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05000528/FIN-2018008-0530 September 2018 23:59:59Palo VerdeMinor ViolationFailure to control the issuance of documents, such as instructions, procedures, and drawings, including changes thereto, which prescribe all activities affecting quality as required by 10 CFR 50, Appendix B, Criterion VI. The team identified that the CAP procedure directed the use of the Cause Analysis Manual in performing some cause evaluations. This cause evaluation process is an activity affecting quality required by 10 CFR 50, Appendix B and the licensees Quality Assurance Program. The licensee failed to control the Cause Analysis Manual in accordance with the Palo Verde Nuclear Generating Station Operations Quality Assurance Program Description, Revision 0, Section 2.6, Document Control. The licensee documented this violation in Condition Report 18-13996. Screening: The performance deficiency is minor because if left uncorrected it would not have led to a more significant safety concern and it did not adversely affect any cornerstone objectives. Enforcement: This failure to comply with 10 CFR 50, Appendix B, Criterion VI constitutes a minor violation that is not subject to enforcement action in accordance with the NRCs Enforcement Policy.
05000313/FIN-2018003-0530 September 2018 23:59:59Arkansas NuclearFailure to Maintain Main Feedwater Pump B Discharge Pressure in Band Caused a Reactor TripThe inspectors reviewed a self-revealed, Green finding and associated non-cited violation of Arkansas Nuclear One, Unit 1, Technical Specifications 5.4.1.a, for the licensees failure to implement Procedure OP-1102.002, Plant Startup, Revision 106. Specifically, control room operators failed to maintain main feedwater pump discharge pressure in the required band to control flow to the steam generators during a plant startup. As a result, the only operating main feedwater pump tripped on high discharge pressure, causing an automatic reactor trip.
05000255/FIN-2018003-0130 September 2018 23:59:59PalisadesWire Not Landed on Safety Injection Initiation Relay CircuitThe inspectors identified a Green finding and an associated non-cited violation (NCV)of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensees failure to accomplish an activity affecting quality in accordance with the implementing procedure. Specifically, only one of two required wires was landed on terminal 13 of relay SIS2 in the right channel of the safety injection system (SIS) actuation logic following surveillance testing that was performed on May 8, 2017. As a result, the right channel of the safety injection system actuation logic was inoperable until the problem was discovered during troubleshooting and the wire was subsequently re-landed onMay 3, 2018
05000313/FIN-2018003-0630 September 2018 23:59:59Arkansas NuclearReactor Power Transient Caused by the Turbine Bypass Valve Failing OpenThe inspectors reviewed a self-revealed Green finding and associated non-cited violation of Arkansas Nuclear One, Unit 1, Technical Specifications 5.4.1.a, for the licensees failure to properly preplan maintenance that can affect the performance of safety-related equipment. Specifically, the licensee failed to properly pre-plan maintenance for the replacement of air supply tubing for turbine bypass valve CV-6687, which resulted in the failure of the air tubing, causing valve CV-6687 to fail open, which led to a manual reactor trip and a subsequent loss of the main condenser.
05000530/FIN-2018003-0130 September 2018 23:59:59Palo VerdeFailure to Maintain Command and Control During a Feedwater Control Valve MalfunctionWhile reviewing the licensee response to a Unit 3 feedwater pump trip, reactor cutback, reactor trip, and main steam isolation system actuation on June 27, 2018, the inspectors identified that the licensee did not meet the command and control standards outlined in station Procedure 40DP-9OP02 Conduct of Operations, Revision 72. Specifically, senior reactor operators in the control room did not effectively coordinate manual main feedwater output adjustments in the control room or operator actions in the field in response to an apparent valve failure with the activities of non-licensed operators locally evaluating the equipment condition in the field. These uncoordinated actions resulted in a significant plant transient
05000317/FIN-2018410-0130 September 2018 23:59:59Calvert CliffsSecurity
05000313/FIN-2018011-0230 September 2018 23:59:59Arkansas NuclearFailure 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.
05000528/FIN-2018008-0130 September 2018 23:59:59Palo VerdeInadequate Corrective Actions For Missing Control Room Hand-Switch Operator KnobThe team reviewed a Green, NRC identified, non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, for the licensees failure to promptly identify and correct the failures of multiple control room hand-switch operator knobs.
05000313/FIN-2018003-0230 September 2018 23:59:59Arkansas NuclearFailure to Implement Welding Standard Guidance and Examination ProceduresThe inspectors reviewed a self-revealed Green finding and associated non-cited violation of Arkansas Nuclear One, Unit 1, Technical Specification 5.4.1.a, for the licensees failure to properly preplan maintenance that can affect the performance of safety-related equipment. Specifically, the licensee failed to implement welding standard guidance and examination procedure guidance during the installation of the high pressure injection system drain line containing drain valves MU-1066A and MU-1066B. The drain line weld developed a crack that caused a leak shortly after plant startup that was determined to have been caused by grinding during the welding process, which was not permitted by the welding standard.
05000336/FIN-2018003-0130 September 2018 23:59:59MillstoneFailure to Assure that Safety-Related Service Water Piping Conformed to the Procurement DocumentsThe inspectors identified a Green finding and associated non-cited violation (NCV) of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion VII, Control of Purchased Material, Equipment, and Services, when the licensee failed to identify that a replacement service water pipe spool (JGD-1-25) was not in conformance with the American National Standards Institute (ANSI) B31.1 code, a condition of the purchase order, and was installed in the plant.
05000313/FIN-2018011-0330 September 2018 23:59:59Arkansas NuclearFailure 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.
05000528/FIN-2018008-0430 September 2018 23:59:59Palo VerdeMinor ViolationFailure to promptly identify and correct conditions adverse to quality as required by 10 CFR 50, Appendix B, Criterion XVI. The team identified a backlog of conditions adverse to quality that the licensee had failed to timely correct. The oldest of these conditions was approximately 10 years old, with several hundred having been identified at least two operating cycles prior to the inspection. The team determined that the licensee was appropriately addressing degraded components that had an impact on safety or security, but was not always tracking or timely correcting nonconformances with its design bases in cases where these nonconformances had been assessed as not impacting safety-related functions. Further, the licensee was unable to initially determine the scope of its nonconformance backlog. The licensee documented this deficiency as Condition Reports 18-13549 and 18-14426. Screening: The performance deficiency was minor because if left uncorrected it would not have led to a more significant safety concern and it did not adversely affect any cornerstone objectives. Enforcement: This failure to comply with 10 CFR 50, Appendix B, Criterion XVI constitutes a minor violation that is not subject to enforcement action in accordance with the NRCs Enforcement Policy.
05000389/FIN-2018003-0130 September 2018 23:59:59Saint LucieFailure to meet the Transient Combustible Requirements Specified by NFPA 805The inspectors identified a Green non-cited violation (NCV) of 10 CFR 50.48(c), National Fire Protection Standard NFPA 805, requirements. Specifically, the licensee failed to comply with transient combustible control requirements in high risk fire zones as required by NFPA 805 and implemented by licensee procedure ADM-19.03, Transient Combustible Control.
05000313/FIN-2018003-0330 September 2018 23:59:59Arkansas NuclearFailure to Provide Complete and Accurate Information in a License Amendment Request to Change Emergency Action Level RequirementsThe inspectors identified a Severity Level IV non-cited violation because the licensee provided inaccurate information to the NRC in a license amendment request for an emergency action level scheme change. Specifically, the licensee provided information about the availability of the postaccident sampling system building radiation monitor and the Unit 1 level instrumentation that was material to the licensing decision, but not accurate. The NRC approved an emergency action level scheme change on November 9, 2012 (ADAMS Accession No. ML12269A455) to allow Arkansas Nuclear One to adopt the Nuclear Energy Institute (NEI) 99-01, Revision 5, scheme. Subsequently, the licensee identified that two of their current emergency action level thresholds could not be implemented in accordance with their emergency classification procedure: On May 26, 2017, Condition Report CR-ANO-2-2017-03161 documented that postaccident sampling system building radiation monitor 2RX-9840 should be removed from all regulatory commitments because the postaccident sampling system had been removed from service, and its building would not be monitored for radiological releases. Radiation monitor 2RX-9840 was being used as a means to evaluate emergency action levels AU1, AA1, AS1, and AG1. In addition, it was used in the loss/potential loss of containment (CNB6) for fission product emergency action levels. The condition report noted that requirements for the postaccident sampling system had been removed from Arkansas Nuclear One licenses in August 2000 and the licensee had abandoned the systems valves (March 2003, EC-ANO-1779), removed power from the postaccident sampling system ventilation system (January 2004), and made radiation monitor 2RX-9840 nonfunctional (May 2008, Condition Report CR-ANO-2-2008-01439 and Work Order 150817). On March 15, 2018, Condition Report CR-ANO-C-2018-01121 documented that the Unit 1 level instrumentation set point used in emergency action level CA1 was below the indicating range of the instrument. The emergency action level indicated that a loss of Unit 1s reactor vessel inventory was shown by an indicated level less than 368 feet, 0 inches. Therefore, the lowest level indicated on the instrument would be higher than the level used in making the emergency classification decision. The inspectors reviewed the licensees license amendment request, dated December 1, 2011 (ADAMS Accession No. ML113350317), Proposed Emergency Action Levels Using NEI 99-01, Revision 5, Scheme, and the licensees response to a request for additional information dated July 9, 2012, (ADAMS Accession No. ML12192A090) to determine whether the conditions identified in the corrective action program existed at the time the licensee requested the license amendment and whether the request correctly described the instruments. The inspectors identified: The December 1, 2011, submittal incorrectly indicated that radiation monitor 2RX-9840 was a viable means of classifying emergency action levels AU1, AA1, AS1, and AG1, as well as providing input for the evaluation of fission product barrier emergency action levels. In the response to NRCs request for additional information (RAI) dated July 9, 2012, the licensee provided additional details about the super particulate iodine noble gas (SPING) radiation monitors used in this application. Response to Question 3 associated with emergency action levels AA1, AS1, and AG1 stated: Each SPING is associated with a particular ventilation pathway and provides continuous monitoring of air discharged via the respective release pathway. The license reviewer concluded that all of the SPING monitors included in the license amendment request were operable and continuously monitoring the specified release pathways, thereby being capable of measuring the radiation levels described in the proposed emergency action levels. 17 The December 1, 2011, submittal indicated that loss of Unit 1 reactor vessel inventory for emergency action level CA1 was a vessel level less than 368 feet, 0 inches. This issue was NRC-identified because when the licensee identified the emergency action level errors, they took action to correct the errors, but failed to address the failure to ensure that technical information provided to the NRC in support of the license amendment request was complete and accurate in all material respects. Corrective Actions: To correct the Unit 1 reactor vessel level emergency action level threshold error, the licensee issued communications regarding correct application of the emergency action level on March 15, 2018, followed by implementation of a change to Procedure OP-1903.010, Emergency Action Level Classification, Revision 56, dated June 26, 2018, with the corrected level. The use of radiation monitor 2RX-9840 is being removed from the emergency action levels as part of an emergency action level scheme change submitted to the NRC on March 29, 2018 (ADAMS Accession No. ML18088B412 and ML18094A155). In the interim, the licensee issued communications to emergency director-qualified staff members to ensure they are aware of the error, how to address it if implementing emergency action levels, and to inform them of the corrective actions in progress. Additionally, the licensee issued Condition Report CR-ANO-C-2018-03597, dated September 13, 2018, for the incomplete and inaccurate emergency action level submission examples to address the completeness and accuracy issues identified by the inspectors.
05000336/FIN-2018010-0130 June 2018 23:59:59MillstoneOver-Duty Breakers on Safety-Related Buses on Unit 2The team identified a finding of very low safety significance (Green) and an associated non-cited violation (NCV) of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion III, Design Control. Specifically, Dominion incorrectly concluded that the 480V safety-related breakers were conforming to the plants licensing basis following their identification that the calculated short circuit fault current exceeded the breaker rating. Dominions evaluation failed to take into consideration that non-class 1E loads fed from safety-related buses must be isolated from the class 1E system by fully qualified safety-related isolation devices (breakers). Dominions design basis requires that a circuit fault on the non-class 1E side of the isolation device shall not cause the loss of the associated safety-related system
05000336/FIN-2018010-0430 June 2018 23:59:59MillstoneFlood Seals Not Installed in Unit 2 A EDG and Auxiliary Building PenetrationsThe team identified a finding of very low safety significance (Green) and associated NCV of 10 CFR Part 50, Appendix B, Criterion XIV, Corrective Actions. Dominion identified a condition adverse to quality but did not correct the condition. Specifically, Dominion performed evaluations and walk downs in 2012 and 2016 to validate that all necessary flood seals for design basis and beyond design basis flood events had been properly installed. Dominion determined that they could not verify 50 wall penetrations had seals installed and entered the deficiency into the corrective action program. The team noted that an electrical conduit that passed through a Unit 2 A emergency diesel generator (EDG) building exterior wall, located below the design basis flood height, was one of the penetrations in question. During the inspection, following NRC questions, Dominion removed the electrical conduit cover plate and confirmed that a seal was not installed.
05000313/FIN-2018002-0130 June 2018 23:59:59Arkansas NuclearFailure to Implement Procedural Guidance to Close Spent Fuel Pool Cooler Outlet Crosstie ValveThe inspectors reviewed a self-revealed, Green finding and associated non-cited violation of Arkansas Nuclear One (ANO) Unit 1 Technical Specification (TS) 5.4.1.a for the licensees failure to implement Procedure OP-1102.015, Filling and Draining the Fuel Transfer Canal, Revision 44. Specifically, operators failed to close spent fuel pool cooler outlet valve SF-9 while lining up to fill the fuel transfer canal (FTC) from the borated water storage tank (BWST). As a result, the licensee drained approximately 2600 gallons from the SFP to the FTC.
05000336/FIN-2018410-0130 June 2018 23:59:59MillstoneSecurity
05000382/FIN-2018002-0230 June 2018 23:59:59Waterford10 CFR 50.59 Evaluation Associated with Emergency Feedwater Logic ModificationThe 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-2018404-0130 June 2018 23:59:59WaterfordSecurity
05000255/FIN-2018011-0230 June 2018 23:59:59PalisadesFailure to Set Action Levels to Ensure that the Assumptions in the Engineering Analysis Remain Valid

The inspectors reviewed a sample of equipment located in the fire areas selectedfor inspection to determine if the licensee had established a proper method of monitoring that equipment as required by NFPA 805, Section 2.6. Section 2.6 of NFPA 805 required that, A monitoring program shall be established to ensure that the availability and reliability of the fire protection systems and features are maintained and to assess the performance of the fire protection program in meeting the performance criteria. Monitoring shall ensure that the assumptions in the engineering analysis remain valid. The licensee utilized Procedure EN-DC-357, NFPA 805 Monitoring Program, Revision 2,to ensure that, the assumptions in the NFPA 805 engineering analyses remain valid by executing an effective and ongoing monitoring program.The inspectors selected the high pressure air compressor (C-6B) and high pressure safety injection pump (P-66B), both of which were located in the West Safeguards Room. The licensee considered these components to be high-safety significant (HSS) structures, systems, or components (SSCs). The licensee chose to monitor the unavailability of these components utilizing the Maintenance Rule (10 CFR 50.65).The licensee set the Maintenance Rule allowable unavailability action level threshold for the high pressure air compressorat 5E-2 (5percent)whereas they assumed in their fire PRA an unavailability of 9.86E-3 (approximately 1percent). For the high pressure safety injection pump the licensee set the Maintenance Rule allowable unavailability at 1.5E-2 (1.5percent) whereas they assumed in their fire PRA an unavailability of 6.32E-3 (approximately 0.6percent). The inspectors believed that by relying on the less conservative action level thresholds in the Maintenance Rule the licensee failed to ensure that the assumptions in the engineering analysis (fire PRA) remained valid.The licensee stated in Procedure EN-DC-357, Section 1.0, Purpose, that, The NFPA 805 Monitoring Program ensures that the assumptions in the NFPA 805 engineering analyses remain valid by executing aneffective and ongoing monitoring program. Under Section 3.0, Definitions, the licensee defined, Action Level Threshold, as, When establishing the action level threshold for reliability and availability, the action level should be no lower than the Fire Probabilistic Safety Analysis (also called fire PRA) assumptions. The licensee stated in Section 5.3.3(c) that, If HSS SSCs have been identified in using the Maintenance Rule guidelines, the associated SSC specific performance criteria may be established as in the Maintenance Rule, provided the criteria are consistent with the Fire Probabilistic safety Analysisassumptions... The inspectors believed that Procedure EN-DC-357 required the licensee set the action level thresholds no lower than the fire PRA assumptions. Procedure section 5.3.4(b)(1) required that HSS equipment that is not sufficiently tracked in the Maintenance Rule be added to the NFPA 805 Monitoring Database. The licensee did not add the high pressure air compressor and the high pressure safety injection pump into the NFPA 805 Monitoring Database. In the SER 2015-2-27 dated February 27, 2015, in which the staff approved the licensee NFPA805 License Amendment Request, the staff noted that the licensee will develop an NFPA 805 Monitoring Program consistent with Frequently Asked Question (FAQ)10-0059. The staff also noted that the stated development of the Monitoring Program would include a review of existing surveillance, inspection, testing, compensatory measures, and oversight

8processes for adequacy. The staff concluded in SER 2015-2-27 that since the final values for availability and reliability, as well as the performance criteria for the SSCs being monitored, have not been established for the Monitoring Program as of the date of this SER, completion of the licensee's NFPA 805 Monitoring Program is an implementation item. Furthermore, the staff concluded that there is reasonable assurance that the licensee will develop a Monitoring Program that meets the requirements specified in Sections 2.6.1, 2.6.2, and 2.6.3 of NFPA 805Section 2.6 of NFPA 805 stated in part that, Monitoring shall ensure that the assumptions in the engineering analysis remain valid. The licensee interpreted this statement to mean that utilizing the existing Maintenance Rule unavailability values is consistent with its commitment in SER 2015-2-27 and would allow the site to appropriately monitor the availability and reliability of fire protection systems and features. The licensee also performed sensitivity studies on the differences in the unavailability values of fire protection systems and features between the Maintenance Rule criteria and the fire PRA values and determined that they were not risk-significant. The inspectors questioned the appropriateness of the licensees interpretation of assumptions as described in Section 2.6 of NFPA 805 above. The inspectors believed that the licensee should monitor the unavailability of fire protection systems and features utilizing the same values as thosedocumented in the fire PRA associated with the NFPA 805 License Amendment Request. The licensee further stated that they were waiting for guidance from the NRCs Office of Nuclear Reactor Regulation and the industry who were working on revising guidance in FAQ10-0059, NFPA 805 Monitoring, to determine if they needed to change their approach. That guidance document was in the process of being revised during the inspection. The inspectors needed to determine if the licensees approach to monitoring the availability and reliability of the fire protection systems and features using the Maintenance Rule monitoring values in order to ensure that the assumptions in the engineering analysis remained valid was an acceptable approach.Planned Closure Action(s): The inspectors will await clarification from the Office of Nuclear Reactor Regulation in order to determine if a performance deficiency exists.Licensee Action(s): The licensee plans to follow the resolution of FAQ 10-0059, Revision 6, and take the appropriate corrective actions based on the guidance provided in that FAQ.
05000528/FIN-2018012-0131 March 2018 23:59:59Palo VerdeFailure to provide adequate guidance to personnel to assure degraded or deficient emergency lighting required for post-fire safe shutdown was corrected in a timely mannerThe licensee provides emergency lighting for access and egress paths, and to illuminate required safe shutdown components to safely shut down the reactor in case of fire requiring control room evacuation, in accordance with 10 CFR 50, Appendix R, Section III.J., Procedure 40DP-9ZZ16, Administrative Controls for Appendix R Equipment, Revision 13, Steps 4.5.1 and 4.6.1, limit the out-of-service time for Appendix R equipment and require restoring the equipment to service within 30 days. The licensee provides guidance to operations department watch standers to check for deficient lighting throughout the plant. Procedure 40DP-9OP20, Watch Standing Practices, Revision 48, Step 4.3.1.1 instructs watch standers to check for adequate or sufficient lighting, among other items during routine tours of the plant. On January 30, 2018, during the walkdown of the control room evacuation due to fire Procedure 40AO-9ZZ19, Control Room Fire, Revision 35, the inspectors identified multiple examples of Appendix R emergency light fixtures that were not functional. The licensee confirmed no condition report had documented these deficient emergency lights at that time. During operator rounds through the area, with offsite power available, the area had adequate and sufficient lighting from the normal AC lighting system. The guidance provided in Procedure 40DP-9OP20 was not adequate to instruct watch standers to identify when an Appendix R emergency light is not functional and to promptly identify the failure to ensure timely restoration of the light.Corrective Actions: The licensee documented the emergency light deficiencies in the corrective action program to initiate repairs, and also issued an Operations Communication Newsflash titled, Actions needed on Emergency (App R) Lighting, dated February 1, 2018. The Newsflash required all operations crews to review procedures for identifying emergency lighting deficiencies and to focus on the emergency light fixtures. The licensee has 30 days to repair and restore the emergency lights to operation. The licensee has a standing compensatory measure for emergency lighting requiring operators to obtain flashlights from the emergency storage locker during a control room evacuation due to fire. The licensee initiated a revision request to provide additional guidance in Procedure 40DP-9OP20, concerning the Appendix R emergency lighting.
05000317/FIN-2018001-0131 March 2018 23:59:59Calvert CliffsFailure to Conduct Adequate Radiation Surveys and Evaluate Potential Radiological HazardsAself-revealed Green non-cited violation(NCV)of Title 10 Code of Federal Regulations(10 CFR) 20.1501, Surveys and Monitoring: General, was identified when Exelon failed to perform adequate surveys of the 11 reactor coolant pump bay area following the aggregation of 25 high dose-rate in-core detectors in one area of the flooded refueling cavity, which is adjacent to the pump bay. Surveys were not performed as required after radiological conditions changed and radiological hazard mitigation measures, such as locking and controlling access in accordance with Exelon procedures, were not implemented, resulting in accessible dose-rates of up to 2,000 millirem per hour(mrem/hr)in the pump bay
05000368/FIN-2018001-0231 March 2018 23:59:59Arkansas NuclearFailure to Preplan and Perform Service Water Pre-Screen MaintenanceThe inspectors reviewed a self-revealed,non-cited violation and associated finding of Arkansas Nuclear One, Unit 2, Technical Specification 6.4.1.a, for the licensees failure to properly preplan maintenance that can affect the performance of safety-related equipment. Specifically, the licensee failed to properly preplan pre-screen cleaning maintenance, causing the trainB service water system to become inoperable
05000335/FIN-2018411-0131 March 2018 23:59:59Saint LucieSecurity
05000335/FIN-2018450-0131 March 2018 23:59:59Saint LucieSecurity
05000255/FIN-2018001-0231 March 2018 23:59:59PalisadesLicensee Implementation of Enforcement Guidance Memorandum 15002, Enforcement Discretion for Tornado-Generated Missile Protection NoncomplianceOn June 10, 2015, the NRC issued Regulatory Issue Summary (RIS) 201506, Tornado Missile Protection (ML15020A419), focusing on the requirements regarding tornado-generated missile protection and required compliance with the facility-specific licensing basis. The RIS also provided examples of noncompliances that had been identified through different mechanisms and referenced Enforcement Guidance Memorandum (EGM) 15002, Enforcement Discretion For Tornado Generated Missile Protection Non-Compliance, which was also issued on June 10, 2015 (ML15111A269) and revised on February 7, 2017 (ML16355A286). The EGM applies specifically to a structure, system, or component (SSC) that is determined to be inoperable for tornado-generated missile protection. The EGM stated that a bounding risk analysis performed for this issue concluded that tornado missile scenarios do not represent an immediate safety concern because their risk is within the LIC504, Integrated Risk-Informed Decision-Making Process for Emergent Issues, risk acceptance guidelines. In the case of Palisades, the EGM provided for enforcement discretion of up to 3 years from the original date of issuance of the EGM. On December 7, 2017, and as supplemented on January 18, 2018, Palisades submitted a request to the NRC to extend the enforcement discretion from June 10, 2018 to June 10, 2020 (ML17341A415 and ML18018A328, respectively). By letter dated February 16, 2018, the NRC granted the request to extend enforcement discretion until June 10, 2020 (ML18046A675). The EGM permitted NRC staff to exercise this enforcement discretion only when a licensee implements, prior to the expiration of the time mandated by the LCO, initial compensatory measures that provide additional protection such that the likelihood of tornado missile effects were lessened. In addition, licensees were expected to follow these initial compensatory measures with more comprehensive compensatory measures within about 60 days of issue discovery. In accordance with the EGM, the comprehensive compensatory measures are toremain in place until permanent repairs are completed, or until the NRC dispositions the non-compliance in accordance with a method acceptable to the NRC such that discretion is no longer needed. Palisades was licensed prior to issuance of Appendix A to 10 CFR Part 50, General Design Criteria for Nuclear Power Plants (GDC). Specifically, GDC 2, Design Bases for Protection Against Natural Phenomena, and GDC 4, Environmental and Dynamic Effects Design Basis, discuss how SSCs important to safety shall be designed to protect against natural phenomena, such as tornadoes and shall be adequately protected against the dynamic effects of tornadoes, including protection against missiles. Palisades site-specific licensing bases compliance with GDC 2 and GDC 4 are described in the Updated Final Safety Analysis Report (UFSAR) Sections 5.1.2.2 and 5.1.2.4. Palisades protection of SSCs against tornado-generated missiles is also discussed in UFSAR Section 5.5, Missile Protection. On January 31, 2018, the licensee initiated condition report (CR) CRPLP201800556, which identified a nonconforming condition in the Palisades licensing basis. Specifically, the surge line from the component cooling water (CCW) surge tank to the CCW suction line was identified to be potentially vulnerable to a tornado missile through a doorway. The licensee previously identified a CCW system-related vulnerability on March 29, 2017. The March 29, 2017 CCW vulnerability and five additional vulnerabilities of other SSCs, which all received enforcement discretion, are documented in NRC Inspection Report 05000255/2017002 (ML17220A349). The licensee assessed this new vulnerability and concluded that previously established compensatory measures for the CCW system were adequate and no additional comprehensive compensatory actions were required. Therefore, the licensee declared the SSC operable, but nonconforming because no additional compensatory measures designed to reduce the likelihood of tornado-generated missile effects were required and the previously implemented compensatory measures were still in place. Corrective Action: The licensee documented the condition of the SSC in the CAP and documented the SSC as operable but nonconforming.Corrective Action Reference: CRPLP201800556 Enforcement: Violation: Enforcement discretion was applied to the required shutdown actions of the following Technical Specification (TS) Limiting Conditions for Operation (LCOs): TS 3.0.3, General Shutdown LCO (cascading or by reference from other LCOs); andTS 3.7.7, Component Cooling Water (CCW) System.Severity/Significance: The subject of this enforcement discretion associated with tornado missile protection deficiencies was determined to be less than red (i.e., high safety significance) based on a generic and bounding risk evaluation performed by the NRC in support of the resolution of tornado-generated missile non-compliances. The bounding risk evaluation is discussed in EGM 15002, Revision 1, Enforcement Discretion for Tornado-Generated Missile Protection Non-Compliance (ML16355A286). 11 Basis for Discretion:The NRC exercised enforcement discretion in accordance with Section 2.3.9 of the Enforcement Policy and EGM 15002 because the licensee initiated initial compensatory measures that provided additional protection such that the likelihood of tornado missile effects were lessened. The licensee implemented more comprehensive compensatory actions to resolve the nonconforming conditions within the required 60 days. These comprehensive measures were to remain in place until permanent repairs were completed, which for Palisades were required to be completed by June 10, 2020, or until the NRC dispositioned the non-compliance in accordance with a method acceptable to the NRC such that discretion was no longer needed.The disposition of this enforcement discretion closes LER 05000255/201700101, Inadequate Protection from Tornado Missiles Identified Due to Nonconforming Design Conditions.
05000382/FIN-2017008-0231 December 2017 23:59:59WaterfordFailure to Meet RG 1.9 Emergency Diesel Testing Requirements during Surveillance Test Results in Missed SurveillanceThe team identified a Green non-cited violation of Waterford Steam Electric Station, Unit 3, Technical Specification Limiting Condition for Operation 3.8.1.1 for failure to maintain operability of two separate independent diesel generators. Specifically, on May 23, 2017, the licensee failed to verify that the train A emergency diesel generator energized all auto-connected shutdown loads through the load sequencer and operated for greater than or equal to five minutes in accordance with Technical Specification Surveillance Requirement 4.8.1.1.2.
05000335/FIN-2017004-0131 December 2017 23:59:59Saint LucieInadequate Reactor System Trip Process for Inoperable Channel Results in Operation in a Condition Prohibited by Technical SpecificationsA Green, self-revealing NCV of 10 Code of Federal Regulations (CFR) Part 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, was identified for the licensees failure to have an adequate procedure for reducing the trip setpoint of the B channel of the reactor protection system (RPS) high startup rate (HSUR) bistable. The licensees failure to establish an adequate procedure, as required by 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, to place the "B" channel wide range nuclear instrument in a tripped condition was a performance deficiency (PD). This deficiency resulted in a violation of Technical Specification (TS) Limiting Condition for Operation (LCO) 3.3.1.1. Following discovery of the condition, the licensee initiated immediate corrective actions to place the B channel RPS HSUR in trip, meeting the TS requirement. The inspectors determined that the finding was more than minor because it was associated with the Mitigating Systems cornerstone attribute of procedural quality and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, there was no procedure to perform the setpoint reduction method as identified in 1-AOP-99.01. The only direction was to Contact I&C in the step. The Instrumentation and Control (I&C) processes used to implement the HSUR reduced setpoint reduction method were inadequate, in that, they did not evaluate all potential failure conditions when setting the HSUR bistable. The finding did not screen as greater than Green because while the degradation affected a single RPS trip signal, it did not affect the function of other redundant trips; and the finding did not involve control manipulations that unintentionally added positive reactivity; and finally the finding did not result in a mismanagement of reactivity by operators. Using IMC 0310, Aspects Within the Cross-Cutting Areas, the inspectors determined that the finding had a cross-cutting aspect in the area of human performance. Specifically, the cross- cutting aspect of resources (H.1) was assigned to the finding because the licensee did not ensure an adequate procedure was available to implement the HSUR setpoint reduction.
05000255/FIN-2017007-0131 December 2017 23:59:59PalisadesFailure to Periodically Test the Emergency Diesel Generators Capacity to Start and Accelerate Design Basis Sequenced LoadsThe team identified a finding of very-low safety significance (Green) and an associated NCV of Title 10 of the Code of Federal Regulations, Part50, Appendix B, Criterion XI, Test Control, for the failureto periodically test the emergency diesel generators(EDGs) capability to start and accelerate all of the sequenced loads within the applicable design voltage and frequency transient and recovery limits.Specifically, EDG testingactivities did not demonstrate that all of the EDG auto-sequenced loads started and accelerated within the applicable voltage and frequency limits during start-up and recovery. In addition, the licensee did not perform adequate post-modification testing after replacing the EDG governor controller system or voltage regulators. Thelicensee captured theseissuesin their Corrective Action Programas Condition Report (CR)2017-05265 and CR 2017-05283, and performed an operability evaluation which reasonably determined the affected structures, systems, and componentswere operable.The performance deficiency was determined to be 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 thatrespond to initiating events to prevent undesirable consequences. The finding screened as of very-low safety significance (Green) becauseit did not result in the loss ofoperability or functionality of mitigating systems. Specifically, the licensee evaluated the most recent voltage and frequency data from the last EDG output breaker testsin which the data recorder was left running after the output breaker shut and reasonably determined that the EDGs and the affected loads were operable. The team did not identify a cross-cutting aspect associated with this finding because it was not confirmed to reflect current performance due to the age of the performance deficiency. Specifically, the associated testingprocedures were established more than 3years ago.
05000382/FIN-2017008-0131 December 2017 23:59:59WaterfordThree examples of Failure to Establish and Maintain Preventive Maintenance Procedures for Safety-Related Electrical EquipmentThe team identified three examples of a Green non-cited violation of Waterford Steam Electric Station, Unit 3, Technical Specification 6.8.1.a, for failure to establish, implement, and maintain written procedures for activities referenced in Appendix A of Regulatory Guide 1.33, Revision 2, dated February 1978. Specifically, prior to November 16, 2017, the licensee failed to establish and maintain procedures covered in Regulatory Guide 1.33, Appendix A, Section 9, Procedures for Performing Maintenance, to implement maintenance for safety-related 1600 A, 600 V non-segregated metal-enclosed bus ducts, safety-related 4.16 kV G.E. Magne-Blast circuit breakers, and safety-related 480 V G.E. switchgear AKR breakers.
05000255/FIN-2017004-0131 December 2017 23:59:59PalisadesImproperly Connected M&TE Leads to Unexpected AFU Fan TripA finding of very low safety significance and an associated NCV of Title 10 of the Code of Federal Regulations (CFR) Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was self-revealed when the licensee failed to follow step 5.4.4.b of Technical Specification surveillance procedure RT85DA, Control Room Emergency Ventilation Filtration Testing A Train. Specifically, the licensee failed to properly connect maintenance and test equipment (M&TE) across flow transmitter test taps which caused V26A, the air filter unit (AFU) VF26A fan, to stop 17 seconds after operators started the fan from the control room. The licensee entered this issue into their Corrective Action Program (CAP) as condition report (CR) CRPLP201705234. Corrective actions included coaching the vendor on ensuring M&TE is properly connected to plant equipment and ensuring suitable field oversight of the vendor during re-performance of the surveillance.The issue was determined to be more than minor in accordance with IMC 0612, Appendix B, Issue Screening, because it was associated with the Barrier Integrity cornerstone attribute of Human Performance and adversely affected the cornerstone objective of providing reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. The finding screened as having very low safety significance (Green) in accordance with IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, Exhibit 3, because the inspectors answered "No" to all screening questions. The finding had across-cutting aspect in the area of Human Performance, in the Field Presence aspect, for the failure to ensure supervisory and management oversight of work activities, including contractors and supplemental personnel (H.2).
05000255/FIN-2017007-0331 December 2017 23:59:59PalisadesContainment Dome Truss AnalysisThedome truss system was originally designed to support the containment liner plate and wet concrete during the construction of the containment dome (i.e., the liner plate initially acted as a form and the truss supported the form). After the concrete cured, the dome truss system was lowered away from the liner and was used to support the safety injection tanks(SITs) and CS system piping and their associated supports. The CS and SIT systemsare both safety-related which were required to be evaluated for seismic loads (self-weight and externally applied loads). The dome truss system would have alsobeen required to be evaluated for seismic loads. The UFSAR,Section 6.1,described the safety-related design function of the SITsystemwas to prevent fuel and cladding damage that could interfere with adequate emergency core cooling, and to limit the cladding-water reaction to less than approximately 1percentfor all break sizes in the primary system piping up to and including the double-ended rupture of the largest primary coolant pipe, for any break location, and for the applicable break time. Also,the SITsystem also functions to provide rapid injection of large quantities of borated water for added shutdown capability during rapid cooldown of the primary system caused by a rupture of a main steam line. UFSAR Section 6.2.1 described the safety-related design function of the CSsystem was to limit the containment building pressure rise and reduce the airborne radioactivity in containment by providing a means for spraying the containment atmosphere after occurrence of a LOCAor a main steam line break.The inspectors requested the design basis analysis of the dome truss system that considers the LOCA loading on the dome truss system as well as the seismic loading due to the applied design loads from the CS and SITsystem. During the time of the inspection, the licensee was unable to locate the dome truss analysis. In response to the inspectors concern, the licensee entered the issue into their CAP asCR 2017-05016, Dome Trusses, dated November 1, 2017. The licensee is investigating the containment dome truss analysis further with the vendor of the dome truss system.This issue is a URI pending additional inspector review of the design basis analysis for the containment dome truss system. (URI 05000255/2017007-03; Containment Dome Truss Analysis)
05000382/FIN-2017403-0131 December 2017 23:59:59WaterfordSecurity
05000255/FIN-2017007-0231 December 2017 23:59:59PalisadesContainment Spray Pipe Support Strap DeficienciesThe inspectors identified a finding of low safety significance (Green) and an associated potential NCV of Title 10of theCode of Federal Regulations,Part 50, Appendix B, Criterion III, Design Control, for failure to meet Updated Final Safety Analysis Reportrequirements for containment spraypiping supports, specifically straps. Specifically, the inspectors identified that Calculation No. EA-SP-03369-02, Revision 0, used inelastic acceptance limits for the pipe straps which connect the pipe to the pipe support, in order to demonstrate Class I compliance which was not in accordance with the design and licensing basis specification. The license entered the issue into their Corrective Action Programas CR-PLP-2017-05246, Spray Pipe Support,dated November 14, 2017. The licensee performed an analysis to establish reasonable assurance of operability and the inspectors with support from the Office from the Nuclear Reactor Regulation reviewed this operability and no performance deficiencies were identified.The performance deficiency was determined to be more-than-minor because it was associated with the Barrier Integrity Cornerstone attribute of design control and adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers (fuel cladding, reactor coolant system, and containment) protect the public fromradionuclide releases caused by accidents or events. This finding is of very-low safety significance (Green) because there was no actual reactor containment barrier degradation. The inspectors did not identify a cross-cutting aspect associated with thisfinding because this was a legacy design issue; and therefore, was not reflective of current performance.
05000382/FIN-2017008-0331 December 2017 23:59:59WaterfordTwo Examples of Failure to Submit and Receive Prior Authorization of Alternatives to ASME OM Code Leak Testing RequirementsThe team identified two examples of a Severity Level IV, non-cited violation of 10 CFR 50.55a(z), for failure to submit and obtain authorization prior to implementation of multiple alternatives to leak testing requirements of the American Society of Mechanical Engineers (ASME) Operation and Maintenance (OM) of Nuclear Power Plants Code. Specifically, prior to November 16, 2017, the licensee did not submit and receive prior authorization to alternative leak testing requirements for safety injection valves SI-512A and SI-602B.
05000528/FIN-2017404-0131 December 2017 23:59:59Palo VerdeSecurity
05000317/FIN-2017004-0131 December 2017 23:59:59Calvert CliffsInadequate Assessment of Fire Brigade Performance During an Announced Fire DrillAn NRC-identified Green non-cited violation (NCV) of Calvert Cliffs Nuclear Power Plant Renewed Facility Operating License DPR-53, DRP-69, Condition E, was identified for Exelons failure to adequately assess the performance of the fire brigade during an announced fire drill. Specifically, Exelon failed to properly assess the command and control performance of the fire brigade leader (FBL) which resulted in the fire drill being improperly evaluated as having met the assessment criteria. The inspectors determined that Exelons failure to properly assess fire brigade performance in accordance with OP-AA-201-003, Fire Drill Performance, Revision 16, was a performance deficiency. Exelon has entered this issue into their corrective action program (CAP) as action request (AR) 04094397The inspectors reviewed IMC 0612, Appendix B, Issue Screening, issued on September 7, 2012, and determined the issue is more than minor because it was associated with the protection against external events (fire) attribute of the Mitigating Systems cornerstone and adversely affected its objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, failure to properly evaluate the performance of the fire brigade and correct identified deficiencies adversely affects the fire brigades ability to protect against the effects of a fire. In accordance with IMC 0609, Attachment 4, Initial Characterization of Findings, issued on October 7, 2016, and IMC 0609, Appendix A, The Significance Determination Process for Findings at Power issued on June 19, 2012, the inspectors determined that this finding is of very low safety significance (Green) since it involved fire brigade training requirements, the fire brigade demonstrated the ability to meet the required times for fire extinguishment for the fire drill scenario, and the finding did not significantly affect the fire brigades ability to respond to a fire. The inspectors determined that the finding has a cross-cutting aspect in the area of Problem Identification and Resolution, Self-Assessment, because Exelon did not conduct a self-critical and objective assessment of the fire brigades performance. Specifically, Exelon failed to conduct a self-critical and objective assessment of the FBLs performance during the fire drill described above.
05000313/FIN-2017015-0131 December 2017 23:59:59Arkansas NuclearSecurity
05000255/FIN-2017003-0130 September 2017 23:59:59PalisadesLeft Train Emergency Diesel Generator Load Sequencer FailureIntroduction: The inspectors identified an Unresolved Item ( URI ) associated with the failure of the left train emergency DG load sequencer to run its program. Since this sequencer is required for left train DG operability, this condition resulted in an unanticipated entry into a TS shutdown action statement. The cause of this failure is currently unknown, pending the results of a vendor evaluation of a failed load sequencer component. Description : On August 3, 2017, the control room received alarm EK 1145, Sequencer Trouble, unexpectedly. The operators identified that the indication lights were not lit on the left channel load sequencer, MC -34L101; declared the associated DG inoperable; and entered the appropriate TS action statement. The failed sequencer was removed and replaced with a new module that was satisfactorily post -maintenance tested and the left train EDG was subsequently declared operable on August 4, 2017. The failed sequencer was sent to an on -site lab for further troubleshooting. No obvious visual signs of failure were identified and the electrolytic capacitors in the module all tested satisfactorily. The module was then bench tested using a test program, which identified that although it would power up, no program would run. The licensee completed an equipment failure evaluation to review the bench test data, along with information collected in the failure modes analysis, and determined that the direct cause of the failure was a memory fault within the sequencer module that caused the sequencer to lock -up and not run its program. A fault in the memory module, memory processing interface circuitry, or the executive module could have caused the sequencer to lock up. At the end of the inspection period, further examination by t he vendor was required and in progress to determine the exact initiating point of the fault. In addition to replacing the failed sequencer, the licensees immediate corrective actions included inspecting the right train load sequencer and completing the quarterly surveillance test to ensure proper operation; the results of which were satisfactory. A plant operating experience review was conducted and did not identify any prior memory failures on the load sequencers. Once the vendors evaluation is complete, the licensee plans to re-assess the failure mechanism and any additional corrective actions required. This item is considered unresolved, pending the inspectors review of the vendor analysis and any changes made to the equipment failure evaluation, to determine if this issue constitutes a performance deficiency and/or violation of NRC requirements. (URI 05000255/2017003 01, Left Train Emergency Diesel Generator Load Sequencer Failure )
05000528/FIN-2017003-0230 September 2017 23:59:59Palo VerdeLoss of Refrigerant Failure of Essential Chiller Unit due to Installation of Incorrect PartsThe inspectors reviewed a self-revealed, Green, non-cited violation of Technical Specification 3.7.10 Condition A for exceeding the allowed outage time of 72 hours to restore one inoperable train of essential chilled water system to an operable status. Specifically, the Unit 1 essential chiller B was inoperable from April 11, 2017, to April 18, 2017, due to a refrigerant leak. The licensee entered this issue into their corrective action program as Condition Report 17-05605. The licensees corrective actions included: isolating the automatic purge unit, thereby stopping the leak; refilling the essential chiller with refrigerant; and retesting the essential chiller unit to return it to an operable status on April 18, 2017. Additionally, the licensee checked the other five essential chillers across the station and found no additional material deficiencies.The inspectors determined that the failure to ensure the correct Swagelok fitting was being installed in accordance with station procedure is a performance deficiency. The performance deficiency is more than minor and a finding because it is associated with the design control 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 April 18, 2013, the licensee installed the incorrect Swagelok fitting during maintenance on the essential chiller. When the licensee placed the auto purge system in service, this resulted in the refrigerant leaking out of the Swagelok fitting rendering the essential chiller inoperable.The inspectors performed the initial significance determination using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, Exhibit 2, Mitigating Systems Screening Questions, Step A.3 which required a senior reactor analyst to perform a detailed risk evaluation because essential chiller B was incapable of performing its safety function for greater than its technical specification allowed outage time. A regional senior reactor analyst performed a detailed risk evaluation and determined that the finding was of very low safety significance (Green). Essential Chiller 1B was assumed to be unavailable for 8 days and the potential for common cause failure on the remaining essential chiller was assumed. This resulted in a change in core damage frequency of 3.6E-7 per year. Losses of offsite power comprised the most dominant core damage sequences. The emergency diesel generators and the emergency feed water systems remained available for mitigation of the dominant sequences.The inspectors determined this finding had a cross-cutting aspect in the area of human performance, avoid complacency, in that the licensee failed to recognize and plan for the possibility of latent issues or mistakes. Specifically, the licensee failed to provide an appropriate post-maintenance testing procedure as required by station procedure. The work order executed on April 11, 2017, gave no direction to test for leaks on the filter assembly (H.12).
05000255/FIN-2017003-0230 September 2017 23:59:59PalisadesCause of 422/RPS Breaker Failure to OpenIntroduction: The inspectors identified an URI associated with the failure mechanism of the 42 -2/RPS control rod clutch breaker failure to open. Specifically, at the end of the inspection period the licensee was working to understand the cause of the breaker failure and determine the actions required to address the failure mechanism. Description : On May 17, 2017, the licensee conducted a shutdown to complete emergent repairs to a leaking seal identified on control rod drive mechanism 40. In accordance with GOP 8, Power Reduction and Plant Shutdown to Mode 2 or Mode 3 525 F, the operators depressed the reactor trip pushbutton from the EC 06, reactor protection system panel. When the pushbutton was depressed, the reactor did not trip as expected. The operators successfully tripped the reactor using the reactor trip pushbutton on the EC 02, primary process and reactor controls console. The licensee identified that the 42 1/RPS breaker tripped as expected when the reactor trip pushbutton on the EC 06 panel was depressed, however, the 42 2/RPS breaker did not trip as expected. This resulted in the reactor trip not occurring as expected when the reactor trip pushbutton on the EC 06 panel was depressed as both breakers a re required to open to result in a reactor trip. The licensee performed troubleshooting activities to determine the cause of the 42 2/RPS breaker failure. The direct cause of the breaker failure was found to be the 42 2/RPS breaker undervoltage release mechanism failing to provide enough downward force to fully depress the trip plunger. This resulted in a physical failure of the breaker to open. At the end of the inspection period, the cause of this physical failure mode was unknown. The licensees equipment failure evaluation identified that it could be age- related degradation or a physical degradation of the breaker. As a corrective action, a failure analysis of the breaker was planned. Once the failure analysis i s complete, the licensee plans to re-assess the failure mechanism and determine any additional corrective actions that are required to address the issue. This item is considered unresolved, pending the inspectors review of the failure analysis and any changes made to the equipment failure evaluation, to determine if this issue constitutes a performance deficiency and/or violation of NRC requirements. (URI 05000255/2017003 02, Cause of 42 2/Reactor Protection System Breaker Failure to Open)
05000529/FIN-2017003-0330 September 2017 23:59:59Palo VerdeFailure to Follow Conduct of Operations ProcedureThe inspectors reviewed a self-revealed, Green, non-cited violation of Technical Specification 5.4.1.a. Procedures, for the licensees failure to implement their Conduct of Operations procedure. Specifically, licensee personnel improperly performed a reactor coolant pump seal injection filter flushing evolution as a skill of the craft task without written instructions. Consequently, Unit 2 experienced a loss of letdown and exceeded the pressurizer level technical specification limit of 56 percent. Licensed operators took immediate corrective actions to restore letdown and lower pressurizer level to within acceptable limits. The licensee entered this issue into their corrective action program as Condition Report 17-09326.The inspectors determined that the failure to follow the Conduct of Operations procedure for performance of skill of the craft tasks is a performance deficiency. The performance deficiency is more than minor, and therefore a finding, because it was associated with the configuration control attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the decision to perform the reactor coolant pump seal filter flushing evolution without a controlled procedure allowed operators to place the system in a configuration causing an automatic isolation of the letdown system that challenged the availability of the pressurizer to respond to reactor coolant system pressure transients. The inspectors evaluated the significance of the issue under the Significance Determination Process, as defined in Inspection Manual Chapter 0609.04, Initial Characterization of Findings, and Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power. The inspectors determined that the finding was of very low safety significance (Green) because it only contributed to the likelihood of a reactor trip and not the likelihood that mitigation equipment or functions would not be available. The inspectors determined 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, latent issues, and inherent risk. Specifically, licensee personnel did not recognize the inherent risks associated with the reactor coolant pump seal filter flushing evolution before proceeding to perform the task without formal written instructions (H.12).
05000255/FIN-2017003-0330 September 2017 23:59:59Palisades12 Diesel Generator Trip During Maintenance Resulting in Additional Unavailability of the 12 DGA finding of very low safety significance and an associated NCV of Technical Specification (TS) 5.4.1, Procedures, was self -revealed on March 31, 2017, when the 12 Diesel Generator ( DG ) tripped during performance of monthly TS surveillance procedure MO 7A 2, Emergency Diesel Generator 1 2. Specifically, during conduct of the monthly surveillance procedure, restoration activities associated with maintenance of breaker 152 213, 1 2 DG to Bus 1D, were being performed. When maintenance personnel closed the trip cutouts for the Z -phase of the 1 2 DG differential overcurrent relay, an unbalanced current flow into the differential relay resulted in relay actuation. This actuation resulted in a trip of the output breaker and subsequently the 1 2 DG. The trip caused a delay in the TS surveillance activities and resulted in the extended unavailability and inoperability of the 1 2 DG. The licensee entered this issue into their corrective action program (CAP) as condition report (CR) CR PLP 2017 01291. Corrective actions included retesting the 1 2 DG and updating the work instructions associated with the differential overcurrent relays to include caution statements that opening or closing trip cutouts for the relays while the output breaker s from the DGs to the associated buses were closed could cause the differential relay s to actuate and trip the DG . The issue was determined to be more than minor in accordance with IMC 0612, Appendix B, Issue Screening, because it was associated with the Mitigating System s cornerstone attribute of Procedure Quality and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding screened as having very low safety significance (Green) in accordance with IMC 0609, Appendix A, The Significance Determination Process for Findings At -Power, Exhibit 2, since the inspectors answered No to all screening questions. The finding had a cross- cutting aspect in the area of Human Performance, in the Work Management aspect , for the licensees failure to identify and manage risk commensurate to the work (H.5).
05000530/FIN-2017003-0130 September 2017 23:59:59Palo VerdeFailure to Initiate Corrective Actions for Thermography TestsThe inspectors reviewed a self-revealed, Green finding for the licensees failure to initiate corrective actions to address elevated temperature measurements identified during thermography inspections of the Unit 3 Phase C main transformer control cabinet. As a result, an extended loss of cooling to the Phase C main transformer resulted in a manual trip of the main turbine and a reactor power cutback. This issue was entered into the licensees corrective action program under Condition Report 17-09022, and the licensee took immediate actions to reinsert and tighten a loose wire associated with the transformer cooling control circuitry. The inspectors determined that the failure to follow procedure 37TI-9ZZ01, Thermography Inspection of Plant Components, Revision 8, Step 4.5.10.1 to initiate a condition notification report following the identification of elevated temperatures during thermography inspections is a performance deficiency. This performance deficiency is more than minor, and therefore a finding, because it was associated with the configuration control attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions duringshutdown as well as power operations. Specifically, the failure to initiate corrective actions following the identification of the hot spot on the Unit 3 Phase C main transformer 4-8 contactor resulted in a reactor power cutback that upset plant stability. Using NRC Manual Chapter 609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, Exhibit 1, Initiating Events Screening Questions, the finding screened as having very low safety significance (Green) because the deficiency resulted in a reactor trip, but mitigation equipment remained unaffected. The inspectors determined this finding had a cross-cutting aspect in the area of problem identification and resolution, identification, in that the licensee failed to identify issues completely, accurately, and in a timely manner in accordance with the corrective action program. Specifically, on three occasions in 2016 and 2017, the licensee collected data indicating potential loose connections at the 4-8 contactor, but failed to recognize and communicate the data in accordance with the corrective action program (P.1).
05000313/FIN-2017007-0130 September 2017 23:59:59Arkansas NuclearFailure to Promptly Identify and Correct an Inadequate Design Bases CalculationThe inspectors identified a Green, non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Actions, requires, in part, that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and nonconformance are promptly identified and corrected. Specifically, from 1996 until August 10, 2017, the licensee failed to properly resolve the environmental conditions in room 38 following a high-energy line break, even when challenged during a self-assessment by members of the quality assurance group in June 29, 2015. In response to this issue, the licensee determined that in the event of a break in the letdown line, an engineered safety feature signal automatic closure of both the inside and outside reactor building isolation valves occurs in approximately 40 seconds, preventing room 38 from going harsh. This finding was entered into the licensees corrective action program as Condition Report CR-ANO-1-2017-02441. The inspectors determined that the licensees failure to adequately evaluate and take prompt corrective actions to resolve an identified condition adverse to quality related to the high energy line break analysis for room 38 was a performance deficiency. The performance deficiency was more than minor because it was associated with the design control attribute of the Mitigating Systems Cornerstone and affected the associated objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, when the licensee identified that the environmental conditions in room 38 of the auxiliary building were harsh, as determined by Design Bases Calculation CALC-01-EQ-1002-02, they failed to properly resolve the condition adverse to quality. In accordance with Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, Exhibit 2, Mitigating Systems Screening Questions, dated July 1, 2012, the inspectors determined that the finding was of very low safety significance (Green) because the finding (1) was not a deficiency affecting the design and qualification of a mitigating structure, system, or component, and did not result in a loss of operability or functionality; (2) did not represent a loss of system and/or function; (3) did not represent an actual loss of function of at least a single train for longer than its allowed outage time, or two separate safety systems out-of-service for longer than their technical specification allowed outage time; and (4) does not represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant for greater than 24 hours in accordance with the licensees maintenance rule program. The finding has a cross-cutting aspect in the area of human resources, training, because the organization failed to provide training and ensure knowledge transfer to maintain a knowledgeable, technically competent workforce and instill nuclear safety values. Specifically, there was a lack of understanding of the current licensing bases for the plant displayed by engineering, operations, and management (H.9).
05000255/FIN-2017201-0130 September 2017 23:59:59PalisadesSecurity
05000336/FIN-2017007-0130 September 2017 23:59:59MillstoneFailure to Replace Auxiliary Feedwater Solenoid Valves within the Required FrequencyThe inspection team identified a Green non-cited violation of Technical Specification 6.8.1.a, Procedures, because Dominion did not implement procedures as required by Regulatory Guide 1.33, Revision 2, Appendix A.9, Procedures for Performing Maintenance, to properly maintain the environmental qualification of safety-related auxiliary feedwater solenoid valves 2-FW-43AS and 2-FW-43BS. Specifically, Dominion failed to implement the recurring work event task and associated work order to ensure that these auxiliary feedwater solenoid valves were replaced prior to exceeding the qualified life of the solenoid coil and elastomer components. Dominion entered this issue into their corrective action program as condition report 1076005, planned replacement of the solenoid valves, and calculated an alternate ambient temperature for use in determining the qualified life of the solenoid valves. Dominion re-performed the qualified life calculation using this revised ambient temperature and extended the qualified life to support operability. The inspection team determined that this issue was more than minor because it adversely impacted the equipment performance attribute of the Mitigating Systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. This issue is also similar to more- than-minor examples 3.j and 3.k presented in IMC 0612, Appendix E, Examples of Minor Issues. Specifically, this performance deficiency resulted in a condition where there was reasonable doubt as to the operability and reliability of the solenoid valves for both auxiliary feedwater regulating valves, and thus, both trains of auxiliary feedwater. As such, Dominion needed to conduct additional engineering evaluation to extend the service life of the solenoid valves, thus justifying that the valves would continue to perform their safety function. The inspection team determined the finding to be of very low safety significance (Green) because the finding was a deficiency affecting the reliability of a mitigating structure, system, or component, and the structure, system, or component maintained its operability or functionality. The inspection team determined that no cross-cutting aspect was applicable because the finding was not indicative of current performance.
05000530/FIN-2017003-0430 September 2017 23:59:59Palo VerdeReactor Trip due to Pressurizer Spray Valve Failing Open due to Volume Booster Internals Not Environmentally Qualified for Anticipated Ambient Operating TemperaturesThe inspectors reviewed a self-revealed, Green, non-cited violation of Technical Specification 5.4.1.a Procedures, for the licensees failure to follow station procedure 73DP-0EE05, Engineering Preventive Maintenance Program. The licensee did not consult design basis resources and operating experience when changing the preventive maintenance frequency of the pressurizer spray valve air-operated volume boosters. The valve internals were not rated for ambient operating temperature conditions, as a result a pressurizer spray valve failed open, requiring operators to trip the reactor. The licensee entered this condition into their corrective action program as Condition Report 16-14219. The licensees corrective actions included replacing the affected pneumatic volume boosters with high temperature qualified soft parts and by revising procedure 73DP-0EE05 to ensure a more thorough engineering management oversight of the equipment reliability engineering template process. The inspectors determined that the failure to follow station procedure 73DP-0EE05, Engineering Preventive Maintenance Program, Revision 6, Step 3.4.7, to consult design basis information including internal operating experience resources when determining a required preventive maintenance frequency is a performance deficiency. The performance deficiency is more than minor, and therefore a finding, because it was associated with the design control attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the pressurizer spray valve failed open requiring the operators to trip the reactor. The inspectors evaluated the significance of the issue under the Significance Determination Process, as defined in Inspection Manual Chapter 0609.04, Initial Characterization of Findings, and Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power. The inspectors determined that the finding was of very low safety significance (Green) because the finding did not cause a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. Specifically after the reactor trip, control room operators were able to regain pressure control by securing the reactor coolant pumps driving pressurizer spray, and initiating auxiliary spray through the charging system. The inspectors determined this finding had a cross-cutting aspect in the area of human performance, consistent process, in that the licensee failed to use a systematic approach to make decisions including incorporating risk insights. Specifically, the pressurizer spray valves are designated as critical components and single point vulnerabilities in 73DP-0EE05, which requires a technical basis to allow for a preventive maintenance frequency change. The licensee did not document the technical basis to increase the service life from one to four cycles (H.13).
05000313/FIN-2017003-0130 September 2017 23:59:59Arkansas NuclearFailure to Maintain Service Water Train SeparationThe inspectors identified a non- cited violation of Technical Specification 5.4.1.a for the licensees failure to maintain train separation between safety -related service water trains when swapping the swing high pressure injection (HPI) pump between trains. Specifically, by following procedure OP 1104.002, Makeup and Purification System Operation, Revision 89, operators cross -tied service water trains, placing the system in an unanalyzed condition. This condition resulted in the train A electrical equipment room emergency chiller and train B reactor building emergency cooling coils being inoperable for a maximum of 25 minutes per occurrence. Additionally, it was determined that service water temperatures over the past 3 years did not result in an actual loss of function associated with these components if a design basis accident would have occurred. The immediate corrective actions were to assess past operability for not maintaining service water train separation and to revise Operating Procedure 1104.002 with adequate work instructions to maintain service water train separation. The licensee entered this deficiency into the corrective action program as Condition Report CR -ANO -1-2017- 02518. The licensees failure to maintain safety -related service water train separation when swapping the swing HPI pump between trains was a performance deficiency. The performance deficiency was more than minor because it was associated with the procedural quality attribute of the Mitigating Systems Cornerstone, and adversely affected the cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events. Specifically, the licensees failure to maintain service water train separation placed the system in an unanalyzed condition and was subsequently determined to cause the train A electrical equipment room emergency chiller and train B reactor building emergency cooling coils to be inoperable for a maximum of 25 minutes per occurrence . Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Finding s At-Power, dated June 19, 2012, the inspectors determined that the finding had very low safety significance (Green) because it: was not a design deficiency; did not represent a loss of system and/or function; did not represent an actual loss of function of at least a single train for longer than its technical specification allowed outage time; and did not result in the loss of a high safety -significant , non -technical specification train. Specifically, inspectors confirmed that service water temperatures were never high enough to result in an actual loss of function for either limiting component. The finding had 3 a cross -cutting aspect in the area of human performance associated with conservative bias because the licensee failed to determine whether the proposed action was safe to proceed, rather than unsafe in order to stop. Specifically, in December 2015 when this approach was revise d to declare only the non- protected service water train inoperable, the licensee did not ensure that the transition lineup was analyzed to be within safety analyses before adopting the revised steps. (H.14)