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| Quarter | Site | Title | Description | |
|---|---|---|---|---|
| 05000390/FIN-2010007-02 | 2010Q4 | Watts Bar | INSTALLED INSULATING FLUID IN INTERIOR TRANSFORMERS POTENTIALLY DEVIATES FROM LICENSE/DESIGN CRITERION IN SSER 10 AND POSITION D.1.g OF APPENDIX A TO BTP (APCSB) 9.5-1 | The inspectors opened an URI related to questions regarding the licensees compliance with all provisions of their NRC-approved FPP. Specifically, the inspectors raised questions regarding the dielectric insulating liquid used for indoor power transformers as specified Appendix FF, Section 5.10.2 of SSER 18 and NRC Position D.1.g of Appendix A to BTP APCSB 9.5-l, Guidelines for Fire Protection for Nuclear Power Plants, dated August 23, 1976. Fire Area FA 37 (AV-064) contained four liquid-insulated 6.9kV to 480V shutdown board transformers, in groups of two inside containment curbs. These medium voltage transformers were insulated with a silicone-type dielectric insulating fluid. Three of the four transformers (1-OXF-212-A2-A, 1-OXF-212-A1-A, and 1-OXF- 212-A-A) contained an estimated 317 gallons of insulating fluid and the other transformer (0-OXF-206-A) contained approximately 205 gallons. Near these transformers were combinations of redundant safety-related cable trays or conduits or both. While performing the review of FA 37 (AV-064), the inspectors identified the indoor power transformers dielectric insulating liquid was not consistent with that described in SSER 18, section 5.10.2, Askarel-Insulated Transformers and NRC Position D.1.g of Appendix A to (BTP) APCSB 9.5-l, Guidelines for Fire Protection for Nuclear Power Plants. Section 5.10.2 of SSER 18 specified that indoor transformers would be either a dry type or insulated with non-combustible liquid. Section 5.10.2 of SSER 18 further stated that Askarel was used as the noncombustible liquid for indoor transformers. The inspectors determined that the SSER reference was based on transformer insulating liquid being noncombustible material (negligible combustible loading) which did not represent an ignition source. However, during the inspection the inspectors found that the transformers in FA 37 did not contain the specified dry type or non-combustible dielectric insulating material, but were insulated with a silicon-based combustible dielectric liquid. Furthermore, Position D.1.g. (ii) of Appendix A to (BTP) APCSB 9.5-l specified that safety related systems that are exposed to flammable oil-filled transformers should be protected from the effects of a fire by enclosing the transformer with a three-hour fire barrier and installing an automatic water spray protection. The transformers had not been enclosed with such a barrier. The inspectors reviewed Part VI of the WBN FPR (Revision 39) and found that the fire rating of the regulatory barriers for the floor and walls in FA 37 was two-hours. The inspectors also reviewed WBN FPR, Part 1, Table 1-1, Summary of Fire Protection Conformance, (Revision 27) which specified that safe shutdown equipment cables were located in FA 37 and were protected with a credited one-hour rated fire resistive wrap. Table 1-1 of the FPR also identified that the area total fixed combustible load fire severity for a 3-hour rated barrier was classified as Moderately Severe, e.g., less-than 240,000 Btu/ft2. The inspectors reviewed the combustible loading summary calculationEPM-DOM-012990, (Revision 41) for FA 37 and found that the fuel load in the area was 164,549 Btu/ft2, which exceeded the 2-hour rated barrier criteria of 160,000 Btu/ft2. Additionally, the review of WBN FPR, Part VII, Deviations and Evaluations, (Revision 10) noted that the licensees evaluation for deviation 2.4 concerning intervening combustibles did not specifically consider the transformers in the area (insulated with a combustible dielectric liquid) as a potential intervening combustible located between redundant components. The licensee was not able to provide a documented technical evaluation which justified the use of the combustible dielectric insulating liquid and its associated contribution to the area combustible load fire severity or intervening combustible evaluation. In response to the inspectors questions, the licensee stated that, although SSER 18 did address Askarel oil, no additional evaluations of the type of oil used in indoor transformers was required since the SSER did not reflect the latest information provided by TVA in Revisions 4 and 5 of their FPR submitted to NRC on September 28, 1995, and November 1, 1995, respectively. The licensee stated that these submittals identified that transformers installed within safetyrelated buildings are either dry-type or insulated and cooled with high fire point (650F) liquid. Based upon the review of the WBN FPR and EPM-DOM-012990, the inspectors concluded that the transformers in the area (insulated with a combustible dielectric liquid) contributed to a total fixed fuel load fire severity that exceeded the credited fire resistive rating of the room fire barriers and could potentially challenge either the credited one-hour barrier for the safety related cables, the walls separating the adjacent FAs or both. The inspectors discussed this issue further with licensee personnel on June 13, 2011 during a teleconference. The licensee personnel stated they would provide additional information related to questions raised by inspectors regarding when the change to the combustible dielectric was made. Based upon questions raised by the inspectors, 40 additional indoor transformers were identified in Unit 1 and areas of Unit 2 (under construction) to have the same combustible dielectric liquid and located within ten (10) additional AVs (AV-1, AV-51, AV-63, AV-64, AV-68, AV-69, AV-89, AV-94, AV-95, and AV-96) at WBN. The licensee initiated service request (SR) 263312 and problem evaluation report (PER) 265331 to address the issues described in this section. Further review and consultation with NRC experts in the Office of Nuclear Reactor Regulation will be needed to determine the regulatory impacts of this issue. As a result, this issue is identified as URI 05000390/2010007-002, Installed Insulating Fluid in Interior Transformers Potentially Deviates from License/Design Criterion in SSER 18 and Position D.1.g of Appendix A to BTP (APCSB) 9.5-1. |
| 05000390/FIN-2010007-03 | 2010Q4 | Watts Bar | Questions Related to OMA to Establish RCP Seal Cooling in the Event of a Fire in AV-076, Computer Room | The inspectors opened an URI involving an OMA credited for establishing (RCP) seal cooling. Specifically, a hand-wheel on a valve required by procedure to be closed in the event of a fire in the control building, FA 48 (AV-076), was missing. The licensee maintained that the action, if not performed, would not have an effect on their ability to achieve and maintain safe shutdown. This item is pending further inspector review. In the event of a fire in AV-076, procedure AOI-30.2 C69, Fire Safe Shutdown Control Building, directed operators to establish RCP seal injection via air-operated valve 1-FCV-62-93. While performing a field walk-down of procedure AOI-30.2 C69, the inspectors identified that Step 4 of Auxiliary Unit Operator Checklist 1 could not be completed as directed, because the hand wheel for valve 1-ISV-32-2934 was missing. Valve 1-ISV-32-2934 is a manual air isolation valve on a 34 inch airline to air-operated valve 1-FCV-62-93. The procedure directed the operator to close valve 1-ISV- 32-2934 to isolate air to valve 1-FCV-62-93, and open the petcock on the regulator for valve 1-FCV-62-93 to bleed off the air, which forced valve 1-FCV-62-93 to fail open. This would allow charging flow to the RCP seals to be controlled by the seal water injection filter via a series of manually-operated valves. This would also provide makeup to the RCS since the primary injection path would be isolated. The inspectors identified that the last time valve 1-ISV-32-2934 was operated was on February 23, 2008, per Work Order WO 07-816218-000. The licensee staff initially told the NRC inspectors that this manual action was not required for SSD. Inspectors requested an evaluation of the impact of the failure to perform this manual action on the ability to achieve and maintain SSD. Upon identification of the missing hand-wheel on October 8, 2010, the licensee initiated Service Request SR-262219 to replace the missing hand-wheel. On October 20, 2010, the inspectors requested a copy of the corrective action documents for the missing hand-wheel, and were told that the service request had been closed to a work order which was still open. As a result, the hand-wheel had not been replaced. The licensee informed the inspectors that in accordance with their corrective action program, a PER should have been initiated for this issue. The licensee then initiated SR 269706 to address the failure to write a PER and untimely replacement of the hand-wheel. The hand-wheel was replaced by licensee staff on October 30, 2010, per WO 11524638. The licensee had not established compensatory measures for the time period the hand wheel was missing, because tools were available in an Operations personnel cabinet for individuals to use. However, the need to obtain the necessary tools to manually close valve 1-ISV-32-2934 was not discussed in procedure AOI-30.2 C69 or evaluated to determine if extra time was available to obtain the tools. On October 22, 2010, inspectors requested information on the effect on SSD if the action was not completed successfully, the fire areas where the action was credited, and the design basis impact if the RCP seal cooling flow criteria was not met. The licensee staff provided a response to the inspectors on November 8, 2010, in which they indicated that RCP seal injection flow rates would be adequate without closing valve 1-ISV-32-2934. As a result of reviewing this information the inspectors requested additional information regarding seal injection flow rates and the effect on the pressurizer. The licensee provided additional information to NRC on December 1, 2010. A conference call with the licensee was conducted on February 24, 2011, to discuss a discrepancy between the licensees November 8, 2010, response and calculation WBNOSG4- 031. On March 24, 2011, the licensee provided clarifying information to the inspectors related to this issue. Pending NRC review of all information this issue is identified as URI 05000390/2010007-003, Questions Related to OMA to Establish RCP Seal Cooling in the Event of a Fire in AV-076, Computer Room. |
| 05000390/FIN-2013007-01 | 2013Q1 | Watts Bar | Failure to Follow Procedure BP-529, Oversight of Supplemental Personnel | Inspectors identified a finding of very low safety significance for failure to follow procedure BP-259, Oversight of Supplemental Personnel, Rev. 9. Specifically, during the licensees review of the vendor instructions for performing maintenance on turbine intercept valve 1-FCV-1-102, the licensee failed to recognize that the vendor instructions were not wholly applicable due to site-specific modifications made on the Electro Hydraulic Control (EHC) system. Consequently, an EHC system leak was identified on valve 1-FCV-1-102 during power ascension at 61% power that led to a manual turbine trip. The issue was entered into the licensees CAP program as Problem Evaluation Report (PER) 686688. The finding was determined to be more than minor because it affected the design control attribute of the initiating events cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Using the Inspection Manual Chapter 0609, Significance Determination Process, Phase 1 worksheet, the finding was determined to have very low safety significance because the condition only affected the initiating events cornerstone and did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions will not be available. The finding was determined to have a cross-cutting aspect in Human Performance, Work Practices, in that the licensee did not ensure supervisory and management oversight of work activities, including contractors, such that nuclear safety is supported. |
| 05000390/FIN-2014007-01 | 2014Q4 | Watts Bar | Security | |
| 05000390/FIN-2015405-01 | 2014Q4 | Watts Bar | Security | |
| 05000395/FIN-2012008-01 | 2012Q3 | Summer | Inadequate Procedures and Procedure Compliance for Preventative Maintenance Deferrals | The inspectors identified a non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings. The licensee failed to ensure that the procedure for performing Preventative Maintenance (PM) deferrals included provisions to ensure that when a Work Order (WO) high value Preventative Maintenance Task Sheet (PMTS) is deferred past its end date that the new end date for the PMTS is updated in the Computerized Maintenance Management System (CMMS). Additionally, the licensee failed to ensure personnel performed PM deferrals when a WO high value PMTS could not be performed by its required end date as directed by the PM program procedure. The licensee entered the issue into the corrective action program as CRs 12-03940, 12-3930, 12-03931, 12-04122, and 12-04152. The licensees failure to have an adequate procedure for PM deferrals and failure to perform PM deferrals as required by procedure SAP 143 was a performance deficiency. The performance deficiency was determined to be more than minor because if left uncorrected, the performance deficiency had the potential to lead to a more significant safety concern. Specifically, the failure to perform PMs at the required intervals could result in degradation or failure of safety significant equipment. The inspectors used IMC 0609, Att. 4, Initial Characterization of Findings, issued 6/19/12, and IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, issued 6/19/12, and determined the finding to be of very low safety significance (Green) because the finding was not a design or qualification deficiency, did not represent a loss of system and/or function, did not result in exceeding a TS allowed outage time and did not represent an actual loss of function of one or more non-Tech Spec Trains. The team identified a crosscutting aspect in the resources component of the human performance area because the licensee failed to ensure that the procedure was complete accurate and up to date. |
| 05000395/FIN-2016007-01 | 2016Q4 | Summer | Failure to Implement Corrective Actions and Restore Compliance for Previous NRCIdentified SLIV NCV | The inspectors identified a cited Severity Level (SL) IV violation of Operating Licensee Condition 2.C.(18) for failure to ensure that conditions adverse to fire protection as noted in a previous NRC-identified SLIV NCV, 05000395/2016001-01, Failure to Implement Adequate Administrative Controls Following a Departure from National Fire Protection Association (NFPA) 80-1973 and Provide NRC Staff Complete and Accurate Information, were promptly corrected. Specifically, the licensee failed to implement corrective actions and restore compliance in a timely manner for (1) the noncompliance with 10 CFR 50.9 to provide staff complete and accurate information and (2) fire doors DRIB/105A&B currently do not meet self-closing requirements in accordance with the current NFPA 805 licensing basis and no actions were specified in licensees corrective action program to restore compliance. The licensee entered the issue in their corrective action program as condition report (CR)-16-04701. The inspectors determined that the performance deficiency was more than minor because it impacted the ability of the NRC to perform its regulatory oversight function and was dispositioned using traditional enforcement. Because the licensee failed to implement corrective actions and restore compliance in a timely manner, this violation is being treated as a cited violation, consistent with Section 2.3.2. a of the NRC Enforcement Policy. This violation involved traditional enforcement and a cross-cutting aspect was not assigned to this violation. |
| 05000395/FIN-2016007-02 | 2016Q4 | Summer | Failure to Correct a Condition Adverse to Quality Associated with a Previously Issued NCV | The inspectors identified a non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, for the failure to correct a condition adverse to quality associated with a previously issued NCV, 05000395/2012004-02, Inadequate Installation of Unit 1 Service Water Piping and Related Pipe Support. The licensee entered the issue in the correction action program as condition report (CR)-16-04621. The PD is more than minor because if left uncorrected, the reduction in design margin of the pipe support could affect the Unit 1 SW systems ability to mitigate a seismic event. Specifically, Unit 1 service water (SW) piping and support had been impacted by the reduction in design margin and without formally updating the associated drawings and calculations or restoring to the original design, future modifications to the system could impact the systems ability to mitigate a seismic event. Using Manual Chapter 0609 Attachment 04, Initial Characterization of Findings, Table 2, dated October 07, 2016, the finding was determined to adversely affect the External Event Mitigating Systems. The inspectors screened the finding using Inspection Manual Chapter (IMC) 0609, Appendix A, Significance Determination Process (SDP) for Findings at-Power, dated June 19, 2012, and determined that it screened as Green (very low safety significance) because the service water system maintained its functionality to mitigate a seismic event. The inspectors determined that the finding had a cross-cutting aspect in the area of PI&R because the licensee did not take effective corrective actions to address this issue in a timely manner (P.3). |
| 05000400/FIN-2008008-01 | 2008Q4 | Harris | Sprinkler System in Cable Spreading Room A Does Not Meet Licensee\'s Fire Protection Program Requirements | The team identified a non-cited violation of Shearon Harris Unit 1 operating license condition 2.F, for the licensees failure to install the sprinkler system in Cable Spreading Room A (CSRA) in accordance with the approved fire protection program (FPP). Specifically, the installed system would not have been able to deliver the sprinkler system design density of 0.3 gallons per minute/square foot in CSRA, as stated in the FPP in Updated Final Safety Analysis Report Section 9.5.1.2.3. The licensee entered this issue in the corrective action program and established a continuous fire watch in CSRA as a compensatory measure in accordance with the Shearon Harris FPP. The licensees failure to install the sprinkler system in CSRA in accordance with the approved FPP is a performance deficiency. This finding is more than minor because the installed sprinkler system degraded one of the fire protection defense in depth elements and it affected the reactor safety Mitigating Systems cornerstone objective. The team completed a Phase 2 screening of the finding in accordance with IMC 0609, Appendix F, Attachment 1, Part 2, Fire Protection SDP Phase 2 Worksheet, and concluded that the finding was of very low safety significance (Green), in accordance with Step 2.5, Task 2.5.5 of the Worksheet, because there was a safe shutdown path available which was independent of CSRA. The cause of this finding was not associated with a cross-cutting area because it is not reflective of current licensee performance. (Section 1R05.04 |
| 05000400/FIN-2008008-02 | 2008Q4 | Harris | Post-Fire Safe Shutdown From Outside the Main Control Room (Alternative Shutdown) | The team identified a noncompliance of very low safety significance with Shearon Harris Technical Specification 6.8.1.a, for inadequate procedural guidance which directed usage of instruments that were not protected from fire damage in FZ 12- A-6-PICR1. Specifically, procedure AOP-004, Remote Shutdown, directed the operators to verify emergency service water (ESW) header flows were above the minimum flow requirement of 7500 gpm using flow indicators (FI) FI-9101A2 and FI-9101B2. These instruments would be unreliable during operation from the ACP because their cables were routed through the FZ of concern and the cables were not protected from fire damage. The violation meets the criteria of NRC Enforcement Policy, Interim Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48) for enforcement discretion. The team noted that procedure AOP-004, Remote Shutdown, would be used to safely shut down the plant from the ACP (utilizing Train B equipment) for a fire in FZ 12-A-6-PICR1. The procedure directed operators to verify ESW header (HDR) flows using FI-9101A2, A HDR Flow and FI-9101B2, B HDR Flow. The team reviewed cable routing data and noted that FI-9101A2 and FI-9101B2 may not provide reliable ESW flow indication for the operators at the ACP because the cables were routed through FZ 12-A-6-PICR1 and were not protected from fire damaged. This may potentially delay operator actions required to bring the plant to SSD conditions. Based on discussions with operations personnel and review of service water system simplified flow diagrams, the team determined that the ESW system was flow balanced to ensure that the 7500 gpm minimum flow would be provided to ESW HDR A and ESW HDR B. During walkdowns of the ACP, the team noted that valve position indication (i.e., open/close) was provided at the ACP for various ESW valves, including 1SW-270, HDR A to Auxiliary Reservoir and 1SW-271, HDR B to Auxiliary Reservoir. These valves were required to be opened (from the ACP) to ensure adequate ESW header flow. Review of cable routing data for valve 1SW-271 showed that this valve was not routed through FZ 12-A-6-PICR1 and would not be affected by a postulated fire in this FZ. The team determined that, based on operator experience, training, and indication of the position of ESW valve 1SW-271 at the ACP, it was likely plant operators would be able to determine that sufficient ESW flow was available and they would take the appropriate actions required to ensure post-fire SSD conditions. The licensee initiated NCR 298072 to address this issue in the CAP. |
| 05000400/FIN-2015008-01 | 2015Q4 | Harris | Untimely 10 CFR 50.73 Notification of an Inoperable CIV | An NRC-identified Severity Level IV violation of 10 CFR 50.73 was identified for the licensees failure to provide a written report to the NRC within 60 days after discovery of a condition prohibited by Technical Specification (TS) Limited Condition for Operation (LCO) 3.6.3, "Containment Isolation Valves."The issue was placed in the licensees corrective action program as CR 01958628.The inspectors determined that the failure to provide a written report to the NRC within the time limits specified in regulations was a violation 10 CFR 50.73. The violation was evaluated using Section 6.9 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. As a result, this violation was evaluated using traditional enforcement. In accordance with Section 6.9.d.9of the NRC Enforcement Policy, this violation was determined to be a Severity Level IV, non-cited violation. The inspectors determined that a cross-cutting aspect was not applicable because the issue involving untimely reports to the NRC was strictly associated with a traditional enforcement violation. |
| 05000400/FIN-2015008-02 | 2015Q4 | Harris | Failure to Follow EPM-410 Procedure | An NRC-identified Green NCV of 10 CFR 50.54(q)(2) was identified, for the licensees failure to follow and maintain, in effect, the Emergency Plan when performing monthly testing of the Technical Support Center (TSC). Specifically, the licensee failed to follow procedural steps when recorded values did not meet acceptance criteria as specified in EPM-410, Communication and Facility Performance Tests. The issue was placed in the licensees corrective action program as CRs 01942073, 01940053. The finding was more than minor because it was associated with the Emergency Response Organization (ERO) Performance attribute and it adversely affected the Emergency Preparedness Cornerstone objective of ensuring that the licensee was capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. Specifically, the failure to follow procedural steps when recorded values did not meet acceptance criteria resulted in a failure to comply with emergency plan. The finding was assessed for significance in accordance with NRC Manual Chapter 0609, Appendix B Emergency Preparedness Significance Determination Process. Attachment 2 of Appendix B, Failure to Comply Significance Logic is as follows: Failure to comply; Loss of Risk Significant Planning Standard Function (RSPS), NO; RSPS Degraded Function, NO; Loss of Planning Standard Function, No; results in a Green finding. The inspectors identified a cross-cutting aspect in the Problem Identification and Resolution area because the licensee did not take effective corrective actions to address issues in a timely manner commensurate with their safety significance (P.3). |
| 05000413/FIN-2011005-01 | 2011Q4 | Catawba | Follow-up for NOED 11-2-004 | The inspectors reviewed NOED 11-2-004 and related documents to determine the accuracy and consistency with the licensees assertions and implementation of the licensees compensatory measures and commitments which included deferring non-essential surveillances and other maintenance activities on the emergency diesel generators, the turbine-driven AFW pumps, the Standby Shutdown System, fire protection systems and switchyard. The inspectors also verified that the licensee briefed the oncoming operations shift on AP/0/A/5500/039, Control Room High Temperature. Additional inspection is required to conduct a review of the LER, root cause, and planned corrective actions. This URI is identified as URI 05000413, 414/2011005-01, Follow-up for NOED 11-2-004 |
| 05000424/FIN-2017007-01 | 2017Q1 | Vogtle | Failure to identify a Degraded Atmospheric Relief Valve | The NRC identified a Green finding for the licensees failure to identify the reduced reliability of Unit 1 loop 3 atmospheric relief valve (ARV) 1PV-3020 as a degraded/nonconforming condition, as required by NMP-AD-012, Operability Determinations and Functionality Assessments, Version 12.5. As a result, corrective maintenance was not prioritized nor conducted at the next available opportunity and led to an additional valve failure in March 12, 2016. The failure to identify aging of 1PV-3020 #285 pilot-to-check valve as a degraded/non conforming condition, as required by NMP-AD-012, was a performance deficiency. The performance deficiency was more than minor because it was associated with the equipment performance attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability o systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the performance deficiency prevented the license from prioritizing and conducting corrective maintenance of 1PV-3020 at the next available opportunity, and led to an additional valve failure in March 2016. Using Exhibit 2 of IMC 0609, Appendix A, the inspectors determined that this finding is of very low safety significance (Green) because, although the performance deficiency (PD) affected the design/qualification of the 1PV3020 operability, it did not result in an actual loss of safety system function, and it did not represent a loss of function of one or more than one train for more than its technical specification (TS) allowed outage time or greater than 24 hours. The finding was assigned a cross cutting aspect of Resolution in the Problem Identification and Resolution area, because the licensee failed to take effective corrective actions to address aging of the #285 pilot-to-check valve in a timely manner. |