Semantic search
Jump to navigation
Jump to search
| Quarter | Site | Title | Description | |
|---|---|---|---|---|
| 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-2016009-01 | 2016Q2 | Arkansas Nuclear | Inadequate Loop Flow Testing | The team identified a non-cited violation of License Conditions 2.C.(8), Fire Protection, for Unit 1; License Condition 2.C.(3)(b), Fire Protection, for Unit 2; and the technical requirements manuals because the licensee did not properly test all portions of the underground fire piping. Specifically, the licensee did not determine the flow rates through two headers that provided water to the ring header supplying the Unit 2 auxiliary building as designed. The licensee entered this violation into their corrective action program as Condition Report CR-ANO-C-2016-02613 and initiated actions to conduct a flow test of the headers. The failure to implement an adequate procedure to test underground fire piping was a performance deficiency. Specifically, the licensee did not test two headers included and designed as part of their underground fire piping to demonstrate that no faults had occurred. This performance deficiency was more than minor because it was associated with the protection against external factors attribute (fire) and adversely affected the Mitigating Systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to test two underground fire piping headers failed to demonstrate the capability to deliver adequate flow and pressure to the fire suppression systems as designed. The finding was screened in accordance with Inspection Manual Chapter (IMC) 0609, Significance Determination Process, Attachment 4, Initial Characterization of Findings, dated June 19, 2012. Because the finding affected fixed fire protection systems or the ability to confine a fire, the team reviewed the finding using IMC 0609, Appendix F, Attachment 1, Fire Protection Significance Determination Process Worksheet, dated September 20, 2013. The finding was screened as a Green finding of very low safety significance in accordance with Task 1.4.7, Fire Water Supply, Question A. Although the licensee failed to test all portions of the underground fire piping in accordance with their license and technical requirements manual, the team determined that at least 50 percent of required fire water capacity would be available based on the testing that is done. As a result, the finding was determined to be of very low safety significance (Green). The team determined that this finding did not have a cross-cutting aspect since it did not reflect current performance. Specifically, the licensee had not flow tested all underground fire piping headers since initial installation. |
| 05000313/FIN-2018003-01 | 2018Q3 | Arkansas Nuclear | Failure to Translate the Design Requirements into Instructions for Refueling Emergency Diesel Generators | The inspectors identified a Green finding and associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to translate current design into instructions for Unit 1 and Unit 2 diesel fuel oil transfer system. Specifically, the licensee failed to translate the current diesel fuel oil transfer system design into instructions to refuel Unit 1 and Unit 2 safety-related fuel bunkers, T-57 and 2T-57, if the non-safety bulk diesel fuel oil tank T-25 was unavailable following a design basis event (e.g., tornado, external flooding, or earthquake) for which it was not designed to withstand. |
| 05000313/FIN-2018003-02 | 2018Q3 | Arkansas Nuclear | Failure to Implement Welding Standard Guidance and Examination Procedures | The 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. |
| 05000313/FIN-2018003-03 | 2018Q3 | Arkansas Nuclear | Failure to Provide Complete and Accurate Information in a License Amendment Request to Change Emergency Action Level Requirements | The 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. |
| 05000313/FIN-2018003-04 | 2018Q3 | Arkansas Nuclear | Failure to Verify Safety-Related 4160 V Breaker Operability Following Maintenance Activities | The 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 perform post-maintenance testing to demonstrate component operability for the train A safety-related 4160 V switchgear A-303 breaker that provides power to the swing service water pump B (P-4B) after the breaker was racked in. The breaker subsequently failed to close when attempting to start the pump. |
| 05000313/FIN-2018003-05 | 2018Q3 | Arkansas Nuclear | Failure to Maintain Main Feedwater Pump B Discharge Pressure in Band Caused a Reactor Trip | The 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. |
| 05000313/FIN-2018003-06 | 2018Q3 | Arkansas Nuclear | Reactor Power Transient Caused by the Turbine Bypass Valve Failing Open | The 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. |
| 05000336/FIN-2010008-01 | 2010Q3 | Millstone | Failure to Control Fire Fighting Strategies | The team identified a non-cited violation of Millstone Unit 2 Operating License Condition 2.C.(3), and Unit 3 Operating License Condition 2.H, for the failure to implement all provisions of the approved Fire Protection Programs. Specifically, Dominion did not implement adequate review, approval and distribution of fire fighting strategies to provide for the adequate development and maintenance of effective strategies. As a result, the team found that Dominion did not provide adequate guidance in the fire fighting strategies for several areas that included the Unit 2 8 emergency diesel generator (EDG) room, and the Unit 3 west switchgear room. This issue was entered into Dominion\\\'s corrective action program as condition report (CR) 388786. The team determined that the failure to administratively control fire fighting strategies as required by the fire protection program was a performance deficiency. This finding was more than minor because it adversely affected the availability and capability objectives of the protection against external events (i.e., fire) attribute under the Mitigating Systems Cornerstone. Specifically, the above examples would likely cause delays in manual fire fighting activities and, therefore, adversely affected the defense-in-depth aspect of the fire protection program to limit fire damage by quick suppression of those fires that occur. The team performed a Phase 1 SDP screening, in accordance with NRC IMC 0609, Appendix F, Fire Protection Significance Determination Process. This finding affected fire prevention and administrative controls, and was screened to very low safety significance (Green) because this failure to control fire fighting strategies was determined to represent a low degradation rating. This finding had a cross-cutting aspect in the area of human performance because Dominion failed to ensure complete and accurate fire fighting strategies were available to the fire brigade to support timely extinguishment of fires. |
| 05000336/FIN-2010008-02 | 2010Q3 | Millstone | Failure to Protect Safe Shutdown Equipment From the Effects of Fire | The team identified a cited violation of 10 CFR Part 50, Appendix R, Section III.G.2 for the failure to protect required post-fire safe shutdown components and cabling to ensure one of the redundant trains of equipment remains free from fire damage. In lieu of providing the required separation, Dominion utilized unapproved operator manual actions to mitigate component malfunctions or spurious operations caused by a single fire induced circuit fault (hot short, open circuit or short to ground). Dominion has entered this issue into the corrective program for resolution. The team found the manual actions to be reasonable interim compensatory measures pending final resolution by Dominion. Dominion\'s failure to protect components credited for post-fire safe shutdown from fire damage caused by single spurious actuation is considered a performance deficiency. The performance deficiency was more than minor because it affected the Mitigating Systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to an external event to prevent undesirable consequences in the event of a fire. Specifically, the use of operator manual actions during post-fire shutdown is not as reliable as normal systems operation which could be utilized had the separation requirements of 10 CFR 50, Appendix R, Section III.G.2 been met and therefore prevented fire damage to credited components and/or cables. The team used IMC 0609, Appendix F, Rre Protection Significance Determination Process (SDP), Phase 1 and an SRA conducted Phase 3 evaluation, to determine that this finding was of very low safety significance (Green). The team determined the finding had a low degradation rating because the manual actions were reviewed by the team and were found to be acceptable interim compensatory measures (pending licensee actions to resolve the non-compliances or obtain exemptions) because they did not require complicated actions, adequate time was available to accomplish the actions and the actions were properly included in the appropriate abnormal operating procedures. This finding had a cross cutting aspect in the area of problem identification and resolution associated with the corrective action program because Dominion did not completely and accurately identify deficiencies related to single spurious actuations of credited post-fire safe shutdown components. |
| 05000361/FIN-2003003-03 | 2003Q2 | San Onofre | Change to EAL C3 resulting in decrease in effectiveness of EP in violation of 10 CFR 50.54(q) | Between March 3 and April 25, 2003, the licensee implemented a change to Emergency Action Level C3 which constituted a decrease in effectiveness of the emergency plan because two conditions which would previously have resulted in site area emergency classification would not be classified by the revised emergency action level. Implementation without prior NRC approval of changes to the emergency plan which constitute reduction in the effectiveness of the plan was a noncited violation of 10 CFR 50.54(q) The finding was evaluated using NUREG-1600, "General Statement of Policy and Procedure for NRC Enforcement Actions," Section IV, because licensee reductions in the effectiveness of its emergency plan impact the regulatory process. The finding had greater than minor significance because deletion of conditions indicative of a site area emergency has the potential to impact safety. The finding was determined to be a noncited Severity Level IV violation because the emergency action level change constituted a failure to implement an emergency planning standard and did not constitute a failure to meet an emergency planning standard as defined by 10 CFR 50.47(b). This finding has been entered into the licensee's corrective action program as Action Request 030400514. |
| 05000368/FIN-2014007-01 | 2014Q1 | Arkansas Nuclear | Failure to Reassess the Effects of Aging | The team identified a non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for failure to follow procedures related to review of indications that could affect the structural integrity of the Unit 2 reactor building. Specifically, the licensee failed to perform a subsequent visual inspection of concrete cracks that exceeded acceptable criteria in the previous 5-year inspection as specified in Procedure CEP-CII-004, General and Detailed Visual Examinations of Concrete Containments, Revision 306. The corrective actions included verifying that the indications did not structurally affect the reactor building in these instances, initiating Condition Report C-2014-00597, and scheduling the affected areas for review during the upcoming 5-year inspection. The team determined that the failure to assess previous indications of concrete degradation, as specified in plant procedures, was a performance deficiency. The team considered the finding more than minor because, if left uncorrected, the finding would have the potential to lead to a more significant safety concern. Specifically, failure to track the growth of existing cracks on the reactor building could allow degradation to continue to the point of affecting the structural integrity. In accordance with Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, Exhibit 3, Barrier Integrity Screening Questions, the issue screened as having very low safety significance (Green) because it did not involve an actual open pathway in the physical integrity of the containment, loss of containment isolation, or reduction in heat removal capability and it did not affect hydrogen igniters. The team determined that this finding had a human performance cross cutting aspect in the area of work management. The licensee did not implement a process of planning, controlling, and executing work activities such that nuclear safety was the overriding priority. |
| 05000368/FIN-2016009-02 | 2016Q2 | Arkansas Nuclear | Inadequate Procedure Used as a Compensatory Measure | The team identified a non-cited violation of License Condition 2.C.(3)(b), Fire Protection, for use of an inadequate procedure as a compensatory measure. Specifically, a procedure for providing temporary cooling to the safety parameter display system room when the normal room cooler is unavailable did not adequately address the impact of the temporary configuration on the ability to maintain safe and stable plant conditions for fires that require shutdown from outside the control room. The temporary room cooler did not have a power supply assured to remain available during a shutdown from outside the control room. The licensee entered this violation into their corrective action program as Condition Reports CR-ANO-2-2016-02143 and CR-ANO-C-2016-02638. In response to this issue, the licensee developed a thermal analysis of the safety parameter display system room temperature during this scenario and confirmed that the maximum room temperature would not challenge the operation to the safety parameter display system. The failure to provide an adequate procedure for use as a compensatory measure was a performance deficiency. The performance deficiency was more than minor because it was associated with the Mitigating Systems cornerstone attribute of procedure quality and adversely affected the associated cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events (fire) to prevent undesirable consequences. Specifically, loss of cooling to the safety parameter display system room could adversely affect the availability, reliability, and capability of the safety parameter display system which is required to respond to a fire resulting in the evacuation of the Unit 2 control room. A senior reactor analyst performed a detailed risk evaluation of this finding because IMC 0609, Appendix F, does not include explicit treatment of fires in the control room. An evaluation of the survivability of the safety parameter display system compared to the best estimate of the heatup of the room housing its equipment demonstrated that the safety parameter display system would survive with high probability until the plant reached a safe and stable condition for the postulated fires. As a result, the finding was determined to be of very low safety significance (Green). This finding did not have a cross-cutting aspect since it was not indicative of present performance in that the performance deficiency occurred more than three years ago. |
| 05000368/FIN-2016009-03 | 2016Q2 | Arkansas Nuclear | Failure to Ensure that the Assumptions in the Engineering Analysis Remain Valid | The team identified a non-cited violation of License Condition 2.C(3)(b), Fire Protection, for the failure to establish an appropriate monitoring program in accordance with National Fire Protection Association Standard 805, Section 2.6. Specifically, the licensee failed to set the action level for the availability of some plant components to ensure that the assumptions in the engineering analysis remained valid and also failed to establish a monitoring plan for the concurrent unavailability of one set of two components. The licensee entered the issues into their corrective action program as Condition Reports CR-ANO-2-2016-02355 and was in the process of developing corrective actions to address the monitoring of the components and work with industry organizations and Office of Nuclear Reactor Regulation to determine long-term resolution. The failure to adequately monitor unavailability of the plant components to ensure that the assumptions in the engineering analysis remained valid was a performance deficiency. The performance deficiency was more than minor because if left uncorrected, the performance deficiency had the potential to lead to a more significant safety concern. Specifically, the performance deficiency could adversely affect the acceptable level of availability of the components which are used to respond to fire initiating events, in that the action levels for availability in the monitoring program were greater than the assumptions in the fire probabilistic risk assessment. The finding was screened in accordance with Inspection IMC 0609, Significance Determination Process, Attachment 4, Initial Characterization of Findings, dated June 19, 2012. Because the finding affected the ability to reach and maintain safe shutdown conditions in case of a fire, the team reviewed the finding using IMC 0609, Appendix F, Attachment 1, Fire Protection Significance Determination Process Worksheet, dated September 20, 2013. The finding was screened as a Green finding of very low safety significance in accordance with Step 1.3, Ability to Achieve Safe Shutdown, B Question. Based on the criteria in Appendix F, Attachment 2, Degradation Rating Guidance Specific to Various Fire Protection Program Elements, dated February 28, 2005, the finding was assigned a low degradation rating. Using Table A2.3, the inspectors assigned the low degradation rating because the issue involved monitoring of components that did not appreciably degrade below acceptable levels during the exposure period. This finding had a cross-cutting aspect associated with change management within the human performance area since leaders did not use a systematic process (e.g., assigning an overall owner) for evaluating and implementing change during the development of the monitoring program for the fire probabilistic risk assessment model for Unit 2 (H.3). |
| 05000368/FIN-2016009-04 | 2016Q2 | Arkansas Nuclear | Failure to Adequately Establish Ignition Frequencies for the Risk-Informed Fire Protection Program | The team identified two examples of a Severity Level IV non-cited violation of License Condition 2.C(3)(b), Fire Protection, for the licensees failure to properly implement their risk-informed fire protection program and accurately capture component ignition frequencies in their fire probabilistic risk assessment. Specifically, the component ignition frequencies for air compressors and ventilation equipment were found to be lower than expected because the licensee misapplied the guidance in NUREG/CR-6850. The licensee entered this issue into their corrective action program as Condition Reports CR ANO-C-2016-2600, CR-ANO-C-2016-2528, and CR-ANO-2-2016-02356, with the intent to perform an extent of condition relating to other potential components that are misclassified in the fire ignition frequency analysis, correct the fire Ignition frequency report and the associated Fire Probabilistic Risk Assessment model calculations to incorporate the correct ignition frequency and the appropriate scenarios. The licensees failure to adequately implement the prescribed guidance in NUREG/CR-6850 to estimate the ignition frequencies for their risk-informed fire protection program was a performance deficiency. The performance deficiency was minor because the answer to all the IMC 0612, Appendix B, more than minor questions was No. The team determined that this issue was a traditional enforcement violation because it impacted the regulatory process when the only NRC-approved framework for conversion to NFPA 805 was not fully followed. The NRC determined that this violation was associated with a minor performance deficiency. The team determined that this violation was a Severity Level IV in the traditional enforcement process when comparing it to the violation examples in Section 6.1, Reactor Operations, of the NRC Enforcement Policy, specifically noting it was similar to Example 6.1.d.4 for failing to adequately assess the baseline risk of plant operations associated with implementation of a risk-informed program (NFPA 805) such that the program was implemented inappropriately. The finding did not have a cross-cutting aspect because traditional enforcement violations are not assessed for cross-cutting aspects. |
| 05000382/FIN-2009006-01 | 2009Q2 | Waterford | Failure to identify conditions adverse to fire protection | The team identified a non-cited violation of License Condition 2.C.9 for the failure to identify conditions adverse to the fire protection program, as required by Procedure UNT-005-013, Fire Protection Program, Revision 10. Specifically, during required inspections of the material condition of the sprinkler system, the licensee failed to identify several instances of either bent or misaligned sprinkler head deflector plates, which were not protected as required by National Fire Protection Association 13-1976, Standard for the Installation of Sprinkler Systems. The failure to identify a condition adverse to fire protection was a performance deficiency. This deficiency was more than minor since, if left uncorrected, the finding would become a more significant safety concern in that the number of damaged sprinklers would continue to increase. The team evaluated the significance of this finding using Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process. The deficiency involved the Fixed Fire Protection Systems category. Using Appendix F, Attachment 2, Degradation Rating Guidance Specific to Various Fire Protection Program Elements, the team determined that the deficiency had low degradation since less than 10 percent of the heads in the affected fire area were nonfunctional, a functional head remained within 10 feet of the combustibles of concern, and the system remained nominally code compliant. This finding screened as having very low safety significance (Green) in Phase 1. This finding has a cross-cutting aspect in the area of human performance associated with resources because the procedure used to inspect the condition of these sprinklers did not contain specific criteria for identifying unacceptable sprinkler conditions (H.2(c)) |
| 05000382/FIN-2009006-02 | 2009Q2 | Waterford | Failure to provide area wide sprinkler coverage as required in an Appendix R, Section III.G.2.c fire area | The team identified a violation of License Condition 2.C.9 for failure to protect post-fire safe shutdown equipment against fire damage, as required by 10 CFR Part 50, Appendix R, Section III.G.2. Specifically, in Fire Area RAB 39 the licensee failed to provide area-wide sprinkler coverage that complied with the requirements in National Fire Protection Association 13-1976. As required in Appendix R, Section III.G.2.c, redundant trains within the same fire area must be protected with detection and an automatic fire suppression system when redundant post-fire safe shutdown equipment is protected with 1-hour fire barriers. The team determined this violation met the Interim Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48) conditions for receiving enforcement discretion (EA-09-171). During plant walk downs of Fire Area RAB 39 (-35-foot corridor area) to review compliance with National Fire Protection Association 13-1976, the team identified three examples of failures to provide the required area-wide sprinkler coverage. • Sprinkler heads installed closer than the allowed 6-foot minimum spacing. When the first sprinkler actuates this short span allows spray to contact an adjacent sprinkler keeping it cool enough to preventing actuation. • No sprinkler coverage for the area under a large ceiling equipment hatch. • Ceiling sprinklers were blocked in four separate locations by large ventilation ducts and cable trays that exceeded the 4-foot limit below obstacles and resulted in less than area-wide coverage. Because of offsetting heights of the obstructions, the team determined that a fire would not produce a plume or a ceiling jet that would activate the existing sprinklers in the following circumstances: o Two parallel cable trays and a large diameter pipe adjacent to the emergency feedwater pump rooms, o Piping, cable trays, ductwork, and structural support members in the narrow passageway in front of the elevator, o Six cable trays and one duct that outside of Stair 6, and o Two parallel cable trays outside of the Train B heat exchanger room and above an open storage locker containing plastic covered radiological protective blankets. As immediate corrective actions, the licensee initiated Fire Impairment 2009-145, which established a continuous fire watch in the fire area, and entered this issue into the corrective action program as Condition Report 2009-01986. The team determined that Fire Area RAB 39 had redundant post-fire safe shutdown trains routed through the area. As specified in 10 CFR Part 50, Appendix R, Section III.G.2.c, an area containing redundant post-fire safe shutdown trains has adequate protection so long as one train has a 1-hour rated fire barrier wrap with detection and fixed fire suppression. The team determined the licensee had not installed some sprinklers in Fire Area RAB 39 in accordance with National Fire Protection Association 13-1976, as required by Final Safety Analysis Report, Section 9.5.1.3.1.E.3.(c). The failure to provide area-wide sprinkler coverage in a fire area that contained redundant trains of post-fire safe shutdown equipment resulted in a failure to meet the requirements of their license. From review of the scope of their National Fire Protection Association 805 conversion, the team confirmed that the licensee had actions scheduled for evaluating each fire area for compliance with the National Fire Protection Association codes. Analysis. Failure to provide area-wide sprinkler coverage in accordance with National Fire Protection Association 13-1976 for a fire area with 1-hour fire barriers was a performance deficiency. The team determined that this finding was more than minor because it is associated with the protection against external factors attribute of the mitigating systems cornerstone and adversely affected the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Because this violation meets the discretion criteria of the Interim Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48) for a noncompliance identified during the transition to National Fire Protection Association 805, the team determined that discretion to take no enforcement action is appropriate at this time, as described in the Enforcement Policy. The team reviewed the risk assessment for the fire area and determined that the licensee demonstrated that the risk was less than high safety significance (Red). Specifically, the team determined that the fixed and transient fire sources would not generate sufficient heat to cause fire damage that rendered the systems incapable of performing their safety function. License Condition 2.C.9 states that the licensee shall implement and maintain in effect all provisions of the approved fire protection program as described in the Final Safety Analysis Report for the facility through and as approved in the Safety Evaluation Report. Final Safety Analysis Report, Section 9.5.1.3.1.E.3.(c) specified that the licensee would install sprinklers in accordance with National Fire Protection Association 13-1976. National Fire Protection Association 13-1976, Section 4-4.13 specified, in part, sprinklers shall be installed beneath ducts that create obstructions over 4 feet wide. The licensee committed to the technical requirements of 10 CFR Part 50, Appendix R, by letter dated November 10, 1981. Appendix R, Section III.G.2.c specifies that the licensee must provide detection and area-wide suppression when the separation requirements for redundant post-fire safe shutdown trains are being met using a 1-hour fire barrier. Contrary to the above, from initial licensing through May 22, 2009, the licensee failed to implement and maintain in effect all provisions of their approved fire protection program, as required by 10 CFR Part 50, Appendix R, Section III.G.2. Specifically, the team identified that the licensee failed to ensure a redundant post-fire safe shut train with a 1-hour fire wrap had adequate protection. The licensee failed to provide area-wide sprinkler coverage under obstructions, under a large ceiling equipment hatch and failed to prevent wetting of sprinkler heads as required by National Fire Protection Association 13-1976. Because the licensee committed to adopting National Fire Protection Association 805 and changing their fire protection program license basis to comply with 10 CFR 50.48(c), this issue is eligible for the enforcement discretion described in the Interim Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48). Specifically, the team determined that the licensee: (1) would have evaluated this issue during the conversion to National Fire Protection Association 805, (2) had entered this issue into their corrective action program and implemented appropriate compensatory measures, (3) would not have likely identified this through routine licensee efforts, and (4) had not committed the error willfully. The team determined that this violation meets the criteria for enforcement discretion for plants in transition to a risk-informed, performance-based fire protection program as allowed per 10 CFR 50.48(c) (EA-09-171). Since all the criteria were met, the NRC is exercising enforcement discretion for this issue and documenting the issue as a finding: FIN 05000382/2009006-02, Failure to provide area wide sprinkler coverage as required in an Appendix R, Section III.G.2.c fire area |
| 05000382/FIN-2009006-03 | 2009Q2 | Waterford | Failure to ensure post-fire safe shutdown valves could be operated | The team identified a violation of License Condition 2.C.9 related to the capability to complete required manual actions, following a control room fire, because of potential fire damage to some motor-operated valves. Specifically, the licensee failed to evaluate the susceptibility of fire damaging circuits in motor-operated valves that needed to be manually operated for post-fire safe shutdown. The licensee did not recognize that the circuits could cause the valves to become stuck. The team determined licensee personnel would not be able to reposition motor-operated valves as specified in plant procedures. The team determined this violation met the Interim Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48) conditions for receiving enforcement discretion (EA-09-171). The licensee implemented their alternative shutdown for a control room fire in accordance with Procedure OP-901-502, Evacuation of Control Room and Subsequent Plant Shutdown, Revision 16. Procedure OP-901-502, Attachment 2, Step 4, required that operators close Valves MS-119A/B, Train A/B main steam isolation valve upstream drip pot startup drain valves, to prevent uncontrolled cool down of the plant. Also, Attachment 4, Step 5, required that operators open Valves BAM-113A/B, Train A/B boric acid make-up tank gravity feed valves, to provide a source of borated water to the reactor coolant system. The team determined that both attachments required operators to use the motor-operated valve hand wheel to manually reposition these valves in the event of a spurious actuation resulting from fire damage. The licensee identified these actions as time-critical in the event of a control room evacuation. Information Notice 92-18, Potential for Loss of Remote Shutdown Capability during a Control Room Fire, described the potential for fire damage to motor-operated valves to prevent operation following a control room evacuation. The information notice described that a valve without thermal overloads could be damaged and not be operated after a control room evacuation. The industry information further described the potential need to rewire circuits to ensure that a hot short would not bypass the torque and limit switches whether a valve had thermal overloads or not. Further, the information notice provided diagrams indicating how a circuit would allow damage and how to rewire the circuit to ensure the torque and limit switches continue to function if a hot short were to occur. The licensee documented their evaluation of Information Notice 92-18 in an internal memorandum dated March 17, 1993. The licensee evaluated whether the forces generated by the motor-actuator at locked rotor current, which would trip the thermal overload, exceeded forces the licensee determined would be needed to fail the motor-operated valve weak link under accident conditions. The licensee had performed valve weak link calculations so that they could modify the valves to withstand the forces generated under accident conditions. The team determined from interviews and review of the evaluation that these calculations demonstrated the motor-operated valves would not cause the failure of the pressure boundary. The licensee did not determine whether the forces generated with the motor-actuator at locked rotor torque would push the valve disc in the seat such that operators could not reposition the valve using the manual hand wheel. This condition would result if a hot short bypassed the torque switch, which could occur under the current control circuit configuration. The team determined that the licensee did not ensure that the required post-fire safe shutdown valves would remain functional as a result of a fire-induced hot short. The team determined that it was possible that the valve disc would be driven into the valve seat with such force that mechanical damage would occur and the valve would not be able to be repositioned, as required by post-fire safe shutdown procedures. The licensee documented this deficiency in Condition Reports 2009-02249 and 2009-02472. The team verified that the licensee had scheduled an evaluation of Information Notice 92-18 during their transition to National Fire Protection Association 805. After the team identified the deficiency in the existing evaluation, the licensee initiated the following actions: (1) confirming the population of post-fire safe shutdown valves affected; (2) performing further evaluations to determine whether they could open the valves manually using the hand wheel; (3) for any valve unable to be opened, the licensee will identify routing of the control cables through the plant; and (4) after identifying the cable routing, the licensee will use fire modeling to identify if the valves would be subjected to fire damage. The team determined the licensee will perform a risk evaluation, if needed, to total all contributions to core damage that result from this performance deficiency. The failure to ensure that safe shutdown equipment could be operated as required during control room fire events was a performance deficiency. The team determined that this finding was more than minor because it is associated with the protection against external factors attribute of the mitigating systems cornerstone and adversely affected the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Because this violation meets the discretion criteria of the Interim Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48) for a noncompliance identified during the transition to National Fire Protection Association 805, the team determined that discretion to take no enforcement action is appropriate at this time, as described in the Enforcement Policy. License Condition 2.C.9 states EOI shall implement and maintain in effect all provisions of the approved fire protection program as described in the Final Safety Analysis Report for the facility and as approved in the Safety Evaluation Report. Final Safety Evaluation Report, Section 9.5.1.4.1 specifies alternate shutdown capability is provided that meets the criteria of Appendix R, Sections III.G.3 and III.L. Section III.L.3 specifies, in part, procedures shall be in effect to implement the alternative shutdown capability. Procedure OP-901-502, Attachment 2, Step 4, directs operators to close Valves MS-119A/B using the manual hand wheel. Attachment 4, Step 5 direct operators to open Valves BAM-113A/B. Contrary to the above, from February 1993 through May 22, 2009, the licensee failed to implement the requirements of License Condition 2.C.9, as specified in Final Safety Analysis Report, Section 9.5.1.4.1 and Appendix R, Section III.L.3. Specifically, the licensee failed to ensure that valves susceptible to fire damage could be manually operated as specified in Procedure OP-901-502, which implemented their alternate shutdown capability. Because the licensee committed to adopting National Fire Protection Association 805 and changing their fire protection program license basis to comply with 10 CFR 50.48(c), this issue is eligible for the enforcement discretion described in the Interim Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48). Specifically, although identified by the team, the licensee: (1) would have evaluated this issue during the conversion to National Fire Protection Association 805, (2) had entered this issue into their corrective action program and implemented appropriate compensatory measures, (3) would not have likely identified this through routine licensee efforts, and (4) had not committed the error willfully. The team determined that this violation meets the criteria for enforcement discretion for plants in transition to a risk-informed, performance-based fire protection program as allowed per 10 CFR 50.48(c) (EA-09-171). Since all the criteria were met, the NRC is exercising enforcement discretion for this issue and documenting the issue as a finding: FIN 05000382/2009006-03, Failure to ensure post-fire safe shutdown valves could be operated |
| 05000397/FIN-2008004-01 | 2008Q3 | Columbia | Failure to provide adequate procedures during mainenance of emergency core cooling system pumps. | The inspectors identified a noncited violation of Technical Specification 5.4.1.a for Energy Northwests failure to provide adequate procedures during maintenance of emergency core cooling system pumps. Specifically, Energy Northwest failed to specify in procedures a maximum torque limit that is applied to emergency core cooling system motor bearing oil reservoir drain plugs. As a result of improper tightening of these plugs, oil leaks have developed in emergency core cooling system motor oil reservoirs, potentially resulting in O-ring deformation, cracking and eventual failure of the plugs. Energy Northwest has entered this deficiency into their corrective action program. In accordance with Manual Chapter 0612, Appendix B, this finding was more than minor because it was an equipment performance issue that affected the mitigating systems cornerstone objective to ensure the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, if left uncorrected, tightening of the emergency core cooling system pump motor bearing oil reservoir drain plugs without specifying maximum torque limits during maintenance could result in o-ring deformation, cracking and eventual failure of the plugs. In addition, under-tightening of drain plugs could cause improper seating of the o-ring seal to the plug bushing. Both conditions as fore mentioned have historically led to oil leaks in emergency core cooling system motor oil reservoirs, increasing the unavailability time to correct the condition. Using Manual Chapter 0609.04, Phase 1 - Initial Screening and Characterization of Findings, the inspectors determined that the finding was of very low risk significance because failure to specify maximum torque limits when tightening of emergency core cooling system pump motor oil reservoir drain plugs did not result in the loss of a safety function of a single train for greater than its technical specification allowed outage time. In addition, the finding would not have likely affected other mitigating systems resulting in a total loss of their safety function. A crosscutting aspect in the area of problem identification and resolution with a corrective action component was identified in that Energy Northwest failed to conduct effective corrective action program reviews to ensure maximum torque limits were incorporated into work instructions (P.1.c). (Section 1R12) |
| 05000397/FIN-2008004-02 | 2008Q3 | Columbia | Failure to maintain administrative control of keys to high radiation area with dose rates in excess of 1 rem per hour. | The inspectors identified a noncited violation of Technical Specification 5.7.2.a.1 for failure to maintain administrative control of door and gate keys to high radiation areas with dose rates greater than 1 rem per hour. Specifically, on August 28, 2008, the licensee did not know the location of two of the three master keys to locked high radiation areas. This issue was entered into the licensees corrective action program as Condition Report 85620. Failure to maintain administrative control of door and gate keys to high radiation areas with dose rates in excess of 1 rem per hour was a performance deficiency. This finding is greater than minor because the finding could be reasonably viewed as a precursor to a significant event in that an individual could receive unanticipated radiation dose by gaining access to a locked high radiation area without the proper controls and briefing. This finding was evaluated using the occupational radiation safety significance determination process and determined to be of very low safety significance because it did not involve: (1) an as low as is reasonably achievable planning or work control issue, (2) an overexposure, (3) a substantial potential for overexposure, or (4) an impaired ability to assess dose. Additionally, the violation has a crosscutting aspect in the area of human performance associated with the work practices component because the lack of peer and self-checking resulted in inadequate control of keys to locked high radiation areas (H.4.a) (Section 2OS1). |
| 05000397/FIN-2008004-03 | 2008Q3 | Columbia | Digital electro-hydraulic leak results in reactor scram. | The inspector reviewed a self-revealing finding for failure of Energy Northwest to provide an adequate procedure for the installation of a compression fitting in a digital electro-hydraulic system modification. Specifically, failure to provide the methods and details for the preparation, review, approval, and implementation of procedures, contributed to the improper installation of a compression fitting in the digital electro-hydraulic system. This improper installation resulted in a failure of the compression fitting, a leak in the digital electro-hydraulic system, a main turbine trip and a subsequent reactor scram. Energy Northwest entered the issue into the corrective action program and conducted a root cause evaluation. This finding is greater than minor because it is an equipment performance issue that affected the initiating events cornerstone objectives to limit the likelihood of those events that upset plant stability. Specifically, use of a less than adequate procedure during the installation of a compression fitting in the digital electrohydraulic system, the rear ferrule was installed backwards, which led to a failure of the compression fitting, a subsequent leak in the digital electro-hydraulic system, a loss of hydraulic pressure, a main turbine trip and a reactor scram (initiating event). The finding was of very low risk significance because the finding did not result in the loss of a safety function of a single train for greater than its technical specification allowed outage time. The cause of the finding is related to the crosscutting aspect of human performance with a resources component, because Energy Northwest failed to provide adequate procedural requirements for compression fitting installation work (H.2.c). (Section 4OA3.1) |
| 05000397/FIN-2008004-04 | 2008Q3 | Columbia | Failure to ensure that Division 2 instrument sensing lines remained free of fire damage. | The inspectors identified a noncited violation of License Condition 2.C.(14) for failure to protect one train of post-fire safe shutdown equipment as required by 10 CFR Part 50, Appendix R, Section III.G. Specifically, the licensee failed to ensure that the Division 2 instrument sensing lines related to residual heat removal flow indication, minimum recirculation valve control, and reactor pressure vessel level and pressure indication remained free of fire damage. The inspectors determined that a fire in Fire Area R-1 could affect the function of the instrument sensing lines needed to achieve and maintain a safe shutdown condition. The licensee entered this deficiency into the corrective action program as Condition Reports 2-06-02399 and 2-06-04898. Failure to ensure that the credited instrument sensing lines would remain free of fire damage was a performance deficiency. The inspectors determined this deficiency was more than minor in that it had the potential to affect the mitigating systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to external events (fire). Because procedures provided adequate guidance to operators in the event of the expected failure modes, the inspectors assigned this post-fire safe shutdown finding a low degradation rating. In accordance with Manual Chapter 0609, Appendix F, \"Fire Protection Significance Determination Process,\" Phase 1, Step 1.3; this finding was determined to have very low safety significance. (Section 4OA5.2) |
| 05000397/FIN-2010004-01 | 2010Q3 | Columbia | Inadequate Risk Assessment Associated with Planned Surveillance Activities | The inspectors identified a Green noncited violation of 10 CFR 50.65(a)(4) for the licensees failure to perform an adequate risk assessment during surveillance testing. Specifically, licensee personnel failed to input the appropriate variable for the reactor core isolation cooling system being unavailable during surveillance testing. When the correct variable was used the risk profile for the day increased one level of significance. This violation has been placed in the licensees corrective action program as Action Request 224294. The performance deficiency was more than minor because it involved a failure to include all maintenance activities ongoing in the plant. The performance deficiency affected the equipment performance attribute of the Mitigating Systems Cornerstone objective to ensure the availability of systems that respond to an initiating event in that the risk profile did not adequately show system availability. The inspectors evaluated the performance deficiency using Manual Chapter 0609, Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process, and determined the performance deficiency to be of very low safety significance (Green) because the risk deficit during the time of the surveillance was calculated to be less than 1.0E-6. This performance deficiency has a crosscutting aspect in the area of human performance, resources, for the failure to provide an up to date work package with the correct input variable for assessing risk (H.2.c) |
| 05000397/FIN-2010004-02 | 2010Q3 | Columbia | Licensee-Identified Violation | The following violation of very low safety significance (Green) was identified by the licensee and is a violation of NRC requirements which meet the criteria of Section 2.3.2.a of the NRC Enforcement Policy for being dispositioned as NCVs: Technical Specification 3.6.4.2, requires each secondary containment isolation valve to be operable. And, with one secondary containment isolation valve inoperable, within 8 hours, isolate the penetration by at least one closed and deactivated automatic valve, closed manual valve, or blind flange, or be in Mode 3 within the next 12 hours. Contrary to this requirement, one secondary containment isolation valve was inoperable, but the licensee failed to take action to isolate the affected penetration within 8 hours, or be in Mode 3 within the next 12 hours. Specifically, between August 13, 1994 and June 30, 2010, valve FDR-V-219 (a secondary containment isolation valve) was inoperable and not fully seated, but the licensee failed to take the actions prescribed in Technical Specification 3.6.4.2. This issue was entered into the licensees corrective action program as Condition Report 220785. The finding is of very low safety significance because it only represented a degradation of the radiological barrier function provided for the reactor building. |
| 05000397/FIN-2010004-03 | 2010Q3 | Columbia | Failure to Assure That One Train of Low Pressure Coolant Injection Remained Free of Fire Damage | License Condition 2.C.(14) states, The licensee shall implement and maintain in effect all provisions of the approved fire protection program as described in Section 9.5.1 and Appendix F of the Final Safety Analysis Report (FSAR) for the facility thru Amendment No. 39 and as described in subsequent letters to the staff through November 30, 1988, referenced in the May 22, 1989, safety evaluation and in other pertinent sections of the FSAR referenced in either Section 9.5.1 or Appendix F and as approved in the Safety Evaluation Report issued in March 1982 (NUREG 0892) and in Supplement 3, issued in May 1983, and Supplement 4, issued in December 1983, and in safety evaluations issued with letters dated November 11, 1987, and May 22, 1989. Safety Evaluation Report (NUREG 0892), Section 9.5.1.7.(3), specifies, in part, By letter dated October 12, 1981, the applicant committed to comply with the technical requirements of Section III.G of Appendix R. Title 10 CFR Part 50, Appendix R, Section III.G.2, requires that where cables or equipment, including associated non-safety circuits that could prevent operation or cause maloperation due to hot shorts, open circuits, or shorts to ground, of redundant trains of systems necessary to achieve and maintain hot shutdown conditions are located within the same fire area outside of primary containment, shall be physically protected from fire damage by one of three specified methods. Contrary to these requirements, the licensee did not properly implement all provisions of the approved fire protection program and 10 CFR Part 50, Appendix R, Section III.G. Specifically, the licensee failed to assure that one train of low pressure coolant injection remained free of fire damage. Specifically, the licensee failed to protect motor-operated valve pairs, (RHR-V-16B and RHR-V-17B; RHR-V-40 and RHR-V-49), from fire damage using one of the physical methods described in Appendix R, Section III.G.2. The licensee had entered this finding into their corrective action program as Condition Report 2-04-06699, established appropriate compensatory measures, and corrected the condition prior to May 2, 2010. Because the violation was associated with multiple fire induced circuit faults and was identified and corrected prior to the end of the discretion period, the NRC is exercising enforcement discretion in accordance with Enforcement Guidance Memorandum 09-002. |
| 05000397/FIN-2010004-04 | 2010Q3 | Columbia | Lack of an Evaluation of the Effect of Fire on the Reactor Protection System/Scram | License Condition 2.C.(14) states, The licensee shall implement and maintain in effect all provisions of the approved fire protection program as described in Section 9.5.1 and Appendix F of the Final Safety Analysis Report (FSAR) for the facility thru Amendment No. 39 and as described in subsequent letters to the staff through November 30, 1988, referenced in the May 22, 1989, safety evaluation and in other pertinent sections of the FSAR referenced in either Section 9.5.1 or Appendix F and as approved in the Safety Evaluation Report issued in March 1982 (NUREG 0892) and in Supplement 3, issued in May 1983, and Supplement 4, issued in December 1983, and in safety evaluations issued with letters dated November 11, 1987 and May 22, 1989. FSAR, Section F.4.3, states, The systems and equipment which are designated as post-fire safe shutdown equipment represent the minimum equipment which is necessary to bring the plant to a safe cold shutdown condition in the event of a fire in any area of the plant. Only that portion of post-fire safe shutdown equipment which is expected to be free of fire damage is credited for post-fire safe shutdown, although other plant systems and equipment could also be available for use after a fire. Contrary to the above, the licensee did not implement the approved fire protection program. The licensee did not assure that the potential effects of fire damage on a required post-fire safe shutdown component would not preclude the ability to bring the plant to cold shutdown. Specifically, fire damage that had the potential to create two simultaneous hot shorts in the mode switch could prevent a reactor scram, and Procedure ABN-CR-EVAC failed to require that operators de-energized the reactor protection system in a timely manner to ensure a full reactor scram resulted prior to emergency depressurization. The licensee had entered this finding into their corrective action program as Condition Reports 2-06-02397 and 2-06-05147, established appropriate compensatory measures, and corrected the condition prior to May 2, 2010. Because the violation was associated with multiple fire induced circuit faults and identified and corrected prior to the end of the discretion period, the NRC is exercising enforcement discretion in accordance with Enforcement Guidance Memorandum 09-002 |
| 05000397/FIN-2016002-01 | 2016Q2 | Columbia | Loss of RCC Cooling Requiring a Reactor Scram | The inspectors reviewed a self-revealed, non-cited violation of Technical Specification 5.4.1.a, Procedures, for the licensees failure to follow procedure OI-41, Operations Work Control Expectations, Revision 59. Specifically, the licensee incorrectly marked steps of procedure OSP-FPC/IST-Q701, Fuel Pool Cooling System Operability Surveillance, Revision 34, as not applicable and therefore did not provide mechanical isolation between the non-safety reactor closed loop cooling system and the safety-related standby service water system. As a result, on March 28, 2016, the reactor closed loop cooling system was momentarily depressurized into the service water system and required a manual reactor scram due to a loss of reactor closed loop cooling for non-safety systems. The licensee entered this issue into their corrective action program as Action Request 346945. The failure to follow procedure OI-41, Operations Work Control Expectations, Revision 59, was a performance deficiency. This performance deficiency was more than minor, and therefore a finding, because it adversely affected the configuration control attribute of the Initiating Events Cornerstone objective of limiting the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Using Inspection Manual Chapter 0609, Attachment 04, Initial Characterization of Findings, and Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 1, Initiating Events Screening Questions, dated June 19, 2012, the inspectors determined 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. The finding had a cross-cutting aspect in the area of human performance associated with avoiding complacency because the licensee failed to recognize and plan for the possibility of mistakes, latent issues, and inherent risk, even while expecting successful outcomes including implementing appropriate error reduction tools. Specifically, licensed operators failed to recognize the possible latent issues and inherent risk of marking large portions of a procedure as not applicable. (H.12) |
| 05000397/FIN-2016002-02 | 2016Q2 | Columbia | Licensee-Identified Violation | Title 10 of the Code of Federal Regulations, Part 50.54(q)(2), requires, in part, that a power reactor licensee follow and maintain the effectiveness of an approved emergency plan which meets the requirements of Appendix E to Part 50, and the planning standards of 10 CFR 50.47(b). The Columbia Emergency Plan, Revision 62, Section 8.7.3, requires a periodic drill involving the response to a simulated injury with contamination. The Columbia Emergency Plan, Revision 62, Table 8-1, defines the drill periodicity as annual. Contrary to the above, between January 1, 2015, and December 31, 2015, Columbia Generating Station failed to follow and maintain the effectiveness of an approved emergency plan which meets the requirements of Appendix E to Part 50, and the planning standards of 10 CFR 50.47(b). Specifically, Columbia Generating Station failed to perform a drill involving the response to a contaminated and injured persons during the annual period, 2015, as required by the Columbia Generating Station Emergency Plan, Revision 62. The violation was more than minor because the performance deficiency adversely affected the Emergency Preparedness cornerstone objective and was associated with the ERO performance cornerstone attribute. The violation was assessed using MC 0609, Appendix B, Emergency Preparedness Significance Determination Process, dated September 23, 2014, and was determined to be of very low safety significance (Green), because it was a failure to comply with NRC requirements, was not a risk-significant planning standard issue, and was not a degraded or lost planning standard function. The violation was entered into the licensees corrective action program as Action Requests 00342463 and 00347490. |
| 05000416/FIN-2013004-01 | 2013Q3 | Grand Gulf | Failure to Follow Procedure Results in Inadequate Operability Determination | The inspectors identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, regarding the licensees failure to follow the requirements of Procedure EN-OP-104, Operability Determinations. Specifically, the inspectors identified that the licensee failed to establish an adequate basis for operability when a degraded or nonconforming condition had been identified. On August 30, 2013, Condition Report CR-GGN-2013-05604 was initiated to document a step change in the standby service water (SSW) siphon line K factor, which is a measure of flow through the siphon line. The K factor could have increased due to air entrapment in the siphon line that resulted from using air to mix the basin water following chemical treatments. The inspectors challenged the validity of the evaluation because the second step change in K factor, from 48 to 64, represented new information that had not been evaluated in the previous condition report. As an immediate corrective action, the licensee re-performed the operability determination and provided an adequate basis of operability by evaluating the system with the additional K factor data. Furthermore, the licensee verified the siphon line did not have any obstructions by observing the SSW basin levels equalize as water flowed through the siphon line. The licensee entered this issue into the corrective action process under Condition Report CR-GGN-2013-05687. The failure to perform an operability determination in accordance with procedure was a performance deficiency. The performance deficiency was more than minor, and is therefore a finding, because it is associated with the equipment performance attribute of the Mitigating Systems Cornerstone and adversely impacted the cornerstone objective of ensuring the reliability, availability and capability of systems that respond to initiating events to prevent undesirable consequences. Using NRC Inspection Manual Chapter 0609, Attachment 4, Initial Characterization of Findings, the inspectors determined that the issue affected the Mitigating Systems Cornerstone. In accordance with NRC Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings at Power, the inspectors determined that the issue has very low safety significance (Green) because all applicable screening questions in Manual Chapter 0609, Appendix A, Exhibit 2, were answered no. The inspectors determined that the apparent cause of this finding was that the licensee had identified and used previously completed operability evaluations without verifying that the previously completed evaluations were fully applicable to the identified conditions. Therefore, the finding had a cross-cutting aspect in the problem identification and resolution area, corrective action program component because the licensee failed to properly evaluate for operability conditions adverse to quality. |
| 05000416/FIN-2013004-02 | 2013Q3 | Grand Gulf | Failure to Obtain NRC Approval for a Change in Method of Evaluation for Determining Reactor Vessel Fluence | The team identified a Severity Level IV non-cited violation of 10 CFR 50.59, Changes, Tests, and Experiments, involving the licensees failure to obtain a license amendment pursuant to 10 CFR 50.90 prior to implementing a new method of evaluation for determining reactor vessel neutron fluence. On November 4, 2003, the NRC issued Amendment Number 160 to the Facility Operating License of the Grand Gulf Nuclear Station. The amendment revised the Updated Final Safety Analysis Report (UFSAR) to change the Reactor Vessel Material Surveillance Program to reflect participation in the Boiling Water Reactor Vessel and Internals Project (BWRVIP) Integrated Surveillance Program (ISP). Additionally, the amendment revised the UFSAR to state that neutron fluence calculations performed after 2002 will be in accordance a methodology that has been approved by the NRC staff and is consistent with the attributes identified in NRC Regulatory Guide 1.190, Calculation and Dosimetry Methods for Determining Pressure Vessel Neutron Fluence. The licensee developed a new neutron fluence calculation method which was based on a neutron fluence calculation method that had been previously approved by the NRC for another facility, which was documented in Nine Mile Point Nuclear Station, Unit No. 1 Issuance of Amendment RE: Pressure-Temperature Limit Curves and Tables, dated October 27, 2003. The NRC identified that the calculation, which was developed for GGNS, used the CASMO-4/SIMULATE code package to calculate the neutron source, whereas the prior calculation performed for Nine Mile Point Nuclear Station (NMP) used the ORIGEN code to calculate the neutron source. The inspectors determined that, although these codes are intended for the same purpose, they are distinct codes and the NRC approved only the use of one neutron source code (i.e., ORIGEN) in the neutron fluence calculation method of evaluation at Nine Mile Point. This finding was entered into the licensees corrective action program as Condition Report CR-GGN-2013-04743. The licensees failure to determine that a change to their method of evaluation for calculating reactor vessel neutron fluence was a departure from a method of evaluation approved by the NRC and required NRC review and approval prior to implementation was a performance deficiency. The performance deficiency was evaluated using traditional enforcement because the finding had the ability to impact the regulatory process. The performance deficiency was more than minor because there was a reasonable likelihood that the change would require NRC review and approval prior to implementation. In accordance with the NRC Enforcement Manual, risk insights from Inspection Manual Chapter 0609, Significance Determination Process, are used in determining the significance of 10 CFR 50.59 violations. Using the Inspection Manual Chapter 0612, Appendix B, Issue Screening, the team determined the finding adversely affected the Barrier Integrity Cornerstone. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, the team determined the finding required a detailed risk evaluation because the finding involved the reactor coolant system boundary. A Senior Reactor Analyst performed the evaluation and determined the finding had very low safety significance (i.e., Green) because the NRC performed calculations and did not determine that the licensees Pressure-Temperature limits had or would have expired or been invalid; therefore, the change in risk was negligible. Since the finding had very low safety significance, the finding was determined to be Severity Level IV, in accordance with the NRC Enforcement Policy. The finding does not have a cross-cutting aspect because cross-cutting aspects are not assigned to traditional enforcement violations. |
| 05000416/FIN-2013004-03 | 2013Q3 | Grand Gulf | Failure to Review Temporary Modifications by Operations Personnel During Turnover | The inspectors identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, regarding the licensees failure to follow the requirements of Procedure 02-S-01-4, Shift Relief and Turnover, Revision 42. Specifically, the licensee failed to ensure proper turnover of the status of temporary modifications installed in the plant was being conducted by operations staff during turnover. The inspectors determined that the operations staff was required by Attachment III of that procedure to review the TMs log prior to taking the shift. The inspectors interviewed the operations staff and asked if the TMs were reviewed prior to taking shift that day. The staff member stated he had not and when asked about Attachment III of the turnover procedure, he was not familiar with that attachment of the procedure. The inspectors interviewed additional operations staff members about the review of temporary modification status during turnover, and they also indicated they had not reviewed temporary modification during turnover. As a corrective action, the licensee added copies of Attachment III of the shift turnover procedure to the operations staff turnover book to ensure TMs were reviewed during shift turnover. The licensee entered this issue into the corrective action process under Condition Reports CR-GGN-2013-04481 and CR-GGN-2013-05955. The failure to review temporary modifications by operations personnel during turnover in accordance with station procedures 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 more significant safety concerns. Specifically, operators not reviewing the status of TMs installed in the plant during turnover could result in a loss of configuration control of plant equipment that could result in an improper response by operators to plant events. Using NRC Inspection Manual Chapter 0609, Attachment 4, Initial Characterization of Findings, the inspectors determined that the issue affected the Mitigating Systems Cornerstone. Using NRC Inspection Manual Chapter 0609, Attachment 4, Table 3, the inspectors were directed to NRC Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power. The inspectors determined that the issue had a very low safety significance (Green) because it was not a deficiency affecting the design or qualification of a mitigating system, structure, or component, does not represent a loss of system or function, does not represent a loss of function for greater than its technical specification allowed outage time, and does not represent a loss of function as defined by the licensees Maintenance Rule program for greater than 24 hours. The inspectors determined the apparent cause of this finding was that licensee personnel were not using Attachment III of the operations turnover procedure. Therefore, the finding has a cross-cutting aspect in human performance area associated with work practices in that the licensee management did not provide proper oversight to ensure a proper turnover was being conducted by operations personnel. |
| 05000416/FIN-2013004-04 | 2013Q3 | Grand Gulf | Failure to Maintain Design Control of the Power Supplies for the Emergency Switchgear and Battery Room Fire Dampers | The inspectors reviewed a self-revealing Green non-cited violation of Facility Operating License Condition 2.C (41), Fire Protection Program, involving the failure to maintain design control of the power supplies for the emergency switchgear and battery room fire dampers. During a surveillance of the division 2 carbon dioxide Fire Damper Actuation System, ten division 1 switchgear and battery room cooler fire dampers were inadvertently closed. Electricians investigated and found that a common ground existed between the division 1 and 2 emergency switchgear and battery room damper control panels. The common ground was determined to originate from a factory installed ground strap connecting the negative terminal to the ground/neutral on the emergency switchgear and battery room damper control power supplies. The licensee reviewed plant drawings and determined that the ground strap on the power supplies should have been removed prior to installation due to this being designed as a non-grounded system. As an immediate corrective action, the licensee removed the factory installed ground straps and restored the system to operable status. The licensee entered this issue into the corrective action process under Condition Report CR-GGN-2013-03827. The failure to verify a new power supply was a like-for-like replacement of the original power supply to ensure the replacement power supply did not alter the design of the damper control system was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it was associated with the configuration control attribute of the Mitigating Systems Cornerstone and adversely impacted the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using NRC Inspection Manual Chapter 0609, Attachment 4, Initial Characterization of Findings, the inspectors determined that the issue affected the Mitigating Systems Cornerstone. Using NRC Inspection Manual Chapter 0609, Attachment 4, Table 3, the inspectors were directed to NRC Inspection Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process. The inspectors determined that the finding had an adverse effect on the fixed fire suppression systems. The inspectors assigned a low degradation rating due to the fact that the automatic fire suppression systems performance and reliability was minimally impacted by the inspection finding. Since the finding was assigned a low degradation rating, it screened as being of very low safety significance (Green). The apparent cause of this finding was the procurement engineering evaluation did not verify the replacement power supplies met the design requirements to be compatible with the unique design of the emergency switchgear and battery room damper control system. Therefore, the finding had a cross-cutting aspect in the area of human performance, work practices component because the licensee failed to properly perform a procurement evaluation in accordance with station procedures. |
| 05000416/FIN-2013004-05 | 2013Q3 | Grand Gulf | Failure to Implement the Offsite Dose Calculation Manual | Inspectors identified three examples of a non-cited violation of Technical Specification 5.5, Programs and Manuals, for failure to maintain and implement requirements of the offsite dose calculation manual (ODCM). Specifically, the licensee failed to: (1) adequately document and justify ODCM changes, (2) approve licensee initiated changes to the ODCM, and (3) implement the radiological effluent controls for liquid releases. The violation was entered into the licensees corrective action program as Condition Report CR-GGN-2013- 05039, and the licensee is evaluating the issue to determine the proper corrective action. Failure to implement the requirements of the offsite dose calculation manual is a performance deficiency. This performance deficiency is more than minor because it affected the Public Radiation Safety Cornerstone attribute of program and process because the failure to adequately justify and approve offsite dose calculation manual changes resulted in 49 liquid effluent releases, contrary to the licensees Offsite Dose Calculation Manual, Revision 37, requirements. Using Inspection Manual Chapter 0609, Appendix D, Public Radiation Safety Significance Determination Process, dated February 12, 2008, the inspectors determined this to be a violation of very low safety significance (Green). The violation was in the effluent release program but was not a substantial failure to implement the effluent program, and the dose to the public did not exceed the 10 CFR Part 50 Appendix I criterion or 10 CFR 20.1301(e) limits. The violation had a cross-cutting aspect in the human performance area associated with the resources component because the licensee failed to ensure the individuals preparing and reviewing offsite dose calculation manual changes had sufficient knowledge of the effluent release control system, its components, and its function to adequately evaluate the impact of the change. |
| 05000416/FIN-2013004-06 | 2013Q3 | Grand Gulf | Failure to Include Some Solid Radwaste Released in the 2012 Regulatory Guide 1.21 Annual Effluent Report | Inspectors identified a non-cited violation of Technical Specification 5.6.3 because the licensee failed to include in the 2012 Annual Radiological Effluent Release Report some solid radioactive waste released to an offsite waste processor. The failure to include in the 2012 Annual Radiological Effluent Release Report all solid radioactive waste released to an offsite waste processor was a performance deficiency, contrary to Technical Specification 5.6.3. The violation was determined to be more than minor because it was associated with the Public Radiation Safety Cornerstone attribute of program and process and adversely affected the cornerstone objective to ensure adequate protection of public health and safety from exposure to radioactive materials released into the public domain as a result of routine civilian nuclear reactor operation, in that some licensed radioactive material, which left the Grand Gulf Nuclear Station, was unaccounted for. Using Inspection Manual Chapter 0609, Appendix D, \"Public Radiation Safety Significance Determination Process,\" dated February 12, 2008, the inspectors determined the violation to be of very low safety significance because, although it was a radioactive material control issue, it was not a transportation issue, and it did not result in public dose greater than 0.005 rem. The violation had a cross-cutting aspect in the human performance area, work control component because the licensee did not appropriately coordinate work activities by incorporating actions to address the need for work groups to communicate and coordinate with each other during activities in which interdepartmental coordination was necessary to assure human performance. |
| 05000416/FIN-2013004-07 | 2013Q3 | Grand Gulf | Failure to Follow Alarm Response Steps to Restore the TSE Following Maintenance | The inspectors reviewed a Green self-revealing finding for the failure to follow Procedure 04-1-02-1H13-P680-9A, TSE INFL OFF, Revision 36; in that operations personnel did not verify steps were followed per this alarm response procedure prior to returning the turbine thermal stress evaluator (TSE) to service following maintenance activities. The failure to follow alarm response procedure then resulted in an automatic reactor scram on July 30, 2013. Site personnel determined that the scram was caused by high reactor pressure resulting from the turbine unloading beyond the capability of the bypass valves after restoring the TSE to service following maintenance. On July 26, 2013, the control room received an alarm TSE-STU CAB FAIL. The licensee failed to determine the correct cause of the alarm due to inadequate troubleshooting. Therefore, when the maintenance was completed and the TSE was returned to service, the turbine started to unload resulting in a reactor scram due to reactor vessel high pressure. The immediate corrective actions included determining the cause of the scram and taking actions to restore equipment prior to plant startup. The licensee documented this issue in their corrective action program as Condition Report CR-GGN-2013-04943. The failure to follow alarm response steps to restore the TSE following maintenance is a performance deficiency. Specifically, Procedure 04-1-02-1H13-P680-9A, TSE INFL OFF, Revision 36, step 4.1 requires operational personnel to ensure that the TSE is functioning correctly following maintenance prior to restoring to service. The performance deficiency is more than minor, and therefore a finding, because it is associated with the Initiating Events Cornerstone attribute of human performance and adversely affected the associated cornerstone objective to limit the likelihood of those events that upset plant stability and that challenge critical safety functions during power operations. Using NRC Inspection Manual Chapter 0609, Attachment 4, Initial Characterization of Findings, the inspectors determined that the issue affected the Initiating Events Cornerstone. In accordance with NRC Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, the inspectors determined that the issue has a very low safety significance (Green) because it only caused a reactor trip and did not cause a loss of mitigating equipment relied on to transition the plant from the onset of a trip to a stable shutdown condition. The inspectors determined that the apparent cause of the finding was that the licensee did not troubleshoot to validate the cause for alarm TSE STU Cab Failure in accordance with station troubleshooting procedures. Therefore, the finding has a cross-cutting aspect in the area of human performance associated with the work practices component because the licensee did not use the troubleshooting process effectively. |
| 05000416/FIN-2013004-08 | 2013Q3 | Grand Gulf | Licensee-Identified Violation | Title 10 CFR 50.54(q) requires, in part, that licensees follow and maintain the effectiveness of an emergency plan that meets the requirements in the planning standards of 50.47(b). Title 10 CFR 50.47(b)(4) requires a standard emergency classification and action level scheme is in use by the nuclear facility licensee. Contrary to the above, the licensee failed to use the emergency classification and action level scheme to classify an event. Specifically, the licensee incorrectly used the emergency classification and action level scheme on May 12, 2013, by declaring a Notice of Unusual Event (NOUE) when an electrical transformer was thought to be on fire. The licensee, during a subsequent investigation, determined that the event was not a fire. This finding was more than minor because over classification potentially puts the public at risk and affected the Emergency Preparedness Cornerstone attribute of emergency response organization performance. The finding was evaluated by the Emergency Preparedness Significance Determination Process and determined to be of very low safety significance (Green) because it was a failure to comply with the NRC requirements and was not a loss of planning standard function. The planning standard function was not lost because the emergency classification and action level scheme basis has not changed. This finding was entered into the licensees corrective action program as Condition Report CR-GGN-2013-4156. |
| 05000416/FIN-2013201-01 | 2013Q2 | Grand Gulf | 10 CFR 54.13 Apparent Violation for failure to provide complete and accurate information in response to RAIs | This letter refers to the evaluations by the U.S. Nuclear Regulatory Commission (NRC) Office of Nuclear Reactor Regulation (NRR) of responses dated May 25,2012, provided by Entergy Operations, Inc. (EOI), to requests for additional information (RAls) associated with the license renewal application for the Grand Gulf Nuclear Station. The responses pertained to requests by the NRC regarding the site\'s implementation of aging management activities for components included in two aging management programs. The NRC evaluation identified one apparent violation of NRC requirements that is being considered for escalated enforcement action in accordance with the NRC Enforcement Policy. The NRC evaluation determined that EOI apparently failed to provide complete and accurate information to the NRC in responses dated May 25, 2012, to RAls B.1.22-1, B.1.22-2, and B.1.41-3. The three RAls addressed several issues with the aging management activities for the Flow-Accelerated Corrosion program and the Service Water Integrity program. The license renewal application stated that both of these programs were consistent with the corresponding programs described in NUREG-1801, \"Generic Aging Lessons Learned (GALL) Report.\" However, during its reviews of operating experience associated with these programs, the staff found indications that aspects of these programs were inconsistent with corresponding programs in the GALL Report. Enforcement is not being considered for the statements in the initial license renewal application, but for the apparent incomplete or inaccurate information in the responses to RAls intended to evaluate potential inconsistencies with the programs in the GALL Report. The RAI responses were material because the NRC needed the requested information to verify that certain components would be adequately managed for erosion mechanisms so that the intended functions will be maintained consistent with the current licensing basis, as required by 10 CFR 54.21 (a)(3). Therefore, EOI appears to be in violation of 10 CFR 54.13. |
| 05000416/FIN-2014005-01 | 2014Q4 | Grand Gulf | Failure to Assure Quality Installation on RCIC Steam Line | The inspectors reviewed a self-revealing non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for failure to assure quality installation of the steam line tubing of the reactor core isolation cooling (RCIC) system. Specifically, the licensee failed to assure that rated performance limits of the ferrule connection, installed at the tee between the steam line and the pressure transmitter tube line, were met during initial installation. This failure resulted in an unplanned inoperability of the RCIC system. The licensee entered this issue into the corrective action program as Condition Report CR-GGN-2014-06792. As an immediate corrective action, the licensee replaced the tubing, the failed transmitter, and recalibrated the instruments. Furthermore, the licensee revised their system operation procedure for the RCIC system. This revision requires all steam isolation valves to be closed during this test, and that system recovery starts by opening Valve 1E51F076 (warming bypass valve around the 1E51F063) to allow adequate warming of the steam lines after isolation. The inspectors determined that the failure to assure quality installation of the ferrule connection on the steam line flow Transmitter 1E31N083B was a performance deficiency. The performance deficiency is more than minor and therefore a finding because it is associated with the design control attribute of the Mitigating Systems Cornerstone. Specifically, failure to assure steam lines in the RCIC system meet rated performance limits, may result in the unavailability and unreliability of a system that is relied upon to respond to initiating events to prevent undesirable consequences. Using NRC Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process for Findings at Power, dated June 19, 2012, the inspectors determined that the issue required a detailed risk evaluation by the regional senior reactor analyst. This was because the finding represented an actual loss of a safety function due to the RCIC system being a single train system that was out of service for approximately 40 hours for repairs. The senior reactor analyst determined the change to the core damage frequency was 8.7E-8/year, and since the change to core damage frequency was less than E-7, no evaluation of external events or the large early release frequency was required. The finding was of very low safety significance (Green). The inspectors did not identify a cross-cutting aspect, as the performance deficiency is not reflective of current plant performance. |
| 05000416/FIN-2014005-02 | 2014Q4 | Grand Gulf | Licensee-Identified Violation | Title 10 of the Code of Federal Regulations, Appendix E to Part 50, Section V, Implementing Procedures states, in part, that licensees who are authorized to operate a nuclear power facility shall submit any changes to the emergency plan or procedures to the Commission, as specified in 10 CFR 50.4, within 30 days of such changes. Title 10 of the Code of Federal Regulations, Section 50.54(q)(5) states, in part, that licensees shall submit a report of changes made after February 21, 2012, that includes a summary of its analysis, within 30 days after the change is put into effect. Contrary to the above, Grand Gulf Nuclear Station did not submit changes to emergency plan implementing procedures within 30 days of such changes, and did not submit a summary of its analysis of the changes within 30 days after the changes were put into effect. Specifically, the license did not submit changes to the following procedures; EN-EP-305, Emergency Planning 10CFR50.54(Q) Review Program, Revision 3, EN-EP-306, Drills and Exercises, Revisions 4 and 5, EN-EP-307, Hostile Action Based Drills and Exercises, Revision 2, EN-EP-308, Emergency Planning Critiques, Revision 2, EN-EP-310, Emergency Response Organization Notification System, Revisions 1 through 3, EN-EP-311, Emergency Response Data System (ERDS) Activation Via the Virtual Private Network (VPN), Revision 2, EN-EP-313, Offsite Dose Assessment Using the Unified RASCAL Interface, Revision 0, EN-EP-801, Emergency Response Organization, Revision 8, EN-TQ-110, Emergency Response Organization Training, Revision 7, and EN-TQ-110-01, Fleet E-Plan Training Course Summary, Revision 10. The licensee did not have a process to ensure that fleet procedures necessary to implement the site emergency plan were submitted to the NRC in accordance with the requirements of Appendix E to 10 CFR 50. This violation was evaluated using the NRC Enforcement Policy because the licensees failure to submit required procedures affected the NRCs ability to perform adequate regulatory oversight. The significance of the violation was evaluated at Severity Level IV (Section 6.6.d of the Enforcement Policy) because it did not affect the licensees ability to perform notification or assessment during an emergency. This issue has been entered into the licensees corrective action program as Condition Reports CR-HQN-2014-00380, CR-HQN-2014-00597, and CR-GGN-2014-05539. |
| 05000416/FIN-2015004-01 | 2015Q4 | Grand Gulf | Failure to Have Appropriate Instructions for Preventative Maintenance on the Division I Diesel Generator Simulated Run | The inspectors reviewed a self-revealing non-cited violation of Technical Specification 5.4.1.a, for the failure to establish adequate instructions to perform a simulated surveillance on the division I diesel generator. Specifically, the simulated surveillance run instructions verified the trip high vibration (E-23H) valve was open, but it did not close the (E-23H) valve following the run to ensure the high vibration trip was bypassed. As a result, the division I diesel generator spuriously tripped on high vibrations during the November 21, 2015, run and was rendered inoperable and unavailable. On November 22, 2015, the licensee closed the trip high vibration (E-23H) valve and successfully ran the division I diesel generator to return it to operable status. The licensee entered this issue into their corrective action program as Condition Report CR-GGN-2015-6831. The failure to establish adequate preventative maintenance instructions to perform a division I diesel generator simulated run and return the valve lineup to the required position was a performance deficiency. This performance deficiency is more than minor, and therefore a finding, because it is 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, following the division I diesel generator simulated run, the preventative maintenance instruction did not require the licensee to close the trip high vibration (E-23H) valve, and therefore the high vibration trip capability remained for a duration of approximately 16 hours. As a result, during the November 21, 2015 run, the diesel generator spuriously tripped on an invalid high vibration signal and was rendered inoperable and unavailable. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, and Inspection Manual Chapter 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, the inspectors determined that the finding is of very low safety significance (Green) because it: (1) was not a deficiency affecting the design or qualification of a mitigating structure, system, or component, and did not result in a loss of 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 technical specification allowed outage time, or two separate safety systems out-of-service for longer than their technical specification allowed outage time; and (4) did not represent 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. The inspectors determined that the finding has a design margin cross-cutting aspect within the human performance area because the licensee failed to ensure margins are carefully guarded and changed only through a systematic and rigorous process. Specifically, the licensee failed to fully implement their design change process such that all effected station documents and procedures were identified and revised after removing the high vibration trip for the division I and division II diesel generators (H.6). |
| 05000416/FIN-2015004-02 | 2015Q4 | Grand Gulf | Failure to Timely Enter Technical Specification Surveillance Requirement 3.0.1 | The inspectors identified a non-cited violation of Technical Specification Surveillance Requirement 3.0.1, for the failure to follow requirements when a surveillance was not performed within the specified frequency and declare the Limiting Condition for Operation not met or follow the provisions in Surveillance Requirement 3.0.3. Specifically, the licensee did not follow Technical Specification Surveillance Requirement 3.0.1, when they discovered that Surveillance Requirement 3.8.1.9 was not performed within its specified frequency and either declare Technical Specification Limiting Condition for Operation 3.8.1 not met, or perform the required actions to determine whether compliance with the requirement to declare the Limiting Condition for Operation not met may be delayed. The licensee failed to enter Technical Specification Surveillance Requirement 3.0.1, until September 29, 2015, after discussions with the NRC. On September 29, 2015, the licensee adequately performed the actions required in Technical Surveillance Requirement 3.0.3. The licensee entered this issue into their corrective action program as Condition Report CR-GGN-2015-5602. The failure to timely enter and perform the actions as required per Technical Specification Surveillance Requirement 3.0.1 was a performance deficiency. This performance deficiency is more than minor, and therefore a finding, because it is 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 perform technical specification surveillance requirements, and associated actions, did not ensure that the diesel generator could appropriately respond to initiating events. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, and Inspection Manual Chapter 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, the inspectors determined that the finding is of very low safety significance (Green) because it: (1) was not a deficiency affecting the design or qualification of a mitigating structure, system, or component, and did not result in a loss of 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 technical specification allowed outage time, or two separate safety systems out-of-service for longer than their technical specification allowed outage time; and (4) did not represent 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. The inspectors determined that the finding has a conservative bias cross-cutting aspect within the human performance area because the licensee failed to use decision makingpractices that emphasize prudent choices over those that are simply allowable. Specifically, operations personnel failed to enter Technical Specification Surveillance Requirement 3.0.1 because the operability determination alone justified operability without doing a detailed risk evaluation (H.14). |
| 05000416/FIN-2015004-03 | 2015Q4 | Grand Gulf | Failure to Make a Required Eight-Hour Report for Loss of Safety Function | The inspectors identified a Severity Level IV, non-cited violation of 10 CFR 50.72(b)(3)(v)(C), for the licensees failure to make a required eight-hour report to the NRC for a condition that could have prevented fulfillment of the safety function of structures or systems that are needed to control the release of radioactive material. Specifically, on October 14, 2015, the licensee failed to make the required eight-hour report following two primary containment isolation valves, 1P11F130 and 1P11F131, in the same flow path being declared inoperable. On October 15, 2015 at 9:07 pm, the licensee made a late Event Notification, EN 51473. The licensee entered this issue into their corrective action program as Condition Report CR-GGN-2015-6043. The failure to make an eight-hour report, as required by 10 CFR 50.72(b)(3)(v)(C), for a condition that could have prevented fulfillment of a safety function was a performance deficiency. This performance deficiency was screened using Inspection Manual Chapter 0612 and was determined to be a minor violation in the Reactor Oversight Process. However, due to the performance deficiency affecting the NRCs ability to perform its regulatory oversight function, this performance deficiency was evaluated for traditional enforcement in accordance with the NRC Enforcement Policy. This performance deficiency was determined to be a Severity Level IV violation in accordance with Section 6.9.d.9 of the NRC Enforcement Policy, dated February 4, 2015. No cross-cutting aspect was assigned to this violation because no Reactor Oversight Process finding existed. |
| 05000416/FIN-2015004-04 | 2015Q4 | Grand Gulf | Failure to Establish Adequate Maintenance Instructions to Perform Work Activities on the Division III Diesel Generator Overspeed Trip Limit Switch | The inspectors reviewed a self-revealing non-cited violation of Technical Specification 5.4.1.a, for the failure to establish adequate maintenance instructions to perform work activities on the division III diesel generator overspeed trip limit switch. Specifically, work orders did not contain adequate instructions to check the overspeed trip switches alignment in accordance with vendor recommendations. As a result, the division III diesel generator was rendered inoperable and unavailable. On July 15, 2015, the licensee appropriately set the limit switch to overspeed actuating arm engagement, and returned the diesel generator to operable. The licensee entered this issue into their corrective action program as Condition Report CR-GGN-2015-3985. The failure to establish adequate work instructions to verify the overspeed switch was properly set and adjusted was a performance deficiency. This performance deficiency is more than minor, and therefore a finding, because it is 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, work orders to check the overspeed trip switches alignment did not contain adequate instructions to successfully perform the maintenance. The division III diesel generator was declared inoperable when the diesel spuriously tripped during the monthly surveillance run on July 13, 2015. The inspectors performed the initial significance determination for the division III emergency diesel generator failure. The inspectors used the NRC Inspection Manual 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions. The finding required a detailed risk evaluation because it involved a performance deficiency that represented a loss of the high pressure core spray system following a postulated loss of offsite power because of the failure of the division III diesel generator. The Region IV senior reactor analyst performed a detailed risk evaluation in accordance with NRC Inspection Manual 0609, Appendix A, Section 6.0, Detailed Risk Evaluation. The detailed risk evaluation result is a finding of very low safety significance (Green). The calculated change in core damage frequency of 5.0 x 10-7 was dominated by an unrecovered station blackout beyond battery depletion. The analyst determined that the bounding risk of a large, early release of radiation was 9.6 x 10 . For the details of the analysis, see Attachment 3. Work orders were developed to address operating experience provided from the diesel generator vendor to the industry in December 2011. The inspectors determined that the cause of the deficiency occurred in 2011, and therefore, determined the finding did not have a cross-cutting aspect since it is not indicative of current licensee performance. |
| 05000416/FIN-2015004-05 | 2015Q4 | Grand Gulf | Licensee-Identified Violation | Technical Specification 3.6.1.3, Surveillance Requirement 3.6.1.3.9, requires, verification of combined leakage rate of 1 gallon per minute times the total number of primary containment isolation valves through hydrostatically tested lines that penetrate the primary containment is not exceeded when these isolation valves are tested at greater than or equal to 1.1 times peak containment pressure. Contrary to the above, since June 6, 2012, the licensee failed to verify combined leakage rate of 1 gallon per minute times the total number of primary containment isolation valves through hydrostatically tested lines that penetrate the primary containment is not exceeded when these isolation valves are tested at greater than or equal to 1.1 times peak containment pressure. Specifically, the post-extended power uprate peak containment pressure analyzed increased to 14.8 psig, resulting in a new required test pressure of 16.28 psig. The licensee did not test primary containment isolation valves 1P11F130 and 1P11F131 using the new higher pressure. The licensee subsequently declared the valves inoperable and tested the two valves using the new peak containment pressure. The valves passed the surveillance test and were declared operable at 11:01 am on October 15, 2015. This finding was entered in the licensee's corrective action program as Condition Report CR-GGN-2015-05072. The finding is more than minor 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 (containment) protect the public from radionuclide releases caused by accidents or events. Specifically, the licensee never performed Technical Specification Surveillance Requirement 3.6.1.3.9, and therefore did not have presumption of operability to provide the reasonable assurance that containment would protect the public from radionuclide releases caused by accidents or events. The significance of the finding was assessed using Inspection Manual Chapter 0609, Appendix A, Exhibit 3, Barrier Integrity Screening Questions, and it was determined to be of very low safety significance (Green). |
| 05000416/FIN-2015004-06 | 2015Q4 | Grand Gulf | Licensee-Identified Violation | Title 10 CFR 50.54(hh)(1)(iv) and (vi) require, in part, that licensees implement onsite actions necessary to enhance the capability of the facility to mitigate the consequences of an aircraft impact; and procedures for dispersal of equipment and personnel. Regulatory Guide 1.214, "Response Strategies for Potential Aircraft Threats," Section 7.1, states that to meet the dispersal requirement, licensee should include security personnel for accomplishing post-impact meditative actions in aircraft threat procedures. It further states, to include suitable locations to which those resources can be repositioned to increase survivability. Contrary to the above, on October 21, 2015, during the Grand Gulf Nuclear Station's biennial NRC evaluated exercise, the licensee failed to implement onsite actions necessary to enhance the capability of the facility to mitigate the consequences of an aircraft impact and did not have procedures for the dispersal of equipment and personnel. Specifically, during an emergency preparedness exercise observed by NRC, the licensee had not established an adequate process to use upon receiving potential aircraft threat warnings (simulated) from the NRC, to decide when or if to disperse or reposition security personnel to increase survivability. This finding was entered in the licensee's corrective action program as Condition Report CR-GGN-2015-06195. The finding is more than minor because if left uncorrected, it would have the potential to lead to a more significant security or safety concern; this failure could potentially and adversely affect survivability of security response personnel in the flight path of a potential aircraft threat as well as the capability to take appropriate actions to ensure adequate security resources when mitigating the consequences of an aircraft impact. The significance of the finding was assessed using NRC IMC 0609, Appendix E, Part I, Baseline Security Significance Determination Process, and it was determined to be of very low security significance (Green). |
| 05000416/FIN-2017002-01 | 2017Q2 | Grand Gulf | Failure to Establish an Appropriate Preventative Maintenance Procedure for the HPCS Jockey Pump | Green . The inspectors reviewed a self -revealed, non- cited violation of Technical Specification 5.4.1.a, for the licensees failure to establish appropriate procedural instructions for performing preventative maintenance on the high pressure core spray jockey pump. Specifically, on January 27, 2017, the high pressure core spray jockey pump failed because the licensee did not establish a preventative maintenance procedure that prescribes oil analysis and additional performance trending for the high pressure core spray jockey pump every 6 months consistent with the licensees preventative maintenance strategy template. On January 29, 2017, the licensee completed repairs and returned the high pressure core spray jockey pump and high pressure core spray system to operable status . The licensee has also incorporated oil analysis and performance trending into the preventative maintenance for jockey pumps. This issue has been entered into the licensees corrective action program as Condition Report CR -GGN -2017- 0917. The failure to establish appropriate preventative maintenance instructions for the high pressure core spray jockey pump was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, 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 establish appropriate preventative and predictive maintenance work instructions resulted in the unplanned inoperability and unavailability of the high pressure core spray system. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At -Power, dated June 19, 2012, and Inspection Manual Chapter 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, the inspectors determined that the finding resulted in a loss of system and/or function; therefore, a detailed risk evaluation was performed. A senior reactor analyst performed a detailed risk evaluation in accordance with Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings at Power. The NRC determined that the increase in core damage frequency for internal initiators was 1.59 E-7/year, and a bounding analysis of external initiators indicated that these events would not result in a 3 change in the color of the finding. Therefore, this finding is of very low safety significance (Green). The analyst also determined that an estimation of large early release frequency (LERF) was required. The result was an increase in LERF of 3.19E -8/year, which is of very low safety significance for LERF (Green). This finding had a cross -cutting aspect in the area of human performance associated with consistent process because the licensee did not use a consistent, systematic approach to make decisions. Specifically, the licensee did not use a consistent approach in developing a preventative maintenance strategy for the high pressure core spray jockey pump by utilizing the approved preventative maintenance strategy template (H.13). |
| 05000416/FIN-2017002-02 | 2017Q2 | Grand Gulf | Licensee-Identified Violation | Title 10 CFR 72.44(d)(3) requires, in part, that an annual report be submitted to the Commission, specifying the quantity of each of the principal radionuclides released to the environment in liquid and in gaseous effluents during the previous 12 months of operation and such other information as may be required by the Commission to estimate maximum potential radiation dose commitment to the public resulting from effluent releases. The report must be submitted within 60 days after the end of the 12- month monitoring period. Contrary to the above, from March 2, 2017 , until April 27, 2017, the licensee did not submit the annual report within 60 days after the end of the 12- month monitoring period. The NRCs significance determination process is not designed to assess the significance of violations that impact or impede the regulatory process. Therefore, the issue of an untimely annual report submittal was assessed using the traditional enforcement process in accordance with the Enforcement Policy. The inspectors determined the violation to be at Severity Level IV because the licensee submitted the annual report approximately 2 months late, and it is similar to examples in the Enforcement Policy , Section 6.9.d. Since this issue was entered into the licensees corrective action program as Condition Report CR-GGN-1-2017-03092 , compliance was restored within a reasonable period of time, the violation was not repetitive, and the violation was not willful, this violation is being treated as a n on-cited violation (NCV), consistent with Section 2.3.2.a of the Enforcement Policy. Traditional enforcement violations are not assigned a cross -cutting aspect . |
| 05000416/FIN-2017002-03 | 2017Q2 | Grand Gulf | Licensee-Identified Violation | License Condition 2.C (46)(f) requires, during the first two scheduled refueling outages after reaching full EPU (extended power uprate) conditions, Entergy shall conduct a visual inspection of all accessible, susceptible locations of the steam dryer in accordance with BWRVIP -139 and GE inspection guidelines. Entergy shall report the results of the visual inspections of the steam dryer to the NRC staff within 60 days following startup. Contrary to the above, on August 16, 2012 , and May 15, 2014, the licensee did not report the results of the visual inspections of the steam dryer to the NRC staff within 60 days following startup. The NRCs significance determination process is not designed to assess the significance of violations that impact or impede the regulatory process. Therefore, the issue of an untimely inspection results submittal was assessed using the traditional enforcement process in accordance with the Enforcement Policy. The inspectors determined the violation to be at Severity Level IV because it is similar to examples in the Enforcement Policy Section 6.9.d. Since this issue was entered into the licensees corrective action program as Condition Report CR -GGN -1-2017 -03404, compliance was restored within a reasonable period of time, the violation was not repetitive, and the violation was not willful, this violation is being treated as a n on-cited violation (NCV), consistent with Section 2.3.2.a of the Enforcement Policy. Traditional enforcement violations are not assigned a cross -cutting aspect. |
| 05000416/FIN-2017002-04 | 2017Q2 | Grand Gulf | Licensee-Identified Violation | License Condition 2.C (46)( g) requires, at the end of the second refueling outage following the implementation of the EPU, the licensee shall submit a long- term steam dryer inspection plan based on industry operating experience along with the baseline inspection results f or NRC review and approval. Contrary to the above, since May 15, 2014, the licensee did not submit a long -term steam dryer inspection plan based on industry operating experience along with the baseline inspection results for NRC review and approval. The NRCs significance determination process is not designed to assess the significance of violations that impact or impede the regulatory process. Therefore, the issue of an untimely inspection plan submittal was assessed using the traditional enforcement process in accordance with the Enforcement Policy. The inspectors determined the violation to be at Severity Level IV because it is similar to examples in the Enforcement Policy Section 6.9.d. Since this issue was entered into the licensees corrective action program as Condition Report CR -GGN -1-2017 -03404, compliance was restored within a reasonable period of time, the violation was not repetitive, and the violation was not willful, this violation is being treated as a n on-cited violation (NCV), consistent with Section 2.3.2.a of the Enforcement Policy. Traditional enforcement violations are not assigned a cross -cutting aspect. |
| 05000416/FIN-2017002-05 | 2017Q2 | Grand Gulf | Licensee-Identified Violation | Title 10 CFR 50.72(b)(2)(iv)(B) requires, in part, the licensee shall notify the NRC as soon as practical , and in all cases within 4 hours of the occurrence, of any event or 24 condition that results in actuation of the reactor protection system (RPS) when the reactor is critical. Contrary to the above, on April 4, 2017, the licensee did not notify the NRC within 4 hours of the occurrence of any event or condition that resulted in actuation of the RPS when the reactor was critical. Specifically, the licensee failed to notify the NRC within 4 hours after they performed a manual scram of the reactor due to a failure in the condensate system. The NRCs significance determination process is not designed to assess the significance of violations that impact or impede the regulatory process. Therefore, the issue of an untimely notification was assessed using the traditional enforcement process in accordance with the Enforcement Policy. The inspectors determined the violation to be at Severity Level IV in accordance with Enforcement Policy Section 6.9.d.9. Since this issue was entered into the licensees corrective action program as Condition Report CR -GGN -1-2017 -03331, compliance was restored within a reasonable period of time, the violation was not repetitive, and the violation was not willful, this violation is being treated as a non-cited violation (NCV), consistent with Section 2.3.2.a of the Enforcement Policy. Traditional enforcement violations are not assigned a cross -cutting aspect. |