3 SSIs included OMAs to direct closure of a spuriously opened MSRV, but the Unit 2 SSIs did not have similar OMAs. The team discussed this inconsistency with licensee personnel who stated that the analyses were different because the vendor who performed the Unit 2 SSA was different from the vendor who performed the SSA for Units 1 and 3. The licensee initiated PER 169487 to evaluate the need for OMAs to isolate an MSRV during a Unit 2 Appendix R fire event. The licensee had hourly roving fire watches in place (which were implemented as additional compensatory measures to address the existing noncompliant OMAs) while this issue was being evaluated. This issue is identified as URI 05000259, 260, 296/2009007-03, Operator Manual Actions to Isolate Main Steam Safety Relief Valves for a Unit 2 Appendix R Fire Event, and is unresolved pending further NRC review of the licensees evaluation during the fall 2009 BFN TFPI |
| 05000259/FIN-2009009-01 | 2009Q4 | Browns Ferry | Deficiencies with Emergency Lighting Units | The team identified a Green non-cited violation of Browns Ferry Units 1, 2, and 3 Operating License Conditions 2.C(13), 2.C(14), and 2.C(7), respectively, for the licensees failure to maintain in effect all provisions of the NRC-approved fire protection program, as described in the Final Safety Analysis Report. The Fire Protection Report (referenced in the Final Safety Analysis Report) requires that measures be established to ensure that conditions adverse to fire protection, such as failures and deficiencies, are promptly identified and corrected. The licensee had not established measures to identify and correct an excessive number of Appendix R emergency lighting unit failures. Specifically, emergency lighting unit failures were not being entered in the corrective action program as problem evaluation reports in order to evaluate and resolve why many of the emergency lighting failures occurred prior to reaching their 6-year replacement date. Additionally, the Fire Protection Report surveillance requirement to replace the Appendix R emergency lighting unit batteries and lamp heads every six years was not being adequately implemented, in that licensee data revealed that several installed emergency lighting units were beyond their 6-year replacement date. The licensee entered this finding into their corrective action program and initiated corrective actions to address these issues. The licensees failure to meet the Fire Protection Report requirements to establish measures to identify and correct a condition adverse to fire protection (excessive Appendix R emergency lighting unit failures); and, to implement the Appendix R emergency lighting system replacement program, is a performance deficiency. The finding is more than minor because it is associated with the reactor safety, mitigating systems cornerstone attribute of protection against external factors (i.e., fire). The excessive emergency lighting unit failures affected the objective of ensuring the reliability and capability of operator manual actions during response to initiating events. The team determined that this finding was of very low safety significance (Green) because the operators had a high likelihood of completing the tasks using flashlights. The cause of this finding has a cross-cutting aspect in the Work Control component of the Human Performance area, in that it was directly related to the licensee not planning and coordinating work activities to support long-term equipment reliability, and their maintenance scheduling was more reactive than preventive (H.3 (b)) |
| 05000259/FIN-2009009-02 | 2009Q4 | Browns Ferry | Failure to Establish Adequate Compensatory Measures for an Out-of-Service Hose Station | The team identified a Green non-cited violation of Browns Ferry Units 1, 2, and 3 Operating License Conditions 2.C(13), 2.C(14), and 2.C(7), respectively, for the licensees failure to maintain in effect all provisions of the NRC-approved fire protection program as described in the Final Safety Analysis Report. The Fire Protection Report (referenced in the Final Safety Analysis Report) requires the licensee to establish adequate compensatory measures for degraded or inoperable fire protection equipment. The licensee failed to establish adequate compensatory measures for an out-of-service hose station, in that the staged additional lengths of hose connected to the closest inservice hose station, established as a compensatory measure, did not provide equal or better protection than the out-of-service hose station that it was replacing. The licensee entered this finding into their corrective action program and took immediate action to review all existing fire protection impairment permits for similar problems. The licensee removed the compensatory measure and restored the out-of-service hose station to service. The licensees failure to provide compensatory measures of equal or better protection for an out-of-service hose station is a performance deficiency because it did not meet the requirements of the approved fire protection program. The finding was more than minor because it affected the protection against external factors attribute of the mitigating systems cornerstone, in that it impacted manual fire suppression (i.e., fire brigade) capability; and, affected the cornerstone objective of ensuring the availability of systems that respond to initiating events. Since Inspection Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process, does not provide guidance for assigning a degradation rating to manual fire suppression, this determination was made using qualitative methods which received NRC management review as provided for in Inspection Manual Chapter 0609, Appendix M, Significance Determination Process Using Qualitative Criteria. This finding was determined to be of very low safety significance (Green) because it represented a low degradation of the manual fire suppression function. Although the fire protection impairment permit had been implemented for an out-of-service hose station, the hose station was still functional at the time this issue was identified, because the water supply to the hose station had not been physically isolated. However, the team concluded the fire brigade would have experienced delays in initiating manual fire suppression for a fire in a fire area covered by the impairment. The cause of this finding has a cross-cutting aspect in the Work Control component of the Human Performance area, in that it was directly related to the licensee not planning and coordinating work activities, consistent with nuclear safety, to ensure that adequate compensatory actions were established for an out-of-service hose station (H.3 (a)) |
| 05000259/FIN-2009009-03 | 2009Q4 | Browns Ferry | Failure to Protect Cables of Systems Necessary to Achieve and/or Maintain Post-Fire Safe Shutdown Conditions for Fire Areas Subject to the Requirements of 10 CFR Part 50, Appendix R, Section III.G.2 | The team identified an apparent violation of Title 10 of the Code of Federal Regulations (10 CFR), Part 50, Appendix R, Section III.G.2, for the licensees failure to ensure one of the redundant trains of cables and equipment required for safe shutdown and located in the same fire area was free of fire damage. Specifically, cables associated with equipment required for safe shutdown had not been protected by one of the methods specified in 10 CFR Part 50, Appendix R, Section III.G.2 (i.e., use of spatial separation, passive barriers, and fire detection and an automatic fire suppression system). This apparent violation applies to Browns Ferry Units 1, 2, and 3, and resulted from review and closure of two unresolved items which were opened in previous inspections. The licensee entered this apparent violation into their corrective action program and posted additional compensatory measures while long term corrective actions are being implemented. Failure to protect one train of cables and equipment necessary to achieve post-fire safe shutdown from fire damage, as required by 10 CFR Part 50, Appendix R, Section III.G.2, is a performance deficiency. This finding is more than minor because it is associated with the reactor safety mitigating system cornerstone attribute of protection against external events (i.e., fire). Failure to protect safe shutdown cables and equipment from fire damage affects the reactor safety mitigating systems cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The team performed a significance determination process Phase 1 screening. Given the likely impact of the risk contribution arising from the assessment of multiple fire areas, Region II senior reactor analysts performed a Phase 3 significance determination, which resulted in a preliminary risk of Greater Than Green. The team determined that this apparent violation did not present an immediate safety concern because the licensee implemented compensatory measures while long-term corrective actions are being implemented. The compensatory measures included operator manual actions to mitigate or prevent damage to equipment necessary for safe shutdown in the event of a fire. The licensee also implemented fire watches as additional compensatory measures to mitigate the safety hazard. Subsequent to the onsite inspection, the licensee evaluated the most critical operator manual actions, and revised selected safe shutdown instructions to include steps for independent confirmation of operator manual actions in order to improve the likelihood of success of these steps, and thus reduce the risk associated with this apparent violation. The cause of this finding has a cross-cutting aspect in the Corrective Action Program component of the Problem Identification and Resolution area, in that the licensee did not take appropriate corrective actions to address the issue in a timely manner, commensurate with the safety significance (P.1 (d)) |
| 05000259/FIN-2009009-04 | 2009Q4 | Browns Ferry | Failure to Meet the Requirements of 10 CFR Part 50, Appendix R, Section III.G.1 for 20 Fire Areas | The team identified an apparent violation of Title 10 of the Code of Federal Regulations (10 CFR), Part 50, Appendix R, Section III.G.1, for the licensees failure to ensure that one train of cables and equipment necessary to achieve and maintain hot shutdown conditions was free of fire damage in 20 fire areas. In addition, these cables had not been protected by one of the methods specified in Appendix R, Section III.G.2 (i.e., use of spatial separation, passive barriers, and fire detection and an automatic suppression system). This apparent violation applies to Browns Ferry Units 1, 2, and 3, and resulted from review and closure of two unresolved items which were opened in previous inspections. The licensee entered this finding into their corrective action program and posted additional compensatory measures while long term corrective actions are being completed. Failure to meet the requirements of 10 CFR Part 50, Appendix R, Section III.G.1 is a performance deficiency. It is more than minor because it is associated with the reactor safety mitigating system cornerstone attribute of protection against external events (i.e., fire). Failure to ensure that one train of safe shutdown cables and equipment was free of fire damage affects the reactor safety mitigating systems cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events. This finding was evaluated in accordance with NRC Inspection Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process. The team performed a significance determination process Phase 1 screening. Given the likely impact of the risk contribution arising from the assessment of multiple fire areas, Region II senior reactor analysts performed a Phase 3 significance determination, which resulted in a preliminary risk of Greater Than Green. The team determined that this apparent violation did not present an immediate safety concern because the licensee implemented compensatory measures while long-term corrective actions are being implemented. The compensatory measures included operator manual actions to mitigate or prevent damage to equipment necessary for safe shutdown in the event of a fire. The licensee also implemented fire watches as additional compensatory measures to mitigate the safety hazard. Subsequent to the onsite inspection, the licensee evaluated the most critical operator manual actions, and revised selected safe shutdown instructions to include steps for independent confirmation of operator manual actions in order to improve the likelihood of success of these steps, and thus reduce the risk associated with this apparent violation. The cause of this finding has a cross-cutting aspect in the Corrective Action Program component of the Problem Identification and Resolution area, in that the licensee did not identify and thoroughly evaluate the problem, and the resolution did not address causes and extent of conditio |
| 05000275/FIN-2014003-01 | 2014Q2 | Diablo Canyon | Failure to Follow Procedure Associated with Seismically Induced System Interactions | The inspectors identified a Green non-cited violation of 10 CFR, Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure to properly identify and evaluate system interactions as required by the licensees Seismically-Induced Systems Interaction Program Procedure AD4.ID3, SISIP Housekeeping Activities. Specifically, the inspectors identified multiple instances of components or sources capable of producing a potential threat related to seismic induced structural interactions of safety related equipment or components. The licensee entered the finding into the corrective action program as Condition Report 50629355. The failure of plant personnel to follow procedure requirements to properly identify and evaluate for impact equipment near sensitive or safety-related equipment was a performance deficiency. This performance deficiency was more than minor and is therefore a finding because it was associated with the protection against external factors (seismic) attribute of the Mitigating Systems Cornerstone objective and adversely affected the objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, because Diablo Canyon staff did not fix or perform evaluations of seismic induced system interactions on safety-related or accident-mitigating systems, this had the potential to challenge the availability, reliability, and capability of various systems required to function following or during earthquakes to prevent undesirable consequence. Using Inspection Manual Chapter 0609, Attachment 04, Initial Characterization of Findings, and Appendix A, Exhibit 2, Mitigating System Screening Questions, the finding was determined to be of very low safety significance (Green) because the finding was associated with seismic design or qualification of systems, structures, and components but did not result in the loss of a system operability or functionality. The inspectors determined this finding has a problem identification and resolution cross-cutting aspect associated with the Identification attribute; specifically in that PG&E personnel failed to implement the Seismically-Induced Systems Interaction Program with a low enough threshold for identifying and assessing seismic induced system interactions in accordance with the program and procedures (P.1). (Section 1R04) |
| 05000275/FIN-2014003-02 | 2014Q2 | Diablo Canyon | Inadequate Design Control with Respect to Seismic Induced System Interaction of Safety Related Components | The inspectors identified a Green non-cited violation of 10 CFR, Part 50, Appendix B, Criterion III, Design Control, involving the licensees failure to verify the adequacy of their design with respect to seismic induced system interaction of safety related components. Specifically, PG&E did not verify the adequacy of interference limitations on structural components associated with the safety-related component cooling water heat exchanger. The licensee entered the finding in the corrective action program as Condition Report 50612919. The licensees failure to verify the adequacy of their design with respect to seismic induced system interaction of safety related components was a performance deficiency. This performance deficiency is more than minor, and is therefore a finding because the finding was associated with the Mitigating Systems Cornerstone attribute of design control and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of the component cooling water system to respond to initiating events to prevent undesirable consequences. Specifically, the original plant design configuration associated with seismic interference clearances for Unit 1 component cooling water heat exchanger components was not adequately controlled to ensure design piping stresses would not be challenged. Using Inspection Manual Chapter 0609, Attachment 04, Initial Characterization of Findings, and Appendix A, Exhibit 2, Mitigating System Screening Questions, the finding was determined to be of very low safety significance (Green) because the finding was associated with seismic design or qualification of systems, structures, and components but did not result in the loss of a system operability or functionality. This finding did not have a cross-cutting aspect because the most significant contributor did not reflect current licensee performance. (Section 1R04) |
| 05000285/FIN-2008009-01 | 2008Q3 | Fort Calhoun | Untimely Corrective Actions for Degraded Fire Protection Water Supply System | The team identified a noncited violation of License Condition 2.D and the Quality Assurance Plan for failure to implement timely corrective actions to address a degraded fire water supply system. Despite determining that the system was degraded and taking compensatory actions to assure the system remained functional in 2006, the licensee failed to correct the condition prior to completing the next outage. Using the guidance of Regulatory Issue Summary 2005-20, Revision 1, Operability Determinations & Functionality Assessments for Resolution of Degraded or Nonconforming Conditions Adverse to Quality or Safety, the team determined the corrective actions were untimely and subject to enforcement. The fire water supply system piping continued to degrade because of corrosion. The licensee documented this deficiency in Condition Report 200805319. The failure to correct the degraded fire water supply system in a timely manner was a performance deficiency. This deficiency was more than minor because if left uncorrected the finding would become a more significant safety concern, as a result of ongoing corrosion. The team evaluated this deficiency using Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process. Because the fire water supply system met its design functions so long as both pumps and all pipe segments remained in service and the licensee established appropriate compensatory measures, the team assigned this finding a low degradation rating. As specified in Appendix F, Step 1.3, this finding had very low safety significance (Green). This finding has a crosscutting aspect in the area of human performance, specifically the resources attribute (H.2(a)), in that the licensee failed to promptly correct degraded fire water supply system and minimize the longstanding condition |
| 05000285/FIN-2008009-02 | 2008Q3 | Fort Calhoun | Inadequate Corrective Actions Related to Revising a POST-FIRE Safe Shutdown Procedure | The team identified a noncited violation of License Condition 2.D and the Quality Assurance Plan for failure to take adequate corrective action for a condition adverse to fire protection. Specifically, the licensee had included steps to open the breakers for the reactor coolant gas vent system valves in response to Noncited Violation 05000285/2005008-07; however, the licensee failed to identify, proceduralize and train operators to identify the instruments needed to implement this action. Spurious actuation of the valves because of fire damage could result in uncontrolled loss of reactor coolant inventory. The licensee documented this deficiency in Condition Report 200805325. The failure to ensure that procedure steps instructed operators how to recognize the need to close spuriously opened reactor coolant gas system vent valves was a performance deficiency. This deficiency was more than minor in that it had the potential to affect the procedure quality attribute of the mitigating systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to external events (fire). The team evaluated this deficiency using Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process. Because of the design of the vent system valves (i.e., three spurious actuations needed to exceed charging pump capability), the availability of reliable reactor coolant system pressure and pressurizer level indications in the control room, and the ability of operator to compensate for the deficiency because of their experience and training, the team assigned this finding a low degradation rating. As specified in Appendix F, Step 1.3, this finding had very low safety significance (Green). This finding has a crosscutting aspect in the area of human performance, specifically the resources attribute (H.2(c)), in that the licensee failed to ensure that operators had complete, accurate and up-to-date procedures providing sufficient guidance to correct spurious reactor coolant gas vent system valve operation |
| 05000285/FIN-2008009-03 | 2008Q3 | Fort Calhoun | Licensee-Identified Violation | From review of the 2005, 2006 and 2007 Quality Assurance Audits, the team determined that Quality Assurance had identified repeat findings in the audits conducted the previous year. The repeat findings for each audit resulted from a different topic. Specifically, the 2005, 2006, and 2007 Audits identified repeat findings in establishing compensatory measures for impaired systems and equipment, security officers assigned to fire brigade duties did not have current fire brigade physicals, and corrective actions to address low water flow, respectively. License Condition 2.D and the Quality Assurance Plan, Section 10.4 require the licensee to promptly identify and correct conditions adverse to the fire protection program. Contrary to these requirements, the licensee failed to correct these deficiencies in a timely manner. The licensee had initiated Condition Report 200800411 to document a lack of responsiveness by site organizations to the Quality Assurance organization |
| 05000285/FIN-2011006-02 | 2011Q4 | Fort Calhoun | Inadequate Corrective Actions to Ensure the Reliability of the RAW Water Pump Power Cables | The NRC identified a cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, for failure to take effective corrective action following the initial discovery of water intrusion in cable vault manholes MH-5 and MH-31 in 1998, 2005, 2009, and 2011. Specifically, the licensee failed to take effective corrective action to establish an appropriate monitoring frequency, which took into account variable environmental conditions to mitigate potential common mode failure of raw water 4160 V motor cables in underground ducts and manholes identified during the Component Design Basis Inspection performed in 2009. The violation is being cited because the licensee had failed to restore compliance in a reasonable period following documentation of the issue as a non-cited violation issued December 30, 2009. The failure to take effective corrective action to ensure the reliability and capability of the safety-related cables powering the raw water pump motors was a performance deficiency. Furthermore, the finding was within the licensee\\\'s ability to foresee and correct because the licensee had multiple opportunities to correct the continuing challenge to the safety-related cables and raceways for the raw water system over an extended period. The finding was more than minor because it adversely affected the Mitigating Systems Cornerstone attribute of design control for ensuring the availability, reliability, and capability of systems that respond to Initiating Events to prevent undesirable consequences. The finding is of very low safety significance because it was a design deficiency that did not result in loss of operability or functionality. This finding has a crosscutting aspect in the decision-making program component of the human performance area because the licensee failed to use conservative assumptions in decision-making and adopt a requirement to demonstrate that the proposed action was safe in order to proceed rather than a requirement to demonstrate that it was unsafe in order to disapprove the action. Specifically, from 2005 until 2011, the licensee chose to postpone installation of proposed water level control corrective actions and failed to appropriately monitor water intrusion into underground ducts and manholes MH-5 and MH-31 for raw water 4160 V motor cables multiple times |
| 05000285/FIN-2012007-01 | 2012Q2 | Fort Calhoun | Failure to Provide Adequate Post-Fire Safe Shutdown Actions in the Switchgear Rooms | The inspectors identified a violation of Technical Specification 5.8.1.c for an inadequate fire protection procedure. Specifically, the post-fire safe shutdown procedure had several deficiencies that would have prevented implementation for fires that occurred in the East and West Switchgear Rooms. This finding, and its corrective actions, will be managed by the Manual Chapter 0350 Oversight Panel. Enforcement Action 12-121 is associated with this finding. The failure to ensure a post-fire safe shutdown procedure could be implemented as written for fires in the East and West Switchgear Rooms was a performance deficiency. The performance deficiency was more than minor because it was associated with the protection against external events (fire) attribute of the Mitigating Systems Cornerstone and it adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The significance of this finding is bounded by the significance of a related Red finding regarding a fire in the 480 Vac safety-related switchgear in June 2011 (Inspection Report 05000285/2012010). The performance deficiency had a cross-cutting aspect in the area of human performance associated with decision making because the licensee did not perform effective interdisciplinary reviews during development of the post-fire safe shutdown procedure. |
| 05000285/FIN-2012007-03 | 2012Q2 | Fort Calhoun | Alternate Shutdown Procedure Does Not Account for Single Worst Case Spurious Actuations | The inspectors identified a non-cited violation with two examples related to the failure to establish an alternate shutdown capability that met the requirements of License Condition 3.D and the performance criteria in 10 CFR Part 50, Appendix R, Section III.L. Specifically, the licensee failed to establish an alternate shutdown capability that accounted for the effects of an inadvertent safety injection actuation signal and failed to ensure the plant parameters remained similar to those experienced during a loss of normal a.c. power following single spurious component actuations. The failure to meet the performance goals prescribed by the alternate shutdown capability was a performance deficiency. The performance deficiency was more than minor because it was associated with the protection against external events (fire) attribute of the Mitigating Systems Cornerstone and it adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors evaluated this deficiency using Inspection Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process. The performance deficiency affected the fire protection defense-in depth strategies involving post-fire safe shutdown systems. Because Appendix F does not address control room fire scenarios, a senior reactor analyst evaluated the significance of this performance deficiency. This finding was evaluated using the process in Inspection Manual Chapter 0609, Attachment 4, Phase 1 Initial Screening and Characterization of Findings, and was determined to be of very low safety significance because the finding was not a design deficiency, confirmed not to result in loss of functionality, did not result in loss of a system safety function, did not result in loss of the safety function for a single train, did not result in loss of safety function for maintenance rule equipment, and did not potentially affect risk significant external initiating events. Because the original failure to comply with the regulations had occurred longer than three years prior to this inspection, this finding did not reflect current licensee performance. |
| 05000285/FIN-2012007-04 | 2012Q2 | Fort Calhoun | Failure to Provide Adequate Alternate Shutdown Capability | The inspectors identified a non-cited violation of Technical Specification 5.8.1.c for an inadequate fire protection procedure. Specifically, the post-fire safe shutdown procedure had several deficiencies that would have prevented implementation of the alternate shutdown capability for fires in the control/cable spreading rooms. The failure to establish a procedure that could be implemented as written for fires that require operators to abandon the control room was a performance deficiency. The performance deficiency was more than minor because it was associated with the protection against external events (fire) attribute of the Mitigating Systems Cornerstone and it adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors evaluated this deficiency using Inspection Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process. The performance deficiency affected the fire protection defense-in depth strategies involving post-fire safe shutdown systems. Because Appendix F does not address control room fire scenarios, a senior reactor analyst evaluated the significance of this performance deficiency. This finding was evaluated using the process in Inspection Manual Chapter 0609, Attachment 4, and was determined to be of very low safety significance because the finding was not a design deficiency, confirmed not to result in loss of functionality, did not result in loss of a system safety function, did not result in loss of the safety function for a single train, did not result in loss of safety function for maintenance rule equipment, and did not potentially affect risk significant external initiating events. This finding had a cross-cutting aspect in the area of human performance associated with decision making because the licensee did not perform effective interdisciplinary reviews during development of the post-fire safe shutdown procedures. |
| 05000285/FIN-2012007-05 | 2012Q2 | Fort Calhoun | Untimely Corrective Actions Related to Revising a Post- Fire Safe Shutdown Procedure | The inspectors identified a non-cited violation of License Condition 3.D and the Quality Assurance Plan for failure to take timely corrective action. Specifically, the licensee revised procedure steps to open the breakers for the reactor coolant gas vent system valves in response to Non-cited Violation 05000285/2008009-02; however, the licensee did not revise the procedures until March 24, 2012, after the inspectors requested to review the corrective actions for the 2008 violation. The failure to take timely corrective action to address inadequate procedure guidance to safely shutdown the plant following a fire was a performance deficiency. The finding was more than minor because it was associated with the protection against external events (fire) 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. This finding was evaluated using the Fire Protection Significance Determination Process and was determined to be of very low safety significance because of the design of the vent system valves (i.e., three spurious actuations needed to exceed charging pump capability), availability of reliable reactor coolant system pressure and pressurizer level indications in the control room, and the ability of the operator to compensate for the deficiency because of their experience and familiarity. This finding had a cross-cutting aspect in the area of human performance associated with decision making because the licensee did not use a systematic process to correct fire protection procedure deficiencies in response to a violation in 2008. |
| 05000285/FIN-2012009-01 | 2012Q2 | Fort Calhoun | Evaluation of Future Discharge Tunnel Inspection Plans | Commitment 32 specified that OPPD will perform a one-time inspection of the circulating water discharge tunnel per the structures monitoring program (B.2.10). The circulating water discharge tunnel will be included within the scope of license renewal as part of the intake structure. The safety evaluation report and updated final safety analysis report identified that the inspections would occur prior to entering the period of extended operation. The inspectors reviewed this area by reviewing the underwater video of the inspection, conducting interviews with personnel, and reviewing documents. The licensee indicated that they planned to drain the discharge canal and perform a 100 percent one-time inspection of the structure. Because of time needed for planning and logistics, the licensee decided to conduct the inspection after entering the period of extended operation. The licensee had performed a 10 CFR 50.59 evaluation that justified allowing the inspection to occur until after they entered the period of extended operation. The inspectors questioned the licensee about performing the inspection during the ongoing extended shutdown. Following questioning by the inspector, the recovery team, who was methodically reviewing previously completed 10 CFR 50.59 evaluations, selected this 10 CFR 50.59 evaluation for independent review. The licensee determined that the 10 CFR 50.59 failed to recognize that License Condition 3.E required that the inspection be completed prior to entering the period of extended operation. Any change that did not meet this time frame would require NRC approval for the change. Consequently, the licensee performed underwater inspections prior to entering the period of extended operation. Divers evaluated the condition of approximately 10 percent of the interior surface area of the discharge tunnel. The divers reviewed low flow areas, areas that had direct impingement of flow, and one area that had the expected flow midway down one wall. The inspectors reviewed the areas selected and identified no concerns. The inspectors determined that underwater inspections of similar structures at other facilities had been performed as a representative sample. At the end of this inspection, the licensee was evaluating whether to conduct periodic inspections of the discharge tunnel as they do other structural inspections or to perform a 100 percent inspection after entering the period of extended operation. The licensee documented the inadequate 10 CFR 50.59 evaluation in Condition Report 2012-03113. The inspectors reviewed the examples in the Enforcement Manual and determined that no violation of 10 CFR 50.59 or other regulatory requirements resulted because the licensee completed the task prior to entering the period of extended operation, as committed. Follow-up and evaluation of the resolution for conducting inspections of the discharge tunnel is an unresolved item. |
| 05000285/FIN-2012009-02 | 2012Q2 | Fort Calhoun | Impact of Wetting on Safety-Related Cables | During the inspection of Manhole 31, the inspectors determined that the cables were routed in conduit. From discussions with the licensee, Manhole 31 is designed to drain to Manhole 5. The inspectors determined that each cable conduit dipped as it passed through the manhole and determined that any water trapped in the conduit had no way to flow into Manhole 5 as designed. The inspectors determined that when Manhole 5 floods an open path exists for water to travel into the conduit and become trapped in the conduit low spots in Manhole 31. The licensee documented this deficiency in Condition Report 2012-04997. Licensee records indicated that Manhole 5 had filled three times in 14 years (since 1998) since they began to keep records. The inspectors noted that corrective action documents described that the cables could be wet. The inspectors will review the specific qualifications of these cables and confirm whether the cables were qualified to be submerged. In addition, the inspectors determined that the licensee specified they would address water intrusion into the manholes prior to startup from the extended shutdown in response to Notice of Violation 05000285/2011006-02. The inspectors will review corrective actions implemented by the licensee and evaluate the impact on the cables resulting from wetting during the commitment inspection. This is considered an unresolved item. |
| 05000285/FIN-2012009-03 | 2012Q2 | Fort Calhoun | Assess Corrective Actions and Determine Structural Effect of Water Intrusion and Boric Acid on Interior Containment Walls | During containment walk downs in the steam generator bays, the inspectors verified the presence of a significant amount of boric acid on the bioshield walls in both steam generator bays outside of the reactor compartment near both the hot and cold legs. Because of the presence of insulation, the inspectors could not identify the condition of the piping and structures inside the bioshield. The licensee indicated the boric acid came from the refueling cavity liner when flooded up during refueling outages. The licensee had initiated a task team to resolve this condition and documented various deficiencies in roll-up Condition Report 2012-00116. The licensee initiated Condition Report 2011-05763 that documented the presence of an eight foot long horizontal crack above the reactor cavity liner leak-off line in the reactor cavity wall. The inspectors noted that the licensee had identified a similar deficiency in 2003, as documented in Condition Report 2003-04261. The licensee concluded the leakage through the crack did not affect the wall structurally based on no evidence of degraded reinforcing steel, the amount of reinforcement, and the thickness of the wall. The inspectors confirmed that Part 9900, Operability Determinations and Functionality Assessments for Resolution of Degraded or Nonconforming Conditions Adverse to Quality or Safety, Section C.13 specified that degraded structures remain operable so long as the degradation does not result in exceeding any acceptance limits specified in the codes and standards specified in the design basis. The licensee also compared the trends of reactor cavity liner leak-off line flow rates to previous outages. The review of trends confirmed that leakage remained constant and low for the last three outages. The inspectors verified no brown discoloration that would indicate wastage of reinforcing steel from the crack. The inspectors questioned the origin of a wetted brown stain on the reactor cavity wall below the insulation around the Steam Generator B hot leg. Consequently, the licensee initiated Condition Report 2012-05067 to determine the cause and take corrective actions. The licensee had previously identified this condition in February 2012, as documented in Condition Report 2012-01339, but had not taken any corrective actions. The inspectors will review the licensee actions to identify and address reactor cavity liner leakage and its impact on the containment structures during a future inspection. This is considered an unresolved item. |
| 05000285/FIN-2013009-01 | 2013Q3 | Fort Calhoun | Evaluation of Environmentally-Assisted Fatigue for Charging Line Nozzle | The team identified that the updated safety analysis report supplement for license renewal submitted with the license renewal application, and approved in the NRC safety evaluation report, stated that the fatigue monitoring program would be based on the industrys automated cycle counting software, FatiguePro. However, the licensee revised the updated safety analysis report after the renewed operating license was issued to use WESTEMS as the cycle counting software without performing a 10 CFR 50.59 screening or evaluation. The team determined that FatiguePro represented a methodology described in the updated safety analysis report to demonstrate that the design function of the in-scope components will be maintained during the period of extended of operation. Therefore, a revision or replacement of the original methodology required an evaluation against the criteria in 10 CFR 50.59, as required by procedure NOD-QP-16, Updated Safety Analysis Report (USAR), Revision 22. The failure to process this change would be a minor violation as described in NRC Enforcement Manual, Section 2.11.d.6 since there was no reasonable likelihood that the change would ever require NRC approval in accordance with 10 CFR 50.59. By considering this as an administrative/non-technical change, the licensee failed to demonstrate an appropriate technical basis for the change to the commitment as described in their updated safety analysis report. The licensee documented this deficiency in Condition Report 2013-10867. The team determined that Procedure SO-O-23 did not reference the license renewal commitments implemented by the procedure. The licensee initiated corrective actions and documented the deficiencies in Condition Report 2013-10661 The team determined that the licensee tracked this commitment as Action Request 29783 and that the licensee had not completed the actions at the time of this inspection. The licensee informed the team that a preliminary fatigue evaluation considering environmental fatigue determined that the charging line nozzle could exceed the design limit prior to the end of the period of extended operation. The licensee used Condition Report 2011-10000 to track completion of this commitment. The licensee had to finalize the fatigue evaluation to then determine the appropriate approach for fatigue management. The licensee expected to complete the fatigue analysis for the charging line nozzle before the period of extended operation. Follow-up and evaluation of the resolution for managing environmentally-assisted fatigue in the charging line nozzle as stated in Commitment 23 is an unresolved item. |
| 05000285/FIN-2013009-02 | 2013Q3 | Fort Calhoun | Evaluation of Operating Cycles for Fatigue Monitoring Program | Additionally, the team identified deficiencies in Program Basis Document PBD-31, Fatigue Monitoring, Revision 2, associated with the guidance provided to effectively implement the program as stated in the licensing basis documents. Specifically, the team found that PBD-31 did not: identify the procedures that would implement the program objectives and elements as described in the GALL Report, clearly identify the pressurizer surge line bounding locations that would be in the scope of the program, clearly identify the Class 2 and 3 components not included in the NUREG-1801 that were subject to fatigue, describe the transient cycles that would be tracked manually and with the WESTEMS counting software reference the vendor calculations and technical documents that supported the basis of the program and demonstrated compliance with the regulatory commitments, include specific guidance for appropriate corrective actions to take in case a cycle count approaches the design limit The team concluded that these deficiencies did not impact any fatigue evaluations or have any immediate impact on plant safety and that most of the deficiencies were administrative. The licensee documented the need to revise PBD-31 to correct these program deficiencies in Condition Report 2013-10658. Commitment 24 specified, Cycles which involve power changes, operating pressure and temperature variations, and feedwater additions with the plant in hot standby conditions will be conservatively estimated from a review of plant operating records to predict current cycles under the FMP. Once current number of cycles has been established, a review will be performed to determine if there is a potential for exceeding the allowable cycles and should be managed. If so, they\'ll be counted and managed by the FMP. The team determined that the licensee considered this commitment complete at the time of this inspection. The team determined that the licensee response to Request for Additional Information 4.3.1-1 provided the basis for this commitment. The team determined that the licensee specified they would perform a conservative estimate of cycles of specific types of cycles, as listed below, which were not being counted by existing plant procedures during the initial operating term: (a) plant loading/unloading at 10 percent of full power per minute (b) step load increase/decrease (c) operating variations of +100 pounds per square inch and +6 degrees Fahrenheit from normal operating pressure and temperature (d) feedwater additions of 300 gallons per minute at 32 degrees Fahrenheit with the plant in hotstandby condition The team identified that the licensee planned to track cycles related to Items (a) and (b) in WESTEMS during the period of extended operation; however, the licensee set the cycles to date at zero since they had not previously counted them in plant procedures. For the operating variations in Item (c), the licensee did not estimate the current number of cycles since they did not monitor them in plant procedures because of their frequent daily occurrence and low fatigue contribution. For the feedwater additions in Item (d), the licensee did not estimate the actual number of cycles accumulated in the current operating term. The team determined that the licensee did not conservatively estimate the number of cycles nor perform an evaluation of whether the potential for exceeding the allowable cycles in the period of extended operation existed, as described in their response to Request for Additional Information 4.3.1-1. The licensee documented the failure to count the cycles as specified in this commitment in Condition Report 2013-10756. Follow-up and evaluation of the resolution for estimating the number of cycles for Commitment 24 is an unresolved item. |
| 05000285/FIN-2013009-03 | 2013Q3 | Fort Calhoun | Flaw Tolerance Evaluation for Thermal Aging Embrittlement of CASS Components | The Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Program aging management program included evaluation of the reactor coolant piping as bounded by the leak-before-break analysis, assessment of other cast austenitic stainless steel components for susceptibility to thermal embrittlement, and performance of volumetric inspection of piping or component-specific flaw tolerance evaluation for susceptible components. The team reviewed program basis document, reviewed scoping evaluations, the license renewal application, the NRC safety evaluation report, and the updated safety analysis report supplement and interviewed the program owner. The team identified that the licensee documented this aging management program in Program Basis Document PBD-39, Thermal Aging Embrittlement of Cast Austenitic Stainless Steel, Revision 1 Commitment 34 specified, Develop the thermal aging embrittlement of cast austinetic stainless steel program that reflects the program elements of GALL AMP XI.M12, and other commitments in response to the NRC staff\'s review, as documented in the responses to staff requests for additional information and potential open items. The team determined that the licensee opted to manage thermal aging embrittlement of cast austinetic stainless steel components in the reactor coolant system through a flaw tolerance evaluation of the main reactor coolant system cast austinetic stainless steel piping. The licensee evaluated the maximum flaw size that could remain in service until the end of the period of extended operation considering thermal aging embrittlement and using the methodology recommended in the GALL Report (i.e. ASME, Section XI, Subsection IWB-3640). However, the team identified two deficiencies associated with the assumptions and conclusions in the flaw tolerance evaluation: The licensee inappropriately ruled out stress corrosion cracking effects in the flaw tolerance evaluation performed for the reactor coolant system cast austinetic stainless steel piping based on the effectiveness of the Water Chemistry Program aging management program (i.e., concluding that stress corrosion cracking was not a credible aging effect requiring management). The team determined that the license renewal application and safety evaluation report described that the licensee credited the thermal aging embrittlement of cast austinetic stainless steel aging management program for managing crack initiation and growth due to stress corrosion cracking and loss of fracture toughness due to thermal aging embrittlement. The conclusions about the resulting postulated flaw sizes did not provide any correlation between the postulated flaw sizes and the detection capability of the non-destructive in-service inspection examination technique currently used or expected to be used. The team determined that postulating flaws without confirming that a qualified non-destructive examination technique could detect the flaws provided insufficient technical justification to reasonably assure that the applicable aging effects would be managed. The team determined that the licensee documented this deficiency in Condition Report 2013-11991. Follow-up and evaluation of licensee corrective actions to address thermal aging embrittlement of cast austinetic stainless steel components in accordance with the GALL Report and the licensing basis is an unresolved item. |
| 05000285/FIN-2013009-04 | 2013Q3 | Fort Calhoun | Thermal Aging Embrittlement of CASS Nozzles in the Reactor Coolant System | The team identified that the licensee had not evaluated other cast austinetic stainless steel components (as listed below) in the reactor coolant system for susceptibility to thermal aging embrittlement in accordance with the GALL Report, Revision 0 and the license renewal application. Consequently, the licensee did not include these components in the scope of the flaw tolerance evaluation nor performed any volumetric examination to detect and size cracks. The licensee had replaced two of the nozzles when they replaced their pressurizer in 2006. The affected reactor coolant system nozzles included: RC-PIPE-2501Q-CHARGE-NOZZ, RC-PIPE-2501Q-DRAIN-NOZZ, RC-PIPE-25011-PM-NOZZ, RC-PIPE-2501Q-PMS-NOZZ, RC-PIPE-2501Q-SDC-INLET-NOZZ, RC-PIPE-2501Q-SDC-OUT-NOZZ. The team determined that the licensee documented this deficiency in Condition Report 2013-11991. Follow-up and evaluation of licensee corrective actions to address thermal aging embrittlement of the six cast austinetic stainless steel nozzles in the reactor coolant system as stated in Commitment 34 is an unresolved item. |
| 05000285/FIN-2013009-05 | 2013Q3 | Fort Calhoun | Submittal of Leak-Before-Break Analysis | Commitment 39 specified, OPPD will complete a plant-specific leak before break (LBB) analysis using the latest LBB criteria. OPPD will submit to the NRC a license amendment request containing the plant-specific LBB evaluation. At the time of this inspection, the licensee did not have a leak-before-break analysis for their existing power level. Report WCAP-17262-NP, Technical Basis for Eliminating Large Primary Loop Pipe Rupture as the Structural Design Basis for Fort Calhoun Unit 1, Revision 0, provided a leak-before-break evaluation at the extended power uprate conditions. During the owner acceptance review of the leak-before-break evaluation at the extended power uprate conditions, the licensee identified that some stress locations on the hot leg and cold leg reactor vessel nozzles at the extended power uprate were lower than those calculated for their current license basis locations. Consequently, the licensee initiated actions to perform the leak-before-break calculation to 60 years at the current operating conditions. The licensee initiated Condition Report 2013-10952 to track completion of the leak-before-break analysis for current power levels. Verification that the licensee submitted their leak-before-break analysis prior to entering the period of extended operation as stated on Commitment 39 is an unresolved item. |
| 05000285/FIN-2014405-01 | 2014Q2 | Fort Calhoun | Security | |
| 05000285/FIN-2014405-02 | 2014Q2 | Fort Calhoun | Security | |
| 05000285/FIN-2014405-03 | 2014Q2 | Fort Calhoun | Security | |
| 05000285/FIN-2014405-04 | 2014Q2 | Fort Calhoun | Licensee-Identified Violation | |
| 05000285/FIN-2014405-05 | 2014Q2 | Fort Calhoun | Licensee-Identified Violation | |
| 05000293/FIN-2016011-01 | 2017Q1 | Pilgrim | Failure to Identify All Root Causes of a Significant Condition Adverse to Quality | The NRC team identified a Green non-cited violation of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion XVI, Corrective Action, because Entergy did not adequately determine all root causes associated with a significant condition adverse to quality related to the failure to identify, evaluate, and correct the A SRVs failure to open upon manual actuation during a plant cooldown on February 9, 2013. Specifically, Entergy did not establish adequate measures to assure that the cause of a significant condition adverse to quality, inadequate shift manager operability determination rigor and its associated causes, were adequately determined and corrective action taken to preclude repetition. Entergys immediate corrective actions included planning to conduct operations management face-to-face conversations with shift manager qualified individuals to reinforce the shift managers responsibility for operability and functionality determination accuracy and rigor. Entergy entered this issue into the corrective action program as CRPNP-2017-00363 and CR-PNP-2017-00828. The performance deficiency was more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone and if left uncorrected, the performance deficiency would have the potential to lead to a more significant safety concern. Specifically, if left uncorrected, the performance deficiency could have the potential to result in repetition of a failure to identify, evaluate, and correct an SRVs failure to open or a similar significant condition adverse to quality. The NRC team evaluated the finding using Exhibit 2, Mitigating Systems Screening Questions, of IMC 0609, Appendix A, Significance Determination Process for Findings At-Power, and determined this finding did not affect the design or qualification of a mitigating structure, system, or component; represent a loss of system and/or function; involve an actual loss of function of at least a single train or two separate safety systems for greater than its technical specification-allowed outage time; or represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant. Therefore, the NRC team determined the finding was of very low safety significance (Green). The NRC team determined that the finding had a cross-cutting aspect in the area of Human Performance, Avoid Complacency, because individuals did not recognize and plan for the possibility of mistakes, latent issues, and inherent risk, even while expecting successful outcomes. Specifically, Entergy incorrectly assumed that CR-PNP-2013-00825 contained inadequate information to determine that the A SRV had not opened, and this assumption ultimately impacted the root cause results documented in CR-PNP-2016-01621 (H.12). |
| 05000293/FIN-2016011-02 | 2017Q1 | Pilgrim | Failure to Establish Corrective Actions to Preclude Repetition of a Significant Condition Adverse to Quality | The NRC team identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, because Entergy did not implement CAPRs for a significant condition adverse to quality identified in root cause evaluation CR-PNP-2016-00716, Implementation of the Corrective Action Program, Revision 2. Specifically, the team identified that CAPRs for Entergys continued weaknesses in the implementation of the corrective action program were inadequate. Entergy entered this issue into their corrective action program for further evaluation as CR-PNP-2017-00053, CR-PNP-2017-00410, and CR-PNP-2017-01134. The performance deficiency was more than minor because if left uncorrected, it had the potential to lead to a more significant safety concern. Specifically, the failure to preclude repetition of this significant condition adverse to quality could result in continuing weaknesses in implementation of the corrective action program, which was designated as a fundamental problem, and thus a contributing factor for PNPS Column 4 performance. Additionally, weaknesses with corrective action program implementation could result in equipment issues where operability is not maintained. The NRC team evaluated the finding using Exhibit 2, Mitigating Systems Screening Questions, of IMC 0609, Appendix A, Significance Determination Process for Findings At-Power, and determined this finding did not affect the design or qualification of a mitigating structure, system, or component; represent a loss of system and/or function; involve an actual loss of function of at least a single train or two separate safety systems for greater than its technical specificationallowed outage time; or represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant. Therefore, the NRC team determined the finding was of very low safety significance (Green). The NRC team determined that the finding had a cross-cutting aspect in the area of Human Performance, Procedure Adherence, because individuals did not follow processes, procedures, and work instructions. Specifically, Entergy did not follow procedure EN-LI-102, which provides the station standards for crafting a corrective action and states, in part, that the corrective action descriptions must be worded to ensure that the adverse condition or cause/factor is addressed (H.8). |
| 05000293/FIN-2016011-03 | 2017Q1 | Pilgrim | Failure to Issue Appropriate Corrective Actions to Preclude Repetition for the Causes of the September 2016 Scram | The NRC team identified a Green finding because Entergy did not issue appropriate CAPRs in accordance with Entergy procedure EN-LI-102, Corrective Action Process, Revision 28. Specifically, Entergy did not issue adequate CAPRs associated with Root Cause 1 of the feedwater regulating valve failure in September 2016 that resulted in a manual scram. As a result of the NRC teams questions, Entergy issued procedure 1.13.2, Vendor and Technical Information Reviews, Revision 0, as continuous use to ensure that planners will always have the checklist in-hand when planning work to ensure that appropriate vendor technical information is always included in applicable work instructions. Entergy entered the NRC teams concerns in the corrective action program as CR-PNP-2017-00687 and CR-PNP-2017-00936. The performance deficiency was more than minor because it is associated with the equipment performance attribute of the Initiating Events cornerstone and if left uncorrected, the performance deficiency would have the potential to lead to a more significant safety concern. Specifically, if left uncorrected, the performance deficiency could have the potential to result in repetition of a significant condition adverse to quality, loss of control of feedwater regulating valve 642A and a manual scram. The NRC team evaluated the finding using Exhibit 1, Initiating Events Screening Questions, of IMC 0609, Appendix A, Significance Determination Process for Findings At-Power, and determined this finding did not cause a reactor trip or the loss of mitigation equipment relied upon to transition the plant from the onset of a trip to a stable shutdown condition. Therefore, the NRC team determined the finding was of very low safety significance (Green). The NRC team determined that the finding had a cross-cutting aspect in the area of Human Performance, Procedure Adherence, because individuals did not follow processes, procedures, and work instructions. Specifically, Entergy did not follow procedure EN-LI-102, which provides the station standards for crafting a corrective action and states, in part, that the corrective action descriptions must be worded to ensure that the adverse condition or cause/factor is addressed (H.8). |
| 05000293/FIN-2016011-04 | 2017Q1 | Pilgrim | Programmatic Issue with Implementation of the Operability Determination Process | The NRC team identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings. Specifically, the NRC team identified a programmatic issue because in some cases, Entergy did not enter the operability determination process when appropriate, and, when the process was entered, did not adequately document the basis for operability, in accordance with Procedure ENOP-104, Operability Determination Process, Revision 11. In each of the examples discussed, though the basis for operability was not adequate, all components were determined to be operable upon further evaluation. Entergy entered this issue into their corrective action program as CR-PNP-2017-00626. The performance deficiency was more than minor because if left uncorrected, could lead to a more significant safety issue. Specifically, the failure to enter and document a basis for operability could lead to not recognizing inoperable safety-related equipment, and place the reactor at a higher risk of core damage in a design basis accident. The NRC team evaluated the finding using Exhibit 2, Mitigating Systems Screening Questions, of IMC 0609, Appendix A, Significance Determination Process for Findings At-Power, and determined this finding did not affect the design or qualification of a mitigating structure, system, or component; represent a loss of system and/or function; involve an actual loss of function of at least a single train or two separate safety systems for greater than its technical specification-allowed outage time; or represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant. Therefore, the NRC team determined the finding was of very low safety significance (Green). This finding had a cross-cutting aspect in the area of Human Performance, Teamwork. Specifically, the operations and engineering departments did not demonstrate a strong sense of collaboration and cooperation with respect to holding each other accountable when performing operability determinations to ensure nuclear safety is maintained (H.4). |
| 05000293/FIN-2016011-05 | 2017Q1 | Pilgrim | Failure to Establish Corrective Actions to Address Scope of Procedure Quality Issues | The NRC team identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, because Entergy implemented inadequate corrective actions to address the procedure quality issues identified in CR-PNP-2016-02058. Specifically, Entergy inappropriately limited their corrective actions to those procedures that increased integrated risk above normal, and did not include other types of safety-related procedures that did not meet their procedure quality standards and resulted in procedure quality being a problem area. Entergy entered this issue into their corrective action program for further evaluation as CR-PNP-2017-00400. The performance deficiency was more than minor because it affected the procedure quality attribute of the Mitigating Systems cornerstone, and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Entergy limited corrective actions to procedures that increased integrated risk above normal or trip sensitive and failed to include other procedures associated with safety-related components that reflected the broader population reviewed during the collective evaluation. The NRC team evaluated the finding using Exhibit 2, Mitigating Systems Screening Questions, of IMC 0609, Appendix A, Significance Determination Process for Findings At-Power, and determined this finding did not affect the design or qualification of a mitigating structure, system, or component; represent a loss of system and/or function; involve an actual loss of function of at least a single train or two separate safety systems for greater than its technical specificationallowed outage time; or represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant. Therefore, the NRC team determined the finding was of very low safety significance (Green). The NRC team determined that this finding had a cross-cutting aspect related to Human Performance, Resources, because the leaders failed to ensure that personnel, equipment, procedures, and other resources are available and adequate to support nuclear safety. Specifically, based on available resources, Entergy chose to limit the scope of safety-related procedures being revised to only those that resulted in high integrated risk or were trip sensitive (H.1). |
| 05000293/FIN-2016011-06 | 2017Q1 | Pilgrim | Design Change Not Appropriately Reviewed by Entergy | The NRC team identified a preliminary greater than Green finding and apparent violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, associated with Entergys failure to ensure that design changes were subject to design control measures commensurate with those applied to the original design and were approved by the designated responsible organization. Specifically, Entergy received a new style right angle drive for the A emergency diesel generator radiator blower fan from a vendor but failed to adequately review the differences in the design of the drives to identify potential new failure mechanisms for the part or the need for related preventive measures. Entergy entered this issue into the corrective action program as CR-PNP-2016-07443. The performance deficiency was more than minor because it was associated with the design control attribute of the Mitigating Systems cornerstone, and affected the associated cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 2 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, the team screened the finding for safety significance and determined that a detailed risk evaluation was required based on the A emergency diesel generator being inoperable for greater than the technical specification allowed outage time. Region I senior reactor analysts performed a detailed risk evaluation. The finding was preliminarily determined to be of greater than very low safety significance (greater than Green). The risk important sequences were dominated by external fire risk. Specifically, a postulated fire in the B 4 kilovolt (KV) switchgear room with a consequential loss of the unit auxiliary generator power supply, non-recoverable loss of off-site power (LOOP) to both safety buses A5 and A6, loss of the B emergency diesel generator with the conditional failure of the A emergency diesel generator, along with the loss of bus A8 feed (from the shutdown transformer or station blackout (SBO) diesel generator) to safety buses A5 and A6. The internal event risk was dominated by weather related LOOPs, failure of the A emergency diesel generator, with failure of the B emergency diesel generator and SBO diesel generator to run, along with failure to recover offsite power or the emergency diesel generators. See Attachment 1, A Emergency Diesel Generator Cooling Water System Degradation Detailed Risk Evaluation, for a detailed review of the quantitative criteria considered in the preliminary risk determination. The NRC team did not assign a cross-cutting aspect to this finding because the performance deficiency occurred in May 2000. Entergys program has undergone changes since May 2000, and the NRC team did not identify any recent examples of this performance deficiency. Other aspects of Entergys performance related to this issue are further discussed in Sections 5.10.3 and 6.3.4. |
| 05000293/FIN-2016011-07 | 2017Q1 | Pilgrim | Failure to Report Condition Prohibited by Technical Specifications and a Safety System Functional Failure | The NRC team identified a Severity Level IV non-cited violation of 10 CFR 50.73, Licensee Event Report System, associated with Entergys failure to submit a licensee event report within 60 days following discovery of an event meeting the reportability criteria. Specifically, on September 28, 2016, Entergy identified the A emergency diesel generator was inoperable. The NRC team determined that the condition was prohibited by technical specifications and the inoperability of the A emergency diesel generator existed for a period of time longer than allowed by Technical Specification 3.5.F, Core and Containment Cooling Systems. This was also reportable as a safety system functional failure. Entergy entered this issue into the corrective action program as CR-PNP-2016-09552. Because this performance deficiency had the potential to impact the NRCs ability to perform its regulatory function, the NRC team evaluated the performance deficiency using traditional enforcement. The violation was evaluated using Section 2.3.11 of the NRC Enforcement Policy, because the failure to submit a required licensee event report may impact the ability of the NRC to perform its regulatory oversight function. In accordance with Section 6.9.d, Example 9, of the NRC Enforcement Policy, this violation was determined to be a Severity Level IV non-cited violation. Because this violation involves the traditional enforcement process and does not have an underlying technical violation, the NRC team did not assign a cross-cutting aspect to this violation, in accordance with IMC 0612, Appendix B. |
| 05000293/FIN-2016011-08 | 2017Q1 | Pilgrim | Failure to Adequately Monitor the Performance of Maintenance Rule Scoped Components | The NRC team identified a Green non-cited violation of 10 CFR 50.65(a)(2), Requirements for monitoring the effectiveness of maintenance at nuclear power plants. Specifically, Entergy did not demonstrate that the performance of 18 maintenance rule scoped components was effectively controlled through the performance of appropriate preventive maintenance, and did not establish goals and monitoring in accordance with 10 CFR 50.65(a)(1). Entergys immediate corrective action was to initiate a CR to evaluate moving the affected systems to 10 CFR 50.65(a)(1) monitoring requirements. Entergy entered this issue in the corrective action program as CR-PNP-2017-00401. The performance deficiency was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and affected the cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, Entergy failed to demonstrate that the performance of the 18 maintenance rule scoped components was being effectively controlled through the performance of appropriate preventive maintenance which adversely impacts the reliability of those systems. The NRC team evaluated the finding using Exhibit 2, Mitigating Systems Screening Questions, of IMC 0609, Appendix A, Significance Determination Process for Findings At-Power, and determined this finding did not affect the design or qualification of a mitigating structure, system, or component; represent a loss of system and/or function; involve an actual loss of function of at least a single train or two separate safety systems for greater than its technical specificationallowed outage time; or represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant. Therefore, the NRC team determined the finding was of very low safety significance (Green). The finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Evaluation, in that Entergy failed to thoroughly evaluate and ensure that resolution of the identified issue, maintenance not being performed on maintenance rule scoped components, included reclassifying the components as necessary. Specifically, Entergy failed to demonstrate that the performance of Maintenance rule scoped components was effectively controlled through the performance of appropriate preventive maintenance, or through performance goals and monitoring. (P.2). |
| 05000293/FIN-2016011-09 | 2017Q1 | Pilgrim | Ineffective Corrective Actions to Address Conditions Adverse to Quality Regarding Components in Contact with or Close Proximity to the Drywell Liner | The NRC team identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, associated with Entergys failure to correct a condition adverse to quality affecting safety-related equipment. Specifically, during a previous NRC inspection in August 2016, inspectors identified numerous locations in the drywell where non-seismic equipment was either in contact, or close proximity, with the drywell liner and had caused damage. Entergy initiated CRs and performed an operability evaluation for the identified issues. However, following a review of these CRs, the NRC team determined that Entergy failed to take corrective actions to address the condition adverse to quality. Entergy entered this issue into the corrective action program as CR-PNP-2016-09346 and CR-PNP-2016-09377 to perform an extent of condition review, secure the loose grating that had caused damage to the liner, and evaluate the need for a clearance criteria between components such as floor grating and support structures and the containment liner. The performance deficiency was more than minor because it was associated with the configuration control attribute of the Barrier Integrity cornerstone and affected the cornerstone objective to provide reasonable assurance that physical design barriers (fuel cladding, reactor coolant system, and containment) protect the public from radionuclide releases caused by accidents or events. Using IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, Exhibit 3, Barrier Integrity Screening Questions, the NRC team determined that this finding was of very low safety significance (Green) because the finding did not represent an actual open pathway in the physical integrity of reactor containment (valves, airlocks, etc.), containment isolation system (logic and instrumentation), and heat removal components. This finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Evaluation, because the engineering evaluation of the degraded condition identified by the inspectors did not thoroughly evaluate the containment liner issues to ensure that resolutions address causes and extents of condition commensurate with their safety significance (P.2). |
| 05000293/FIN-2016011-10 | 2017Q1 | Pilgrim | Failure to Promptly Correct a Condition Adverse to Quality for the Residual Heat Removal System | The NRC team identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, because Entergy did not take timely corrective action for a previously identified condition adverse to quality. Specifically, Entergy failed to adequately resolve, through repair or adequate evaluation, gasket leakage on the B residual heat removal heat exchanger, which resulted in continued degradation and leakage for the heat exchanger gasket. Entergy did not consider this leakage as a degraded condition, with the potential to impact both the operability of the residual heat removal system, and PNPSs licensing basis with regards to leakage of a closed loop system outside of containment. After the NRC team raised the issue, Entergy performed an operability determination that established a reasonable expectation of operability pending implementation of corrective actions. Entergy entered this issue into their corrective action program as CR-PNP-2016-09725. The performance deficiency was more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to correct identified gasket leakage resulted in continued degradation and leakage of the heat exchanger gasket. The NRC team evaluated the finding using Exhibit 2, Mitigating Systems Screening Questions, of IMC 0609, Appendix A, Significance Determination Process for Findings At-Power, and determined this finding did not affect the design or qualification of a mitigating structure, system, or component; represent a loss of system and/or function; involve an actual loss of function of at least a single train or two separate safety systems for greater than its technical specification-allowed outage time; or represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant. Therefore, the NRC team determined the finding was of very low safety significance (Green). The finding had a cross-cutting aspect in Human Performance, Conservative Bias, because Entergy failed to use decision making practices that emphasize prudent choices over those that are simply allowable (H.14). |
| 05000293/FIN-2016011-11 | 2017Q1 | Pilgrim | Failure to Adequately Develop and Implement Targeted Performance Improvement Plans | The NRC team identified a Green finding because Entergy did not adequately develop and implement a CAPR of a root cause related to a Category A CR, as required by Entergy Procedure EN-LI-102, Corrective Action Program. Specifically, Entergy did not adequately develop and implement the Targeted Performance Improvement Plans, which were designated as a CAPR for the root cause for the Nuclear Safety Culture Fundamental Problem. Entergy documented this issue in the corrective action program for further evaluation as CR-PNP-2017-00406. The performance deficiency was more than minor because if left uncorrected, it could lead to a more significant safety concern. Specifically, inadequate implementation of the Targeted Performance Improvement Plans could result in recurrence of a culture in which leaders are not holding themselves and their subordinates accountable to high standards of performance, resulting in continuing performance issues at the station. The NRC team evaluated the finding using Exhibit 2, Mitigating Systems Screening Questions, of IMC 0609, Appendix A, Significance Determination Process for Findings At-Power, and determined this finding did not affect the design or qualification of a mitigating structure, system, or component; represent a loss of system and/or function; involve an actual loss of function of at least a single train or two separate safety systems for greater than its technical specification-allowed outage time; or represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant. Therefore, the NRC team determined the finding was of very low safety significance (Green). This finding had a cross-cutting aspect in the area of Human Resources, Change Management, because leaders did not use a systematic process for evaluating and implementing change so that nuclear safety remains the overriding priority. In this case, PNPS leaders did not apply sufficient rigor in development and implementation of the Targeted Performance Improvement Plans such that they would be an adequate method to drive and sustain positive changes in the stations safety culture (H.3). |
| 05000293/FIN-2016011-12 | 2017Q1 | Pilgrim | Licensee-Identified Violation | 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, and shall be accomplished in accordance with those structures, procedures, and drawings. Entergy procedure EN-DC-148, Vendor Manuals and Vendor Re-Contact Process, Revision 6, requires, in part, that the station update vendor manuals every three years. Contrary to this, in July 2016, PNPS determined through a self-assessment that they had 13 vendor manuals that had not been evaluated for changes within 3 years. The NRC team determined that this finding did not affect the design or qualification of a mitigating structure, system or component; did not represent a loss of a system and/or function; did not result in loss of a train or two safety systems greater than any technical specification allowed outage time; did not result from an actual loss of safety function; and did not involve loss of any external event mitigating system. Consequently, the NRC team determined that this performance deficiency screened as having very low safety significance (Green). PNPS documented this issue in their corrective action program as CR-PNP-2016-05115. |
| 05000293/FIN-2016011-13 | 2017Q1 | Pilgrim | Licensee-Identified Violation | 10 CFR 50.54(q)(2) requires, in part, that the licensee follow and maintain the effectiveness of an emergency plan to meet the planning standard of 10 CFR 50.47(b)(4). Specifically, the licensee was to maintain the necessary equipment to support the effectiveness of EALs. Contrary to these requirements, PNPS identified in CR-PNP-2016-01491 that on three past occasions (March 15 through August 8, 2012; September 4 through October 14, 2012; and June 4 through June 14, 2015) both trains of the H2O2 monitors and the Post-Accident Sampling System were unavailable to ensure the effectiveness of EAL 24, Deflagration concentrations exist inside PC, for the potential loss of the containment barrier within the Fission Product Barrier category of the EALs. This issue meets the criteria for very low safety significance (Green) because, due to other EALs, an appropriate emergency declaration could have been made in an accurate and timely manner. |
| 05000298/FIN-2001010-06 | 2001Q3 | Cooper | CROSS-CUTTING Issues: Identification and Resolution of Problems | No Color. Numerous examples of inadequate corrective actions and improper implementation of the corrective action program demonstrated continued inadequate problem identification and resolution. This was primarily due to a general lack of understanding and ownership of site-wide programs and procedures associated with the identification and resolution of problems. Each of the program areas discussed below include violations of NRC requirements that were determined to be more than minor but of very low safety significance (Green) using the significance determination process. The licensee documented this issue in their corrective action process as Notification 10112315, which is being addressed in Significant Condition Report 2001-0938, "Continued Difficulty in Implementing the Corrective Action Program." For example: The team identified that during the implementation of the corrective action program issues were improperly characterized and classified resulting in those issues being inappropriately removed from the corrective action program. This resulted in ineffective and untimely corrective actions since the items were either closed or awaiting resolution. This issue is described in this report and involves both the mitigating systems and barrier integrity cornerstones of reactor safety. Numerous concerns with scaffolds constructed near operable safety-related equipment were identified. The licensee had not constructed scaffolding in accordance with plant procedures and the required scaffolding engineering evaluations for nonconforming items had not been performed. Previous similar findings associated with improper scaffolding had been identified in NRC Inspection Report 50-298/00-04. Despite corrective actions involving new procedures and training, similar problems continued. The licensee had not effectively corrected problems with personnel recognizing when and how to perform adequate operability determinations and evaluations. A noncited violation was identified, which involved examples from both the mitigating system and barrier integrity cornerstones. This cross-cutting issue was documented in the previous NRC problem identification and resolution inspection and other similar findings associated with this cross-cutting issue are noted in NRC Inspection Reports 50-298/00-10, 50-298/00-13, 50-298/00-14, and 50-298/01-02. |
| 05000298/FIN-2009010-01 | 2009Q4 | Cooper | Adequacy of aging management for the torus | The team reviewed the results of the Section XI, Subsection IWE inspections to assess the effects of aging. The applicant began performing the Section XI, Subsection IWE-required 100 percent wetted area torus inspection in 2001. Because the torus had a continuously wetted surface with evidence of pitting, the applicant categorized their torus as Category E-C. The team evaluated the torus inspection results from 2001, 2005 and 2008. The torus acts as the containment liner and contains the suppression pool water and components. It is made of carbon steel, with thicknesses of the torus wall ranging from 0.616 inches in the general shell to 1.1875 inches at the ring girder joints and at the penetrations. Because carbon steel is susceptible to corrosion, it is coated with a zincbased paint. The zinc acts as a sacrificial anode, which is consumed over time. The torus has historically collected sludge and corrosion products, resulting in murky water and solid deposits that appear to exceed what is typical for boiling water reactors of that vintage. The applicant does not have a cleanup system to help maintain the water chemistry in the suppression pool. The coating applied to the inside of the torus is the original un-top-coated zinc-based paint, which has worn and been locally damaged. In areas where the coating is degraded or missing, the containment liner has experienced corrosion. Below the waterline in the suppression pool, there is significant pitting corrosion. The torus coating repairs performed following the installation of the tee quenchers had begun to degrade. The team reviewed inspection results that indicated 2091 pits have been identified in the wetted surface of the suppression pool containment liner. This is an active problem, as hundreds of new pits were identified at each inspection. The team reviewed inspection videos from the last torus inspection and noted areas with exposed metal and significant general corrosion, including catwalk bracing, tee quencher piping and supports, ring girders, downcomer bracing, and near penetration regions on the shell. Corrosion on structures and supports undergoing generalized corrosion contributed to the increasing volume of sludge being removed, indicating the problem is getting worse with time. The applicant has documented in a 2001 inspection that the torus coating system was in fair to poor condition. The team noted that the applicant has not scheduled any actions to correct this condition. The applicants evaluations show that the pitting corrosion does not have a significant affect on the torus structurally. The applicant performed a stress evaluation in accordance with the American Society of Mechanical Engineers, Section III, Subsection NE. From this evaluation, the applicant identified a minimum wall thickness of 0.153 inches. The team reviewed design calculations that established acceptance criteria for identified pits and provided coating repair criteria. All pits evaluated by the applicant remained well within the structural integrity acceptance criteria. The applicant coated all pits that measured greater than 0,030 inches near penetrations and 0.050 inches near ring girders. Although no pitting on the general shell required repair, the torus general shell had dense pitting at localized areas without coating that ranged from one to two mils deep with occasional depths of 40 to 50 mils. The applicant was taking the following actions to manage the corrosion: Visually inspect 100 percent of the wetted surface of the torus once each period as specified in their 10-year inservice inspection plan to identify pitting locations and measure pit depth. Pits that exceed a threshold (values vary by location) were covered with an epoxy coating that cures underwater to arrest corrosion. Pits that do not exceed the threshold were monitored for growth at the next inspection. All pits that were identified were recorded on a pit map. The applicant has considered coating repairs or replacement, but has not scheduled any action Based on the above, the team needed additional information to determine whether the applicant would effectively manage the effects of aging in the wetwell. The inspectors had the following observations and concerns: The expected life of the original coating was not documented in the final safety analysis report or other documents reviewed by the inspectors. A review of general information on this type of coating seems to indicate that the coating used at Cooper Nuclear Station should not be expected to have a 40-year service life. In addition, the inspection reports provided to the applicant discuss that un-top-coated zinc coatings have on average an expected life of 15 years. Based on the current degree of coating failure, it does not appear that the existing coating is suitable for another 20 years or service. Depletion of the zinc has reduced the ability to provide corrosion protection to the exposed steel substrate and localized coating failures have exposed areas of bare steel. If the zinc remained available in sufficient quantities, localized bare metal surrounded by intact coating should not be exhibiting active corrosion as it has been. The applicant has not been managing the coating failures by making coating repairs to areas that have had localized coating failures, whether above or below the waterline. This has apparently resulted in localized galvanic corrosion with high corrosion rates (pitting), instead of very low and predictable general corrosion rates. It has also contributed to the amount of sludge and corrosion products collecting in the suppression pool. Instead, the applicant has been allowing corrosion and applying an epoxy coating intended to arrest the pitting. The applicant was attempting to manage the pitting corrosion in the context of structural integrity without correcting the causes. The available data indicate that the condition worsened over time, so this method of aging management is not being successful. Pitting corrosion rates are typically much higher and less predictable than general corrosion rates, and a through-wall pit would impact containment integrity without necessarily impacting structural integrity. The inspectors concluded that while the applicant met their obligations under the ASME Code, so this is not a current safety concern. However, the ASME Code does not address consideration of plant life extension or determination of when a coating should be replaced. Because additional information is needed to determine whether the applicant had established a program to manage the effects of aging for the wetwell during the period of extended operation, this issue will be tracked as an unresolved item: URI 05000298/2009010-01, Adequacy of aging management for the torus. |
| 05000298/FIN-2010005-05 | 2010Q4 | Cooper | Diesel Generator Overspeed Governor Loose Bolting Issue | The inspectors identified an unresolved item associated with the loose bolting issue on the over speed governor of diesel generator two. Specifically, the issue concerns past operability of the diesel, adequacy of previous evaluations and corrective actions taken by the licensee, and procedure quality and use. On September 8, 2009, while performing a monthly surveillance run of diesel generator two, the overspeed governor trip mechanism was observed to be vibrating significantly. The licensee secured the diesel generator, and during subsequent inspection found that all eight nuts that that were used to retain the governor were loose (less than finger tight). The licensee determined that this event had been caused by gasket creep and thermal cycle effects, and had this been occurring over a very long period of time, approximately 30 years. The licensee took corrective actions based on these identified causes. Subsequently, on August 17, 2010, while performing bolt tightness checks the licensee discovered six of eight nuts that were used to retain the diesel generator two overspeed governor drive unit were loose (less than finger tight), and one bolt was at a reduced torque (48 ft-lbs). The licensee determined that the cause of this event was improper torque being applied to the nuts when they had been reassembled following the September 2009 issue along with thermal cycle effects. During review of the root cause report for the loose bolting issue found on diesel generator two in August 2010, the inspectors noted that this condition appeared to be a repeat occurrence of what had been found in September 2009, and as such, questioned the licensees determined cause for the 2010 issue. The inspectors also questioned key assumptions used by the licensee when evaluating this issue. Furthermore, the inspectors noted that the past operability evaluation that the licensee performed failed to consider all pertinent conditions that could have affected the equipments ability to perform its design basis function, specifically elevated vibrations associated with the asfound condition. As such, the inspectors determined that more inspection was necessary to resolve this issue. Accordingly, this issue is being considered an unresolved item pending further review. An unresolved item is an issue requiring further information to determine if it is acceptable, if it is a finding, or if it constitutes a violation of NRC requirements. As such, no analysis of this issue has occurred. Additional information was needed to determine whether a violation of regulatory requirements occurred. Pending further review of additional information provided by the licensee, this issue is being treated as an Unresolved Item 05000298/2010005-05, Diesel Generator Overspeed Governor Loose Bolting Issue. |
| 05000298/FIN-2011003-02 | 2011Q2 | Cooper | Failure to Follow Procedure Results in Inadequate Operability Determinations | The inspectors identified multiple examples of a noncited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, regarding the licensees failure to follow the requirements of EN-OP-104, Operability Determinations. Specifically, the inspectors identified examples in which operations failed to properly document the basis for operability when a degraded or nonconforming condition had been identified. The licensee entered these issues into their corrective action program with individual condition reports for each issue. Corrective actions resulted in revised operability reviews and corrective actions to processes and training to prevent similar operability determination problems. The performance deficiency is more than minor because the condition of performing inadequate operability determinations could become more significant if left uncorrected. Unrecognized degradation of essential equipment impacts 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 (i.e., core damage). Using Manual Chapter 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, the finding was determined to have very low safety significance because the finding: (1) was not a design or qualification issue confirmed not to result in a loss of operability or functionality; (2) did not represent an actual loss of safety function of the system or train; (3) did not result in the loss of one or more trains of nontechnical specification equipment; and (4) did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. This finding was determined to have a cross-cutting aspect in the area of problem identification and resolution associated with the corrective action component, in that, the licensee failed to thoroughly evaluate problems such that the resolutions addressed causes and extent of conditions. Specifically, licensee personnel failed to thoroughly evaluate conditions adverse to quality and perform meaningful operability determinations (P.1(c))(Section 1R15). |
| 05000298/FIN-2011003-03 | 2011Q2 | Cooper | Failure to Follow Procedure Results in Personnel Contaminations | The inspectors reviewed a self-revealing, noncited violation of Technical Specification 5.4.1, resulting from workers who entered a posted contamination area without required protective clothing and were contaminated as a result. The condition was detected when contamination monitors alarmed during the workers attempt to process out of the radiologically controlled area. The workers were then decontaminated prior to exiting. The licensee entered the issue into the corrective action program as Condition Report CR-CNS-2011-03311. The corrective actions included communication of the issue throughout the department. The failure to follow radiation work permit requirements is a performance deficiency. The finding was more than minor because it was associated with the Occupational Radiation Safety Cornerstone attribute (exposure control) of program and process and affected the cornerstone objective, in that, working in an area outside the scope of the radiation work permit and not following protective clothing requirements resulted in personnel contaminations. Using the Occupational Radiation Safety Significance Determination Process, the inspectors determined the finding to have very low safety significance because: (1) it was not associated with ALARA planning or work controls, (2) there was no overexposure, (3) there was no substantial potential for an overexposure, and (4) the ability to assess dose was not compromised. The finding was determined to have a cross-cutting aspect in the area of human performance, associated with the work control component, in that, the licensee failed to appropriately coordinate work activities by incorporating actions to address plant conditions that may affect work activities. Specifically, the radiation protection technician failed to verify current conditions prior to briefing workers on expected plant conditions that may affect work activities (H.3(b))(Section 1R20.1). |
| 05000298/FIN-2011003-04 | 2011Q2 | Cooper | Communication of an NRC Inspectors Presence by Station Personnel | The inspectors identified a Severity Level IV noncited violation of 10 CFR 50.70, Inspections, associated with the licensees failure to ensure that the arrival and presence of NRC inspectors was not communicated to persons at the facility. Specifically, a radiation protection technician manning the access point to the drywell informed other individuals entering the drywell to perform work of inspectors presence and location during an unannounced walkdown of the drywell to observe licensee work activities. This issue was entered into the licensees corrective action program as Condition Report CR-CNS-2011-4124. Licensee personnels action of announcing the presence and location of NRC inspectors during an unannounced walkdown inspection was a performance deficiency. The inspectors reviewed this issue in accordance with NRC Inspection Manual Chapter 0612 and the NRC Enforcement Manual. Through this review, the inspectors determined that traditional enforcement was applicable to this issue because the NRC\'s regulatory ability was affected. Specifically, the NRC relies on its ability to perform unannounced inspections to evaluate licensee performance, and communicating the presence and location of NRC inspectors affects their ability to perform these inspections, and as such the regulatory function is impacted. The inspectors determined that this finding was not suitable for evaluation using the significance determination process, and as such, was evaluated in accordance with the NRC Enforcement Policy. The finding was reviewed by NRC management and because the violation was determined to be of very low safety significance, was not repetitive or willful, and was entered into the corrective action program, this violation is being treated as a Severity Level IV noncited violation consistent with the NRC Enforcement Policy. The inspectors determined that there was no cross-cutting aspect associated with this finding because this issue was not indicative of current performance because the violation did not affect any of the safety culture components (Section 1R20.3). |
| 05000298/FIN-2011003-05 | 2011Q2 | Cooper | Failure to Follow Radiation Work Permit Requirements | The inspectors reviewed a self-revealing, noncited violation of Technical Specification 5.4.1, resulting from workers who failed to follow radiation work permit requirements and entered a high radiation area, after climbing from one scaffold to another. As corrective action, the licensee posted the area, searched for similar situations in the plant, and entered the issue into the corrective action program as Condition Reports CR-CNS-2011-0318 and -03217. The failure to follow radiation work permit requirements is a performance deficiency. The finding was more than minor because it was associated with the Occupational Radiation Safety Cornerstone attribute (exposure control) of program and process and affected the cornerstone objective, in that, working in an area outside the scope of the radiation work permit and not knowing the dose rates in the high radiation area had the potential to increase personnel dose. Using the Occupational Radiation Safety Significance Determination Process, the inspectors determined the finding to have very low safety significance because: (1) it was not associated with ALARA planning or work controls; (2) there was no overexposure; (3) there was no substantial potential for an overexposure; and (4) the ability to assess dose was not compromised. The finding has a human performance cross-cutting aspect associated with work practices component because the individuals did not use peer or self-checking before climbing to the second scaffold (H.4(a))(Section 2RS01). |