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05000352/FIN-2018010-012018Q3LimerickMinor ViolationDuring this inspection, the team reviewed the details and status of Exelons corrective actions. Relative to EDG voltage, the TSs specified a lower limit of 4160 Vac; however, Exelons existing analysis determined the lower EDG voltage limit should be 4235 Vac. Exelon determined that this higher voltage value was necessary in order to ensure full EDG operability and qualification when considering a specific criteria (voltage drop during the loading sequence) as per NRC Regulatory Guide 1.9, Application and Testing of Safety-Related Diesel Generators in Nuclear Power Plants. The team determined that there was not an operability concern because Exelon determined that, although the voltage drop during the starting of the largest electrical load was slightly below the Regulatory Guide 1.9 value, all required loads would, in fact, successfully start and run as designed when started at the 4160 Vac level. Further, the EDG voltage regulators are designed and calibrated to operate the EDGs at 4235 Vac. Notwithstanding, the team identified that the associated EDG surveillance procedures did not contain the higher, administrative limit of 4235 Vac as an acceptance criterion (4160 Vac was specified). The team reviewed this issue using Inspection Manual Chapter 0612, Appendix B, Issue Screening, and determined that the use of non-conservative acceptance criterion was a minor procedure violation because the EDGs were controlled and operated to maintain voltage at 4235 Vac (and 4160 Vac does not render the EDGs inoperable), and EDG reliability or availability were not adversely affected. Exelon entered this minor violation in their corrective action program as IR 4164579 to document and correct this deficiency. For EDG frequency, the TSs allowed an acceptance band (58.8 61.2 Hertz), which is a range typical of EDG transient loading conditions. However, as described in WCAP-17308-NP, and as determined by Exelon engineering staff, a more narrow band (59.9 60.2 Hertz) is the appropriate operating range for steady state EDG operation. Exelon has appropriately maintained the narrow band as the acceptance criteria in the associated EDG surveillance procedures (compensatory action until TSs are revised). However, during this inspection, the team identified that in 2016, Exelon had slightly widened the acceptable band a one-tenth hertz to 59.8 60.2 Hertz. Further review by the team identified that this change was not properly evaluated in accordance with Exelons procedure change process. In particular, the procedure change received a less rigorous review than a 10 CFR 50.59 screen would have provided; and the team concluded that this screen should have been performed. In response, Exelon evaluated past surveillance results and analyzed the lower frequency value of 59.8 Hertz, and determined there to be no adverse consequence at 59.8 Hertz. The team reviewed Exelons analysis and similarly concluded that there was no adverse safety impact. The team reviewed this issue using Inspection Manual Chapter 0612, Appendix B, Issue Screening, and determined that the improper procedure change was a minor procedure violation because there were no adverse consequences and EDG reliability or availability were not adversely affected. Exelon entered this minor violation in there corrective action program as IR 4160819 and IR 4161542 to document and correct this deficiency.
05000336/FIN-2018003-012018Q3MillstoneFailure to Assure that Safety-Related Service Water Piping Conformed to the Procurement DocumentsThe inspectors identified a Green finding and associated non-cited violation (NCV) of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion VII, Control of Purchased Material, Equipment, and Services, when the licensee failed to identify that a replacement service water pipe spool (JGD-1-25) was not in conformance with the American National Standards Institute (ANSI) B31.1 code, a condition of the purchase order, and was installed in the plant.
05000286/FIN-2018002-012018Q2Indian PointReactor Pressure Boundary Leakage Due to Weld Failure in Reactor Vessel Head Penetration #3A self-revealing Severity Level IV NCV of Technical Specification (TS) 3.4.13.a, Reactor Coolant System Operational Leakage, was identified when Entergy operated the reactor in Mode 1 with pressure boundary leakage for a period of time longer than the allowable limiting condition of operation. Specifically, a leak in the J-weld around reactor pressure vessel (RPV) head penetration #3 occurred during the last operating cycle and was not identified until after the reactor was shutdown for a refueling outage.
05000244/FIN-2018011-022018Q1GinnaFailure to Procedurally Verify Fuel Transfer Cart Results in Fuel Interference EventA self-revealing Green non-cited violation (NCV)of Technical Specification 5.4.1.a, Procedures, was identified for the failure of Exelon to operate refueling equipment in accordance with technical procedures in April and May of 2017, which resulted in a fuel interference event, damage to the rod cluster control assembly, and the need for a detailed inspection of a fuel assembly
05000244/FIN-2018011-012018Q1GinnaPotential Preconditioning of Turbine Driven Auxiliary Feedwater Surveillance TestingThe NRC identified a Green non-cited violation (NCV) of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion XI, Test Control, because Exelon established unevaluated preconditioning, with a reasonable doubt of whether the preconditioning was acceptable, prior to testing of the turbine driven auxiliary feedwater pump. This results in the loss of as-found conditions which challenge the capability of the test to assure that the turbine driven auxiliary feedwater pump will perform satisfactorily in service.
05000423/FIN-2017004-012017Q4MillstoneFailure to Maintain RCS Pressure during Solid Plant CooldownA self-revealed NCV of very low safety significance (Green) of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified wherein, on October 13, 2017, Dominion failed to accomplish an activity affecting quality, Plant Cooldown, in accordance with approved procedures. Specifically, during solid plant cooldown, over the course of 18 seconds, reactor coolant system (RCS) pressure increased from 350 psia to 472 psia, which exceeded the limit of 435 psia established by Attachment 1, RCS Cooldown Curves, of operating procedure OP 3208, Plant Cooldown, Revision 028. Dominion operations staff took prompt actions to restore RCS pressure within limits and completed a required engineering evaluation to determine the effect of the out of limit condition on the structural integrity of the RCS. Dominion entered this issue into the corrective action program (CAP) as condition report (CR) 1080842 and completed a root cause evaluation of the event. This finding was determined to be more than minor because it adversely affected the configuration control attribute of the Barrier Integrity cornerstone objective to provide reasonable assurance that physical design barriers (RCS) protect the public from radionuclide releases caused by accidents or events. The inspectors evaluated the finding using IMC 0609, Appendix G, Attachment 1, Shutdown Operations Significance Determination Process Phase 1 Initial Screening and Characterization of Findings, and determined the finding to be of very low safety significance (Green). The finding had a cross-cutting aspect in the area of Human Performance related to Work Management because the licensee did not implement an adequate process of planning, controlling, and executing work activities such that nuclear safety was the overriding priority. Specifically, Dominion failed to recognize the increased risk of isolating instrument air during solid plant operations. (H.5)
05000336/FIN-2017003-012017Q3MillstoneInadequate Procedure Results in Inadvertent Lowering of Spent Fuel Pool LevelA self-revealing NCV of very low safe ty significance (Green) of Technical Specification (TS) 6.8, Procedures, was identified because Dominion did not adequately establish Operating Procedure (OP) 2305, Spent Fuel Pool Cooling and Purification System. Specifically, from initial issuance until June 20, 2017, the procedure did not direct operators to verify the primary demineralizer bypass valve was closed while lining up to fill the spent fuel pool from the coolant waste receiver tanks, resulting in an unexpected loss of spent fuel pool inventory. Dominion has documented this condition within their corrective action program (CAP) as condition report (CR) 1064323, revised procedure OP 2305, and performed an apparent cause evaluation. The inspectors determined that the finding was more than minor because it was associated with the procedure quality attribute of the Barrier Integrity cornerstone and adversely affected its objective to provide reasonable assurance that physical design barriers, such as fuel cladding, protect the public from radionuclide releases caused by accidents or events. Specifically, spent fuel pool level was inadvertently lowered when operators aligned the system in accordance with OP 2305, which resulted in a reduced net positive suction head for the spent fuel pool cooling pumps as indicated by control room alarm. The finding screened to be of very low safety significance (Green) because it did not result in a loss of spent fuel pool water inventory below the minimum analyzed level limit and did not cause the spent fuel pool temperature to exceed the maximum analyzed temperature limit. This finding has a cross-cutting aspect in the Human Performance cross-cutting area, Avoid Complacency because Dominion did not recognize and plan for the possibility of a latent deficiency in procedure OP 2305 when used while the primary demineralizers were bypassed. (H.12)
05000336/FIN-2017002-012017Q2MillstonePotential Untimely Corrective Action for Anchor Darling Double Disc Gate ValvesThe inspectors identified that Dominion has not implemented corrective actions to address potential substantial safety hazards associated with several safety significant valves at Millstone Unit 2 that was reported in a 10 CFR Part 21 notification letter dated February 25, 2013. Specifically, after establishing a corrective action plan, to date Dominion has not implemented actions to either evaluate or inspect susceptible valves. However, inspectors need to compare actions taken to Dominions CAP requirements and review industry recommendations to address the Part 21 letter to determine if this represents a performance deficiency or violation of NRC requirements. As a result, the NRC has opened an unresolved item (URI) related to this issue of concern. Description. In 2012, Browns Ferry Nuclear Plant Unit 1 experienced a failure of an isolation valve due to a failure of the valve stem to wedge anti-rotation wedge pin as noted in a 10 CFR Part 21 Notification Letter dated January 4, 2013. Subsequent analysis by Flowserve, owner of Anchor/Darling, determined the cause was a manufacturing defect, wherein the wedge pin installation torque was insufficient to meet the design needs of the valve. Flowserve further concluded that other valves of this type, Anchor Darling double disc gate valves in motor operated valve (MOV) applications with Limitorque or Rotork actuators, could be susceptible to similar failures. As documented in the associated 10 CFR Part 21 Notification Letter from Flowserve dated February 25, 2013, Millstone was susceptible to a potential substantial safety hazard due to this potential failure mechanism. Dominion captured this condition in CR504097 and determined that the following Millstone Unit 2 valves were susceptible: CS-4.1A, Containment Spray Header Isolation CS-4.1B, Containment Spray Header Isolation CS-13.1A, RWST Outlet Isolation CS-13.1B, RWST Outlet Isolation CS-16.1A, Containment Sump Outlet Header Isolation CS-16.1B, Containment Sump Outlet Header Isolation The Dominion fleet MOV Program owner accepted the action (CA284339) to establish a corrective action plan on November 21, 2014, approximately 21 months after 10 CFR Part 21 notification by Flowserve. The corrective action plan for the susceptible valves included valve performance monitoring consistent with current MOV program requirements as well as stem position monitoring during travel every cycle which would indicate potential degradation of the wedge pin. Ultimate resolution for each location incorporates valve disassembly, intrusive inspection, and re-torque of the stem/wedge connection to mitigate the notified potential substantial safety hazard. To date, Dominion has not performed stem position monitoring, contrary to their corrective action plan, thereby limiting their capacity to identify wedge pin degradation without assessment of the change. Furthermore, due to the invasive nature of the ultimate resolution as well as the safety functions of the susceptible locations, final corrective actions for each valve must be performed with the unit offline. Dominion initially established ultimate resolution at each location in spring of either 2016 or 2017 without alignment to an outage schedule or cycle plan. On February 16, 2016, because the 2016 valves would be worked during a refueling outage, the facilities safety review committee met, extending due dates until June 1, 2017. Immediately preceding the spring 2017 refueling outage, Dominion realigned ultimate resolution for the susceptible valves to the fall 2018 and spring 2020 refuel outages due to failure to receive parts required to complete contingency maintenance. Ultimately, from February 25, 2013, through the present, the inspectors identified that Dominion delayed implementation of corrective actions for multiple potential substantial safety hazards that was communicated in a 10 CFR Part 21 notification letter. However, inspectors need to compare actions taken to Dominions CAP requirements and review industry recommendations to address the Part 21 letter to determine if this represents a performance deficiency or violation of NRC requirements. (URI 05000336/2017002-01, Potential Untimely Corrective Action for Anchor Darling Double Disc Gate Valves)
05000336/FIN-2017001-012017Q1MillstoneFailure to Maintain CST Temperature in Accordance with Procedural RequirementsGreen. The inspectors identified a Green NCV of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure to adequately implement Operating Procedure (OP) 2319B, Condensate Storage and Surge System. Specifically, Dominion failed to maintain the Millstone Unit 2 condensate storage tank (CST) temperature above procedural requirements. Dominion has documented this condition within their corrective action program (CAP) as condition report (CR) 1066291. The inspectors determined this finding was more than minor as it adversely affected the protection from external factors attribute of the Mitigating Systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The reliability of the mitigating systems heat removal function was challenged based upon the reasonable doubt of lost operability of the CST to provide a sufficient supply of water to the auxiliary feedwater (AFW) system. There was reasonable doubt of lost operability due to indications of CST water temperature below OP 2319B prescribed limitations, winter temperatures falling, and an inability to restore CST recirculation system in a timely manner. The finding was determined to be of very low safety significance (Green), when all screening questions were answered No as the conditions discussed in the Dominion engineering evaluation, approved on January 7, 2017, were capable of showing that no safety systems or functions were lost. This finding has a crosscutting aspect in the Problem Identification and Resolution, Resolution, in that Dominion did not take effective corrective actions or corrective maintenance to address CST recirculation pump degradation in a timely manner, prior to the onset of winter, commensurate with their safety significance such that operations could maintain CST water temperature above procedurally defined limitations. (P.3)
05000423/FIN-2017001-022017Q1MillstoneChange of C Charging Pump Testing Requirements Contrary to ASME OMGreen. The inspectors identified a Green NCV of 10 CFR 50.55a(f) because Dominion did not perform all required inservice testing (IST) of the Unit 3 C charging pump, 3CHS*P3C, in accordance with the American Society of Mechanical Engineers (ASME) Operation and Maintenance (OM) Code. Specifically, from April 15, 2016, to the end of the inspection period, Dominion stopped the required Group A quarterly surveillances which could result in a condition where degradation of the charging pump would remain undetected by IST testing. Dominion entered this issue into their CAP as CR 1064337. 4 This finding was more than minor in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, dated September 7, 2012, as it adversely affected the Equipment Performance attribute of the Mitigating Systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Eliminating quarterly IST surveillance tests could challenge the reliability of the C charging pump and allow degradation of the equipment remaining undetected. In accordance with IMC 0609, Significance Determination Process, Attachment 4, Initial Characterization of Findings, and IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, Section A, Mitigating Systems, Structures or Components and Functionality, the finding screened to be of very low safety significance (Green), when the deficiency affecting the design or qualification whereupon the component maintains operability or functionality question was answered yes. The C charging pump has not yet experienced any failures. This finding has a cross-cutting aspect in Human Performance, Change Management, in accordance with IMC 0310, Aspects within the Cross-Cutting Areas, where leaders use a systematic process for evaluating and implementing change so that nuclear safety remains the overriding priority. Specifically, Dominion evaluated this change to the IST program without requesting relief from the ASME Code requirements. (H.3)
05000336/FIN-2017001-032017Q1MillstoneLicensee-Identified ViolationAs discussed in Section 4OA2.2 of this report, the inspectors concluded that the ECCS minimum flow recirculation check valves should have been characterized as Category A valves, and should have been leak rate tested as per the IST Program. The associated LER is discussed in Section 4OA3.1. Title 10 CFR 50.55a, Codes and Standards, Section (f)(4), required in part, that throughout the service life of a pressurized water-cooled nuclear power facility, valves that are classified as Class 1, 2, or 3 must meet the IST requirements set forth in the ASME OM Code. Dominions Code of Record, ASME OM Code - 2001 Edition, Subsection ISTC-1300, Valve Categories, required that valves within the scope of Subsection ISTC-1300 shall be placed in one or more of the following categories, which included Category A (those valves for which seat leakage is limited 28 to a specific maximum amount in the closed position for fulfillment of their required function). The inspectors concluded that minimum flow recirculation check valve 2- CS-6A should have been a Category A valve, and leak rate tested, to assure fulfillment of its safety function (to mitigate the dose consequences of a postulated accident). Contrary to the above, since 1975, when the check valve 2-CS-6A was initially categorized, Dominion failed to appropriately categorize the subject valve and therefore did not meet the ASME OM Code requirements and 10 CFR 50.55a requirements. Specifically, failure to categorize the check valve as a Category A resulted in the valve not being subject to leak rate testing. This issue is more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors determined that the finding was of very low safety significance because it did not result in the loss of operability or functionality of a system or train, and the actual leakage through the check valve would not have resulted in a radiological dose in excess of regulatory requirements. Dominion entered the issue into the CAP as CR 582112 and CA 3013009. Because Dominion identified this issue of very low safety significance and it has been entered into their CAP, this finding is being treated as a licensee-identified NCV, consistent with Section 2.3.2.a of the NRC Enforcement Policy. This item was considered licensee-identified because it was identified by Dominion as a result of deliberate observation by licensee personnel, and was entered into their CAP.
05000247/FIN-2016004-052016Q4Indian PointLicensee-Identified Violation10 CFR 55.53(e) requires, in part, that to maintain active status, a licensee shall actively perform the functions of an operator or senior operator on a minimum of seven 8-hour shifts or five 12-hour shifts per calendar quarter and that if a licensee has not been actively performing the functions of an operator or senior operator, the licensee may not resume activities authorized by a license issued except as permitted by 10 CFR 55.53(f). 10 CFR 55.53(f) requires, in part, that before resumption of licensed functions, an authorized representative of the facility licensee shall certify that: 1) the licensees qualification and status of the licensee are current and valid; and 2) that the licensee has completed a minimum of 40 hours of shift functions under the direction of an operator or senior operator as appropriate and in the position to which the individual will be assigned. Contrary to the above, between July 2, 2016, and July 5, 2016, Entergy did not properly ensure that the qualifications and status of an SRO was current and valid, regarding the SRO meeting the minimum of seven 8-hour or five 12-hour shifts per calendar quarter. Specifically, the SRO stood watch as a control room supervisor in July 2016 while having stood only four of the five required 12-hour proficiency watches in a creditable position in the prior quarter. In the prior quarter, the SRO stood watch as a shift technical advisor and field support supervisor. These watches are not creditable toward the proficiency requirement. The SRO was removed from shift and was properly reactivated as required by 10 CFR 55.53(f). This issue was entered in Entergys CAP as CR-IP2-2016-04440. Corrective actions taken included counseling of the SRO and the auditor. To prevent reoccurrence, a software fix was implemented to check the proficiency status of operators when logging into their shift. This violation was assessed using the traditional enforcement process because it involved an operator license condition that was not met, which impacts the NRCs regulatory process. Although this violation is similar to a Severity Level III example in the NRC Enforcement Policy, based on the circumstances surrounding the issue including a verification that there were no operational errors as a result of the violation, the issue was evaluated as a Severity Level IV.
05000336/FIN-2016004-012016Q4MillstoneRoutine Failure to Perform Engineering Evaluation of Long Term ScaffoldingThe inspectors identified a Green NCV of Title 10 of the Code of FederalRegulations (10 CFR) Part 50, Appendix B, Criterion V, Instructions, Procedures, andDrawings, for the failure to adequately implement procedure MA-AA-105, Scaffolding,Revision 17. Specifically, Dominion routinely failed to perform engineering evaluations oflong term scaffolding installed in the plant for greater than 90 days. Dominion hasdocumented this condition within their corrective action program (CAP) as condition reportCR1049493.The inspectors determined that this finding was more than minor as it represents the routine failure to perform 10 CFR 50.59 engineering evaluations consistent with the requirements of procedures MA-AA-105 and CM-AA-400 which if left uncorrected, would have the potential to lead to a more significant safety concern as informed by IMC 0612, Appendix E,Examples of Minor Issues, example 4.a. The finding screened to be of very low safety significance (Green), when all screening questions were answered No as the conditions identified did not challenge safety system functions. This finding has a cross-cutting aspect in the Problem Identification and Resolution, cross-cutting area associated with Resolution,in that under CR1049057, Dominion did not take effective corrective action to resolve and correct the identified gaps in the tracking and assessment of scaffolding installed for greater than 90 days as directed by MA-AA-105 and CM-AA-400, resulting in three further failures to evaluate long term scaffolding identified by the inspectors in the Unit 2 A Safeguards Room. (P.3)
05000336/FIN-2016004-022016Q4MillstoneFailure to Maintain Licensed Operator Examination IntegrityThe inspectors identified an NCV of 10 CFR 55.49, Integrity of Examinations and Tests, for the failure of the licensee to ensure that the integrity of an operating test administered to licensed operators was maintained. During the annual operating exam, 19of the Unit 2 licensed operators received more than two of five job performance measures(JPMs) (>50 percent) for their operating tests that had been administered to other licensed operators in previous weeks of the same exam cycle. This failure resulted in a compromise of examination integrity because it exceeded the Dominion Nuclear Fleet Procedure TR-AA-730, "Licensed Operator Biennial and Annual Operating Requalification Exam Process,4 Revision 9, requirement to repeat less than or equal to 50 percent of the JPMs during the exam cycle. However, this compromise did not lead to an actual effect on the equitable and consistent administration of the examination. This issue was entered into Dominions CAP as CR1056308.The failure of Dominions training staff to maintain the integrity of examinations administered to licensed operations personnel was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because if left uncorrected, the performance deficiency could have become more significant in that allowing licensed operators to return to the control room without valid demonstration of appropriate knowledge on the biennial examinations could be a precursor to a more significant event. Using IMC 0609, Significance Determination Process, and the corresponding Appendix I, Licensed Operator Requalification Significance Determination Process, the finding was determined to have very low safety significance (Green) because although the finding resulted in a compromise of the integrity of operating test JPMs and compensatory actions were not immediately taken when the compromise should have been discovered in 2016, the equitable and consistent administration of the test was not actually impacted by this compromise. This finding has a cross-cutting aspect in the area of Human Performance associated with Field Presence, because the licensee failed to ensure that deviations from standards and expectations are corrected promptly such that the 50 percent maximum limit on repeated JPMs was not exceeded. Specifically, Dominion supervisory review and approval of the original examination plan and subsequent changes to that plan could have discovered the deviation from standards and expectations. (H.2)
05000423/FIN-2016004-032016Q4MillstoneUntimely Corrective Action for Vital InvertersThe inspectors identified a Green NCV of 10 CFR 50, Appendix B, Criterion XVI,Corrective Action, for Dominions failure to take timely corrective actions to replacedegraded diodes in Unit 3 vital inverters INV-1 and INV-2 upon receipt of information that called their reliability into question. Specifically, following two inverter failures, Dominion had not taken any corrective actions to replace degraded diodes in the Unit 3 vital inverters from the receipt of the Exelon Power Labs report on September 20 until the susceptible diodes were inspected and replaced on November 17 and 22. Dominion entered this issue into their CAP as CR1041301. The inspectors found that Dominions failure to take timely corrective action to replace degraded vital inverter diodes was a performance deficiency within Dominions ability to foresee and correct. This performance deficiency was considered to be more than minor because it would affect the Mitigating Systems cornerstone equipment performance attribute objective to ensure the availability and reliability of vital 120V power. Specifically,manufacturing defects in the diodes caused these subcomponents to fail when they were expected to last the life of the inverter. The finding was evaluated in accordance with IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, and determined to be of very low safety significance (Green) because although the failure challenged the reliability of the inverters, it did not result in a loss of operability or functionality. This finding has a cross-cutting aspect in the Human Performance crosscutting area associated with Work Management, in that Dominion focused on managing the risk associated with voluntarily entering a 24 hour technical specifications (TS) limiting condition for operation (LCO) to replace the degraded diodes instead of the potential risk of another inverter failure. (H.5)
05000336/FIN-2016004-042016Q4MillstoneLicensee-Identified Violation10 CFR 50, Appendix B, Criterion XVI, Corrective Action, states in part that measures shall be established to assure that conditions adverse to quality are promptly identified and corrected. Contrary to this, Dominion failed to identify 3SWP*MOV115A, the circulating water pump lube water valve, was part of a population of valves subject to dealloying and did not take appropriate corrective actions prior to valve failure. Dominion discovered this issue during a planned system walkdown and entered it into the CAP as CR1052697. The inspectors evaluated this finding using IMC 0609.04, Initial Characterization of Findings, and IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, and determined that the finding was of very low safety significance (Green) because the finding did not represent a loss of system or function, or an actual loss of a train for greater than its TS allowed outage time, or an actual loss of function of one or more non-TS trains of equipment designated as high safety-significant in accordance with the licensees maintenance rule program for greater than 24 hours.
05000286/FIN-2016004-012016Q4Indian PointInadequate Preventive Maintenance Classification of Starting Air Relief Valve Led to FailureGreen. The inspectors identified a finding of very low safety significance because Entergy did not correctly classify relief valve DA-5-2 as a high critical component. DA-5-2 is a relief valve in the emergency diesel generator (EDG) air start system; and when it failed in service 4 due to an inadequate preventive maintenance frequency, it caused a loss of air that depressurized the air start system, rendering it inoperable. Entergy took corrective action to replace the failed relief valve and wrote CR-IP3-2016-03851 to review the classification of DA-5-2. This performance deficiency was more than minor because it was associated with the Mitigating Systems cornerstone and affected the equipment performance attribute. Specifically, the failure of the relief valve reduced the air available for starting the 32 EDG and reduced its reliability. The inspectors performed a risk screening in accordance with IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions. The finding was of very low safety significance (Green) because it did not represent an actual loss of function of a single train for greater than its TS allowed outage time. Specifically, the air pressure in the starting air tank was below the TS limit for less than an hour, and the allowed outage time for the starting air tank is 48 hours. The inspectors determined that there was no cross-cutting aspect associated with this finding because it is not associated with current performance. Specifically, the decision to extend the preventive maintenance frequency was made in 2010, and there had been no other failures of similar components since then that would have prompted Entergy to review the basis for that decision.
05000286/FIN-2016004-022016Q4Indian PointInadequate Operability Evaluation of Leak in Service Water Pump Discharge PipeGreen. The inspectors identified an NCV of very low safety significance of Title 10 of the Code of Federal Regulations (10 CFR) 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, because Entergy staff did not perform an adequate operability review under EN-OP-104, Operability, for a service water (SW) piping leak described in CR-IP3-2016-1113. Entergy based the flooding portion of the operability review on the assumption that a non-safety-related sump pump would function to prevent flooding of the room, although under accident conditions it would not have electrical power. Entergy implemented corrective actions to revise their operability evaluation and also installed a housekeeping patch that greatly reduced the leak rate. The performance deficiency was determined to be more than minor because the finding was similar to Example 3j of NRC IMC 0612, Appendix E, Examples of Minor Issues, in that incorrect assumptions of the ability of the Zurn pit sump pump to remove the water resulted in reasonable doubt regarding operability and warranted additional evaluation. This issue impacts the protection against the external factors attribute of the Mitigating Systems cornerstone and impacts its objective to ensure the availability of systems that respond to initiating events to prevent undesirable consequences. Specifically, Entergy did not properly evaluate the operability impacts of an increase in the leak rate from a preexisting SW leak in the Zurn strainer pit and, therefore, did not implement compensatory measures to prevent internal flooding in the event the installed, non-safety-related sump pump failed. The inspectors determined the finding could be evaluated using the Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings. Because the finding impacted the Mitigating Systems cornerstone, the inspectors screened the finding through IMC 0609 Appendix A, The Significance Determination Process for Findings At-Power, using Exhibit 2, Mitigating Systems Screening Questions. The finding required a detailed risk evaluation because it represented the potential loss of the entire SW system. A detailed risk assessment was conducted assuming that a loss of offsite power (LOOP) could challenge the functionality of the SW system due to flooding impacts on the system strainers. The resulting change in core damage frequency was estimated to be in the mid E-6 range, Green. The inspectors concluded this finding had a cross-cutting aspect in the area of Human Performance, Avoid Complacency, because Entergy did not recognize and 5 plan for the possibility of latent issues and inherent risk. Entergy had experienced numerous SW system leaks that remained small and did not plan for the possibility that this one would increase. Once the leak had increased significantly, Entergy did not appropriately revise the operability determination to reflect the changed circumstances and take appropriate compensatory measures to promptly restore operability. (H.12 Avoid Complacency)
05000286/FIN-2016004-032016Q4Indian PointFailure to Provide Indication of a Bypassed RPS Channel During TestingGreen. The inspectors identified a finding of very low safety significance when Entergy conducted testing on the Unit 3 reactor protection system (RPS) that was contrary to the guidance in IEEE standard 279-1968, a standard to which Indian Point Unit 3 was committed. Specifically, Entergy made temporary changes to their Unit 3 reactor coolant temperature channel functional test procedures, pressurizer pressure loop functional test procedures, and nuclear power range channel axial offset calibration procedures to use jumpers to bypass RPS trip functions, without meeting the requirement to have continuous indication in the control room when a part of RPS is bypassed for any purpose. Entergy closed the temporary modification and returned to testing without using jumpers to bypass the tested channel. The inspectors determined the finding was more than minor because this finding was associated with the procedure quality attribute of the Mitigating Systems cornerstone and affected its objective to ensure the reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the new test method reduced the reliability of the RPS tripping the unit under conditions requiring an overtemperature delta temperature (OTDT) trip. The inspectors evaluated this finding using IMC 0609, Attachment 4, Initial Characterization of Findings. The inspectors determined that the finding affected the Mitigating Systems cornerstone and evaluated the finding using Appendix A, Exhibit 2, Mitigating Systems Screening Questions. The finding is of very low safety significance (Green) because it did not affect both the RPS trip signal to initiate a reactor scram and the function of other redundant trips or diverse methods of reactor shutdown. The inspectors identified a cross-cutting aspect in the area of Human Performance, Conservative Bias, because Entergy did not determine the test method was safe in order to proceed. Specifically, Entergy staff rationalized that the use of jumpers was allowable because they were focused on completing the required surveillance testing. (H.14 Conservative Bias)
05000247/FIN-2016004-042016Q4Indian PointFailure to Follow RPS Logic Train B Actuation Logic TestGreen. A self-revealing NCV of Technical Specification (TS) 5.4.1(a), Procedures, was identified because Entergy did not follow procedure 2-PT-2M3A, Reactor Protection System Logic Train B Actuation Logic Test and Tadot, required by NRC Regulatory Guide 1.33, Appendix A, during planned testing on July 6, 2016, resulting in a Unit 2 reactor trip. Specifically, Entergy positioned key #183 in the channel B reactor logic key lock switch to the defeat position without procedural guidance and prior to commencing 2-PT-2M3A. 2-PT-2M3A requires that the reactor trip bypass breaker B be racked in when the channel B reactor protection logic key lock switch is taken to defeat to prevent a reactor trip. Entergy entered this issue into the corrective action program (CAP) as CR-IP2-2016-04320. The corrective actions include procedure enhancements, operations work challenges, and a site all hands meeting. This finding was determined to be more than minor because it is associated with the human performance attribute of the Initiating Events cornerstone and affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, Entergy operated plant equipment without direction from procedural guidance which resulted in an unplanned reactor trip. This finding was determined to be of very low safety significance (Green) because it did not cause the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition, high energy line-breaks, internal flooding, or fire. This finding had a cross-cutting aspect in the area of Human Performance, Field Presence, because Entergy leaders did not reinforce standards and expectations with regard to procedure use and adherence. Specifically, Entergy did not have sufficient urgency for changing worker behaviors through the work observation program. (H.2 Field Presence)
05000423/FIN-2016003-022016Q3MillstoneFailure to Scope Safety Related Acoustic Valve Monitoring System into the Maintenance RuleThe inspectors identified a Green NCV of Title 10 of the Code of Federal Regulations (10 CFR) 50.65(b)(1), for Dominions failure to include the safety-related Unit 2 Pressurizer Safety Valve, Acoustic Valve Monitoring System (AVMS) SSC within the scope of the maintenance rule program. Specifically, Dominion removed the Millstone Unit 2 AVMS, which is required to remain functional during and following a design bases event to provide indication to operators in the control room of significant abnormal degradation of the reactor coolant pressure boundary and monitor for loss of coolant due to an open safety relief valve, from the scope of the maintenance rule monitoring program. Dominion has documented this condition in their CAP as CR1049493. The inspectors determined that the finding was more than minor because it was associated with the equipment performance attribute of the Initiating Events cornerstone and adversely affected the objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, Dominions removal of AVMS from maintenance rule performance and condition monitoring and the failures observed have resulted in the complete loss of availability and reliability of each channel of AVMS such that they cannot perform their intended function. The finding was determined to be of very low safety significance (Green) because the conditions associated with the most applicable design basis event are bound by the small break loss of coolant accident (LOCA) analysis and did not affect other systems used to mitigate a LOCA. This finding has a crosscutting aspect in the Human Performance cross-cutting area associated with Procedure Adherence, in that Millstone Maintenance Rule Expert Panel (MREP) members did not follow the Dominion maintenance rule program implementing procedure, ER-AA-MRL-100, which provides guidance for scoping systems into the maintenance rule. (H.8)
05000336/FIN-2016003-012016Q3MillstoneFailure to Review Standing OrdersThe inspectors identified a Green NCV of Technical Specification (TS) 6.8.1.a, for Dominions failure to implement procedures as required by Regulatory Guide 1.33, Revision 2, Appendix A.1, Administrative Procedures, during the performance of watch turnover. This resulted in multiple operators across multiple crews in both Unit 2 and 3 standing watch without performing a review of the applicable standing orders for up to 4 months from March to July 2016. Dominion entered the condition in their corrective action program (CAP) as condition report (CR)1042287. The inspectors determined that the finding was more than minor because if left uncorrected the performance deficiency could lead to a more significant event. Specifically, the operators did not review TS amendments, emergency action level classifications, emergency operating procedures, and plant computer issues impacting the plant prior to taking watch. Without reviewing the standing orders to understand the information contained within, operators could potentially take improper actions to control the plant during evolutions and abnormal conditions. The finding was determined to be of very low safety significance (Green) because it did not affect design or qualification of a mitigating structure, system, and component (SSC), did not represent a loss of system function, and did not involve external event mitigation systems. The inspectors determined that the finding has a cross-cutting aspect in the Human Performance cross-cutting area associated with Field Presence, where leaders are commonly seen in the work areas of the plant observing, coaching, and reinforcing standards and expectations. Specifically, Dominion leadership observations in the control room or management review of monthly standing order audits could have discovered the deviation from standards and expectations. (H.2)
05000336/FIN-2016002-012016Q2MillstoneSecondary Containment Inoperability Due to Inadequate ProceduresThe inspectors documented a self-revealing Green NCV of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, because Dominion did not develop a Unit 3 supplementary leak collection and release system (SLCRS) damper procedure that was adequate to prevent the inoperability of the system. Specifically, deficiencies in procedure SP 3614I.3A, Supplementary Leak Collection and Release System Boundary Isolation Damper Test, as well as the SLCRS damper monitoring program and preventative maintenance strategy, led to both trains of the Unit 3 SLCRS failing their respective surveillance tests resulting in the inoperability of secondary containment. After the issue was identified, Dominion entered the condition into their corrective action program (CAP) as condition report (CR)1033408, declared the secondary containment inoperable until the plant entered a mode of technical specifications non-applicability, and conducted walkdowns and repairs to the system to restore it to compliance. This performance deficiency was considered to be more than minor because it adversely affected the system, structure, and component (SSC) and barrier performance attribute of the Barrier Integrity cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, inadequate maintenance of the SLCRS system led to a system differential pressure during operation that was not adequate to meet its design basis surveillance requirement and thus rendered the system inoperable. Additionally, the performance deficiency was similar to IMC 0612, Appendix E, minor example 2.a. The finding was evaluated in accordance with IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, and determined to be of very low safety significance (Green) since it only represented a degradation of the radiological barrier function provided for the auxiliary building. The finding is related to the cross-cutting aspect of Human Performance, Design Margins, because Dominion did not operate and maintain equipment within design margins. Specifically, Dominion did not appropriately monitor and maintain the SLCRS system in such a way that declining damper performance trends were identified and prevented prior to the inoperability of the system.
05000313/FIN-2016007-192016Q1Arkansas NuclearLicensee-Identified ViolationTitle 10 CFR Part 50, Appendix B, Criterion XI, Test Control, requires, in part, that a test program shall be established to assure that all testing required to demonstrate that structures, systems, and components will perform satisfactorily in service is identified and performed in accordance with written test procedures which incorporate the requirements and acceptance limits contained in applicable design documents. Test results shall be documented and evaluated to assure that test requirements have been satisfied. Contrary to these requirements, from April 16, 2009, through January 31, 2015, ANO identified that a test program had not been established to assure that all testing required to demonstrate that structures, systems, and components will perform satisfactorily in service was identified and performed in accordance with written test procedures which incorporated the requirements and acceptance limits contained in applicable design documents. Specifically, the failure to monitor the flow rate through the Unit 1 SW to SFP makeup line, which is subject to biofouling, to demonstrate this line would perform satisfactorily in service to meet the design flow rate. The 18 month surveillance flow test was not sufficient to monitor, predict and take actions to correct for the loss of flow caused by biofouling, consequently, line blockage occurred that resulted in the loss of the capability to provide full design makeup flow rates. ANO documented this violation in the CAP as CR-ANO-1-2014-01628. The team determined that this issue was of very low safety significance (Green) after reviewing IMC 0609, Attachment 0609.04, and Appendix A, Exhibit 3 Barrier Integrity Screening Questions. Specifically, the team answered no to each of the SFP questions in Exhibit 3.
05000368/FIN-2016007-202016Q1Arkansas NuclearLicensee-Identified ViolationTitle 10 CFR Part 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, Section (a)(4), requires, in part, that before performing maintenance activities, the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activities. Contrary to these requirements, on July 8, 2015, ANO identified that they failed to assess and manage the increase in risk that may result from the proposed maintenance activities. Specifically, ANO failed to assess and manage the risk associated with removing and cleaning the Unit 2 SW system pre-screens for maintenance. ANO documented this violation in the CAP as CR-ANO-2-2015-01865. Additionally, ANO added guidance to procedure COPD-024 to address this issue. The team determined that this issue was of very low safety significance (Green) after reviewing IMC 0609 Attachment 0609.04, and Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process, dated May 19, 2005. Specifically, the team determined the incremental core damage probability deficit was not greater than 1E-6.
05000313/FIN-2016007-212016Q1Arkansas NuclearLicensee-Identified ViolationTitle 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that instructions, procedures, or drawings include appropriate quantitative or qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished. Contrary to this requirement, ANO identified that in 2010, maintenance work orders installing safety-related circuit breakers in motor control centers D-15 and D-25 did not have appropriate quantitative or qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished. Specifically, Engineering Change 5832 was completed to replace seven safety-related existing and obsolete Gould circuit breakers inside safety-related motor control centers D-15 and D-25 with Siemens ED6 series molded case circuit breakers, using work orders 122821 and 122823. Subsequent review of these work orders confirmed that the installation instructions properly included specific torque values for the breaker mounting hardware, but the specified torque values were not recorded in the work orders, and the torqueing operations were not verified by quality control as required by procedures. ANO documented this issue in the CAP as CR-ANO-1-2015-02230. The team determined that this issue was of very low safety significance (Green) after reviewing IMC 0609, Attachment 0609.04, Appendix A, Exhibit 2 Mitigating Systems Screening Questions. Specifically, the team answered no to each of the questions in Exhibit 2.
05000336/FIN-2016001-022016Q1MillstoneFailure of Feedwater Isolation Valve to Close Due to Electrical Jumper Being InstalledThe inspectors identified a self-revealing Green NCV of TS 3.3.2 for Dominions failure to meet the operability requirements for the C feedwater isolation valve (FWIV) testing and valve limit testing work associated with Design Change MP3-09-01030, an electrical jumper was left installed in the C FWIV (3FWS*CTV41C) control circuit. This prevented both channels of the engineered safety features actuation system (ESFAS) signal from closing the C FWIV when called upon during an actual feedwater isolation actuation associated with the reactor trip on January 25, 2016. The installed jumper rendered the C FWIV inoperable for over one year. Dominions immediate corrective actions included restoring the channels for 3FWS*CTV41C to operable status by removing the electrical jumper, inspecting the other FWIV control circuits for electrical jumpers, and retesting all of the FWIVs for proper operation. The performance deficiency was determined to be more than minor because it adversely affected the configuration control attribute of the Mitigating Systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to remove an electrical jumper on the C FWIV during the implementation of a design change led to the failure of the valve to perform its closure safety function when called upon. The finding was evaluated in accordance with IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, and determined to be of very low safety significance (Green) since it did not represent an actual loss of safety function of the system as there was a redundant means of feedwater isolation. The finding has a cross-cutting aspect in Human Performance, Work Management, because Dominion did not implement a process of planning, controlling, and executing work activities such that nuclear safety is the overriding priority. Specifically, maintenance and operations personnel did not follow the work management procedure for generating a new work order when the additional electrical jumper was installed (H.5).
05000313/FIN-2016007-172016Q1Arkansas NuclearDetermine Impact of Modifying Fire Seals for Flood ProtectionThe team identified an unresolved item related to ability to meet the requirements of License Condition 2.C.(8) and 2.C.(3)(b), Fire Protection Program, in Units 1 and 2, respectively. Specifically, the team identified ANO had modified numerous fire rated seals to also provide a flood protection barrier without ensuring existing fire protection requirements continued to be met. ANO Units 1 and 2 used a 3- hour fire rated silicon foam material to seal floor and walls penetrations in order to provide adequate separation to prevent the spread of fire between fire areas. ANO determined that numerous exiting fire seals were also required to provide flood protection. To provide an 3-hour fire barrier and also be capable of withstanding a design basis flood, ANO issued design changes to use several materials, such as Polywater FST Foam Sealant, Promatec Product 12 (P12), Sylgard, and Promatec High Density Silicone Elastomer (HDSE and HDSE-IR), to create dual purpose seals. The team determined that HDSE, HDSE-IR and Sylgard have been tested as a 3-hour fire barrier and tested satisfactorily to provide adequate flood protection. However, ANO could not produce documentation to show that fire rating testing or qualification testing had been performed for the new dual function seals using P12 and Polywater. This was documented in CR-ANO-C-2016-00490. ANO has determined that the population of the non-qualified seals was 139 (96 containing Polywater and 43 containing P12). ANO stated that all of the new dual function seals using P12 consist of the flood protective layer of P12 being placed on top of the existing originally qualified 10 inch fire silicone seal, and that no credit was given to the P12 layer to provide any additional fire protection capabilities. The P12 has been tested by Promatec with silicone seals for flood and was flood tested by the station for use with silicone foam seals. Therefore, ANO believes that no negative chemical reactions can be expected. ANO installed Polywater material either on top of the currently installed fire barrier seal, or in electric conduits that are not required to have a fire seal present. Polywater is designed to create an air and watertight barrier suitable for use in conduits. ANO did not remove any portion of the originally qualified silicon foam fire seals, therefore the flood protection layer of Polywater was applied on top of the existing qualified fire seal. As part of the approved Fire Protection Program, a periodic visual inspection of fire penetration seals is required by TRM 3.7.12.3 and TRM 3.7.5, for Units 1 and 2 respectively, such that 10 percent of the total fire seal population is inspected each year. These inspections are conducted per Unit 1 procedure OP 1405.016, U-1, Penetration Fire Barrier Visual Inspections, and Unit 2 procedure OP 2405.016, U-2, Penetration Fire Barrier Visual Inspections. The team reviewed the inspection procedures and interviewed the fire protection engineers. The team was concerned that for many of the new dual function seals, the original fire rated and qualified seal was no longer accessible for performance of required visual inspections. The team was concerned that because the silicone fire seals are no longer accessible for inspection, the intent of the required fire seal inspection to detect surface flaws or damage to indicate potential underlying damage has occurred to the qualified fire penetration system per the fire protection program could not be met. The team concluded that not having fire rating qualification testing for the existing configuration of some fire seals, and the inability to perform required periodic visual inspections for newly modified fire seals, was a performance deficiency that was reasonably within ANOs ability to foresee and prevent. Since ANO has not yet completed the evaluation or fire testing qualification of the modified seals, the team was unable to evaluate the overall impact of this condition or classify the performance deficiency. ANO intended to complete the evaluation of these issues and document the results in CR-ANO-C-2016-00490. Some of the actions being considered include performing required 3-hour fire testing in representative dual function configurations containing Polywater or P12; and doing a feasibility study for removal and replacement of these seals with fire and flood qualified materials. The team concluded that further review is necessary in order to properly evaluate and disposition the significance of this condition. Specifically, the NRC will need to review the following: ANOs evaluation, extent of condition, and disposition and/or testing results of the non-qualified dual function fire/flood seals; and the significance of the non-qualified population (139 seals containing Polywater or P12). This item is being treated as an unresolved item (URI) 05000313/2016007-17 and 05000368/2016007-17, Fire Seals Modified for Flood with Material not Qualified for Fire and Inability to Perform Required Periodic Visual Inspection.
05000313/FIN-2016007-142016Q1Arkansas NuclearFailure to Properly Implement the Corrective Action ProgramThe team identified a Green finding and an associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensees failure to follow corrective action program procedures. Specifically, the team identified that condition reports were not being promptly screened for operability by the control room as required by procedure EN-LI-102-ANO-RC, Corrective Action Program. The licensees corrective actions included ensuring that there was no direct impact on safety and performing an operability determination for the identified condition reports, revising station policy to require that all condition reports be routed to the control room for review, and documenting the issue in the corrective action program as condition reports CR-ANO-C-2016-00359, CR-ANO-C-2016-00400, and CR-ANO-C-2016-00558. The failure to properly evaluate condition reports for classification and operability determination was a performance deficiency. The performance deficiency was determined to be more than minor because, it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to properly evaluate condition reports in accordance with applicable procedures could result in conditions adverse to quality being left uncorrected or not being evaluated to ensure operability was maintained. The finding was evaluated using Inspection Manual Chapter 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, and Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2 Mitigating Systems Screening Questions, dated June 19, 2012. The team determined the finding was of very low safety significance (Green) because the finding was a deficiency affecting the design or qualification of a mitigating system, structure or component, but the system, structure or component maintained its operability. This finding had a human performance cross-cutting aspect of Change Management because the licensee failed to adequately implement changes, including the training of staff concerning those changes, so that nuclear safety remained an overriding priority. Specifically, the licensee failed to ensure that station personnel were able to identify the difference between an adverse and non-adverse condition following the change which added these criteria to procedure EN-LI-102-ANO-RC (H.3).
05000336/FIN-2016001-012016Q1MillstoneRepetitive Failures to Correct Unit 3 Turbine Driven Auxiliary Feedwater Pump Performance IssuesThe inspectors identified a Green NOV of Title 10 of the Code of Federal Regulations (10 CFR) 50, Appendix B, Criterion XVI, Corrective Action, for Dominions repetitive failure to take effective corrective actions for significant conditions adverse to quality involving the degradation of the Unit 3 turbine driven auxiliary feedwater (TDAFW) pump turbine control valve linkage. Specifically, Dominions corrective actions to correct the TDAFW control system have not fully considered all potential failure modes such that continued unreliable operation due to linkage and control systems problems resulted in an overspeed trip of the TDAFW system in February 2016. Inspectors have previously documented this condition under two separate violations of 10 CFR 50, Appendix B, Criterion XVI. The performance deficiency was determined to be more than minor since it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and adversely affected its objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. In accordance with IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, the inspectors determined this issue required a detailed risk evaluation based on the finding representing an actual loss of function of a single train for greater than its technical specification (TS) allowed outage time. A Region I Senior Reactor Analyst (SRA) completed a detailed risk evaluation and concluded the risk significance of this issue was in the high E-8 range, or very low safety significance (Green). In accordance with IMC 0310, Aspects within the Cross-Cutting Areas, dated December 4, 2014, this finding has a cross-cutting aspect in Human Performance, Design Margins, in that the organization failed to operate and maintain equipment within design margins. The Unit 3 TDAFW has little margin to inoperability. Dominion did not pursue a thorough review of the potential interactions of different failure modes after correcting the obvious causes from past failures, which contributed to the February 22, 2016, overspeed event (H.6).
05000423/FIN-2016001-032016Q1MillstoneLicensee-Identified ViolationDominion identified a Severity Level (SL) IV NCV of 10 CFR 50.59(d)(1), Changes, Tests, and Experiments, for the failure to perform an evaluation of a change to the facility as described in the UFSAR which would have required prior approval. During a design basis review of Millstone Unit 3 SW system, Dominion discovered that multiple fittings installed in the system beginning in 1989 were manufactured with Nickel Copper Alloy (UNS N04400) per material specification SB366. Although a material with improved properties, this is not an ASME Boiler Pressure Vessel Code of record Section III (ASME III) permitted material fabrication specification without required additional documentation. The Millstone Unit 3 UFSAR Table 3.2-1, List of QA Category I and Seismic Category I Structures, Systems, and Components, Revision 24.3, requires the SW system to be compliant with ASME III Code Class 3. The inspectors determined that the failure of Dominion to perform written evaluations in accordance with 10 CFR 50.59(d)(1) when installing non-conforming material into Unit 3 beginning in 1989 was a performance deficiency which was within Dominions capability to foresee and prevent. The inspectors identified this condition as more than minor as installation of an ASME III non-conforming material into the Unit 3 SW system would have required prior approval. Because the performance deficiency impacted the ability of the NRC to perform its regulatory function, the inspectors evaluated the issue using the traditional enforcement process. In accordance with the NRC Enforcement Policy, Section 6.1.d.2, this condition screened as SL IV as it was assessed as having very low safety significance (Green) by IMC 0609, Significance Determination Process, when the screening questions were all answered No. 10 CFR 50.59(d)(1), Changes, Tests, and Experiments, states in part, The licensee shall maintain records of changes in the facility, of changes in procedures, and of tests and experiments made pursuant to paragraph (c) of this section. These records must include a written evaluation which provides the bases for the determination that the change, test, or experiment does not require a license amendment pursuant to paragraph (c)(2) of this section. Contrary to the above, from March 1993 through March 29, 2016, Dominion did not perform written evaluations to provide the bases for determining that a change, test, or experiment made pursuant to 10 CFR 50.59(c)(2) did not require a license amendment for installation of SB-366 components into the SW system. Because Dominion identified this issue of very low safety significance (Green) and it has been entered into their CAP (CR1031360), this finding is being treated as a SL IV, licensee-identified NCV consistent with the NRC Enforcement Policy Section 2.3.2. This item was considered licensee identified since Dominion identified this issue during a design basis review.
05000286/FIN-2016001-032016Q1Indian PointInadequate Screening of Reactor Protection System Test Method ChangeThe inspectors identified that Entergy conducted testing on the Unit 3 RPS that was not described in the UFSAR without performing an adequate 50.59 evaluation, contrary to EN-LI-100, Process Applicability Determination. Specifically, Entergy made temporary changes to the Unit 3 reactor coolant temperature channel functional test procedures, pressurizer pressure loop functional test procedures, and nuclear power range channel axial offset calibration procedures to use jumpers to bypass RPS trip functions. As a result, the NRC opened an URI related to this concern. On October 21, 2014, Entergy implemented temporary procedure changes to three sets of reactor protection system surveillance procedures. These procedures were 3-PT-Q87A, B, and C, Channel Functional Test of Reactor Coolant Temperature Channel 411, 421, and 431; 3-PT-Q95A, B, and C, Pressurizer Pressure Loop P-455, 456, and 457 Functional Test; and 3-PT-Q109A, B, and C, Nuclear Power Range Channel N-41, 42, and 43 Axial Offset Calibrations. Entergy made the temporary procedures changes as an interim corrective action following a trip of Unit 3 on August 13, 2014, during reactor protection system surveillance testing when a spurious actuation signal occurred in the channel that was not being tested. Entergy was initially unable to identify and correct the cause of the spurious over-temperature delta temperature (OTDT) channel trip and, therefore, wanted to perform their TS required surveillances without risking another unit trip should another spurious actuation occur in the degraded channel not under test. In each case, the change was to install a jumper at the beginning of the testing to maintain the trip relay in an energized condition for the tested channel of the OTDT trip circuit thereby effectively bypassing the channel in test. Each quarterly test was performed three or four times over the course of approximately ten months. On July 1, 2015, Entergy determined that they had corrected the cause of the spurious OTDT channel trips and removed the temporary procedure changes from the controlled document system. Despite this, on August 12, 2015, Entergy performed the surveillances 3-PT-Q95A, B, and C, Pressurizer Pressure Loop P-455, 456, and 457 Functional Test, which incorporated the temporary procedure changes that had been discontinued. Operating experience has shown that human error has allowed jumpers to remain installed even after testing is over because there is no obvious indication that the channel is in bypass when a jumper is used. Indian Point is committed to IEEE Standard 279-1971, Criteria for Protective Systems for Nuclear Power Plants. Section 4.13, Indication of Bypass, requires that any channel placed in a bypass configuration for testing shall have continuous indication in the control room that the channel has been removed from service. These standards preclude the use of jumpers for routine testing. This commitment was further documented in the Safety Evaluation Report for TS Amendment 107 that approved the extension of surveillance testing intervals and approved the use of the bypass feature for testing. Although Unit 3 was not originally built with RPS bypass switches, New York Power Authority had planned to install bypass switches, which would comply with IPEEE 279-1971. Entergy terminated the WO for installation of these switches. Normally, during the course of RPS channel surveillance testing, the affected channel of the OTDT trip circuit would de-energize the trip relay. If one of the other three redundant RPS channels spuriously de-energized at the same time, the two of four signal RPS trip logic would be satisfied and Unit 3 would trip, as occurred on August 13, 2015. By putting the jumper in place, the affected channel trip relay would remain energized under all conditions, including actual conditions that would require a plant trip on OTDT. During testing, the use of the jumper did not increase the likelihood of a malfunction of an SSC over that previously evaluated in the UFSAR because Unit 3 had received a license amendment (Agencywide Documents Access and Management System (ADAMS) Accession No. ML003779650) that allowed testing a bypassed channel. However, the safety evaluation report for that license amendment stated that, The licensee further commits that only those instruments whose hardware capability does not require the lifting of leads or installing of jumpers will be routinely tested in bypass. When Unit 3 applied for the license amendment, the intent was to permanently install bypass switches that would allow bypassing a channel and would clearly indicate in the control room that a channel was bypassed. The risk of inadvertently leaving a jumper in place is greater than the risk of inadvertently leaving a channel bypassed using hardware that brings in an alarm in the control room, because the jumper can go unnoticed for a longer period of time since it does not result in clear indication in the control room. Per procedure EN-LI-100, Entergy performed a 50.59 screening review for these temporary procedure changes. In this screening, they incorrectly determined that the temporary procedure changes did not involve a test not described in the UFSAR, and as a result, did not perform a 50.59 evaluation. Although the UFSAR describes reactor protection system testing by bypassing channels, it specifically does not authorize the use of jumpers to do so. The UFSAR for Unit 3, chapter 7, states, Test procedures also allow the bistable output relays of the channel under test to be placed in the bypassed mode prior to proceeding with the analog channel test ... this may only be done for circuits whose hardware does not require the use of jumpers or lifted leads to be placed in bypass mode. Jumpering out the RPS trip relay in an RPS channel under test created an adverse condition because it removed the automatic trip signal from the RPS logic. Entergy was required to fully evaluate the adverse condition rather than authorize the change under an abbreviated 50.59 screening process. The inspectors concluded that not performing an adequate 50.59 evaluation was a performance deficiency that was reasonably within Entergys ability to foresee and correct and should have been prevented. Because Entergy was in the process of performing a retroactive 50.59 evaluation at the end of the inspection period, the inspectors were not able to evaluate if the performance deficiency was more than minor. The inspectors determined that the issues concerning the use of jumpers for RPS testing is an URI pending Entergy completion and NRC review of the 50.59 evaluation.
05000313/FIN-2016007-032016Q1Arkansas NuclearInadequate Operating Experience EvaluationsThe team identified a Green finding for the licensees failure to evaluate operating experience as required by procedure EN-OE-100-02, Operating Experience Evaluations. This procedure allowed taking no action for operating experience issues that were applicable to the station if multiple barriers existed to preclude failure. The team identified two examples where the licensee had not correctly verified the adequacy of credited barriers and as a result, represented a vulnerability to a similar event occurring at the station. The licensees corrective actions included re-performing the operating experience evaluations and documenting the issue in the corrective action program as condition reports CR-ANO-C-2016-00463 and CR-ANO-C-2016-00782. The failure to evaluate operating experience was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the protection against external factors attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the failure to take corrective action to address the large motor and respiratory protection operating experience could result in a similar adverse condition or event at the station. The finding was evaluated using Inspection Manual Chapter 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, and Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 1 Initiating Events Screening Questions, dated June 19, 2012. The team determined the finding was of very low safety significance (Green) because the finding would not result in exceeding the reactor coolant system leak rate for a small loss of coolant accident or affect systems used to mitigate a loss of coolant accident, did not cause a reactor trip and loss of mitigation equipment, did not involve the loss of a support system, did not involve a degraded steam generator tube condition, and did not impact the frequency of a fire or internal flooding event. This finding had a human performance cross-cutting aspect of Conservative Bias because the licensee failed to ensure that individuals used decision making-practices that emphasized prudent choices over those that were simply allowable. Specifically, individuals performing evaluations rationalized assumptions rather than verifying the actual conditions (H.14).
05000313/FIN-2016007-042016Q1Arkansas NuclearInadequate Control of Monitoring for Wall Loss in the Service Water SystemThe team identified a Green finding and an associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, because the licensee failed to implement the Microbiologically Influenced Corrosion Monitoring Program in a manner that would monitor for pipe wall loss in the service water system. Specifically, the team identified that the licensee had not maintained representative monitoring points and allowed an excessive time period between pipe wall thickness inspections. The licensees corrective actions included initiating an evaluation of the Microbiologically Influenced Corrosion Monitoring Program and documenting the issue in the corrective action program as condition reports CR-ANO-C-2016-00435, CR-ANO-C-2016-00524 and CR-ANO-C-2016-00546. The team did not identify a loss of structural integrity in any service water system pipe caused by these errors and therefore did not have an operability concern. The failure to implement the Microbiologically Influenced Corrosion Monitoring Program was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone objective 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 monitor service water system pipe locations for microbiologically influenced corrosion could result in a loss of pipe structural integrity (e.g., large pipe break) resulting in the loss of a service water train and adversely affecting safety-related equipment necessary for accident mitigation. The finding was evaluated using Inspection Manual Chapter 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, and Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2 Mitigating Systems Screening Questions, dated June 19, 2012. The team determined the finding was of very low safety significance (Green) because the finding was a deficiency affecting the design or qualification of a mitigating system, structure or component, but the system, structure or component maintained its operability. This finding had a human performance cross-cutting aspect of Conservative Bias because the licensee failed to ensure that individuals used decision-making practices that emphasized prudent choices over those that were simply allowed. Specifically, the program database contained errors related to non-conservative decisions regarding the impact of monitoring points following pipe replacement and limiting the maximum time between monitoring for wall loss (H.14).
05000313/FIN-2016007-062016Q1Arkansas NuclearFailure to Correct Degraded Unit 2 Train B Emergency Diesel Generator Heat Exchangers Service Water Flow and Degraded Unit 1 Containment CoatingsThe team identified two examples of a Green finding and an associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, for the licensees failure to correct conditions adverse to quality. Specifically, the licensee failed to correct long term degraded service water flow to the Unit 2 safety-related train B emergency diesel generator heat exchangers since 2008, and degraded Unit 1 reactor containment building coatings since 2009. The licensees corrective actions included performing an operability determination and determining that the service water system and the Unit 1 containment sump were operable and documenting the issue in the corrective action program as condition reports CR-ANO-C-2016-00946, and CR-ANO-1-2015-00200. The failure to correct conditions adverse to quality associated with Unit 2 service water flow to the B emergency diesel generator heat exchangers and the Unit 1 reactor containment building coatings was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to correct long term degraded: 1) service water flow beyond the action limit in accordance with procedure EN-DC-159, Component and System Monitoring, to the B emergency diesel generator heat exchangers, which challenged the capability of emergency diesel generator response to design basis events; and 2) containment coatings which challenged the Unit 1 emergency core cooling system capacity. The finding was evaluated using Inspector Manual Chapter 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, and Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, dated June 19, 2012. The team determined the finding was of very low safety significance (Green) because the finding was a deficiency affecting the design or qualification of mitigating system, structure or component, but the system, structure or component maintained operability. This finding had a human performance cross-cutting aspect of Design Margins because the licensee failed to place special attention on maintaining margins in safety related equipment. Specifically the licensee has repeatedly: 1) throttled service water flow away from the safety-related shutdown cooling heat exchangers, reducing the shutdown cooling design margins to maintain minimally acceptable flow to the emergency diesel generator heat exchangers since 2008; and 2) reduced the available containment sump margin rather than correct containment coating deficiencies (H.6).
05000313/FIN-2016007-092016Q1Arkansas NuclearEmergency Feedwater Pump Casing Wall Loss Not MonitoredThe team identified a Green finding and an associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion XI, Test Control, for the licensees failure to establish a test program for monitoring the Unit 1 emergency feedwater pumps casing wall thickness loss to demonstrate that the pumps would remain satisfactory for service. The scope of the Wall Thinning Aging Management Program included the emergency feedwater pumps casing. However, the team noted that the procedure did not include wall thickness measurements on the emergency feedwater pumps casings. The licensees corrective actions included performing an immediate operability determination and determining the pumps were operable, and documenting the issue in the corrective action program as condition report CR-ANO-1-2016-00606. The failure to establish a test program for monitoring the Unit 1 emergency feedwater pumps casing wall thickness loss was a performance deficiency. The performance deficiency was determined to be more than minor because, it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to monitor the Unit 1 emergency feedwater pumps casing wall thickness could result in a corrosion- or erosion-induced pump casing failure. The finding was evaluated using Inspection Manual Chapter 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, and Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2 Mitigating Systems Screening Questions, dated June 19, 2012. The team determined the finding was of very low safety significance (Green) because the finding was a deficiency affecting the design or qualification of a mitigating system, structure or component, but the system, structure or component maintained its operability. This finding had a human performance cross-cutting aspect of Work Management for failing to implement a process of planning, controlling, and executing work activities such that nuclear safety is an overriding priority. Specifically, the licensee entered the period of extended operation in May 2014 and had not established a surveillance procedure to monitor the corrosion induced wall loss of the pump casings as required by the approved aging management program (H.5).
05000313/FIN-2016007-132016Q1Arkansas NuclearFailure to Update Probabilistic Risk Assessment Model in a Timely Manner Results in Failure to Submit Complete and Accurate InformationThe team identified a Green finding for the licensees failure to update the Level 1 probabilistic risk assessment model as required by procedure EN-DC-151, Probabilistic Safety Assessment (PSA) Maintenance and Update, Revision 5. This finding also involved a Severity Level IV, non-cited violation of 10 CFR 50.9, Completeness and Accuracy of Information, because the licensee failed to submit complete and accurate model maintenance information in their license amendment request for the extension of the integrated leak rate testing for the Unit 1 reactor building. Procedure EN-DC-151 established requirements to ensure that ANOs models represent the as-built, as-operated plant in a manner sufficient to support the applications for which they are used, including performing periodic updates within four years of the previous update. The licensee had not updated the internal events model for Unit 1 since July 2009 and for Unit 2 since 2008. The licensees corrective actions included completing the model update for Unit 1 on April 15, 2016, for Unit 2 on February 29, 2016, and documenting the issue in the corrective action program as condition report CR-ANO-C-2016-01573. The failure to perform probabilistic risk assessment updates as required by procedure EN-DC-151 was a performance deficiency and therefore a finding. An NRC-identified violation of 10 CFR 50.9 was associated with this finding because it impacted the regulatory process in that inaccurate information was provided to the NRC that was material in making a licensing decision. Therefore, in accordance with Inspection Manual Chapter 0612, Appendix B, Issue Screening, this issue was evaluated using both the finding and traditional enforcement processes. This violation is associated with a finding that has been evaluated by the significance determination process and communicated with a significance determination process color reflective of the safety impact of the deficient licensee performance. The significance determination process, however, does not specifically consider the regulatory process impact. Thus, although related to a common regulatory concern, it is necessary to address the violation and finding using different processes to correctly reflect both the regulatory importance of the violation and the safety significance of the associated finding. The performance deficiency was determined to be more than minor because it was associated with the equipment performance and procedure quality attributes of the Mitigating Systems cornerstone objective 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 lack of a formal process to ensure that probabilistic risk assessment model updates were performed as scheduled impacted license amendment requests, performance indicator accuracy, and daily maintenance risk evaluations for planned and emergent maintenance activities since the internal events model was not reflective of current plant conditions. The finding was evaluated using Inspection Manual Chapter 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, and Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2 Mitigating Systems Screening Questions, dated June 19, 2012. The team determined the finding was of very low safety significance (Green) because it did not represent an actual loss of function of at least a single train for greater than its technical specification allowed outage time, and did not involve the loss or degradation of equipment or function specifically designed to mitigate a seismic, flooding, or severe weather initiating event. Consistent with Section 6.9 of the NRC Enforcement Policy, this violation was determined to be a Severity Level IV violation because inaccurate information was provided, but it would not have likely caused the NRC to reconsider its regulatory position or undertake substantial further inquiry. This finding had a human performance cross-cutting aspect of Resources because the licensee did not ensure that sufficient personnel resources were available to perform all probabilistic risk assessment duties, including model maintenance (H.1).
05000313/FIN-2016007-162016Q1Arkansas NuclearFailure to Properly Calibrate Unit 1 Reactor Building Atmospheric Particulate Radiation Monitor RE-7460The team identified a Green finding and an associated non-cited violation of 10 CFR 20.1501(c) because the licensee failed to ensure that instruments and equipment used for quantitative radiation measurements were calibrated periodically for the radiation measured. Specifically, the licensee did not properly calibrate the Unit 1 Reactor Building Atmospheric Particulate Radiation Monitor RE-7460. The licenses corrective actions, included removing radiation monitor RE-7460 from service, instituting compensatory measures for assessing reactor coolant system leak detection in accordance with Technical Specification 3.4.15, RCS Leakage Detection Instrumentation, and documenting the issue in the corrective action program as condition reports CR-ANO-1-2016-00056 and CR-ANO-1-2016-01087. The failure to properly calibrate radiation monitor RE-7460 was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the plant instrumentation attribute of the Occupational Radiation Safety cornerstone and adversely affected the cornerstone objective to ensure adequate protection of the worker health and safety from exposure to radiation from radioactive material. Specifically, the failure to properly calibrate radiation monitor RE-7460 adversely impacted its ability to be used to identify reactor coolant system leakage and the ability to assess radioactive airborne concentrations and dose rates. The finding was evaluated using the significance determination process in accordance with Inspection Manual Chapter 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, dated June 19, 2012, and Appendix C, Occupational Radiation Safety Significance Determination Process, dated August 19, 2008. The team determined that the finding was of very low safety significance (Green) because it was not an as-low-as-reasonably-achievable (ALARA) issue, there was no overexposure or substantial potential for an overexposure, and the ability to assess dose was not compromised. This finding had a human performance cross-cutting aspect of Documentation because the licensee failed to create and maintain complete, accurate and up-to-date documentation. Specifically, the licensee personnel failed to translate the vendor manual instruction to ensure the detector was installed against the hard stop so that it was in the correct position to make the calibration valid (H.7).
05000313/FIN-2016007-012016Q1Arkansas NuclearFailure to Complete Extent of Condition Reviews for the Stator Drop Significant Condition Adverse to Quality EventThe team identified a Green finding and an associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, because the licensee failed to follow procedure EN-LI-102, Corrective Action Program, which required verification that the required action has been completed as intended. Specifically, for the extent of condition reviews for the stator drop event, two corrective actions were closed even though the actions were inadequate. The licensees corrective actions included re-performing the actions and documenting the failures in the corrective action program as condition reports CR-ANO-C-2016-00479 and CR-ANO-C-2016-00480. The failure to complete two of the extent of condition reviews associated with the stator drop event specified in the associated corrective action plan was a performance deficiency. The performance deficiency was determined to be more than minor because, it was associated with the design control attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the failure to complete actions related to identifying and correcting the extent of condition for a significant condition adverse to quality could potentially lead to an initiating event. The finding was evaluated using Inspection Manual Chapter 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, and Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 1 Initiating Events Screening Questions, dated June 19, 2012. The team determined the finding was of very low safety significance (Green) because the inadequate closure of corrective actions did not cause a reactor trip or the loss of mitigation equipment relied upon to transition the plant from the onset of a trip to a stable shutdown condition. This finding had a problem identification and resolution cross-cutting aspect of Resolution because the licensee did not take effective corrective actions to address issues in a timely manner commensurate with their safety significance. Specifically, the scope of the actions taken as part of the corrective actions did not resolve the issue as describe in the corrective action statement (P.3).
05000313/FIN-2016007-022016Q1Arkansas NuclearInadequate Effectiveness Reviews for Corrective Actions to Prevent RecurrenceThe team identified a Green finding for the licensees failure to ensure that effectiveness reviews to assess the adequacy of corrective actions as required by procedure EN-LI-118-ANO-RC, Cause Evaluation Process, were appropriate. Specifically, the team identified numerous examples in which effectiveness reviews for corrective actions to prevent recurrence failed to assess whether corrective actions achieved the intended results. The licensees corrective actions included revising the effectiveness reviews to ensure that the corrective actions achieve the desired effect, and documenting the issue in the corrective action program as condition reports CR-ANO-C-2016-00482 and CR-ANO-C-2016-01013. The failure to establish adequate effectiveness review success criteria to verify the intended results for corrective actions to prevent recurrence were achieved was a performance deficiency. The performance deficiency was determined to be more than minor because, it impacted the human performance attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the failure to complete actions related to identifying and correcting the extent for a significant condition adverse to quality could potentially lead to an initiating event. The finding was evaluated using Inspection Manual Chapter 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, and Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 1 Initiating Events Screening Questions, dated June 19, 2012. The team determined the finding was of very low safety significance (Green) because it did not cause a reactor trip or the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. This finding had a problem identification and resolution cross-cutting aspect of Self-Assessment because the licensee did not ensure that the organization routinely conducted self-critical and objective assessments of its programs and practices. Specifically, the Corrective Action Review Board tasked with validating the effectiveness of the corrective action plans did not ensure that the effectiveness review plans assessed whether the implemented corrective actions were effective (P.6).
05000368/FIN-2016007-102016Q1Arkansas NuclearFailure to Develop an Operability Decision-Making Issue for Degraded Condition on Safety Injection TankThe team identified a Green finding for the licensees failure to create an operational decision making issue document per procedure EN-OP-111, Operability Decision Making Issue (ODMI) Process. Specifically, the licensee failed to evaluate the plant impact and operational challenges associated with not repairing safety injection tank check valve 2SI-13D bonnet leakage, which was identified prior to starting up from the fall 2016 outage. The leakage increased to the point where normal makeup capability was challenged. The licensees corrective actions included performing an unplanned shutdown to repair safety injection tank check valve 2SI-13D, and documenting the issue in the corrective action program as condition reports CR-ANO-2-2016-00546, CR-ANO-C-2016-0948, and CR-ANO-C-2016-01348. The failure to establish operational decision making issue guidance per procedure EN-OP-111 to address safety injection tank check valve 2SI-13D leakage was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the equipment reliability 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 leak became an operational challenge, in that, operators were filling the safety injection tank for the majority of the shift. The finding was evaluated using Inspection Manual Chapter 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, and Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2 Mitigating Systems Screening Questions, dated June 19, 2012. The team determined the finding was of very low safety significance (Green) because it did not represent an actual loss of function of at least a single train for greater than its technical specification allowed outage time, and did not involve the loss or degradation of equipment or function specifically designed to mitigate a seismic, flooding, or severe weather initiating event. This finding had a problem identification and resolution cross-cutting aspect of Self-Assessment because the licensee did not conduct self-critical and objective reviews of degraded plant issue to determine whether they should be addressed using the operational decision making issue process (P.6).
05000313/FIN-2016007-112016Q1Arkansas NuclearPressurizer Block Valve Not Installed in the Qualified Environmental ConfigurationThe team identified a Green finding and an associated non-cited violation of 10 CFR 50.49(f) for the licensees failure to ensure that Unit 1 pressurizer block valve CV-1000, was installed in the qualified configuration. Specifically, the safety-related motor operated block valve was installed with the limit switch compartment facing downward instead of up. The licensees corrective actions included performing a prompt operability determination and determining the valve was operable, evaluating the extent of condition, and documenting the issue in the corrective action program as condition report CR-ANO-C-2016-00884. The failure to ensure the pressurizer motor operated block valve CV-1000 was in the qualified configuration was a performance deficiency. The performance deficiency was determined to be more than minor because, it was associated with the design control and equipment performance attributes 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, valve CV-1000 not being installed in the qualified configuration increased the possibility of leaking grease or accumulating condensation in the limit switch compartment which could cause failure, electrical shorts or erratic operation. The finding was evaluated using Inspection Manual Chapter 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, and Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2 Mitigating Systems Screening Questions, dated June 19, 2012. The team determined the finding was of very low safety significance (Green) because the finding was a deficiency affecting the design or qualification of a mitigating system, structure or component, but the system, structure or component maintained its operability. This finding had a problem identification and resolution cross-cutting aspect of Operating Experience because the licensee failed to systematically and effectively collect, evaluate, and implement relevant internal and external operating experience in a timely manner (P.5).
05000313/FIN-2016007-122016Q1Arkansas NuclearFailure to Perform Predictive Maintenance on Safety-Related Medium-Voltage SwitchgearThe team identified a Green finding for the licensees failure to fully implement procedure EN-DC-310, Predictive Maintenance Program, Revision 7. Specifically, the licensee failed to perform predictive maintenance-related thermography on medium-voltage safety-related electrical switchgear. The team identified that the predictive maintenance equipment list appropriately included the medium-voltage switchgear as components in the predictive maintenance program. However, the monitoring was not being scheduled or performed. The licensees corrective actions included performing an operability determination and determining that there was no impact to the performance of the switchgear, creating tasks to perform thermography, and documenting the issue in the corrective action program as condition report CR-ANO-C-2016-00571. The failure to perform predictive maintenance on safety-related medium-voltage switchgear as required by procedure EN-DC-310 was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, degradation of safety-related medium voltage switchgear could go unidentified for extended periods, reducing system reliability. The finding was evaluated using Inspection Manual Chapter 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, and Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2 Mitigating Systems Screening Questions, dated June 19, 2012. The team determined the finding was of very low safety significance (Green) because it did not represent an actual loss of function of at least a single train for greater than its technical specification allowed outage time, and did not involve the loss or degradation of equipment or function specifically designed to mitigate a seismic, flooding, or severe weather initiating event. This finding had a problem identification and resolution cross-cutting aspect of Identification because the licensee did not identify issues completely, accurately, and in a timely manner. Specifically, the licensee did not identify that their implementation of the Predictive Maintenance Program did not appropriately address safety-related medium-voltage switchgear as requiring periodic thermography inspections (P.1).
05000313/FIN-2016007-182016Q1Arkansas NuclearLicensee-Identified ViolationTitle 10 CFR Part 50, Appendix B, Criterion XVIII, Audits, requires, in part, that a comprehensive system of planned and periodic audits shall be carried out to verify compliance with all aspects of the QA program and to determine the effectiveness of the program. Quality Assurance Program Manual Section C.2.a.(2) requires biennial audits of site programs, including the ASME Code Section XI ISI Program. Contrary to these requirements, ANO identified that from 2011 through December 17, 2015, a periodic audit of the ASME Code Section XI ISI Program was not carried out to verify compliance with all aspects of the QA program and to determine the effectiveness of the program. ANO documented this violation in the CAP as CR-ANO-C-2015-05011. The team determined that this issue was of very low safety significance (Green) after reviewing IMC 0609, Attachment 0609.04, and Appendix A, Exhibit 1 Initiating Events Screening Questions. Specifically, the team answered no to each of the questions in Exhibit 1.
05000313/FIN-2016007-152016Q1Arkansas NuclearFailure to Maintain Structural Design Clearances inside the Unit 1 and 2 Reactor Containment BuildingsThe team identified a Green finding and an associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to ensure that numerous structural components located inside Units 1 and 2 reactor containment buildings were installed per structural drawings. The team identified numerous sections of floor grating and 14 inch plate steel supports that came in direct contact with the containment liner. In some cases, contact between the containment liner and the components resulted in damage to the liner and the liner protective coating. The licensees corrective actions included performing an operability determination and determining that the Units 1 and 2 containment liner was operable but degraded and nonconforming, establishing plans to correct the deficiencies in each units upcoming outage, and documenting the issue in the corrective action program as condition reports CR-ANO-1-2016-00492, CR-ANO-2-2016-00397, and CR-ANO-2-2016-00413. The failure to ensure that numerous structural components inside Units 1 and 2 reactor containment buildings were properly installed was a performance deficiency. The performance deficiency was determined to be more than minor because, it was associated with the configuration control attribute of the Barrier Integrity cornerstone and adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accident or events. Specifically, the failure to ensure that items inside the Units 1 and 2 reactor containment buildings were installed per structural drawings could result in damage to the safety-related containment liner and challenge its function to protect the public from radionuclide releases. The finding was evaluated using Inspection Manual Chapter 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, and Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 3 Barrier Integrity Screening Questions, dated June 19, 2012. The team determined the finding was of very low safety significance (Green) because the finding did not represent as actual open pathway in the physical integrity of reactor containment and did not involve an actual reduction in function of hydrogen ignitors. This finding had a problem identification and resolution cross-cutting aspect of Identification because the licensee failed to implement a corrective action program with a low threshold for identifying issues. Specifically, the licensee failed to identify numerous containment liner stand-off clearance deficiencies during the required containment liner inspections over the operating life of the plant (P.1).
05000368/FIN-2016007-052016Q1Arkansas NuclearFailure to Include Unit 2 Service Water Pump Supports in the ASME Code Section XI Inservice Inspection ProgramThe team identified a Green finding and an associated non-cited violation of 10 CFR 50.55a(g)(4) for the licensees failure to inspect Unit 2 service water pump supports in accordance with ASME Code Section XI. Specifically, the licensee failed to include Unit 2 service water pump supports in the Inservice Inspection Program and had not completed a visual VT-3 examination since the supports were installed in 1991. The licensees corrective actions included incorporating the supports into the Unit 2 Inservice Inspection Program, performing an immediate operability determination, assigning a corrective action to determine the past operability, and documenting the issue in the corrective action program as condition reports CR-ANO-2-2016-00361 and CR-ANO-2-2016-00421. The failure to inspect the Unit 2 service water pump supports in accordance with ASME Code Section XI was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the design control attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to periodically inspect the pump supports could result in the failure to identify a nonfunctional support that would increase the risk of a pump failure. The finding was evaluated using Inspection Manual Chapter 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, and Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2 Mitigating Systems Screening Questions, dated June 19, 2012. The team determined the finding was of very low safety significance (Green) because the finding was a deficiency affecting the design or qualification of a mitigating system, structure or component, but the system, structure or component maintained its operability. The team did not identify a cross-cutting aspect for this issue because the cause of this performance deficiency was not reflective of current performance.
05000368/FIN-2016007-072016Q1Arkansas NuclearFailure to Maintain Service Water Design Cooling to the Unit 2 High Pressure Safety Injection Pump Seal and Bearing CoolersThe team identified a Green finding and an associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to assure that the design basis service water cooling flow rates for the Unit 2 high pressure safety injection pump bearing and seal coolers were correctly translated into operating and surveillance procedures. Specifically, the pump surveillance and operating procedures were inadequate to monitor for, or correct degraded service water flow to the pump seal and bearing coolers. The procedures allowed for zero flow to the coolers, whereas the design drawing required 20 gallons per minute. The licensees corrective actions included performing an immediate operability determination and determining the pumps were operable based on the most recent surveillance flow tests, requesting a prompt operability determination, scheduling inspection of the seal and bearing coolers, and documenting the issue in the corrective action program as condition reports CR-ANO-2-2016-00672 and CR-ANO-2-2016-00674. The failure to correctly incorporate the design basis service water cooling flow for the Unit 2 high pressure safety injection pump coolers into the operating and surveillance procedures was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the design control attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to incorporate the design basis service water cooling flow into the operating and surveillance procedures could result in the failure of the high pressure safety injection pumps during accident mitigation. The finding was evaluated Inspection Manual Chapter 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, and Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2 Mitigating Systems Screening Questions, dated June 19, 2012. The team determined the finding was of very low safety significance (Green) because the finding was a deficiency affecting the design or qualification of a mitigating system, structure or component, but the system, structure or component maintained its operability. The team did not identify a cross-cutting aspect for this issue because the cause of this performance deficiency was not reflective of current performance.
05000368/FIN-2016007-082016Q1Arkansas NuclearInadequate Flow Monitoring of Unit 2 Service Water to Emergency Feedwater Pump Suction SupplyThe team identified a Green finding and an associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion XI, Test Control, for the licensees failure to establish a test program for the Unit 2 service water supply to emergency feedwater pump suction lines. Specifically, the licensee failed to demonstrate that flow through this line would remain satisfactory for design basis accidents. The licensees corrective actions included performing an operability determination and determining that the last performance of the procedure in 2015 documented a flow rate greater than the required value, was evaluating the lack of a surveillance test program for monitoring flow rate loss in these lines, and documenting the issue in the corrective action program as condition report CR-ANO-2-2016-00670. The failure to establish a test program for the Unit 2 service water to emergency feedwater pump suction supply line was a performance deficiency. The performance deficiency was determined to be more than minor because, it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to monitor the flow through the Unit 2 service water to emergency feedwater pump suction supply line could result in loss of adequate flow to support emergency feedwater pumps for accident mitigation. The finding was evaluated using Inspection Manual Chapter 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, and Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2 Mitigating Systems Screening Questions, dated June 19, 2012. The team determined the finding was of very low safety significance (Green) because the finding was a deficiency affecting the design or qualification of a mitigating system, structure or component, but the system, structure or component maintained its operability. The team did not identify a cross-cutting aspect for this issue because the error that caused this deficiency was not reflective of current performance.
05000336/FIN-2015004-012015Q4MillstoneCharging Packing Lubrication Pump Inadequate Operating Procedure Acceptance CriteriaThe inspectors identified a Green NCV of Title 10 of the Code of Federal Regulations (10 CFR) 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, associated with Dominions failure to include in the Unit 2 charging pump operating procedure appropriate acceptance criteria for determining operability of the Unit 2 charging pumps upon the loss of the associated charging flushing/lubrication pump. Specifically, Dominion implemented a procedure change which stated that the condition of the charging flushing/lubrication pumps does not affect charging pump operability or mission time without supporting technical information and contrary to guidance provided in the charging pump vendor technical manual, impacting an operability determination on December 13, 2015. Dominion has entered the concern associated with the charging pump operability acceptance criteria into their corrective action program (CAP) under condition report (CR)1021512. This finding was determined to be more than minor in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, dated September 7, 2012, because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and adversely affected its objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Further, this finding was found to be consistent with more than minor examples 3.j and 3.k of IMC 0612, Appendix E, Examples of Minor Issues, dated August 11, 2009. This finding was evaluated in accordance with IMC 0609, Significance Determination Process, Attachment 4, Initial Characterization of Findings, and IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, Section A, Mitigating Systems, Structures or Components and Functionality, and screened as very low safety significance (Green) since it was not a qualification or design deficiency, did not represent a loss of system or function, and did not exceed its technical specification (TS) allowed outage time. Inspectors identified a cross-cutting aspect in Human Performance, Documentation, in that Dominion lacked technical documentation to support the operability assertion in the charging pump operating procedure to address contrary guidance provided in the charging pump vendor manual.
05000336/FIN-2015004-022015Q4MillstoneTurbine Driven Auxiliary Feedwater Pump Corrective Actions to Prevent RecurrenceThe inspectors identified a Green NCV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, for Dominions failure to take corrective action to prevent repetition for a significant condition adverse to quality according to the definition in PI-AA-200, Corrective Action. Specifically, PI-AA-200 lists unplanned entry into a TS action that results in taking a unit off-line as an example of a significant condition adverse to quality. On July 26, 2014, Dominion performed a TS required shutdown of Unit 2 due to the inoperability of the turbine driven auxiliary feedwater (TDAFW) pump. Dominion cancelled the root cause evaluation (RCE) assigned to investigate the cause of the plant shutdown, stating that the direct cause of the shutdown was foreign material in the flow orifice in a recirculation line for the TDAFW pump. No corrective actions to prevent recurrence (CAPRs) were assigned after the direct cause was determined. Dominion entered this issue into their CAP as CR1019514. This performance deficiency was determined to be more than minor in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, dated September 7, 2012, because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and adversely affected its objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, taking CAPRs will help to ensure the availability and reliability of the TDAFW pump. This finding was evaluated in accordance with IMC 0609, Significance Determination Process, Attachment 4, Initial Characterization of Findings, and IMC 0609, Appendix A, Exhibit 2, and screened as very low safety significance (Green) since it was not a qualification or design deficiency, did not represent a loss of system or function, and did not exceed its TS allowed outage time. The inspectors determined this issue had a cross cutting aspect in Human Performance, Consistent Process, where individuals use a consistent, systematic approach to make decisions. Specifically, Dominion inappropriately used the corrective action procedure to change the causal evaluation category without properly balancing the risk of the decision, and therefore did not develop CAPRs for a significant condition adverse to quality.
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