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| Quarter | Site | Title | Description | |
|---|---|---|---|---|
| 05000313/FIN-2018011-02 | 2018Q3 | Arkansas Nuclear | Failure of Both Arkansas Nuclear One Units to Establish Adequate Corrective Actions Resulting in Excessive Instances of Damaged and Broken Internals of the Emergency Feedwater Pum o Turbine Steam Admission Check Valves. | An NRC identified Green, non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Actions," was identified for failure to establish an adequate corrective action program and the resulting inability to correct a deficient system design which resulted in damaged and broken internals of the check valves admitting steam to the emergency feedwater turbine. |
| 05000313/FIN-2018011-01 | 2018Q3 | Arkansas Nuclear | Failure to Properly Size the Unit 1 Emergency Diesel Generator Room Ventilation Svstems | An NRC identified Green, non-cited violation of 10 CFR Part 50, Appendix B, Criterion Ill, "Design Control," was identified for failure to properly size the Unit 1 emergency diesel generator room ventilation systems to be capable of removing the design heat load during the most limiting design conditions while maintaining redundancy of the exhaust fans. |
| 05000313/FIN-2018011-03 | 2018Q3 | Arkansas Nuclear | Failure to Evaluate the Effects and the Suitability of Components in Containment from a Main Steam Line Break. | The team identified an unresolved item (URI) related to the containment environment that would result from a main steam line break. Specifically, for ANO Unit 1 the licensee did not analyze the containment temperature, or evaluate the suitability of components in containment for the effects of a main steam line break (MSLB) accident. The Final Safety Analysis Report states, in part, that "At the end of Cycle 19, the original once through steam generators (OTSGs) were replaced. In support of Cycle 20 operation, an evaluation of the containment pressure/temperature response with the replacement OTSGs for loss of coolant accidents (LOCA) and MSLB was performed. For the MLSB, the containment pressure response with the replacement OTSGs was bounded by the current analysis. The post-MSLB temperature response w ith the replacement OTSGs would be worse. Entergy Operations, Inc. has adopted NUREG-0458 into the AN0-1 licensing basis which recognizes that the post-MSLB atmosphere may become superheated, but the temperature spike is of such short duration that the thermal lag of any SSC inside containment will not increase significantly. Consequently, the initial temperature peak does not define operating limits on any system, structure, or component (SSC) and the long-term containment temperature (which is essentially the saturation temperature) dominates the temperature response of SSCs. Therefore, as long as the peak MSLB pressure is less than the peak pressure following a LOCA, the temperature response of SSCs will still be defined by the LOCA." The NRC issued several bulletins subsequent to the issuance of NUREG-0458. Specifically IEB-79-01, as supplemented, and NRC Order CLI 80-21 state, in part, that "The Guidelines leave open the question of what standard will be applied to replacement parts in operating plants. Unless there are sound reasons to the contrary, the 1974 standard in NUREG-0588 will apply. The Guidelines and NUREG-0588 apply progressively less strict standards to the older plants. The justification for this position was not articulated at the time the older plants were grandfathered from the provisions of Reg. Guide 1.89." The NRC issued a Safety Evaluation Report to ANO, which states, in part, "A final rule on environmental qualification of electric equipment important to safety for nuclear power plants became effective on February 22, 1983. This rule, Section 50.49 of 10 CFR 50, specifies the requirements of electrical equipment important to safety located in a harsh environment. In accordance with this rule, equipment for Arkansas Unit 1 may be qualified to the criteria specified in either the DOR Guidelines or NUREG-0588, except for replacement equipment. Replacement equipment installed subsequent to February 22, 1983 must be qualified in accordance with the provisions of 10 CFR 50.49, using the guidance of Regulatory Guide 1.89, unless there are sound reasons to the contrary." The NRC issued Information Notice 85-39 states, in part, that the "Qualification of some replacement equipment was based on previously allowed DOR guidelines that stated "equipment is considered qualified for main steam line break environmental conditions if it was qualified for a loss-of-coolant accident environment in plants with automatic spray systems not subject to disabling single component failures." This basis of qualification is not acceptable without additional justification for replacement equipment that was procured and installed after February 22, 1983." The replacement steam generators have several design differences compared to the original steam generators. Specifically, the replacement steam generators were designed with larger secondary volumes, more tubes, flow-restricting venturis, and different materials (Alloy 690 vs. Alloy 600). Because the replacement steam generators were installed in 2005 (after 10 CFR 50.49 became effective on February 22, 1983) all replacement equipment must be qualified using the guidance of NUREG-0588 or Regulatory Guide 1.89. In addition, as stated above the licensee did not analyze or quantify the containment temperature that would result from a MSLB, and instead compared the containment pressures and the mass/energy releases that would result from a MSLB using the superseded guidance of NUREG-0458. The NRC team identified that there are several parameters that could have changed with the replacement steam generators which could impact the containment response. Specifically, input parameters such as: sub-compartment analysis, net positive suction head analysis, containment volume, heat sinks, properties of materials, heat transfer coefficients, initial conditions, and possibly cooling water temperature may affect the containment temperature response. |
| 05000382/FIN-2018002-03 | 2018Q2 | Waterford | Licensee-Identified Violation | This violation of very low safety significance was identified by the licensee and has been entered into the licensee corrective action program and is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy. Violation: Technical Specification 3.6.3, Containment Isolation Valves, requires, in part, that when an isolation valve for containment penetrations associated with an open system are inoperable, the licensee must restore the inoperable valve(s) to operable status within 4 hours, isolate the affected penetration within 4 hours, or be in hot standby within the next 6 hours. Contrary to the above, between December 8, 2017, and December 11, 2017, with containment isolation valves inoperable, the licensee did not restore the inoperable valves to operable status within 4 hours, isolate the affected penetrations within 4 hours, or place the unit in hot standby within the next 6 hours. The licensee restored the valves to operable status on December 20, 2017, exceeding the Technical Specification 3.6.3 allowed outage time by approximately 70 hours. Significance/Severity Level: The finding was of very low safety significance (Green) because the containment isolation valves were maintained closed during the period and did not represent an actual open pathway in the physical integrity of the reactor containment. Corrective Action Reference: CR-WF3-2018-00983 |
| 05000528/FIN-2018002-02 | 2018Q2 | Palo Verde | Failure to Implement and Maintain Procedures Regarding Breathing Air Quality | The inspectors identified a Green, non-cited violation of 10 CFR 20.1703 for failing to implement and maintain written procedures to ensure that respiratory protection equipment (air compressors and bubble hood suites) supplied respirable air of grade D quality or better to radiation workers. |
| 05000530/FIN-2018002-03 | 2018Q2 | Palo Verde | Failure to Assess the Operability of a Degraded or Nonconforming Structure, System, or Component | The inspectors identified a Green, non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensees failure to evaluate conditions adverse to quality for impacts on the operability of the essential spray ponds. |
| 05000528/FIN-2018002-01 | 2018Q2 | Palo Verde | Failure to Re-baseline Valve Stroke Times as Required by ASME OM Code | The inspectors identified a Green, non-cited violation of Palo Verde Technical Specification 5.5.8, Inservice Testing Program, which requires inservice testing of ASME Code Class 1, 2, and 3 components in accordance with the ASME Code for Operation and Maintenance of Nuclear Power Plants (OM Code). On October 22, 2017, the licensee failed to establish new stroke time reference values for Unit 1 safety injection (SI) valve 660 following maintenance which could affect the valves performance |
| 05000298/FIN-2018002-02 | 2018Q2 | Cooper | Failure to Maintain Adequate Work Instructions for Traversing In-Core Probe System Limit Switches | A self-revealed, Green non-cited violation of Technical Specification 5.4, Procedures, was identified when the licensee failed to maintain Procedure 14.2.14, TIP Chamber Shield Maintenance, with adequate instructions for reinstalling the traversing in-core probe system in-shield limit switches. As a result, the licensee experienced multiple failures of the shield limit switches resulting in inoperable primary containment isolation valves. |
| 05000298/FIN-2018002-01 | 2018Q2 | Cooper | Failure to Maintain Alarm Procedure for Service Water Booster Pump Ventilation Manual Actions | The inspectors identified a Green non-cited violation of Technical Specification 5.4, Procedures, when the licensee failed to maintain Procedure 2.3_R-1 with the bounding time restrictions for required manual ventilation actions identified in Engineering Evaluation NEDC 92-064, Transient Temperature Rise in SWBP Room After Loss of Cooling, Revision 3C2. As a result, the licensee relied on procedure guidance that contained an incorrect, less restrictive allowance of 13 hours for completion of manual actions rather than the bounding 5.8-hour allowance described in NEDC92-064. |
| 05000382/FIN-2018002-02 | 2018Q2 | Waterford | 10 CFR 50.59 Evaluation Associated with Emergency Feedwater Logic Modification | The licensee changed the emergency feedwater logic, as described in the Updated Final Safety Analysis Report (UFSAR), Section 7.3.1.1.6, from flow control mode to level control mode during a safety injection actuation signal. To accomplish this change, the licensee had to modify the following logic system signals and setpoints: steam generator critical level, steam generator lo level, steam generator lo-lo level, safety injection actuation, control board manual control, and the steam generator lo-lo level annunciator. The NRC team questioned whether the emergency feedwater modification required additional information to determine if the 10 CFR 50.59 evaluation was adequate, or if NRC approval was needed for the change. Specifically, the NRC team questioned if the emergency feedwater logic change: used a method of evaluation other than what was described in the UFSAR (e.g. the use of the TRANFLOW program) or would result in a more than minimal increase in the likelihood of occurrence of a malfunction of a system important to safety. Specifically, because the emergency feedwater logic change introduced the potential to overcool the reactor, and substituted a previous automatic action for manual operator action, the NRC team questioned if the change and associated 50.59 evaluation addressed these concerns. Planned Closure Actions: The NRC and the licensee are working to gather more information related to the Final Safety Analysis Report-described methods for steam generator analyses and if the change resulted in a more-than-minimal increase in risk. Specifically, the licensee plans to provide an analysis that demonstrates the emergency feedwater logic change would not result in a more than minimal increase in the likelihood of an overcooling accident. Licensee Actions: The licensee has implemented a compensatory measure to take manual control of the emergency feedwater system during a safety injection signal such that an overcooling event will be prevented. Corrective Action References: CR-WF3-2017-06067, CR-WF3-2017-05882, CR-WF3-2017-05173 |
| 05000382/FIN-2018002-01 | 2018Q2 | Waterford | Failure to Ensure Appropriate Chemistry Controls on the Component Cooling Water Heat Exchangers | The inspectors reviewed a self-revealed, Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, which occurred because the licensee did not prescribe procedures for preventing fouling of the component cooling water heat exchangers that were appropriate to the circumstances. Specifically, the licensee did not require in its instructions for adding biocide to the auxiliary component cooling water system that additions be coupled with running the associated auxiliary component cooling water pump or other means of ensuring that the biocide would be sufficiently circulated through the system. As a result, on February 8, 2018, component cooling water heat exchanger B failed a performance test and therefore would not maintain required design basis temperatures under all accident conditions due to biological fouling. |
| 05000323/FIN-2018001-01 | 2018Q1 | Diablo Canyon | Improper Troubleshooting Results in Reactor Trip Signal and Loss of Source Range Nuclear Instrument Power | The inspectors reviewed a Green,self-revealed non-cited violation of Technical Specification 5.4.1.a Procedures, because PG&E personnel failed to follow the requirements of MA1.DC54, Conduct of Maintenance, Revision 15. Specifically, on March 20, 2018, with the reactor in Mode 3 during informal troubleshooting of high background count rate on source range nuclear instrument (NI) NI-32, PG&E personnel caused a short in NI cabinet B resulting in a blown fuse and the loss of power to the cabinet. This resulted in the loss of power to power range NI-42, intermediate range NI-36, source range NI-32, a reactor trip signal, a turbine trip signal, and all associated reactor protection interlocks. Power was automatically removed from the remaining source range NI due to reactor protection interlock P-10, resulting in no safety-related source range NI indication being available for control room operators. |
| 05000323/FIN-2018001-02 | 2018Q1 | Diablo Canyon | Failure to Follow Operating Experience Procedures Results in Inadequate Screen of Operating Experience Report | The inspectors identified a finding of very low safety significance (Green) because PG&E personnel failed to follow the requirements of OM4.ID3, Operating Experience Program, Revision 20. Specifically, PG&E personnel failed to screen relevant operating experience relating to a safety-related centrifugal charging pump (CCP) journal bearing failure due to non-metallic anti-rotation pin shear failure. This operating experience notice was received by PG&E September 2011 and was not screened per OM4.ID3, Operating Experience Program, preventing actions from being identified and implemented that could have eliminated vulnerabilities and prevented a similar event from occurring at DCPP. On November11,2017, CCP 2-1 was declared inoperable and determined to be non-functional due to a damaged journal bearing caused by non-metallic, anti-rotation pin shear failur |
| 05000416/FIN-2017011-06 | 2018Q1 | Grand Gulf | Failure to Perform Functionality Assessments as Required by Procedures | The inspectors identified a finding for the licensees failure to follow Procedure EN-OP-104, Operability Determination Process, Revisions 10 through 12. Specifically, the licensee did not perform functionality assessments for adverse conditions on the offgas system as required by the procedure. The licensee entered this issue into their corrective action program as Condition Report CR-GGN-2017-11265. The licensee initiated corrective actions to perform functionality assessments for the conditions identified and to evaluate any potential programmatic issues. The failure to perform functionality assessments required by Procedure EN-OP-104 was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because if left uncorrected, it had the potential to lead to a more significant safety concern. Specifically, the failure to perform functionality assessments could affect the availability and reliability of the offgas system to maintain the doses associated with releases to the environment as low as reasonably achievable. Using Nuclear Regulatory Commission Inspection Manual Chapter 0609, Appendix D, Public Radiation Safety Significance Determination Process, the inspectors determined that the finding was of very low safety significance (Green) because it involved the Effluent Release Program, it did not impair the ability to assess dose, and did not exceed the 10 CFR Part 50, Appendix I, or 10 CFR 20.1301(d) limits. This finding had a cross-cutting aspect in the area of human performance, consistent process, because the licensee did not use a consistent, systematic approach to make decisions. Specifically, the licensees failure to consistently disposition adverse conditions associated with the offgas system resulted in the station not performing required functionality assessments (H.13) |
| 05000416/FIN-2017011-05 | 2018Q1 | Grand Gulf | Failure to Correct Control Room Boundary Door Resulted in Loss of Safety Function | The inspectors reviewed a self-revealed, non-cited violation of 10 CFR Part 50, Criterion XVI, Corrective Action, for the licensees failure to appropriately correct a condition adverse to quality. Specifically, the control room envelope door had been documented in several condition reports for not consistently working properly. Subsequent to these condition reports, on July 9, 2017, the door was opened and did not close automatically, and therefore the door was left in an unsecured position. The licensee entered this issue into their corrective action program as Condition Report CR-GGN-2017-06705. The licensee restored compliance by securing the door and replacing the hinge bushings to ensure the door would close properly. The failure to correct a condition adverse to quality for a control room envelope boundary door was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it was associated with the structures, systems, and components and barrier performance attribute of the Barrier Integrity Cornerstone and adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers (functionality of the control room) protect the public from radionuclide releases caused by accidents or events. Specifically, on July 9, 2017, since the licensee had not corrected the adverse conditions identified on the control room envelope door, the door was left in an unsecured position and resulted in the station declaring both trains of standby fresh air inoperable. Using Nuclear Regulatory Commission Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, and Nuclear Regulatory Commission Inspection Manual Chapter 0609, Appendix A, Exhibit 3, Barrier Integrity Screening Questions, the inspectors determined that the finding was of very low safety significance (Green) because the finding did not represent a degradation of the radiological barrier function provided for the control room, auxiliary building, spent fuel pool, or standby gas treatment system, and did not represent a degradation of the barrier function of the control room against smoke or a toxic atmosphere. The period of the barrier in the open position was of short duration, approximately 1 minute, and therefore did not result in significant risk input. This finding had a cross-cutting aspect in the area of problem identification and resolution, resolution, because the licensee did not take corrective actions in a timely manner commensurate with their safety significance. Specifically, the licensee did not ensure proper priority of corrective actions on the degraded control room envelope boundary door (P.3). |
| 05000416/FIN-2017011-04 | 2018Q1 | Grand Gulf | Failure to Install the Residual Heat Removal Pump A Mechanical Seal in Accordance with Procedures | The inspectors reviewed a self-revealed, non-cited violation of Technical Specification 5.4, Procedures, for the licensees failure to perform maintenance on the residual heat removal pump A mechanical seal in accordance with written procedures. Specifically, on September 22, 2016, maintenance did not install seal assembly drive pins in accordance with Step 7.8.2 of Procedure 07-S-14-279, Revision 007. The licensee entered this issue into their corrective action program as Condition Reports CR-GGN-2017-08269 and CR-GGN-2017-11009. The licensee implemented immediate corrective actions by declaring the pump inoperable and replacing the mechanical seal. The failure to perform maintenance on the residual heat removal pump A mechanical seal in accordance with written procedures was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it was associated with the human performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, on September 22, 2016, mechanical maintenance installed the residual heat removal pump A seal drive pins backwards. As a result, the drive pins damaged the seal and on August 23, 2017, caused an unisolable leak from the seal. This resulted in unplanned inoperability and unavailability of the residual heat removal pump A from August 23, 2017, through August 25, 2017, when the mechanical seal was replaced. Using Nuclear Regulatory Commission Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, and Nuclear Regulatory Commission Inspection Manual Chapter 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, the inspectors determined that the finding was of very low safety significance (Green) because it was related to, but was not itself: (1) a deficiency affecting the design or qualification of a mitigating structure, system, or component, and did not result in a loss of operability or functionality; (2) a loss of system and/or function; (3) an actual loss of function of at least a single train for longer than its technical specification allowed outage time, or two separate safety systems out-of-service for longer than their technical specification allowed outage time; and (4) an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant in accordance with the licensees Maintenance Rule program. This finding had a cross-cutting aspect in the area of human performance, avoid complacency, because the licensee failed to recognize and plan for the possibility of mistakes, and individuals failed to implement appropriate error reduction tools. Specifically, the licensee failed to use appropriate error reductions tools such as self-check or peer checking which resulted in incorrect performance of procedural steps (H.12) |
| 05000416/FIN-2017011-03 | 2018Q1 | Grand Gulf | Failure to Conduct Common Cause Failure Evaluation in Response to Inoperable Emergency Diesel Generator | The inspectors identified three instances of a non-cited violation of Technical Specification 3.8.1, AC Sources Operating, for the licensees failure to take required actions for an inoperable emergency diesel generator. Specifically, after classifying the Division I or Division II emergency diesel generator as inoperable on the basis of nonconforming conditions, and after failing to either verify that the opposite train emergency diesel generator was not inoperable due to common cause failure within 24 hours or conduct a surveillance run on the opposite train emergency diesel generator within 24 hours, the licensee failed to enter Mode 3 within 12 hours as required by Technical Specification 3.8.1, Actions B.3.1, B.3.2, and G.1, respectively. The licensee entered this issue into their corrective action program as Condition Report CR-GGN-2017-11393. The licensee initiated corrective actions to conduct an adverse condition analysis. The failure to take required actions for an inoperable emergency diesel generator was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it was associated with the equipment reliability 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. Actions B.3.1 and B.3.2 of Technical Specification 3.8.1 exist to ensure the availability, reliability, and capability of at least one emergency diesel generator in scenarios where there is a potential for a common cause failure of both emergency diesel generators, and the licensee took neither action. Using Nuclear Regulatory Commission Inspection Manual Chapter 0609, Appendix A, Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, the inspectors determined that the finding was of very low safety significance (Green) because the finding did not represent an actual loss of function of either the Division I or Division II emergency diesel generator for greater than its technical specifications allowed outage time. The finding had a cross-cutting aspect in the area of human performance, consistent process, because the licensee failed to use a consistent, systematic approach to make decisions. Specifically, the licensee failed to review the required actions of the applicable technical specification to ensure that all of those actions would be properly carried out (H.13). |
| 05000416/FIN-2017011-02 | 2018Q1 | Grand Gulf | Failure to Disposition Adverse Conditions as Required by Procedures | The inspectors identified a finding for the licensees failure to disposition conditions as required by Procedure EN-LI-102, Corrective Action Program, Revisions 24 through 30. Specifically, the licensee did not identify 72 conditions as either Adverse Category B, C, or D as required by the procedure. As a result, the licensee failed to perform the required cause evaluations and develop corrective actions to address the conditions. The licensee entered the conditions into their corrective action program as Condition Report CR-GGN-2017-10896. The licensee initiated corrective actions to re-categorize the conditions and perform the required evaluations. The failure to disposition conditions as adverse (B, C, or D) as required by Procedure EN-LI-102 was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because if left uncorrected, it had the potential to lead to a more significant safety concern. Specifically, condition reports associated with deficiencies or potential deficiencies involving safety-related equipment are required to be categorized as adverse and appropriate corrective actions are assigned including causal analyses appropriate to the circumstances per licensee Procedure EN-LI-102. The inspectors performed an initial screening of the finding in accordance with Nuclear Regulatory Commission Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power. Using Nuclear Regulatory Commission Inspection Manual Chapter 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, the inspectors determined that the finding was of very low safety significance (Green) because it was related to, but was not itself: (1) a deficiency affecting the design or qualification of a mitigating structure, system, or component, and did not result in a loss of operability or functionality; (2) a loss of system and/or function; (3) an actual loss of function of at least a single train for longer than its technical specification allowed outage time, or two separate safety systems out-of-service for longer than their technical specification allowed outage time; and (4) an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant in accordance with the licensees Maintenance Rule program. This finding had a cross-cutting aspect in the area of human performance, consistent process, because the licensee did not use a consistent, systematic approach to make decisions. Specifically, the licensees failure to consistently disposition identified conditions as adverse led to the failure to fully evaluate the conditions (H.13). |
| 05000416/FIN-2017011-01 | 2018Q1 | Grand Gulf | Failure to Categorize Condition Reports for Significant Conditions Adverse to Quality as Required by Procedures | The inspectors identified five examples of a finding for the licensees failure to categorize and evaluate conditions in accordance with procedural requirements. Specifically, the licensee did not categorize adverse conditions that represented the loss of a safety function as significant conditions adverse to quality as required by Procedure EN-LI-102, Corrective Action Program, Revisions 24 through 28. The licensee entered the conditions into their corrective action program as Condition Report CR-GGN-2017-10896. The licensee initiated corrective actions to re-categorize the conditions and perform the required evaluations. The failure to categorize conditions that represent the loss of a safety function as significant conditions adverse to quality as required by Procedure EN-LI-102 was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because if left uncorrected, it had the potential to lead to a more significant safety concern. Specifically, root cause evaluations, corrective actions to prevent recurrence, and effectiveness reviews are used per licensee Procedure EN-LI-102 to ensure availability and reliability of structures, systems, and components are maintained. Using Nuclear Regulatory Commission Inspection Manual Chapter 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, the inspectors determined that the finding was of very low safety significance (Green) because it was related to, but was not itself: (1) a deficiency affecting the design or qualification of a mitigating structure, system, or component, and did not result in a loss of operability or functionality; (2) a loss of system and/or function; (3) an actual loss of function of at least a single train for longer than its technical specification allowed outage time, or two separate safety systems out-of-service for longer than their technical specification allowed outage time; and (4) an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant in accordance with the licensees Maintenance Rule program. This finding had a cross-cutting aspect in the area of human performance, consistent process, because the licensee did not use a consistent, systematic approach to make decisions. Specifically, the licensees failure to consistently evaluate the conditions during initial screening led to the incorrect categorization of the condition reports (H.13) |
| 05000416/FIN-2017007-07 | 2017Q4 | Grand Gulf | Licensee-Identified Violation | The following violations of very low safety significance (Green) were identified by the licensee and are violations of NRC requirements which meet the criteria of the NRC Enforcement Policy for being dispositioned as non- cited violations. Technical Specification 5.4.1(a) requires written procedures to be established, implemented, and maintained as recommended by Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Section 4.e recommends, in part, instructions for startup of shutdown cooling and reactor vessel head spray system be prepared. Contrary to the above, from about 2004 until September 1, 2017, the 04-1-01-E12-2 instruction failed to provide instruction for placing the alternate decay heat removal system in service. Specifically, Step 4.9.2a.7(d) instructs an operator to, Manually control component cooling water temperature by throttling P44-F010A(B)(C), PSW inlet to CCW HXs. However, the purpose of that step is to throttle plant service water flow through the alternate decay heat removal system and component cooling water system to ensure both systems have plant service water flow, which is not accomplished by the instruction step. The licensee identified this procedural violation before the system was credited for availability during an inservice demonstration on September 1, 2017, and entered it in the corrective action program as Condition Report CR-GGN-2017-08643. The violation is of very low safety significance (Green) because, although the procedure did delay placing the system in service due to the procedure error, the system was capable of performing its design function, consistent with Inspection Manual Chapter 0609, Appendix G, Attachment 1, Exhibit 3 screening. |
| 05000416/FIN-2017007-08 | 2017Q4 | Grand Gulf | Licensee-Identified Violation | 10 CFR 50 Appendix B, Criterion III, requires in part, That measures shall be established to assure that the design bases are correctly translated into specifications, drawings procedures, and instructions. Contrary to the above, from original plant construction until June 22, 2016, GGNS failed to ensure the design basis tornado and differential pressures associated with it, would not cause a spurious trip of the Division I and II standby diesel generators. Specifically, a design basis tornado, includes a differential pressure of 3.0 psig, whereas an active diesel generator trip on high crankcase pressure actuates at 1.5 psig. The licensee identified this issue using an effective operating experience program and entered it in the corrective action program as Condition Report CR -GGN -2016- 04919. The violation is of very low safety significance (Green), for the same reason as NCV -05000416/2017007 -05, discussed in Section 1R21.4.5 of this report. |
| 05000416/FIN-2017007-06 | 2017Q4 | Grand Gulf | Failure to Ensure Adequate Design Control Measures Are in Place Associated with Leakage Control Systems | The team identified a Green, non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, which states, in part, Measures shall be established to assure that applicable regulatory requirements and the design basis...for those structures, systems, and components to which this appendix applies are correctly translated into specifications, drawings, procedures, and instructions. Specifically, prior to October 17, 2017, the licensee failed to provide adequate procedures or training to licensed operators to ensure the main steam isolation valve-leakage control system and feedwater leakage control system are manually started consistent with the licensees design basis assumptions. In response to this issue the licensee has provided specific guidance and training to the operators. This finding was entered into the licensees corrective action program as Condition Report CR-GGN-2017-09112. The team determined that the failure to ensure adequate design control measures are translated into procedures and training is a performance deficiency. The performance deficiency is more than minor, and therefore a finding, because it was associated with the barrier performance attribute of the Barrier Integrity Cornerstone and adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, the plant was operated at power for an extended period of time without adequate procedures and training for licensed operators to ensure that the system would be placed in service in a manner that ensured radiological leakage across main steam isolation valves and through feedwater pi ping is addressed during a postulated accident. In accordance with Manual Chapter 0609, Significance Determination Process, Attachment 4 (effective date October 7, 2016); and the corresponding Appendix A, The Significance Determination Process (SDP) f or Findings At-Power, Exhibit 3, Barrier Integrity Screening Questions (issue date June 19, 2012); the issue was evaluated using Appendix H, Containment Integrity Significance Determination Process (issue date May 6, 2004). Because the opportunities to ensure the design control measures were correctly captured in procedures and instructions for the main steam isolation valve-leakage control system and feedwater leakage control system were in 2001 and 1987, respectively; and the licensee instituted a time-critical operator action program within the last year to prevent such issues from occurring, the issue was determined to have very low safety significance (Green). The performance deficiency was not indicative of current performance. Therefore, no cross-cutting aspect is being assigned. |
| 05000416/FIN-2017007-05 | 2017Q4 | Grand Gulf | Failure to Update a Calculation and Procedure to Address Standby Service Water Passive Failure | The team identified a Green, non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, which states, in part, Measures shall be established to assure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions. Specifically, since September 25, 2013, the licensee failed to include a design basis standby service water system (SSWS) piping crack in the appropriate design calculation and procedure. In response to this issue the licensee performed an operability determination to ensure that the ultimate heat sink basins would still have sufficient capacity to meet the 30 -day mission time. This finding was entered into the licensees corrective action program as Condition Report CR-GGN-2017-10192. The team determined that the failure to update a design calculation and a procedure to address a postulated standby service water passive failure was a performance deficiency. The finding was more than minor because it was associated with the Mitigating Systems Cornerstone attribute of equipment performance and affected the cornerstone objective of ensuring the availability, reliability, and capability of mitigating systems to respond to initiating events to prevent undesirable consequences. In accordance with Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, the issue screened as having very low safety significance (Green) because it was a design or qualification deficiency that did not represent a loss of operability or functionality; did not represent an actual loss of safety function of the system or train; did not result in the loss of one or more trains of non-technical specification equipment; and did not screen as potentially risk-significant due to seismic, flooding, or severe weather. The team determined that this finding did not have a cross-cutting aspect because the most significant contributor did not reflect current licensee performance. |
| 05000416/FIN-2017007-04 | 2017Q4 | Grand Gulf | Failure to Update the Final Safety Analys is Report | The team identified three examples of a Severity Level IV, non-cited violation of 10 CFR 50.71, Maintenance of Records, Making of Reports, Section (e), which states, in part, Each person licensed to operate a nuclear power reactor shall update periodically the final safety analysis report originally submitted as part of the application for the license, to assure that the information included in the report contains the latest information developed. This submittal shall contain all the changes necessary to reflect information and analyses submitted to the Commission by the applicant or licensee, or prepared by the applicant or licensee pursuant to Commission requirement since the submittal of the original or the last update to the final safety analysis report. Specific ally, prior to September 29, 2017, the licensee failed to ensure the final safety analysis report reflected the current plant configuration. In response to this issue, the licensee created a corrective action to update the final safety analysis report. The finding was entered into the licensees corrective action program as Condition Reports CR -GGN -2017- 09154, CR- HQN- 2017- 01356, and CR -GGN -2017 -09747. 5 The team determined that the failure to update the final safety analysis report in accordance with 10 CFR 50.71(e) was a performance deficiency. Following the Reactor Oversight Process (ROPs) significance determination process, the team determined this violation was associated with a minor performance deficiency. The ROPs significance determination process does not specifically consider the regulatory process impact in its assessment of licensee performance. Therefore, it is necessary to also address this violation which impedes the NRCs ability to regulate using traditional enforcement to adequately deter non- compliance. Assessing the performance deficiency in accordance with the NRC Enforcement Policy, the team determined it to be a Severity Level IV violation because the lack of up- to-date information in the final safety analysis report has not resulted in any unacceptable change to the facility or procedures. This finding did not have an assigned cross-cutting aspect because cross-cutting aspects are not assigned to traditional enforcement violations |
| 05000416/FIN-2017007-03 | 2017Q4 | Grand Gulf | Failure to Establish a Preventive Maintenance Procedure for Safety -Related Equipment | The team identified a Green, non -cited violation of Technical Specification (TS) 5.4.1, which states , in part , Written procedures shall be established, implemented, and maintained covering the following activities , referenced in Regulatory Guide (RG) 1.33, Revision 2, dated February 1978, Appendix A.9 , Procedures for Performing Maintenance, which requires that maintenance that can affect the performance of safety -related equipment should be properly pre- planned and performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstance. Specifically, prior to September 29, 2017, the licensee did not have a procedure to implement maintenance as recommended by the vendor in Vendor Document VM460000161, ELMA Cast Coil Power Transformers Installation, Maintenance, Operating, and Storage Instructions. In response to this issue, the licensee performed testing to ensure that the transformer will perform its design function and is developing an improved maintenance procedure. The finding was entered into the corrective action program as Condition Report CR- GGN -2017- 09390. The team determined that the failure to implement vendor recommended preventive maintenance is a performance deficiency. The finding was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to have procedures that implement vendor recommended maintenance resulted in a question regarding the functionality of the transformer at elevated temperature. In accordance with Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At -Power, dated July 19, 2012, the finding screened as having very low safety significance (Green) because it was a design or qualification deficiency that did not represent a loss of operability or functionality; did not represent an actual loss of safety function of the system or train; did not result in the loss of one or more trains of non- technical specification equipment; and did not screen as potentially risk -significant due to seismic, flooding, or severe weather. This finding had a cross -cutting aspect in the area of human performance associated with conservative bias because the licensee failed to ensure that maintenance implement a process of planning, controlling, and executing work activities such that nuclear safety is the overriding priority (H.5). |
| 05000416/FIN-2017007-02 | 2017Q4 | Grand Gulf | Failure to Correct Standby Diesel Generator Trip | The team identified a Green, self -revealed, non -cited violation of 10 CFR 50 Appendix B, Criterion XVI, Corrective Actions, which states, in part, Conditions adverse to quality are promptly identified and corrected. On June 22, 2016, the station identified a condition adverse to quality affecting the standby diesel generators, but did not promptly correct the issue until September 22, 2017. Specifically, the actions described in Standing Order 17 -0011 were not appropriate for restoring full capability during a design basis tornado event, which could affect the capability of the Division I and II standby diesel generators. In response to this issue the licensee revised the standing order to have the operator press the diesel generator manual start button while the diesel is running to eliminate the associated non- safety trips. The finding was entered into the corrective action program as Condition Report CR -GGN -2017 -09751. The team determined that the failure to promptly correct a condition adverse to quality, regarding diesel generator capability during a design basis tornado is a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it was associated with the design control attribute of the Mitigating Systems Cornerstone. Specifically, the failure to correct an identified condition adverse to quality resulted in a prolonged design challenge to the Division I and II standby diesel generator capability, which adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. In accordance with Inspection Manual Chapter 0609, Appendix A, Exhibit 2, dated June 19, 2012, the team determined that the finding required a detailed risk evaluation, per Exhibit 4 screening question number 1, for external event mitigation systems. According to the tornado analysis database prepared by the Office of Reactor Research, the frequency of an F -2 tornado or stronger at Grand Gulf Nuclear Station (GGNS) is 4.71E -4/year. The design basis tornado at GGNS has a maximum wind velocity of 360 mph which correlates to a strong F- 5 tornado. The design basis tornado generates a differential pressure of 3 psi. The pressure of concern is the 1.5 psi that could affect operation of the Division I and II diesel generators. Given that pressure is proportional to the square of the velocity, the wind speed affecting the diesel generators would be approximately 250 mph. 250 mph is in the range of an F- 4 tornado. Using generic distributions of the frequency of varying tornado strengths, the analyst estimated that the frequency of an F- 4 tornado or stronger at GGNS is 3.93E -6/year. Using the site- specific SPAR model, the analyst quantified the conditional core damage probability for a tornado- induced loss of offsite power with the failure of both Division I and II diesel generators. The conditional core damage probability was 6.35E -2. Therefore, the incremental conditional core damage probability of the performance deficiency, using the bounding assumption that all F -4 or stronger tornados striking the site would fail both diesel generators, was 2.50E -7. Qualitatively, given this bounding assumption, and the potential to recover the diesels after failure, the analyst determined that the CDF was less than 1E -7. This results in a finding of very low safety significance (Green). This finding had a cross -cutting aspect in the area of human performance associated with procedure adherence because the licensee failed to follow the operability evaluation process to properly determine operability (H.8). |
| 05000528/FIN-2017002-02 | 2017Q2 | Palo Verde | Licensee-Identified Violation | Title 10 CFR 50.55a(g)(4), Inservice Inspection Standards Requirement for Operating Plants, states, in part, Throughout the service life of a pressurized water-cooled nuclear power facility, components that are classified as ASME Code Class 1, Class 2, and Class 3 must meet the requirements set forth in Section XI of the ASME Code. The ASME Code, Section XI, Article IWA-2610, requires that a reference system be established for all welds and areas subject to a surface or volumetric examination. This includes identifying each weld that is subject to ASME Section XI requirements.Contrary to the above, prior to April 12, 2017, the licensee failed to establish a reference system for all welds and areas subject to a surface or volumetric examination. Specifically, five welds located in an ASME Code, Section XI, Class 2, train A and train B refuel water suction lines were not identified as applicable ASME Section XI welds. The licensee restored compliance by correctly reclassifying the subject welds and entering them in the ASME Section XI program. The finding was of very low safety significance(Green) because the finding did not represent an actual loss of safety function of a system or train and did not result in the loss of a single train for greater than technical specification allowed outage time. This issue was entered into the licensees corrective action program as Condition Report 17-05607. |
| 05000528/FIN-2017002-01 | 2017Q2 | Palo Verde | Inoperable Containment Isolation Valve Due toNot Operating Valve in Accordance with Station Procedures | The inspectors reviewed a Green self-revealing non-cited violation of Technical Specification 3.6.3 Condition C for exceeding the allowed outage time of 4 hours to isolate the flow path of an inoperable containment isolation valve. Specifically, Unit 1 containment isolation valve SG-1134 was inoperable from June 28, 2016, to September 21, 2016, due to improper restoration from planned maintenance. The licensee entered this condition in their corrective action program and performed a Level 2 cause analysis under Condition Report 16-14896. The licensee also undertook immediate actions to restore the valve from the neutral position and remotely stroke the valve per procedure.The inspectors concluded the failure to restore Unit 1 containment isolation valve SG-1134 from maintenance in accordance with station procedures was a performance deficiency. The performance deficiency was more-than-minor and a finding because it is associated with the configuration control attribute of maintaining functionality of containment under the Barrier Integrity cornerstone which affects the cornerstone objective to provide reasonable assurance that physical design barriers will protect the public from radionuclide releases caused by accidents or events. Specifically, the inoperability of this containment isolation valve allowed the potential of a radioactive release during a design basis accident. The inspectors performed the initial significance determination using NRC Inspection Manual Chapter 0609, Appendix H, Containment Integrity Significance Determination Process, Issue Date: 05/06/04. Section 4.1 determined this to be a Type B finding since the degraded condition did not affect the likelihood of core damage. Table 4.1 shows that containment isolation valves in lines connecting reactor coolant systems to environments with small lines would not contribute to large early release frequency. Since valve SG-1134 is a small (one-inch) valve, this finding screened to Green using the flow chart in Figure 4.1 LERF-based Significance Determination Process. This finding has a cross-cutting aspect in the area of human performance associated with the documentation component. Specifically, the licensee failed to provide a work package that was complete, thorough, accurate, and current in accordance with station procedure 40OP-09OP01, Operation of Air Operated Valves, when returning SG-1134 to its normal operating condition following maintenance. As a result, the valve handwheel was left out of neutral, thereby preventing remote operation (H.7). |
| 05000529/FIN-2016004-01 | 2016Q4 | Palo Verde | Inadequate monitoring of MSIV nitrogen pre-charge pressure | The inspectors reviewed a self-revealing non-cited violation of Technical Specification 3.7.2 for exceeding the Condition A completion time for an inoperable main steam isolation valve (MSIV) single actuator train and not immediately declaring the affected main steam isolation valve inoperable in accordance with Condition E. Specifically, the Unit 2 main steam isolation valve 171 actuator A was inoperable from July 30, 2016, to August 9, 2016, when a known nitrogen leak was not adequately monitored. The licensees inadequate monitoring allowed the nitrogen pre-charge pressure in the actuator to decrease to below the minimum acceptable limit for operability. The licensee restored the pre-charge pressure and entered this issue into their corrective action program as Condition Report 16-12740. The failure to perform adequate monitoring for a degraded condition as required by procedure 40DP-9OP26, Operations Condition Reporting Process and Operability Determination/Functional Assessment, was a performance deficiency. The performance deficiency was more-than-minor and therefore a finding because it affected the equipment performance attribute of the Mitigating Systems Cornerstone to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically the failure to adequately monitor a known nitrogen leak resulted in depressurizing one of two hydraulic accumulators thereby reducing the reliability of the system to initiate a fast closure of MSIV 171 upon receipt of a main steam isolation signal. The inspectors performed the initial significance determination using NRC Inspection Manual Chapter 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, Issue Date: June 9, 2012. The finding required a detailed risk evaluation since it represented a loss of function for a single train for greater than the Technical Specification allowed outage time. A Region IV senior reactor analyst determined the finding was of very low safety significance (Green) since the MSIV remained capable of performing its safety function with the alternate actuator. The finding has a cross-cutting aspect in the area of human performance associated with the teamwork component. Specifically, the licensee failed to coordinate activities across organizational boundaries in that the operations personnel did not obtain engineering input to ensure that additional monitoring requirements for the nitrogen pre-charge leak were adequate to verify continued MSIV 171 operability (H.4). |
| 05000416/FIN-2016004-01 | 2016Q4 | Grand Gulf | Failure to Incorporate Design Requirements for Switchgear Room Cooling | Green. The inspector identified a non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, involving the failure to implement appropriate design control measures associated with a safety-related service water flow calculation. Specifically, several unverified and potentially nonconservative inputs were identified associated with Calculation MC-QIP41-97020, Revision 11, Determination of Minimum Allowable SSW Flows (LOCA Lineup) to Safety Related Heat Exchangers, used to analyze minimum service water flow to the vital switchgear room coolers. The licensee entered this issue into their corrective action program as Condition Report CR-GGN-2016-07597, initiated action to update Calculation MC-QIP41-97020, and initiated actions to analyze the ability of vital switchgear room cooling to meet its specified safety function. This performance deficiency was more than minor, and therefore a finding, because it was associated with the design control attribute of the Mitigating Systems Cornerstone, and it adversely affected the cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensee did not assure that the vital switchgear ventilation system was capable of maintaining the rooms temperature below design requirements under all conditions. The NRC performed an initial screening of the finding in accordance with NRC Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power. Using Inspection Manual Chapter 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, dated July 1, 2012, this finding had very low safety significance (Green) because it: (1) was not a deficiency affecting the design or qualification of a mitigating system; (2) did not represent a loss of system and/or function; (3) did not represent an actual loss of function of a single train for greater than its technical specification allowed outage time; and (4) did not represent an actual loss of function of one or more nontechnical specification trains of equipment designated as high safety-significant in accordance with the licensees maintenance rule program for greater than 24 hours. This finding had a cross-cutting aspect in the documentation aspect of the human performance cross-cutting area because the licensee failed to maintain complete, accurate, and up-to-date documentation of the design temperature limits for safety-related equipment. Specifically, the licensee failed to document and evaluate a change to temperature limits related to switchgear cooling to ensure that its use as a design parameter was consistent with original design specifications of the equipment (H.7). |
| 05000416/FIN-2016004-02 | 2016Q4 | Grand Gulf | Failure to Use Procedures and Engineering Controls to Maintain Occupational Doses ALARA | Green. The inspectors identified a non-cited violation of 10 CFR 20.1101(b) for the licensees failure to implement radiation exposure reduction procedures and engineering controls to minimize unplanned and unintended radiation dose to workers and to maintain occupational doses as low as is reasonably achievable (ALARA). Several radiological work permits exceeded initial dose estimates with minimal or no actions taken to evaluate the basis for the dose overrides and to develop mitigating strategies. The primary contributor to the unplanned exposures was elevated dose rates from increased cobalt-60 activity associated with a failure to properly plan and execute spent fuel pool and reactor cavity cleanup operations. In addition, the licensee failed to observe radiological work permit hold points, to initiate ALARA Management Committee meetings, and to perform radiological assessments of radiological work permit dose estimates as procedurally required. As immediate corrective actions, the licensee reviewed the work activity, documented lessons learned, and generated Condition Reports CR-GGN-2016-03151 and CR-GGN-2016-08543 to address these programmatic weaknesses for future outages. The failure to implement procedures and engineering controls to minimize unplanned and unintended radiation dose and to maintain occupational doses as low as is reasonably achievable was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it was associated with the Occupational Radiation Safety Cornerstone attribute of program and process (ALARA planning) and adversely affected the cornerstone objective to ensure the adequate protection of worker health and safety from exposure to radiation from radioactive material during routine civilian nuclear reactor operation. Specifically, inadequate ALARA planning and radiological controls resulted in unplanned, unintended dose for a number of work activities in which the actual collective dose exceeded 5 person-rem and exceeded the planned, intended dose by more than 50 percent. Using Inspection Manual Chapter 0609, Appendix C, Occupational Radiation Safety Significance Determination Process, the inspectors determined this finding to be of very low safety significance (Green) because the finding involved ALARA planning and controls, and because the licensees latest 3-year rolling average did not exceed 240 person-rem per unit for boiling water reactors. The finding had a cross-cutting aspect in the area of problem identification and resolution, associated with operating experience, in that, the licensees organization failed to systematically and effectively collect, evaluate, and implement relevant internal and external operating experience in a timely manner. Specifically, the licensee failed to implement and incorporate relevant internal operating experience from Refueling Outage 18, which was of similar radiological circumstances, to mitigate the effects of cobalt-60 activity in the reactor cavity and unplanned spent fuel pool cleanup outages (P.5). |
| 05000482/FIN-2016002-06 | 2016Q2 | Wolf Creek | Licensee-Identified Violation | Technical Specification 3.6.3, Containment Isolation Valves, requires each containment isolation valve to be operable in modes 1, 2, 3, and 4. To be operable, containment isolation valves GTHZ0007 and GTHZ0009, which are Category 3 valves, must be closed with the motive force removed. Technical Specification 3.6.3, Condition A, Required Action A.1, requires, in part, that the affected penetration flow path for any inoperable Category 3 containment isolation valve be isolated within 12 hours. Additionally, Required Action A.2, requires, in part, that the licensee verify the affected penetration flow path is isolated prior to entering mode 4 from mode 5. Contrary to the above, from April 28, 2015, through May 5, 2015, the licensee failed to verify the affected penetration flow path was isolated prior to entering mode 4 from mode 5 on April 28, 2015. As a result, Technical specification 3.6.3, Condition A, was not met On May 5, 2015, the licensee discovered that the motive force for valves GTHZ0007 and GTHZ0009 was not removed and the air supply valves had not been locked closed, and the affected penetration flow paths were not isolated prior to entering mode 4 from mode 5 on April 28, 2015. The inspectors noted that although the motive force was not removed for valves GTHZ0007 and GTHZ0009, the valves were in their closed safeguards positions and redundant valves in series were closed with the motive force removed, which ensured each penetration flow path had one operable valve closed with its motive force removed. Using Exhibit 3, Barrier Integrity Screening Questions, of Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process for Finding At-Power, dated June 19, 2012, the inspectors determined 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), or heat removal components, and the finding did not involve an actual reduction in function of hydrogen igniters in the reactor containment. Therefore, the inspectors determined that this finding is of very low safety significance (Green). |
| 05000482/FIN-2016002-05 | 2016Q2 | Wolf Creek | Licensee-Identified Violation | Technical Specification 3.4.15, (Reactor Coolant System) Leakage Detection Instrumentation, states, in part, that reactor coolant system leakage detection instrumentation shall be operable, including the containment sump level and flow monitoring system. Required Action A of Technical Specification 3.4.15, states, in part, that with the required containment sump level and flow monitoring system inoperable, restore the required containment sump level and flow monitoring system to operable status within 30 daysif the required action and associated completion time are not met, Condition E requires the reactor to be in mode 3 within 6 hours and in mode 5 within 36 hours. Contrary to the above, from the period of July 13, 2013, to November 20, 2013, with the containment sump level and flow monitoring system inoperable for greater than 30 days, the reactor was not placed in mode 3 within 6 hours or mode 5 within 36 hours. Specifically, the instrument tunnel sump level indication was inoperable because of erratic indication, but the licensee did not take the required action of Technical Specification 3.4.15. The licensee placed this issue in the corrective action program as Condition Report 84690. Using Manual Chapter 0609, Appendix A, Significance Determination Process, for Findings at Power, dated June 19, 2012, this issue screened to Green because it did not result in reactor coolant system leakage or degrade the licensees ability to detect and mitigate a small break loss of coolant accident. |
| 05000482/FIN-2016002-04 | 2016Q2 | Wolf Creek | Licensee-Identified Violation | Technical Specification 3.4.3, (Reactor Coolant System) Pressure and Temperature Limits, states, in part, that reactor coolant system pressure, reactor coolant system temperature, and reactor coolant system heatup and cooldown rates shall be maintained within the limits specified in the Pressure and Temperature Limits Report (PTLR). Section 2.1.2 of the PTLR specifies that the reactor coolant system shall be maintained within the parameters of Figure 2.1-1 of the PTLR, which specifies a minimum pressure of 0 psig. Required Action C.1 of Technical Specification 3.4.3 specifies that with the reactor coolant system parameters outside the limits of the PTLR, restore the parameters to within the limits immediately. Contrary to the above, on May 8, 2011, and March 30, 2013, with the reactor coolant system parameters outside the limits of the PTLR, parameters were not restored to within the limits immediately. Specifically, the licensee drew a vacuum on the reactor coolant system to less than 0 psig to support filling operations but did not take action to immediately restore the reactor coolant system pressure to greater than or equal to 0 psig, as specified in the PTLR. The licensee placed this issue in the corrective action program as Condition Report 78920. The licensee performed Engineering Evaluation EER 92-BB-02 and determined that drawing a vacuum on the reactor coolant system would not result in excessive stresses for reactor coolant system structures, systems and components. Using Manual Chapter 0609, Appendix G, Shutdown Operations Significance Determination Process, dated May 9, 2014, this issue screened to Green because it did not result in a loss of reactor coolant system barrier integrity. |
| 05000482/FIN-2016002-03 | 2016Q2 | Wolf Creek | Licensee-Identified Violation | Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality shall be accomplished in accordance with documented instructions, procedures, or drawings of a type appropriate to the circumstances. Licensee Procedure AP 26C-004, Operability Determination and Functionality Assessment, Revision 32, an Appendix B quality related procedure, provides instructions for determining whether equipment is operable when oil leakage is identified. Procedure AP 26C-004, Step 6.2.1.1, states in part, that if operability of a system/component is being questioned due to system leakage that the leak rate has been quantified and total identified leakage for the affected system has been determined and compared to the limits of Attachment F, Allowable Oil Leakage for Successful Mission. Contrary to the above, from May 28, 2016, until May 31, 2016, operability of a system/component was being questioned due to system leakage and the leak rate had not been quantified and the total identified leakage for the affected system was not determined and compared to the limits of Attachment F, Allowable Oil Leakage for Successful Mission. Specifically, operability of the B component cooling water pump was questioned due to system leakage as documented in Condition Report 104910, and the leak rate had not been quantified and the total identified leakage for the affected system was not determined, which resulted in the immediate operability determination being incorrect and the immediate operability determination requiring revision. Immediate corrective actions included revising the immediate operability determination for the B component cooling water pump from operable to inoperable, generating a required reading for senior reactor operators, and documenting Condition Report 104959. Using Exhibit 2, Mitigating Systems Screening Questions, of Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process for Finding At-Power, dated June 19, 2012, the inspectors determined this finding was not a deficiency affecting the design or qualification of a mitigating SSC that maintained its operability or functionality, the finding did not represent a loss of system and/or function, the finding did not represent an actual loss of function of at least a single train for greater than it Technical Specification allowed outage time, and the finding did not represent an actual loss of function of one or more non-Technical Specification trains of equipment designated as high safety-significant. Therefore, the inspectors determined the finding was of very low safety significance (Green). |
| 05000482/FIN-2016002-02 | 2016Q2 | Wolf Creek | Licensee-Identified Violation | Technical Specification 5.7.2 states, in part, that high radiation areas with dose rates greater than 1.0 rem per hour at 30 centimeters shall be conspicuously posted as a high radiation area and shall be provided with a locked or continuously guarded door or gate to prevent unauthorized entry. Contrary to the above, on January 27, 2016, room 7406 on the 2013 foot elevation of the radwaste building areas had dose rates greater than 1.0 rem per hour and was not conspicuously posted as a high radiation area nor provided with a locked or continuously guarded door or gate to prevent unauthorized entry. This issue was identified by radiation protection technicians performing radiological surveys in the area. The licensee documented this issue in the corrective action program as Condition Report 102344. The finding was determined to be of very low safety significance (Green) because it was not an as-low-as-reasonably-achievable planning issue, there was no overexposure or potential for overexposure, and the licensees ability to assess dose was not compromised. |
| 05000482/FIN-2016002-01 | 2016Q2 | Wolf Creek | Failure to Adequately Establish Control Room Air Conditioning System Testing Flow Rate Acceptance Criteria | The inspectors identified a Green non-cited violation of Technical Specification Limiting Condition for Operation 3.7.11 and 3.0.3 for the licensees failure to place the unit in mode 3 within 7 hours, mode 4 within 13 hours, and mode 5 within 37 hours with two trains (SGK04A and SGK04B) of the control room air conditioning system (CRACS) inoperable. Specifically, the licensee failed to adequately establish CRACS testing flow rate acceptance criteria, which resulted in train A of the safety-related CRACS being inoperable from October 11, 2005, to August 13, 2013; and train B being inoperable from October 3, 2002, to July 18, 2013. The licensees immediate corrective actions included corrective maintenance on the CRACS to increase the airflow to meet acceptance criteria limits. Condition Report 105208 was initiated by the licensee for any necessary process changes and extent of condition actions. This finding is more than minor because it is associated with the equipment performance attribute of the Mitigating Systems Cornerstone, and affected the associated cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). The inspectors utilized Inspection Manual Chapter 0609.04, Initial Characterization of Findings, and Exhibit 2 of Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, and determined this finding was not a deficiency affecting the design or qualification of a mitigating SSC that maintained its operability or functionality, the finding did not represent a loss of system and/or function, the finding did not represent an actual loss of function of at least a single train for greater than its Technical Specification allowed outage time, and the finding did not represent an actual loss of function of one or more non-Technical Specification trains of equipment designated as high safety-significant. Therefore, the inspectors determined the finding was of very low safety significance (Green). The finding has a cross-cutting aspect in the area of human performance, change management, because leaders did not use a systematic process for evaluating and implementing change so that nuclear safety remains the overriding priority. Specifically, there is not currently a formal process for procedure writers to consider measurement uncertainty when establishing and changing testing acceptance criteria, which resulted in extended inoperability of both the SGK04A and SGK04B units following significant changes to Technical Specifications that included adding surveillance requirements for the SGK04A and SGK04B units in 1999. This issue is indicative of current performance because the same issue would be expected to occur today (H.3). |
| 05000482/FIN-2016007-02 | 2016Q2 | Wolf Creek | Failure to Verify the Adequacy of Design of the Control Circuitry of the Fuel Oil Transfer Pumps | The team identified a Green, non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, which states, in part, The design control measures shall provide for verifying or checking the adequacy of design, such as by the use of alternate or simplified calculational methods, or by the performance of a suitable testing program. Specifically, prior to April 28, 2016, the licensee failed to verify the adequacy of the design of the fuel oil transfer pump control circuitry to ensure that the thermal overloads associated with the fuel oil transfer pump would not activate, trip the pump, and render the emergency diesel generator inoperable in the case of excessive cycling. In response to this issue, the licensee conducted a preliminary evaluation of the fuel oil transfer pump and confirmed there is not any significant active leakage on the day tank which would lead to excessive cycling, and that starting currents are sufficiently below the thermal overload trip settings and are unlikely to trip the pump. Additionally, the licensee planned to initiate a program to determine fuel oil leakage from the day tank and require operators to initiate interim corrective actions until final corrective actions can be determined. This finding was entered into the licensee's corrective action program as Condition Report 104066. The team determined the failure to evaluate the effects of cyclical fuel oil transfer pump operation was a performance deficiency. The performance deficiency was more-than-minor, and therefore a finding, because it related to the design control attribute of the Mitigating Systems cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the design of the fuel oil transfer pump control circuity does not prevent activation of the pump thermal overloads that would trip the pump and render the emergency diesel generator inoperable in the event of cyclical operation of the fuel oil transfer pump. In accordance with Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated July 19, 2012, the finding screened as having very low safety significance (Green) because it was a design or qualification deficiency that did not represent a loss of operability or functionality; did not represent an actual loss of safety function of the system or train; did not result in the loss of one or more trains of non-technical specification equipment; and did not screen as potentially risk-significant due to seismic, flooding, or severe weather. This finding did not have a cross-cutting aspect because the most significant contributor did not reflect current licensee performance. |
| 05000482/FIN-2016007-01 | 2016Q2 | Wolf Creek | Inadequate Degraded Voltage Analyses of Class 1E Systems | The team identified a Green, non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, which states, in part, The design control measures shall provide for verifying or checking the adequacy of design, such as by the use of alternate or simplified calculational methods, or by the performance of a suitable testing program. Specifically, prior to April 28, 2016, the licensee failed to verify the adequacy of the design of the Class 1E electrical equipment, because it failed to perform adequate analyses demonstrating 1) that the degraded voltage relay setpoints specified in technical specifications would ensure adequate voltage to safety-related equipment, 2) adequate voltage would be available to the safety-related loads during transient voltage conditions caused by load sequencing, and 3) that the degraded voltage relay-associated time delays provide timely separation from offsite power and transfer to the emergency diesel generator to ensure that the Class 1E safety-related loads can achieve their safety function without protective device tripping. In response to these issues, the licensee performed preliminary analyses to demonstrate that the Class 1E electrical equipment would function at degraded voltages and was operable. This finding was entered into the corrective action program as Condition Reports 47791, 104253, 104098, 104389, and 104390. The team determined the licensees failure to ensure the adequacy of the design of the Class 1E electrical equipment was a performance deficiency. The performance deficiency was more-than-minor, and therefore a finding, because it related to the design control attribute of the Mitigating Systems cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensees electrical analyses failed to verify degraded voltage relay setpoints specified in technical specifications would ensure adequate voltage to safety-related equipment, that adequate voltage would be available to the safety-related loads during transient voltage conditions caused by load sequencing, and that degraded voltage relay time delays would provide timely separation from offsite power and transfer to the emergency diesel generator to ensure that the Class 1E safety-related loads can achieve their safety function without protective device tripping. In accordance with Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated July 19, 2012, the finding screened as having very low safety significance (Green) because it was a design or qualification deficiency that did not to result in loss of operability or functionality; did not represent an actual loss of safety function of the system or train; did not result in the loss of one or more trains of non-technical specification equipment; and did not screen as potentially risk-significant due to seismic, flooding, or severe weather. This finding did not have a cross-cutting aspect because the most significant contributor did not reflect current licensee performance. |
| 05000482/FIN-2016007-04 | 2016Q2 | Wolf Creek | Failure to Promptly Correct Deficiencies With Operator Time Critical Actions | The team identified a Green, non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, which states, in part, Measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and nonconformances are promptly identified and corrected. Specifically, prior to April 28, 2016, the licensee failed to correct deficiencies identified in 2012 for operator time critical actions associated with control room habitability; in 2013 after revising training materials for control room habitability time critical actions; in a 2014 condition report documenting the failure to validate scenarios in the time critical action program; and again in a 2015 self-assessment of the time critical action program. During the inspection, five out of six operators in a test crew failed to complete the control room habitability scenario within the required two minutes. In response to this finding, the licensee performed just-in-time training to remediate the crews and ensure time critical actions can be met. After re-training, each crew successfully performed the control room habitability time critical action within the two-minute requirement. This finding was entered into the licensee's corrective action program as Condition Reports 103910, 103915, and 103658. The team determined the failure to correct the deficiencies with the control room habitability time critical action was a performance deficiency. The performance deficiency was morethan- minor, and therefore a finding, because it related to the human performance attribute of the Mitigating Systems cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, operators failed to meet the time critical action for the control room habitability scenario within the required two minutes. In accordance with Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated July 19, 2012, the finding screened as having very low safety significance (Green) because it was a design or qualification deficiency that did not represent a loss of operability or functionality; did not represent an actual loss of safety function of the system or train; did not result in the loss of one or more trains of non-technical specification equipment; and did not screen as potentially risk-significant due to seismic, flooding, or severe weather. This finding had a cross-cutting aspect in the area of human performance associated with training because the licensee failed to provide training and ensure knowledge transfer to maintain a knowledgeable, technically competent workforce and instill nuclear safety values (H.9). |
| 05000482/FIN-2016007-03 | 2016Q2 | Wolf Creek | Inadequate Analysis of Essential Service Water Piping | The team identified a Green, non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, which states, in part, The design control measures shall provide for verifying or checking the adequacy of design, such as by the use of alternate or simplified calculational methods, or by the performance of a suitable testing program. Specifically, prior to April 28, 2016, the licensee failed to verify the design of the essential service water piping because the analyses assumed that the essential service water piping upstream of the containment air coolers was full of water after a loss of offsite power. However, the essential service water pump check valve was never tested to ensure water would not drain from the essential service water piping. In response to this issue, the licensee conducted a preliminary evaluation using data from the last surveillance test and inspection of the check valve, and concluded that the worst-case expected leakage through the check valve was not large enough to cause a water hammer event in the piping that exceeded operability criteria. This finding was entered into the licensee's corrective action program as Condition Reports 104222 and 104184. The team determined that the failure to verify the adequacy of the design of the essential service water piping was a performance deficiency. The performance deficiency was morethan- minor, and therefore a finding, because it related to the design control attribute of the Mitigating Systems cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to account for check valve leakage in the essential service water system led to a non-conservative assumption that the piping upstream of the containment air coolers would not drain after a loss of offsite power, which contributes to water hammer events that could challenge the integrity of the piping. In accordance with Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated July 19, 2012, the finding screened as having very low safety significance (Green) because it was a design or qualification deficiency that did not represent a loss of operability or functionality; did not represent an actual loss of safety function of the system or train; did not result in the loss of one or more trains of non-technical specification equipment; and did not screen as potentially risk-significant due to seismic, flooding, or severe weather. This finding was assigned a cross cutting aspect in the area of problem identification and resolution, specifically operating experience, because the water hammer issue was previously documented in several NRC inspection reports, the licensee made recent modifications to the system, and a companion check valve in the normal service water system was installed and correctly categorized in the inservice testing basis document. The operating experience cross-cutting aspect requires that the licensee systematically and effectively collects, evaluates, and implements relevant internal and external operating experience in a timely manner (P.5). |
| 05000483/FIN-2016001-01 | 2016Q1 | Callaway | Possible Incorrect Screening of the Spent Fuel Pool Decay Heat Removal Key Safety Function | The inspectors identified an unresolved item associated with the National Fire Protection Association (NFPA) Standard 805, Performance-Based Standard for Fire Protection for Light-Water Reactor Electric Generating Plants, non-power operations assessment. Specifically, the inspectors developed an issue of concern in that the licensee screened the potential loss of spent fuel pool cooling from further consideration for any fire event based on adequate procedural guidance and time when the procedures would not maintain the fuel in a safe and stable condition. On January 13, 2014, the licensee transitioned their fire protection program to a risk-informed, performance-based program based on NFPA Standard 805, Performance-Based Standard for Fire Protection for Light Water Reactor Electric Generating Plants. Paragraph 1.3.1 of NFPA Standard 805 requires licensees to provide reasonable assurance that a fire during any operational mode and plant configuration will not prevent the plant from achieving and maintaining the fuel in a safe and stable condition. Paragraph 1.5.1 of NFPA Standard 805 lists five nuclear safety performance criteria. These criteria provide requirements to demonstrate that fire protection features are capable of providing reasonable assurance that the plant is not placed in an unrecoverable condition in the event of a fire. For the decay heat removal nuclear safety performance criterion, the standard requires that decay heat removal shall be capable of removing sufficient heat from the reactor core or spent fuel such that fuel is maintained in a safe and stable condition. Paragraph 1.6.56 of NFPA Standard 805 defines safe and stable conditions: For fuel in the reactor vessel, head on and tensioned, safe and stable conditions are defined as the ability to maintain Keff <0.99, with a reactor coolant temperature at or below the requirements for hot shutdown for a boiling water reactor and hot standby for a pressurized water reactor. For all other configurations, safe and stable conditions are defined as maintaining Keff <0.99 and fuel coolant temperature below boiling. The licensee described how they satisfied the nuclear safety performance criteria in Calculation KC-26, Nuclear Safety Capability Assessment, Revision 1. The Nuclear Safety Capability Assessment applied to both power and non-power operations. For non-power operations, the licensee evaluated the spent fuel pool decay heat removal key safety function and determined that the spent fuel pool decay heat removal key safety function did not require a detailed review since adequate time was available, and procedural guidance was provided, for operators to respond to and mitigate a loss of spent fuel pool decay heat removal, even under full hot core offload conditions. The licensee stated that the shortest time to boil, under worst case conditions for a normal plant shutdown, was two hours. In addition, the licensee stated that all of the analyses to address a loss of spent fuel pool decay heat removal utilized a success criterion of no boiling. The licensee implemented the process outlined in Frequently Asked Question (FAQ) 07-0040, Non-Power Operations Clarifications, Revision 4, for the non-power operations assessment. This FAQ stated that licensees should conservatively assume the entire contents of a fire area are lost and document the loss of success paths. This FAQ also stated that licensees should specifically identify those areas (pinch points) that cause the loss of all success paths for a key safety function. The inspectors noted that the licensee did not perform these actions for the spent fuel pool decay heat removal key safety function because this key safety function was screened out from further consideration. If the licensee had evaluated the spent fuel pool decay heat removal key safety function using the process outlined in this FAQ, then the licensee would have assumed that both trains of spent fuel pool cooling are lost during a fire in the fuel handling building because both trains are located within the same fire area and were unprotected. This FAQ also stated that fire modeling may be used to determine if postulated fires in a fire area are expected to damage equipment (and cabling), thereby eliminating a pinch point. However, the licensee stated that no fire modeling was used to eliminate the identification of pinch point fire areas as part of the non-power operations assessment performed using the process in FAQ 07-0040. In the event that a fire in the fuel handling building disabled both trains of spent fuel pool cooling, operators were expected to enter Procedure OTO-EC-00002, Spent Fuel Pool High Temperature, Revision 9, due to the increasing temperature of the spent fuel pool. This procedure provided directions for operators to restore one or both trains of spent fuel pool cooling. Since both trains of spent fuel pool cooling were assumed lost due to the fire, the operators would be unable to restore spent fuel pool cooling using this procedure. After a period of time, the spent fuel pool would begin boiling and the level would begin lowering. At this time, operators were expected to enter Procedure OTO-EC-00001, Loss of SPF/Refuel Pool Level, Revision 13. Procedure OTO-EC-00001 directed the operators to open two normally locked essential service water valves to restore and maintain spent fuel pool level. The licensees procedures allowed the spent fuel pool to reach boiling conditions prior to restoring and maintaining level. Since NFPA Standard 805 defined safe and stable conditions, in part, as fuel coolant temperature below boiling, the procedures did not maintain the fuel in a safe and stable condition. The inspectors identified an issue of concern in that the licensee screened the potential loss of spent fuel pool cooling from further consideration for any fire event based on adequate procedural guidance and time when the procedures would not maintain the fuel in a safe and stable condition. The inspectors determined that additional information is required to determine if a performance deficiency exists. Specifically, the inspectors need to determine if this scenario should have been addressed as part of the current FAQ 07-0040 guidance, or if new guidance is needed to address this type of scenario where the full core has been offloaded to the spent fuel pool. On March 31, 2016, additional guidance was requested from the Office of Nuclear Reactor Regulation via a request to review and update FAQ 07-0040. This memorandum is documented in ADAMS as Accession Number ML16091A152. The licensee entered this issue of concern into the corrective action program as Callaway Action Request 201600726. This issue of concern is being treated as Unresolved Item 05000483/2016001-01, Possible Incorrect Screening of the Spent Fuel Pool Decay Heat Removal Key Safety Function. |
| 05000298/FIN-2016001-02 | 2016Q1 | Cooper | Failure to Assess Operability of Technical Specification System Functions during Surveillance Testing | The inspectors identified a non-cited violation of Technical Specification 5.4.1.a, for the licensees failure to follow Station Procedure 0.26, Surveillance Program, and assess the operability of high pressure coolant injection steam line isolation instrumentation during surveillance testing. Specifically, the licensee failed to assess the operability of required isolation instrumentation when maintentance personnel opened terminal box 392 during surveillance testing and temporarily invalidated its environmental qualification. Licensee procedures required operations personnel to either establish compensatory measures to restore the terminal box during an event, or declare the instrumentation inoperable and enter the applicable technical specification actions when the terminal box was opened. As an immediate corrective action, the licensee implemented Standing Order 2016-03, which directed operators to establish compensatory measures, if applicable, or declare the affected equipment inoperable when environmentally qualified terminal boxes would be opened during testing. The licensee entered this issue into their corrective action program for resolution as Condition Reports CR-CNS-2016-00320 and CR-CNS-2016-00476. The licensees failure to assess the operability of high pressure coolant injection instrumentation when the associated terminal box was opened during surveillance testing, in violation of Station Procedure 0.26, was a performance deficiency. The performance deficiency was determined to be more than minor, and therefore a finding, because it was associated with the structure, system, component, and barrier performance attribute of the Barrier Integrity Cornerstone, and adversely affected the cornerstone objective to ensure the radiological barrier functionality of containment isolation. Specifically, with terminal box 392 open, its environmental qualification was temporarily invalidated, making the high pressure coolant injection low steam pressure and high steam flow containment isolation instrumentation inoperable during surveillance testing. In addition, two other terminal boxes and their associated surveillances were impacted by the performance deficiency. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, the inspectors determined that the finding had very low safety significance (Green) because it: (1) did not represent an actual open pathway in the physical integrity of reactor containment, containment isolation system, or heat removal components; and (2) did not involve an actual reduction in function of hydrogen igniters in the reactor containment. The finding had a cross-cutting aspect in the area of human performance associated with work management. Specifically, the licensee failed to implement a process of planning, controlling, and executing work activities such that nuclear safety was the overriding priority, including the identification and management of risk commensurate with opening terminal box 392 during surveillance testing (H.5). |
| 05000313/FIN-2016007-17 | 2016Q1 | Arkansas Nuclear | Determine Impact of Modifying Fire Seals for Flood Protection | The team identified an unresolved item related to ability to meet the requirements of License Condition 2.C.(8) and 2.C.(3)(b), Fire Protection Program, in Units 1 and 2, respectively. Specifically, the team identified ANO had modified numerous fire rated seals to also provide a flood protection barrier without ensuring existing fire protection requirements continued to be met. ANO Units 1 and 2 used a 3- hour fire rated silicon foam material to seal floor and walls penetrations in order to provide adequate separation to prevent the spread of fire between fire areas. ANO determined that numerous exiting fire seals were also required to provide flood protection. To provide an 3-hour fire barrier and also be capable of withstanding a design basis flood, ANO issued design changes to use several materials, such as Polywater FST Foam Sealant, Promatec Product 12 (P12), Sylgard, and Promatec High Density Silicone Elastomer (HDSE and HDSE-IR), to create dual purpose seals. The team determined that HDSE, HDSE-IR and Sylgard have been tested as a 3-hour fire barrier and tested satisfactorily to provide adequate flood protection. However, ANO could not produce documentation to show that fire rating testing or qualification testing had been performed for the new dual function seals using P12 and Polywater. This was documented in CR-ANO-C-2016-00490. ANO has determined that the population of the non-qualified seals was 139 (96 containing Polywater and 43 containing P12). ANO stated that all of the new dual function seals using P12 consist of the flood protective layer of P12 being placed on top of the existing originally qualified 10 inch fire silicone seal, and that no credit was given to the P12 layer to provide any additional fire protection capabilities. The P12 has been tested by Promatec with silicone seals for flood and was flood tested by the station for use with silicone foam seals. Therefore, ANO believes that no negative chemical reactions can be expected. ANO installed Polywater material either on top of the currently installed fire barrier seal, or in electric conduits that are not required to have a fire seal present. Polywater is designed to create an air and watertight barrier suitable for use in conduits. ANO did not remove any portion of the originally qualified silicon foam fire seals, therefore the flood protection layer of Polywater was applied on top of the existing qualified fire seal. As part of the approved Fire Protection Program, a periodic visual inspection of fire penetration seals is required by TRM 3.7.12.3 and TRM 3.7.5, for Units 1 and 2 respectively, such that 10 percent of the total fire seal population is inspected each year. These inspections are conducted per Unit 1 procedure OP 1405.016, U-1, Penetration Fire Barrier Visual Inspections, and Unit 2 procedure OP 2405.016, U-2, Penetration Fire Barrier Visual Inspections. The team reviewed the inspection procedures and interviewed the fire protection engineers. The team was concerned that for many of the new dual function seals, the original fire rated and qualified seal was no longer accessible for performance of required visual inspections. The team was concerned that because the silicone fire seals are no longer accessible for inspection, the intent of the required fire seal inspection to detect surface flaws or damage to indicate potential underlying damage has occurred to the qualified fire penetration system per the fire protection program could not be met. The team concluded that not having fire rating qualification testing for the existing configuration of some fire seals, and the inability to perform required periodic visual inspections for newly modified fire seals, was a performance deficiency that was reasonably within ANOs ability to foresee and prevent. Since ANO has not yet completed the evaluation or fire testing qualification of the modified seals, the team was unable to evaluate the overall impact of this condition or classify the performance deficiency. ANO intended to complete the evaluation of these issues and document the results in CR-ANO-C-2016-00490. Some of the actions being considered include performing required 3-hour fire testing in representative dual function configurations containing Polywater or P12; and doing a feasibility study for removal and replacement of these seals with fire and flood qualified materials. The team concluded that further review is necessary in order to properly evaluate and disposition the significance of this condition. Specifically, the NRC will need to review the following: ANOs evaluation, extent of condition, and disposition and/or testing results of the non-qualified dual function fire/flood seals; and the significance of the non-qualified population (139 seals containing Polywater or P12). This item is being treated as an unresolved item (URI) 05000313/2016007-17 and 05000368/2016007-17, Fire Seals Modified for Flood with Material not Qualified for Fire and Inability to Perform Required Periodic Visual Inspection. |
| 05000313/FIN-2016007-21 | 2016Q1 | Arkansas Nuclear | Licensee-Identified Violation | Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that instructions, procedures, or drawings include appropriate quantitative or qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished. Contrary to this requirement, ANO identified that in 2010, maintenance work orders installing safety-related circuit breakers in motor control centers D-15 and D-25 did not have appropriate quantitative or qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished. Specifically, Engineering Change 5832 was completed to replace seven safety-related existing and obsolete Gould circuit breakers inside safety-related motor control centers D-15 and D-25 with Siemens ED6 series molded case circuit breakers, using work orders 122821 and 122823. Subsequent review of these work orders confirmed that the installation instructions properly included specific torque values for the breaker mounting hardware, but the specified torque values were not recorded in the work orders, and the torqueing operations were not verified by quality control as required by procedures. ANO documented this issue in the CAP as CR-ANO-1-2015-02230. The team determined that this issue was of very low safety significance (Green) after reviewing IMC 0609, Attachment 0609.04, Appendix A, Exhibit 2 Mitigating Systems Screening Questions. Specifically, the team answered no to each of the questions in Exhibit 2. |
| 05000368/FIN-2016007-20 | 2016Q1 | Arkansas Nuclear | Licensee-Identified Violation | Title 10 CFR Part 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, Section (a)(4), requires, in part, that before performing maintenance activities, the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activities. Contrary to these requirements, on July 8, 2015, ANO identified that they failed to assess and manage the increase in risk that may result from the proposed maintenance activities. Specifically, ANO failed to assess and manage the risk associated with removing and cleaning the Unit 2 SW system pre-screens for maintenance. ANO documented this violation in the CAP as CR-ANO-2-2015-01865. Additionally, ANO added guidance to procedure COPD-024 to address this issue. The team determined that this issue was of very low safety significance (Green) after reviewing IMC 0609 Attachment 0609.04, and Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process, dated May 19, 2005. Specifically, the team determined the incremental core damage probability deficit was not greater than 1E-6. |
| 05000313/FIN-2016007-19 | 2016Q1 | Arkansas Nuclear | Licensee-Identified Violation | Title 10 CFR Part 50, Appendix B, Criterion XI, Test Control, requires, in part, that a test program shall be established to assure that all testing required to demonstrate that structures, systems, and components will perform satisfactorily in service is identified and performed in accordance with written test procedures which incorporate the requirements and acceptance limits contained in applicable design documents. Test results shall be documented and evaluated to assure that test requirements have been satisfied. Contrary to these requirements, from April 16, 2009, through January 31, 2015, ANO identified that a test program had not been established to assure that all testing required to demonstrate that structures, systems, and components will perform satisfactorily in service was identified and performed in accordance with written test procedures which incorporated the requirements and acceptance limits contained in applicable design documents. Specifically, the failure to monitor the flow rate through the Unit 1 SW to SFP makeup line, which is subject to biofouling, to demonstrate this line would perform satisfactorily in service to meet the design flow rate. The 18 month surveillance flow test was not sufficient to monitor, predict and take actions to correct for the loss of flow caused by biofouling, consequently, line blockage occurred that resulted in the loss of the capability to provide full design makeup flow rates. ANO documented this violation in the CAP as CR-ANO-1-2014-01628. The team determined that this issue was of very low safety significance (Green) after reviewing IMC 0609, Attachment 0609.04, and Appendix A, Exhibit 3 Barrier Integrity Screening Questions. Specifically, the team answered no to each of the SFP questions in Exhibit 3. |
| 05000313/FIN-2016007-18 | 2016Q1 | Arkansas Nuclear | Licensee-Identified Violation | Title 10 CFR Part 50, Appendix B, Criterion XVIII, Audits, requires, in part, that a comprehensive system of planned and periodic audits shall be carried out to verify compliance with all aspects of the QA program and to determine the effectiveness of the program. Quality Assurance Program Manual Section C.2.a.(2) requires biennial audits of site programs, including the ASME Code Section XI ISI Program. Contrary to these requirements, ANO identified that from 2011 through December 17, 2015, a periodic audit of the ASME Code Section XI ISI Program was not carried out to verify compliance with all aspects of the QA program and to determine the effectiveness of the program. ANO documented this violation in the CAP as CR-ANO-C-2015-05011. The team determined that this issue was of very low safety significance (Green) after reviewing IMC 0609, Attachment 0609.04, and Appendix A, Exhibit 1 Initiating Events Screening Questions. Specifically, the team answered no to each of the questions in Exhibit 1. |
| 05000313/FIN-2016007-14 | 2016Q1 | Arkansas Nuclear | Failure to Properly Implement the Corrective Action Program | The team identified a Green finding and an associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensees failure to follow corrective action program procedures. Specifically, the team identified that condition reports were not being promptly screened for operability by the control room as required by procedure EN-LI-102-ANO-RC, Corrective Action Program. The licensees corrective actions included ensuring that there was no direct impact on safety and performing an operability determination for the identified condition reports, revising station policy to require that all condition reports be routed to the control room for review, and documenting the issue in the corrective action program as condition reports CR-ANO-C-2016-00359, CR-ANO-C-2016-00400, and CR-ANO-C-2016-00558. The failure to properly evaluate condition reports for classification and operability determination was a performance deficiency. The performance deficiency was determined to be more than minor because, it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to properly evaluate condition reports in accordance with applicable procedures could result in conditions adverse to quality being left uncorrected or not being evaluated to ensure operability was maintained. The finding was evaluated using Inspection Manual Chapter 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, and Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2 Mitigating Systems Screening Questions, dated June 19, 2012. The team determined the finding was of very low safety significance (Green) because the finding was a deficiency affecting the design or qualification of a mitigating system, structure or component, but the system, structure or component maintained its operability. This finding had a human performance cross-cutting aspect of Change Management because the licensee failed to adequately implement changes, including the training of staff concerning those changes, so that nuclear safety remained an overriding priority. Specifically, the licensee failed to ensure that station personnel were able to identify the difference between an adverse and non-adverse condition following the change which added these criteria to procedure EN-LI-102-ANO-RC (H.3). |
| 05000313/FIN-2016007-06 | 2016Q1 | Arkansas Nuclear | Failure to Correct Degraded Unit 2 Train B Emergency Diesel Generator Heat Exchangers Service Water Flow and Degraded Unit 1 Containment Coatings | The team identified two examples of a Green finding and an associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, for the licensees failure to correct conditions adverse to quality. Specifically, the licensee failed to correct long term degraded service water flow to the Unit 2 safety-related train B emergency diesel generator heat exchangers since 2008, and degraded Unit 1 reactor containment building coatings since 2009. The licensees corrective actions included performing an operability determination and determining that the service water system and the Unit 1 containment sump were operable and documenting the issue in the corrective action program as condition reports CR-ANO-C-2016-00946, and CR-ANO-1-2015-00200. The failure to correct conditions adverse to quality associated with Unit 2 service water flow to the B emergency diesel generator heat exchangers and the Unit 1 reactor containment building coatings was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to correct long term degraded: 1) service water flow beyond the action limit in accordance with procedure EN-DC-159, Component and System Monitoring, to the B emergency diesel generator heat exchangers, which challenged the capability of emergency diesel generator response to design basis events; and 2) containment coatings which challenged the Unit 1 emergency core cooling system capacity. The finding was evaluated using Inspector Manual Chapter 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, and Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, dated June 19, 2012. The team determined the finding was of very low safety significance (Green) because the finding was a deficiency affecting the design or qualification of mitigating system, structure or component, but the system, structure or component maintained operability. This finding had a human performance cross-cutting aspect of Design Margins because the licensee failed to place special attention on maintaining margins in safety related equipment. Specifically the licensee has repeatedly: 1) throttled service water flow away from the safety-related shutdown cooling heat exchangers, reducing the shutdown cooling design margins to maintain minimally acceptable flow to the emergency diesel generator heat exchangers since 2008; and 2) reduced the available containment sump margin rather than correct containment coating deficiencies (H.6). |