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| Quarter | Site | Title | Description | |
|---|---|---|---|---|
| 05000247/FIN-2018003-03 | 2018Q3 | Indian Point | Containment Fan Cooler 24 Through-Wall Service Water Leak Caused by Inadequate Application of Epoxy Coating Resulting in Corrosion and a Safety System Functional Failure of Containment | A self-revealing Green NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified when Entergy did not ensure that activities affecting quality were prescribed by documented instructions or procedures, of a type appropriate to the circumstances, and that these activities were accomplished in accordance with these instructions, procedures or drawings. Furthermore, Entergy did not ensure that the instructions or procedures included appropriate quantitative or qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished. Specifically, Entergy did not ensure that the maintenance procedure for applying the internal EneconTM epoxy coating to the 24 fan cooler main cooler supply line elbow was adequate to ensure proper epoxy coating adherence, and Entergy did not adequately verify the coating adherence prior to placing the elbow in service. This resulted in a through-wall leak and a safety system functional failure of containment. |
| 05000247/FIN-2018003-02 | 2018Q3 | Indian Point | Containment Fan Coolers 21 and 24 Motor Cooler Elbow Through-Wall Leaks Due to Excessive Service Water Flow Rates and Safety System Functional Failures of Containment | A self-revealing Green NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, was identified when Entergy did not ensure that measures were established for the selection and review for suitability of application of materials, parts, equipment, and processes that are essential to the safety-related functions of the structures, systems, and components. Specifically, in 1998, when the former license-holder for Unit 2 decided to replace the original-construction large-radius, butt-welded elbow joints in the service water motor cooler return lines from the Unit 2 FCUs with a new design (a short radius, socket-weld fitting), these elbow joints were not properly evaluated for suitability of application. The service water flow velocity through the modified FCU return piping was in excess of the vendor-allowable flow velocity limit, which resulted in the gradual erosion of the motor cooler elbow joints, eventually leading to through-wall leaks on an ASME class III piping system inside containment, leading to breaches of containment integrity and safety system functional failures. |
| 05000247/FIN-2018003-01 | 2018Q3 | Indian Point | Inadequate Procedural Guidance for Spent Fuel Movement and Storage Requirements | The inspectors identified a Green NCV of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion V, Procedures, when Entergy did not have appropriate documented instructions or written procedures for spent fuel movement and storage requirements adjacent to potentially degraded Boraflex panels. Specifically, configuration restrictions were not addressed in some cases and, therefore, did not comply with controls to meet the criticality analysis of record (CAOR) in 2016; and the resultant revised guidance did not accurately reflect the modeled supporting analysis |
| 05000336/FIN-2018003-01 | 2018Q3 | Millstone | Failure to Assure that Safety-Related Service Water Piping Conformed to the Procurement Documents | The 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. |
| 05000247/FIN-2018003-04 | 2018Q3 | Indian Point | Inadequate Procedure for Turbine Startup Caused a Reactor Trip | A self-revealing Green NCV of TS 5.4.1, Procedures, was identified because Entergy did not provide adequate guidance in 2-SOP-26.4, Turbine Generator Startup, Synchronization, Voltage Control, and Shutdown. Specifically, Entergy did not provide adequate procedural direction to ensure the main turbine control oil stop valve Z was in the correct position. As a result, the steam generator water level exceeded the trip setpoint for the main boiler feed pumps which led the operators to insert a manual reactor trip. |
| 05000286/FIN-2018002-01 | 2018Q2 | Indian Point | Reactor Pressure Boundary Leakage Due to Weld Failure in Reactor Vessel Head Penetration #3 | A 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. |
| 05000286/FIN-2018001-02 | 2018Q1 | Indian Point | Inadequate Procedure for Placing Chemical and Volume Control System Demineralizer In Service | A self-revealing Green NCV of Technical Specification 5.4.1, Procedures, was identified because Entergy failed to provide adequate guidance in 3-SOP-CVCS-004, Placing the CVCS Demineralizers In or Out of Service. Specifically, Entergy did not provide adequate procedural direction to prevent exceeding the reactor coolant filter differential pressure while placing the demineralizers in service. As a result, the pressurizer water level technical specification limit was exceeded and the CVCS piping upstream of the filter was over-pressurized resulting in diaphram ruptures on valves CH-305 and CH-352 thereby spreading contamination throughout the Primary Auxiliary Building. |
| 05000247/FIN-2018001-01 | 2018Q1 | Indian Point | Failure to Incorporate Adequate Test Controls for Quarterly Stroke Close Testing of the Steam Supply Valves to Turbine-Driven Auxiliary Feedwater Pump | The inspectors identified a Green NCV of 10 CFR Part 50, Appendix B, Criterion XI, Test Control, when Entergy did not assure that surveillance tests required to demonstrate that structures, systems, and components will perform satisfactorily in service are identified and performed in accordance with written test procedures which incorporate the requirements and acceptance limits contained in applicable design documents. Specifically, during quarterly stroke testing of the steam isolation valves to the 22 turbine-driven auxiliary feedwater pump, PCV-1310A and PCV-1310B, Entergy did not ensure that these valves traveled to the closed position as required to verify that the safety function was met. |
| 05000247/FIN-2017003-01 | 2017Q3 | Indian Point | Component Misalignments for Nuclear Instrumentation P6 Permissive and AFW Flow Transmitter FI-1201 Following Scheduled Maintenance | A self-revealing Green NCV of Technical Specification (TS) 5.4.1, Procedures, with two examples was identified when Entergy failed to implement procedures to ensure correct system alignment for the nuclear instrumentation permissive interlock, P6, and auxiliary feedwater (AFW) flow transmitter, FI-1201. Entergy promptly corrected the alignment issues and entered them into their corrective action program (CAP) as condition report (CR)-IP2-2017-02193 for the P6 permissive interlock and CR-IP2-2017-02150 for the AFW flow transmitter. This performance deficiency is more than minor because it affects the configuration control attribute of the Mitigating System cornerstone to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, in both cases, the instrumentation was left disabled following maintenance such that they could not perform their safety functions required by TSs. Additionally, the first example was similar to IMC 0612, Appendix E, example 2.g, because Entergy changed plant modes from Mode 5 to Mode 2 without ensuring P6 was operable. The second example was similar to IMC 0612, Appendix E, examples 5.a and 5.b, because Entergy failed to return the AFW flow transmitter to service after the refueling outage. The inspectors assigned a cross-cutting aspect in the area of Human Performance, Work Management, because both examples demonstrated a failure in the planning, control, and execution of work, and a lack of coordination between work groups to ensure quality.(H.5) |
| 05000286/FIN-2017002-01 | 2017Q2 | Indian Point | Failure to Maintain Flow Channeling Gate Closed in Accordance with the Containment Procedure | Green. The inspectors identified a Green NCV of Technical Specification (TS) 5.4.1, Procedures, for Entergys failure to implement procedure OAP-007, Containment Entry and Egress. Specifically, workers transiting the inner and outer crane wall sections of containment on May 14, 2017, did not maintain flow channeling gate C secured during Mode 4 to ensure availability of the containment sumps to provide suction for the emergency core cooling system (ECCS). Entergy immediately restored gate C to an acceptable configuration, and generated condition report (CR)-IP3-2017-02737 to address this issue. This performance deficiency was more than minor because it is associated with the configuration control (shutdown equipment lineup) attribute and adversely affected the Mitigating Systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). A detailed risk assessment was conducted and the change in core damage frequency was determined to be 2E-8, therefore, this issue represents a Green finding. The inspectors determined that this finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Resolution, because Entergy did not take effective corrective actions to address issues in a timely manner commensurate with their safety significance. Specifically, the corrective actions from the event for the prior year were ineffective at preventing this occurrence. (P.3) |
| 05000286/FIN-2017001-01 | 2017Q1 | Indian Point | Inadequate Standard Operation Procedure for the Backup Spent Fuel Pool Cooling System | Green. The inspectors identified an NCV of very low safety significance of TS 5.4, Procedures, because Entergy did not adequately establish and maintain procedure 3- SOP-SFP-003, Operation of the Backup Spent Fuel Pool Cooling (BSFPC) System. The 4 updated final safety analysis report (UFSAR) for Unit 3 included several administrative controls for the use of the BSFPC system as the sole source of cooling to the fuel pool; and some of these controls were not captured in 3-SOP-SFP-003 and, therefore, were not implemented. Entergy wrote CR-IP3-2017-00510 to enter this concern into their corrective action program (CAP). The inspectors determined that failing to include all of the administrative controls in procedure 3-SOP-SFP-003 was a performance deficiency. This performance deficiency was more than minor because it is associated with the Procedure Quality attribute of the Barrier Integrity cornerstone; and if the condition was left uncorrected, the latent equipment issues in the system could have resulted in an undetected or uncorrectable loss of spent fuel pool (SFP) cooling. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 3 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, issued June 19, 2012, the inspectors determined that the finding was of very low safety significance (Green) because it did not cause the SFP temperature to exceed the maximum analyzed temperature limit specified in the licensing basis. This finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Evaluation, because when Entergy improved 3-SOP-SFP-003 in response to other identified procedural deficiencies, they did not capture the missing administrative controls in their extent of condition. (P.2) |
| 05000286/FIN-2017001-02 | 2017Q1 | Indian Point | Operation in Mode 1 with Pressurizer Code Safety Valves in an Inoperable Condition | Green. The inspectors identified an NCV of very low safety significance of Technical Specification (TS) 3.4.10, Pressurizer Safety Valves, when two of three pressurizer code safety valves, RC-PCV-464 and RC-PCV-468, were reported to have failed surveillance test 3.4.10.1 on July 1, 2015, at Wylie Laboratory. Entergy reported these failures under Unit 3 licensee event reports (LERs) 2015-006-00 and 2015-006-01, and concluded that Unit 3 had violated TS 3.4.10, Condition B. Entergy had failed to evaluate three prior test failures from RC-PCV-468 and recognized that RC-PCV-468 had degraded reliability. As a result, Entergy elected not to reinstall RC-PCV-468 at the end of the current outage (condition report (CR)-IP3-2017-0913). The inspectors determined that failing to correlate the symptoms and identify the cause for the repeated failure history of valve RC-PCV-468 over the last ten years resulted in a reported violation of TS 3.4.10 as reported in LERs 2015-006-00 and 2015-006-01. RC-PCV-468 was reinstalled in the system in 2012 and subsequently failed its lift setpoint test in 2015. The performance deficiency was determined to be more than minor because it is associated with the Equipment Performance attribute of the Mitigating Systems cornerstone and adversely impacts the objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). The finding was determined to be of very low safety significance (Green) because the small increase (5 percent) in the lift setpoint of the safety valves would not have prevented the valve from failing to relieve and, therefore, the failed surveillance test did not represent a loss of safety function. The inspectors concluded this finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Evaluation, because Entergy did not thoroughly evaluate the failure history to address causes and extent of conditions commensurate with their safety significance. (P.2) |
| 05000247/FIN-2017001-03 | 2017Q1 | Indian Point | Licensee-Identified Violation | 10 CFR 72.150 states, in part, that the licensee, applicant for a license, certificate holder, and applicant for a CoC shall prescribe activities affecting quality by documented instructions, procedures, or drawings of a type appropriate to the circumstance and shall require that these instructions, procedures, and drawings be followed. Entergy established requirements in 2-DCS-008-GEN, Unit 2 MPC Loading and Sealing Operations, to load pre-selected fuel assemblies per the approved loading pattern using 2-SOP-17.12, Spent Fuel Handling Machine and Spent Fuel Pit Operations, and Attachment 14, Fuel Movement Requirements. Attachments 4 (MPC Cross Section) and Attachment 12 (MPC Bridge/Trolley Coordinate) were provided in the procedure as references to orient the DCS crew as to the specific cell within the MPC where spent fuel bundles are to be placed. Contrary to the above, on January 24, 2017, IPEC DCS crew failed to follow 2-DCS-008-GEN. Specifically, instead of using the approved Attachment 4 from 2-DCS-008-GEN, the DCS crew used an MPC diagram provided by email from reactor engineering causing the initial bundle to be placed in cell F-5 rather than cell A-2. Traditional enforcement violations are not assessed for cross-cutting aspects Because the issue involved ISFSI operations, consistent with the guidance in Section 2.2 of the NRC Enforcement Policy, the inspectors evaluated this performance deficiency in accordance with the traditional enforcement process. Informed by the significance determination process, IMC 0609, Appendix A, Exhibit 3, Barrier Integrity Screening Questions, this violation was determined to be Severity Level IV. Because this violation was of very low safety significance and was entered into Entergys CAP as CR-IP2-2017-00356, this violation is being treated as an NCV, consistent with Section 2.3.2.a of the NRC Enforcement Policy. |
| 05000286/FIN-2016004-01 | 2016Q4 | Indian Point | Inadequate Preventive Maintenance Classification of Starting Air Relief Valve Led to Failure | Green. 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-2016004-02 | 2016Q4 | Indian Point | Inadequate Operability Evaluation of Leak in Service Water Pump Discharge Pipe | Green. 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-2016004-03 | 2016Q4 | Indian Point | Failure to Provide Indication of a Bypassed RPS Channel During Testing | Green. 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-2016004-04 | 2016Q4 | Indian Point | Failure to Follow RPS Logic Train B Actuation Logic Test | Green. 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) |
| 05000247/FIN-2016004-05 | 2016Q4 | Indian Point | Licensee-Identified Violation | 10 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. |
| 05000286/FIN-2016003-01 | 2016Q3 | Indian Point | Failure to Adequately Assess Fire Risk Associated with Maintenance on the Unit 3 Appendix R Diesel Generator | The inspectors identified a Green NCV of Title 10 of the Code of Federal Regulations (10 CFR) 50.65(a)(4) because between August 1, 2016, and August 17, 2016, Entergy did not perform an adequate risk assessment for the maintenance on the Unit 3 Appendix R diesel generator (ARDG). As a result, they did not take the required risk mitigating actions (RMAs). Entergy wrote Condition Report (CR)-IP3-2016-2538, changed fire risk status to Yellow, and began implementing RMAs on August 17, 2016. The inspectors determined that this performance deficiency was more than minor because it is associated with the Protection Against External Factors attribute of the Mitigating Systems cornerstone and adversely affected its objective to ensure the reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, due to the inadequate risk assessment, Entergy did not perform shiftly walkdowns for transient combustibles and related fire and ignition sources on the available safe shutdown train. Using IMC 0609.04, Initial Characterization of Findings, and IMC 0609, Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process, the inspectors determined that the failure to conduct RMAs for the unavailability of the ARDG required further assessment. A Region I senior reactor analyst (SRA) used SAPHIRE, Revision 8.1.14, and the Indian Point Unit 3 Standardized Plant Analysis Risk (SPAR) Model, Revision 8.20, to complete an evaluation this performance deficiency. The incremental conditional core damage probability (ICCDP) for this finding was calculated to be less than 1E-7 or very low safety significance (Green). This finding has a cross-cutting aspect in the area of Problem Identification and Resolution, Identification, because Entergy did not identify that an improperly racked-in breaker had a fire risk impact when combined with other plant conditions. |
| 05000247/FIN-2016003-07 | 2016Q3 | Indian Point | Inadequate Control of Floor Drains to Minimize Groundwater Contamination | The inspectors identified an NOV of 10 CFR 20.1406(c), Minimization of Contamination, for Entergys failure to conduct operations to minimize the introduction of residual radioactivity into the subsurface of the site (groundwater). Specifically, Entergy did not maintain the floor drain systems clear of obstructions and interferences and did not verify the ability of the floor drains to handle the volume and flowrates for draining activities being conducted. In January 2016, a spill caused by multiple floor drain obstructions resulted in the backup of contaminated water onto the floor of the 35-foot elevation of the primary auxiliary building (PAB) and the subfloor of the FSB and subsequent leakage to onsite groundwater. Entergy entered this issue into their CAP as CR-IP2-2016-00264, CRIP2- 2016-00266, and CR-IP2-2016-00564 with actions to characterize and evaluate the leak. Similarly, in June/July 2016, another event occurred due to an obstructed flow path through a floor drain in the FSB, which spilled to the subfloor and contaminated the onsite groundwater. This event was documented by Entergy in CR-IP2-2016-05060. The issue is more than minor because it is associated with the Program and Process attribute of the Public Radiation Safety cornerstone and adversely affected the cornerstone objective to ensure Entergys ability to prevent inadvertent release and/or loss of control of licensed material to an unrestricted area. In accordance with IMC 0609, Appendix D, "Public Radiation Safety Significance Determination Process," the finding was determined to be of very low safety significance (Green) because Entergy had an issue involving radioactive material control but did not involve transportation or public exposure in excess of 0.005 Rem. The finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Resolution, in that effective corrective actions to address issues identified in two prior groundwater contamination events since 2014 were not implemented in a timely or effective manner, which could have prevented two additional groundwater contamination events that occurred in 2016. |
| 05000247/FIN-2016003-02 | 2016Q3 | Indian Point | Missed Inspections on Automatic Voltage Regulator Cards Results in Emergency Diesel Generator Failure to Run | The inspectors identified a self-revealing Green NCV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Actions, because between 2012 and 2016, Entergy did not perform vendor specified inspections of the 23 emergency diesel generator (EDG) automatic voltage regulator (AVR) cards. As a result, on March 7, 2016, and March 10, 2016, the 23 EDG failed to run due to poor voltage regulation caused by degraded connections on the AVR card. Entergy replaced the AVR card in the 23 EDG, repaired similarly degraded solder joints on the AVR cards for the 21 and 22 EDGs, and wrote CR-IP2-2016-1260 and CR-IP3-2016-1370. The inspectors determined that this performance deficiency was more than minor because it is associated with the Equipment Performance attribute of the Mitigating Systems cornerstone and adversely affected its objective to ensure the reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the 23 EDG failed to run on March 7, 2016, and March 10, 2016. The inspectors evaluated the finding in accordance with IMC 0609, Appendix A and concluded it required a detailed risk evaluation (DRE). The DRE was performed by a Region I SRA and concluded the performance deficiency resulted in a change in core damage frequency of low E-8/year or very low safety significance (Green). The inspectors determined that this violation was not indicative of current performance because the last time Entergy would reasonably have been prompted to create corrective actions to perform periodic inspections was during the initial inspections in 2010. Therefore, no cross-cutting aspect was assigned. |
| 05000286/FIN-2016003-03 | 2016Q3 | Indian Point | Untimely Corrective Actions to Address Degraded Automatic Voltage Regulator Cards | The inspectors identified a Green NCV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Actions, because Entergy did not take timely corrective action to perform an inspection of the 33 EDG AVR card. As a result, the degraded solder connections on the card were not repaired for an excessive period of time. Entergy repaired the solder joints on the AVR card in the 33 EDG and wrote CR-IP3-2016-3018. This performance deficiency was more than minor because it is associated with the Equipment Performance attribute of the Mitigating Systems cornerstone and adversely affected its objective to ensure the reliability of systems that respond to initiating events to prevent undesirable consequences. The existence of degraded solder joints on the AVR card decreases the reliability of the EDG, and the untimely corrective action allowed the degradation to exist for longer than necessary without being corrected. In accordance with IMC 0609, Appendix A, The Significance Determination Process for Findings at Power, the inspectors determined that the finding was of very low safety significance (Green) because the 33 EDG maintained its operability or functionality, it did not represent a loss of system or function, and it did not involve external mitigation systems. The inspectors determined that this finding had a cross-cutting aspect in the area of Human Performance, Conservative Bias, because leaders did not take a conservative approach to decision making, particularly when information is incomplete or conditions are unusual. Specifically, Entergy did not inspect the 33 EDG AVR cards at the first available opportunity due to resource constraints. |
| 05000247/FIN-2016003-04 | 2016Q3 | Indian Point | Entry into a High Radiation Area without Radiological Briefing | The inspectors identified a self-revealing NCV of TS 5.7.1e when workers entered the Unit 2 Fuel Storage Building (FSB) truck bay that was posted and controlled as a high radiation area (HRA) without receiving a briefing on the dose rates prior to entering the HRA. Specifically, on June 6, 2016, two nuclear plant operators (NPOs) entered the Unit 2 FSB truck bay to hang tags on the backup spent fuel pool cooling filters. The NPOs signed in on a HRA radiation work permit (RWP) but did not receive a briefing on the radiological conditions in this work area. After entering the HRA, one worker received an electronic dosimeter dose rate alarm; and subsequently, both workers promptly exited the area. Immediate corrective actions included restricting the access of the two NPOs to the radiologically controlled area (RCA). The issue was entered into Entergys corrective action program (CAP) as CR-IP2-2016-03610. The failure to adhere to a radiological briefing prior to entry into a HRA is a performance deficiency that was reasonably within Entergys ability to foresee and correct. The performance deficiency was determined to be more than minor based on similar example 6.h in IMC 0612, Appendix E, Examples of Minor Issues, and because it adversely affected the Human Performance attribute of the Occupational Radiation Safety cornerstone objective. Specifically, Entergy violated the TS 5.7.1e HRA radiological briefing requirements designed to protect workers from unnecessary radiation exposure. Using IMC 0609, Appendix C, Occupational Radiation Safety Significance Determination Process, the finding was determined to be of very low safety significance (Green) because it did not involve: (1) ALARA occupational collective exposure planning and controls, (2) an overexposure, (3) a substantial potential for overexposure, or (4) an impaired ability to assess dose. The inspectors determined that the finding had a cross-cutting aspect of Human Performance, Procedure Adherence, in that the workers did not follow processes, procedures, and work instructions for entering a posted HRA. |
| 05000247/FIN-2016003-05 | 2016Q3 | Indian Point | Failure to Maintain Radiation Exposure ALARA During Unit 2 Reactor Cavity Liner Repairs | The inspectors identified a self-revealing finding (FIN) of very low safety significance due to Entergy having unintended occupational collective exposure resulting from performance deficiencies in work planning while preparing to perform reactor cavity liner repair activities during the spring 2016 Unit 2 refueling outage. Inadequate work planning that included an incomplete scope of work, welding method qualification, and inadequate timing of shield placement resulted in unplanned, unintended collective exposure due to conditions that were reasonably within Entergys ability to foresee. The work activity planning deficiencies resulted in the collective exposure for these activities increasing from the planned dose of 2.386 person-rem to an actual dose of 10.305 person-rem. This issue was entered into Entergys CAP as CR-IP2-2016-02528, CR-IP2-2016-02502, and CR-IP2- 2016-02548. The performance deficiency was more than minor because it was associated with the Program and Process attribute of the Occupational Radiation Safety cornerstone and adversely affected the cornerstone objective to ensure the adequate protection of the worker health and safety from exposure to radiation. Additionally, the performance deficiency was more than minor based on similar example 6.i in Appendix E of IMC 0612, Examples of Minor Issues, in that the actual collective dose exceeded 5 person-rem and exceeded the planned, intended dose by more than 50 percent. In accordance with IMC 0609, Appendix C, "Occupational Radiation Safety Significance Determination Process," the finding was determined to be of very low safety significance (Green) because Entergy had an issue involving ALARA Planning, and Unit 2's current three-year rolling average collective dose is less than the significance determination process criterion of 135 person-rem per pressurized water reactor unit. The finding had a cross-cutting aspect in the area of Human Performance, Work Management, in that the lack of accurate planning for work activities adversely impacted radiological safety. |
| 05000247/FIN-2016003-06 | 2016Q3 | Indian Point | Failure to Maintain Two Qualified AC Sources of Offsite Power | The inspectors identified a self-revealing Green NCV for failing to comply with Technical Specification (TS) Limiting Condition of Operation (LCO) 3.8.1, Electrical Power Systems, Alternating Current (AC) Sources Operating, from February 26, 2014, to March 29, 2016. Specifically, Entergy failed to maintain the auto transfer function for the 6.9 kilovolt (kV) offsite electrical buses in an operable condition because the safety injection (SI) anticipatory signal to the station auxiliary transformer (SAT) load tap changer (LTC) was disconnected. As a result, one of two qualified offsite AC circuits was not operable. Entergy initiated corrective actions and promptly restored the SAT LTC SI signal to operation prior to restarting the plant from the refueling outage. The failure to restore the LTC SAT SI signal following maintenance activities was a performance deficiency that was more than minor because it is associated with the Equipment Performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the failure to reinstate the SAT LTC SI anticipatory signal following maintenance resulted in the qualified offsite source of AC power becoming inoperable for a period of time in excess of the TS allowable outage time. In accordance with IMC 0609, Appendix A, The Significance Determination Process for Findings at Power, the inspectors determined that the finding was of very low safety significance (Green) because a detailed risk analysis determined the likelihood of core damage was less than E-8/year. The inspectors determined that the finding had a cross-cutting aspect of Human Performance, Work Management, because Entergy did not implement a process of controlling and executing work activities. The work process did not coordinate with different groups or job activities to ensure the state links were restored at the end of the work activities. |
| 05000247/FIN-2016002-01 | 2016Q2 | Indian Point | CVCS Goal Monitoring Under the Maintenance Rule | The maintenance rule requires that licensees shall monitor the performance or condition of structures, systems, or components, against licensee-established goals, in a manner sufficient to provide reasonable assurance that these structures, systems, and components are capable of fulfilling their intended functions. These goals shall be established commensurate with safety and, where practical, take into account industrywide operating experience. When the performance or condition of a structure, system, or component does not meet established goals, appropriate corrective action shall be taken. EN-DC-206, Maintenance Rule (a)(1) Process, provides the requirements and processes for managing SSCs for which (a)(2) monitoring has not demonstrated effective maintenance. EN-DC-206 specifies that (a)(1) action plans should not be closed until effectiveness of all corrective actions has been demonstrated by meeting performance goals through the monitoring period (or by other means specified in the action plan). Since 2013, there have been several repeat functional failures of equipment in the CVCS resulting in a failure to meet the performance criterion for reliability. These failures included: A failure of the 23 charging pump on August 6, 2013, after the internal oil pump discharge tubing broke causing the pump to trip on low oil pressure and a loss of charging. The 21 charging pump had tripped for the same reason in 2010. A failure of the 22 charging pump on January 14, 2014, due to cracked internal check valves caused by an inadequate fill-and-vent that left air in the pump following maintenance. The 21 charging pump had failed due to the same cause in 2013. A failure of the Unit 2 valve FCV-110A, boric acid flow control valve, to fully open on January 5, 2015. The valve had insufficient insulation; and as a result, boron crystalized above the valve plug and blocked its movement. The Unit 3 FCV-110A had failed in the same way in 2011, with earlier failures of other valves for the same cause going back to 1997. In each case, the CVCS for Unit 2 was already (a)(1), so Entergy either updated the existing (a)(1) action plan or created another one to operate in parallel with the existing one. Upon reviewing the associated (a)(1) action plans, the inspectors noted that in each example Entergys goals may not have been in accordance with EN-DC-206(a)(1) Process. It specifies that monitoring intervals should be at least six months for normally operating SSCs, at least three surveillances for SSCs monitored by surveillance and long enough to detect recurrence of the applicable failure mechanism. It also states that performance goals that provide reasonable assurance that the SSC is capable of performing its intended functions should be monitored throughout the time the SSC is classified (a)(1). EN-DC-206 defines an SSC as any discreet component grouping that has caused a monitoring failure, including any applicable extent of condition. In the examples provided, NRC inspectors challenged whether Entergy either chose a shorter monitoring interval or a goal that did not include the applicable extent of condition. Specifically: The (a)(1) action plan for the broken oil tubing had a goal of no noticeable decrease in 23 charging pumps running oil pressure for the next three quarterly surveillances. The chosen monitoring interval met the procedural expectation, but Entergy limited the monitoring to the 23 charging pump without written justification, when the 21 charging pump had failed previously for the same reason and the other pumps were susceptible to the same failure mechanism. During the monitoring interval, the 21 charging pump experienced low oil pressure. When Entergy performed repairs on the 21 charging pump for an unrelated issue, they discovered that the oil tubing had failed in the same way the 23 charging pump oil tubing had failed, although it had not yet caused a pump trip. The (a)(1) action plan for the cracked check valves had a goal of no check valve failure for six months for the next charging pump that underwent maintenance. This happened to be the 22 charging pump. Entergy chose a six-month monitoring interval, even though only one of the three charging pumps is in service at any given time, and the 22 charging pump only ran for four out of the six months it was monitored. Additionally, the action plan did not justify why a single successful filland-vent demonstrated adequate corrective actions. On November 19, 2014, during the six month monitoring interval, the 21 charging pump underwent maintenance requiring a fill-and-vent, and experienced check valve failure two weeks later on December 4. Entergy documented this as a maintenance rule functional failure, and discussed the possibility that it could be due to an inadequate fill-and-vent, but did not change the (a)(1) action plan. The (a)(1) action plan for FCV-110A specified a monitoring interval of six months to include the winter because the previous valve failures had all occurred during the winter months. However, the actual monitoring interval documented in the corrective action was from April to October 2015, and therefore did not cover the winter months as intended. In January 2016, Entergy performed maintenance on valve CH-297 on Unit 3, which is a heat-traced boric acid valve, and did not properly restore the insulation. The valve function was not impacted because it does not often contain high concentrations of boric acid. The (a)(1) action plans described above were all reviewed and approved by the maintenance rule expert panel. Further information regarding the performance of these SSCs is required to determine whether these issues of concern represent performance deficiencies and whether they are more than minor. (URI 05000247/2016002-01, CVCS Goal Monitoring Under the Maintenance Rule) |
| 05000286/FIN-2016002-02 | 2016Q2 | Indian Point | Withdrawn - Failure to Follow Operability Determination Procedure for Unit 3 Baffle-Former Bolts | The inspectors identified a Green NCV of 10 CFR 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," because Entergy did not adequately accomplish the actions prescribed by procedure EN-OP-104, Operability Determination Process, for a degraded condition associated with the Unit 3 baffle-former bolts. Specifically, Entergy incorrectly concluded that no degraded or non-conforming condition existed related to the Unit 3 baffle-former bolts and exited the operability determination procedure. Entergy subsequently performed the remaining steps in the procedure and provided appropriate justification for their plans to examine the baffle-former bolts at the next Unit 3 refueling outage (RFO). Entergys immediate corrective actions included entering the issue into its corrective action program (CAP) as CR-IP3-2016-01961 and documenting an operability evaluation to support the basis for operability of the baffle-former bolts and the emergency core cooling system (ECCS). This performance deficiency is more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 2 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, issued June 19, 2012, the inspectors screened the finding for safety significance and determined it to be of very low safety significance (Green), because the finding did not represent an actual loss of system or function. After inspector questioning, Entergy performed an operability evaluation, which provided sufficient bases to conclude the Unit 3 baffle assembly would support ECCS operability. This finding is related to the cross-cutting aspect of Problem Identification and Resolution, Operating Experience, because Entergy did not effectively evaluate relevant internal and external operating experience. Specifically, Entergy did not adequately evaluate the impact of degraded baffle bolts at Unit 3 when relevant operating experience was identified at Unit 2. (P.5 Operating Experience) |
| 05000247/FIN-2016002-03 | 2016Q2 | Indian Point | Failure to Maintain Flow Channeling Gates Closed in Accordance with the Containment Procedure | The inspectors identified a Green NCV of Technical Specification (TS) 5.4.1, Procedures, for Entergys failure to implement procedure OAP-007, Containment Entry and Egress. Specifically, workers transiting the inner and outer crane wall sections of containment failed to maintain at least one (of two) flow channeling gate closed to ensure availability of the containment sumps to provide suction for the ECCS. Entergy immediately coached the gate monitor and restored the gates to an acceptable position. Entergy generated CR-IP2-2016-04036 to address this issue. This performance deficiency is more than minor because it was associated with the configuration control (shutdown equipment lineup) attribute of the Mitigating Systems cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). A detailed risk assessment was conducted and determined that the change in core damage frequency was determined to be 7E-9, therefore, this issue represents a Green finding. This finding had a cross-cutting aspect in the area of Human Performance, Avoid Complacency, because Entergy did not consider potential undesired consequences of actions before performing work and implement appropriate error-reduction tools. Specifically, the work crew did not understand the requirements and potential consequences prior to commencing work and the gate monitor did not enforce these requirements to maintain at least one gate locked or pinned closed as required by OAP-007. (H.12 Avoid Complacency) |
| 05000247/FIN-2016002-04 | 2016Q2 | Indian Point | Failure to Scope Safety-Related Main Boiler Feedwater Pump Discharge Valves into the Maintenance Rule Program | The inspectors identified a Green NCV of 10 CFR 50.65(b)(1) for Entergys failure to include a function of a safety-related system within the scope of the maintenance rule program. Specifically, Entergy failed to include the feedwater isolation function performed by the main boiler feedwater pumps (MBFPs) discharge valves, MBFPs, and feedwater regulating valves, which are required to remain functional during and following a design basis event to mitigate the consequence of the accident within the scope of the maintenance rule monitoring program. Entergy initiated corrective actions to include the feedwater isolation function performed by the MBFP discharge valves, MBFPs, and feedwater regulating valves within the maintenance rule monitoring program. Entergy entered this issue into the CAP as CR-IP2-2016-03963. This performance deficiency is more than minor because it was associated with barrier performance attribute of the Barrier Integrity cornerstone and adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, the failure to properly scope the feedwater isolation function prevented Entergy from identifying that equipment reliability was no longer effectively controlled through preventive maintenance. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 2 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, issued June 19, 2012, the inspectors determined that the finding was of very low safety significance (Green) because the finding did not represent an actual open pathway in the physical integrity of reactor containment, containment isolation system, and heat removal components. This finding does not have a cross-cutting aspect since the failure to scope this equipment into the maintenance rule program was not recognized when Entergy combined the maintenance rule basis documents for Units 2 and 3 in 2012 and, as a result, is not indicative of current licensee performance. |
| 05000286/FIN-2016001-03 | 2016Q1 | Indian Point | Inadequate Screening of Reactor Protection System Test Method Change | The 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. |
| 05000247/FIN-2016001-02 | 2016Q1 | Indian Point | Failure to Adequately Implement Risk Management Actions for the Containment Key Safety Function | The inspectors identified an NCV of Title 10 of the Code of Federal Regulations (10 CFR) 50.65(a)(4) because Entergy did not effectively manage the risk associated with refueling maintenance activities. Specifically, Entergy did not demonstrate they could implement their planned risk management action to restore the containment key safety function within the time-to-boil using the equipment hatch closure plug. Entergy wrote CRIP2- 2016-01503 and CR-IP2-2016-01883 to address this issue. This performance deficiency is more than minor because it impacted the barrier performance attribute of the Barrier Integrity cornerstone and affected the objective to provide reasonable assurance that containment protects the public from radionuclide releases caused by accidents or events. Specifically, Entergy did not demonstrate that they could install the hatch plug within the time-to-boil and that the plug would seal the equipment hatch opening, which affected the reliability of containment isolation in response to a loss of shutdown cooling or other event inside containment. The inspectors determined the finding could be evaluated using Attachment 0609.04, Initial Characterization of Findings. Because the finding degraded the ability to close or isolate the containment, it required review using IMC 0609, Appendix H, Containment Integrity Significance Determination Process. Since containment status was not intact and the finding occurred when decay heat was relatively high, it required a phase two analysis. Since the leakage from containment to the environment was less than 100 percent containment volume per day, the finding screens as very low safety significance (Green). A subsequent demonstration showed that the hatch plug provided an adequate seal with the containment hatch opening. The inspectors concluded this finding had a cross-cutting aspect in the area of Human Performance, Documentation, because Entergy did not maintain complete, accurate, and up-to-date documentation related to the use of the hatch plug. Specifically, they tested the seal integrity without using a work order (WO), and made pen-and-ink changes to the procedure without processing a procedure change form. |
| 05000247/FIN-2016001-04 | 2016Q1 | Indian Point | Failure to Implement Surveillance Requirement for Main Boiler Feed Pump Trip Function | The inspectors identified an NCV of TS 3.7.3, Main Feedwater Isolation, Surveillance Requirement (SR) 3.7.3.3 on March 26, 2016, when the inspectors determined that Entergy had not conducted surveillance testing on the main boiler feed pump (MBFP) trip function as required. Specifically, the MBFP trip function had never been tested. The MBFP trip is designed to ensure isolation of feedwater flow into containment during a feedline break accident to prevent exceeding pressure and temperature limits inside containment. Entergy wrote CR-IP2-2016-02247 and assigned a mode 3 hold to evaluate the testing to comply with the TS. This finding is more than minor because it is associated with the procedural quality attribute of the Mitigating Systems cornerstone because Entergy had not prepared a testing procedure to verify that the surveillance requirements were met. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 3 of IMC 0609, Appendix A, The Significance Determination Process for Findings at Power, the inspectors determined that a detailed risk evaluation was required because the finding represented a loss of function of a single train for greater than its TS allowable outage time (AOT). The detailed risk evaluation concluded that the finding was of very low safety significance (Green) because of the very low probability of a feedwater line break inside containment when combined with the high probability that the feedwater regulating valve (FRV) and feedwater isolation valve (FWIV) would successfully close from a safety injection signal to isolate feedwater flow into containment. The total core damage contribution of this event is approximately 1E-7 and based on the above considerations, the core damage risk was assessed to be very low or Green. This finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Evaluation, because Entergy failed to thoroughly evaluate the MBFP failure to trip during a reactor trip to ensure that corrective actions address causes and extent of conditions commensurate with their safety significance (P.2 Evaluation). |
| 05000247/FIN-2016001-05 | 2016Q1 | Indian Point | Failure to Provide Adequate Procedural Guidance in Order to Prevent an Overcurrent Condition | A self-revealing NCV of Technical Specification (TS) 5.4.1, Procedures, was identified for Entergys failure to provide adequate guidance in procedure 2-PT-R084C, 23 Emergency Diesel Generator (EDG) Eight-Hour Load Test. Specifically, Entergy failed to provide adequate procedural guidance in order to prevent an overcurrent condition on the 52/3A 480 volt (V) bus normal feeder breaker. As a result, the plant experienced a loss of normal power to their four 480V vital buses and a momentary loss of residual heat removal (RHR) cooling. Entergy wrote condition report (CR)-IP2-2016-01256 and revised the test procedure to add a specific amperage restriction on the vital buses and designate the control indication to be used. The finding was more than minor because it is associated with the procedure quality 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. The performance deficiency caused a loss of normal power to the vital 480V buses, which also resulted in a loss of RHR event. The Region I Senior Risk Analyst (SRA) used IMC 0609, Appendix G, Shutdown Operations Significance Determination Process, to assess the safety significance of this event. The SRA determined that Worksheet 3 in Plant Operating State 1 (reactor coolant system (RCS) closed with steam generators available for decay heat removal), best represents the actual event and associated mitigation system available. Throughout the event, the RCS was intact with steam generators available and 24 reactor coolant pump (RCP) running; therefore, it was determined that this finding was of very low safety significance (Green). This finding had a cross-cutting aspect in the area of Human Performance, Challenge the Unknown, because personnel did not stop when faced with uncertain conditions. Risks were not adequately evaluated and managed before proceeding. |
| 05000247/FIN-2016001-06 | 2016Q1 | Indian Point | 23 Emergency Diesel Generator Automatic Voltage Regulator Failure | Following the initial loss of 480V vital buses and loss of RHR cooling, the operating crew was taking actions to restore normal power to all 480V buses. Before the crew was able to restore off-site power to the 6A bus, the 23 EDG tripped on overcurrent resulting in a loss of bus 6A and the subsequent blackout/unit trip signal that stripped all loads from the remaining 480V buses. The cause of this second trip is still under review by Entergy, and the NRC opened an URI related to this concern to assess whether a performance deficiency exists. On March 7, 2016, approximately one hour after the trip of the 3A normal feed breaker, the 23 EDG tripped on overcurrent while powering the 6A bus. The operators responded by re-entering 2-AOP-480V-1, Loss of Normal Power to Any 480V Bus, and 2-AOP-RHR-1, Loss of RHR. The RHR cooling was restored within five minutes. Throughout the transient, 24 RCP remained in service and available for RCS heat removal as it is powered from 6.9 kV which remained energized from offsite power. Due to ongoing performance of restoration actions from the previous trip, the 21 EDG was not ready to automatically start, so initially only the 2A bus loaded on the 22 EDG. The delay in the starting of 21 EDG combined with the associated loss of 23 vital instrument bus resulted in loss of power to the C pressurizer level channel which then caused both a loss of letdown and loss of pressurizer heaters. These conditions along with the malfunctioning of the 24 loop pressurizer spray valve controller created additional challenges to the operator tasked with controlling pressurizer pressure and level. The delay in the start of the 21 EDG also affected the operator tasked with restoring RHR as the RHR heat exchanger outlet motor operated valves associated with 21 RHR pump were powered from the 5A bus. The crew was able to restore the 3A bus with the 22 EDG, and then start the 21 RHR pump. The 6A bus remained de-energized until the crew restored 6A via off-site power. The 23 EDG was declared inoperable. By 1:49 p.m., all four 480V buses were restored to off-site power; and by 2:07 p.m., 21 and 22 EDGs had been shut down and returned to standby (auto start) condition. Entergys initial review of the second electrical transient determined the most probable cause was a spurious actuation of the A, B, or C phase voltage controlled overcurrent relays. These relays were replaced under WO 00440073 with spare, calibrated relays. Operator observations during the event indicated that the 23 EDG breaker tripped while loads were still being added, including the start of the turbine auxiliary bearing oil pump and various motor control centers, but the 23 EDG load never exceeded the continuous load rating of 1750 kilowatt (kW). Local diesel observations indicated approximately 1650 kW load on the 23 EDG just prior to the trip. Entergy then concluded that all other equipment functioned as per design and that a monthly load test surveillance would be utilized to determine operability after replacing the overcurrent relays. On March 8, 2016, 23 EDG was declared operable following successful completion of the monthly diesel surveillance procedure. The 23 EDG was run, closed onto Bus 6A, and loaded to 2275 kW. Later, as-found bench testing of the overcurrent relays indicated that the relay trip settings were within calibration and should have functioned as designed. Subsequently, on March 10, 2016, during performance of PT-R14, Automatic Safety Injection System Electrical Load and Blackout Test, 23 EDG exhibited anomalous behavior during the train B load sequencing. During the test, the voltage on bus 6A dropped to approximately 200V when the 23 AFW pump was sequenced onto the bus (CR-IP2-2016-01430). 23 EDG was again declared inoperable and the period of inoperability was backdated to March 7, 2016, when it originally tripped. Further troubleshooting and additional failure modes analysis found a degraded resistor associated with the 23 EDG automatic voltage regulator. The 23 EDG voltage regulator was replaced, and the 23 EDG was again tested satisfactorily. The low voltage issue exhibited during PT-R14, Automatic Safety Injection System Electrical Load and Blackout Test, was documented in CR-IP2-2016-01430 and has been closed in CR-IP2-2016-01260 to be included in the ACE associated with the tripping of 23 EDG breaker on March 7, 2016. Entergy was in the process of performing a failure analysis and an ACE at the end of the inspection period. NRC review of Entergys failure analysis and causal evaluation will be performed to evaluate if a performance deficiency exists. The inspectors determined that the issue is an URI. |
| 05000247/FIN-2016001-07 | 2016Q1 | Indian Point | January 2016 Groundwater Contamination | The inspectors identified an URI related to whether a performance deficiency exists associated with Entergys controls to prevent the introduction of radioactivity into the site groundwater were adequate. Specifically, Entergy obtained increased tritium concentrations from groundwater MW samples in January 2016 indicating that a leak or spill had occurred allowing the introduction of radioactivity into the subsurface of the site. Entergy entered this issue into their CAP as CR-IP2-2016- 00264, CR-IP2-2016-00266, and CR-IP2-2016-00564 with actions to characterize and evaluate this new leak. The initial Entergy investigation focused on identifying the source of the contamination which was preliminarily determined to originate from the reject water of the RO skid that was in service from January 1631, 2016. This cause determination was based on the timing of the groundwater contamination event and based on the unique matching of the radionuclide signature from the groundwater samples and the RO skid reject water. Entergy has yet to identify the specific leakage pathway or the root cause for this event. An URI is initiated for further determination of whether a performance deficiency exists following Entergys finalization of their root cause analysis. |
| 05000247/FIN-2016001-01 | 2016Q1 | Indian Point | Baffle-Former Bolts with Identified Anomalies | The inspectors determined the level of degradation of baffle-former bolts reported to the NRC as a condition not previously analyzed was an issue of concern that warrants additional inspection to determine whether there is a performance deficiency. As a result, the NRC opened a URI. Additional inspection is warranted to determine whether a performance deficiency exists related to event number 51829 dated March 29, 2016, in which Entergy reported to the NRC that the level of degradation of baffle-former bolts was a condition not previously analyzed. The baffle-former bolts secure plates in the reactor core barrel to form a shroud around the fuel core. The inspectors planned to review the results of Entergys cause evaluation of this issue. |
| 05000336/FIN-2015004-02 | 2015Q4 | Millstone | Turbine Driven Auxiliary Feedwater Pump Corrective Actions to Prevent Recurrence | The 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. |
| 05000336/FIN-2015012-03 | 2015Q4 | Millstone | Procedure Failed to Direct Adequate Venting of SDC System | A self-revealing Green NCV of Millstone Power Station Unit No. 2 TS 6.8.1, Procedures, was identified because the procedure used by Dominion to place the SDC system in service did not verify that the SDC suction line to the LPSI pumps was filled and vented prior to placing the system in service which appears to be the likely cause for opening SDC suction Relief Valve (RV) 2-SI-468. To address this issue, Dominion revised the procedure to include venting at SI-075 as part of step 4.12.2 of OP 2207. Dominion entered this issue into their corrective action program as CR1011898. The finding was more than minor because it was associated with procedure quality attribute of the Initiating Events cornerstone and affected the cornerstone objective of limiting the likelihood of events that upset plant stability and challenge critical safety functions during shutdown operations. Specifically, the finding identifies an increase in the likelihood of a loss of SDC resulting from the unexpected opening of RV 2-SI-468. Using a bounding and conservative quantitative detailed risk analysis, coupled with deterministic risk-informed defense-in-depth considerations, the finding was determined to be of very low risk significance (Green). This finding had a cross-cutting aspect in the area of Human Performance, Resources, because Dominion did not ensure procedures were adequate to support nuclear safety. Specifically, the plant cooldown procedure did not ensure that the SDC suction line to the LPSI pumps was full of water prior to placing the system in service (H.1). |
| 05000336/FIN-2015012-04 | 2015Q4 | Millstone | Licensee-Identified Violation | 10 CFR Part 50.54(q), states that power reactor licensees shall follow and maintain in effect emergency plans which meet the standards in 10 CFR Part 50.47(b) and Appendix E to Part 50. 10 CFR Part 50.47(b)(4) requires, in part, that the nuclear facility licensee have a standard emergency classification and action level scheme in use, and state and local response plans call for reliance on information provided by facility licensees for determinations of minimum initial off-site response measures. Appendix E, Section IV.C.2 states in part that, nuclear power reactor licensees shall establish and maintain the capability to assess, classify, and declare an emergency condition within 15 minutes after the availability of indications to plant operators that an emergency action level has been exceeded and shall promptly declare the emergency condition as soon as possible following identification of the appropriate emergency classification level. Contrary to the above, when the crew entered AOP-2568A at 8:53 a.m., charging flow was about 80 gpm greater than letdown flow with PZR level lowering and the RCS cooldown was secured. The SM did not declare a UE (Identified Leakage greater than 25 gpm) until 9:32 a.m. Dominion determined that the event declaration was accurate because the SM ultimately determined that the leakage was Identified Leakage but untimely and entered the issue into the CAP (CR1011949). Because of the UE condition, the inspectors determined that the finding is of very low safety Significance (Green) using IMC 0609, Appendix B, "Emergency Preparedness Significance Determination Process, Attachment 1, "Failure to Implement (Actual Event) Significance Logic." |
| 05000247/FIN-2015004-01 | 2015Q4 | Indian Point | Licensee-Identified Violation | From 2010 to 2014, Indian Point made four shipments of radioactive material that contained category two levels of radioactive material quantity of concern but did not implement a transportation security plan for these shipments, which is contrary to the requirements of 49 CFR 172, Subpart I, Safety and Security Plans. This performance deficiency adversely affected the Public Radiation Safety cornerstone attribute of Program and Process based on inadequate procedures associated with the transportation of radioactive materials. This issue was documented in Entergys CAP as CR-IP2-2015-01985 and HQ-2015-00526. Corrective actions included revision of procedure EN-RW-106 and selection of a vendor to regularly review the federal register for regulatory changes that can impact plant operations. |
| 05000336/FIN-2015012-02 | 2015Q4 | Millstone | Failure of the STA to Support the Crew During a Plant Cooldown | The NRC identified a Green NCV of Millstone Power Station Unit No. 2 TS 6.8.1, Procedures involving the shift technical advisors (STAs) failure to follow position-specific procedural guidance, to support all phases of plant operation. Specifically, the STA was not involved in providing independent, objective, and technical assessment of plant conditions when PZR level began to decrease when SDC was being place in service and during the subsequent cooldown. Later in the event, the STA did provide support to the crew to confirm the existence of a leak. After the event, the STA was removed from watch standing duties pending remediation. Dominion entered this issue into their corrective action program as CR1012358. The finding was more than minor because it is associated with the human 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 (i.e., core damage). Specifically, during the initiation and operation of the SDC system, the STA did not provide sufficient technical input to aid the crew in the determination of the existence of a reactor coolant system leak. The finding screened to very low safety significance (Green) using Manual Chapter 0609, Appendix G, Attachment 1, Shutdown Operations Significance Determination Process Phase 1 Screening and Characterization of Findings, Exhibit 3 - Mitigating Systems Screening Questions. Specifically, the finding did not represent a loss of system safety function. This finding had a cross-cutting aspect in the area of Human Performance, Teamwork, in that individuals and work groups communicate and coordinate their activities within and across organizational boundaries to ensure nuclear safety is maintained. Specifically, the STA did not fulfill his responsibilities to support the crew by assessing plant conditions during the initiation and operation of the SDC system during the plant cooldown. |
| 05000336/FIN-2015004-01 | 2015Q4 | Millstone | Charging Packing Lubrication Pump Inadequate Operating Procedure Acceptance Criteria | The 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-2015012-01 | 2015Q4 | Millstone | Failure to Implement Procedural Guidance During a Loss of RCS Inventory | The NRC identified a Green NCV of Millstone Power Station Unit No. 2 Technical Specifications (TS) 6.8.1, Procedures involving Dominions failure to implement procedural steps when prompted by plant conditions to mitigate the event. Specifically, when pressurizer (PZR) level began to decrease while placing the shutdown cooling (SDC) system in service, the crew did not implement procedural guidance in OP-2207, Plant Cooldown, nor enter AOP 2568A, RCS Leak, Mode 4, 5, 6, and Defueled, as these procedures would have directed operators to locate the source of the leak. Later in the event, once the procedural guidance was implemented, action was taken to identify the location of the leak and it was isolated. After the event, selected crew members were removed from watch standing duties pending remediation. Dominion entered this issue into their corrective action program as CR1012358. The finding was more than minor because it is associated with the human 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 (i.e., core damage). Specifically, when entry conditions were met, operators did not implement procedural guidance that would have directed them to locate the source of the leak. The finding screened to very low safety significance (Green) using Manual Chapter 0609, Appendix G, Attachment 1, Shutdown Operations Significance Determination Process Phase 1 Screening and Characterization of Findings, Exhibit 3 - Mitigating Systems Screening Questions. Specifically, the finding did not represent a loss of system safety function. This finding had a cross-cutting aspect in the area of Human Performance, Procedure Adherence, in that licensed operators are expected to implement processes, procedures, and work instructions. Specifically, Dominion operators did not implement procedural guidance when prompted by plant conditions immediately after starting the A Low Pressure Safety Injection Pump (LPSI). |
| 05000336/FIN-2015004-03 | 2015Q4 | Millstone | Licensee-Identified Violation | 10 CFR Part 50.54(q), states that power reactor licensees shall follow and maintain in effect emergency plans which meet the standards in 10 CFR Part 50.47(b) and Appendix E to Part 50. 10 CFR Part 50.47(b)(4) requires, in part, that the nuclear facility licensee have a standard emergency classification and action level scheme in use, and state and local response plans call for reliance on information provided by facility licensees for determinations of minimum initial off-site response measures. Appendix E, Section IV.C.2 states in part that, nuclear power reactor licensees shall establish and maintain the capability to assess, classify, and declare an emergency condition within 15 minutes after the availability of indications to plant operators that an emergency action level has been exceeded and shall promptly declare the emergency condition as soon as possible following identification of the appropriate emergency classification level. Contrary to the above, on November 4, Unit 3 control room operators received a fire alarm in the A EDG enclosure at 10:56 AM, but did not declare an Unusual Event for a fire in a safe shutdown area until 11:25 AM. The control room received a report from the EDG enclosure at approximately 10:55 AM that there were visible flames on the exhaust line of the A EDG and they entered Emergency Operating Procedure 3509, Fire Emergency, but the declaration was not made within the required 15 minutes. The control room operators received additional information that there was charring and scorching on the A EDG at 11:33 AM and appropriately upgraded the emergency declaration to an Alert (fire affecting a safe shutdown area and damage to the equipment indicated). The upgraded Alert declaration was made at 11:35 AM, within the required 15 minutes. The inspectors determined that the finding is of very low safety significance (Green) because it was related to the timeliness of an NOUE, in accordance with IMC 0609, Appendix B, "Emergency Preparedness Significance Determination Process, Attachment 1, "Failure to Implement (Actual Event) Significance Logic." Dominion entered the issue into the CAP as CR 1017078. |
| 05000336/FIN-2015003-03 | 2015Q3 | Millstone | Licensee-Identified Violation | 10 CFR 50, Appendix B, Criterion VII, Control of Purchased Material, Equipment, and Services, requires, in part, that measures shall be established to assure that purchased services conform to the procurement documents. Contrary to Criterion VII, Design Change MP3-09-01030, Replacement of Actuators on 3FWS*CTV41 A/D (FWIVs), was supplied by Dominions vendor (Flowserve) and accepted by Dominion with an inadequate valve weak link analysis (valve backseat determined to be the weak link versus the steam coupling bolts). This was identified by Dominion during installation of MP3-09-01030 which required significant changes to the modification design prior to returning the FWIVs to service. This issue is more than minor because, if left uncorrected, the issue would have the potential to lead to a more significant safety concern. Specifically, not correcting the valve weak link analysis had the potential to lead to damage and/or failure of the FWIV stem coupling bolts rendering the valve inoperable. The inspectors evaluated this finding using IMC 0609.04, Initial Characterization of Findings, and IMC 0609, Appendix A, Exhibit 3, Barrier Integrity Screening Questions. The inspectors determined that the finding was of very low safety significance (Green) because the finding did not represent an actual open pathway in the physical integrity of reactor containment. Dominion documented the issue in CRs 564977 and 564801. |
| 05000423/FIN-2015003-02 | 2015Q3 | Millstone | Inadequate Procedural Direction to Mitigate a LOCA and Failure of an RSS Heat Exchanger Tube | The inspectors identified a Green NCV of Millstone Unit 3 TS 6.8.1, as specified by Regulatory Guide (RG) 1.33, associated with Dominions failure to implement adequate procedures to address a hypothetical large break loss of coolant accident (LBLOCA) inside containment with a failure of a recirculation spray system (RSS) heat exchanger tube resulting in a loss of coolant accident (LOCA) that bypasses the containment barrier. 4 Dominion did not provide adequate procedural direction or training to the operators for the control of the emergency core cooling systems (ECCS) during this hypothetical event in June of 2015. Dominion entered the issue into their corrective action program as condition report (CR) 1008205. The finding was more than minor in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, dated September 7, 2012, as it represented a challenge to the procedure quality attribute of the Barrier Integrity cornerstone to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. The finding was screened to be of very low safety significance (Green) as the deficiency did not represent an actual open pathway in the physical integrity of reactor containment in accordance with IMC 0609, Significance Determination Process, Attachment 4, Initial Characterization of Findings, and IMC 0609, Appendix A, Exhibit 3, Barrier integrity Screening Questions, Section B, Reactor Containment. The inspectors identified a cross-cutting aspect in Problem Identification and Resolution, Evaluation, because the organization failed to evaluate the issue to ensure that resolution addressed causes and extent of conditions commensurate with their safety significance. |
| 05000423/FIN-2015003-01 | 2015Q3 | Millstone | Change of Pump Reference Values Contrary to ASME OM | The inspectors identified a Green NCV of Millstone Unit 3 Technical Specification (TS) Surveillance Requirement 4.0.5 because Dominion did not implement the Inservice Testing (IST) Program in accordance with the American Society of Mechanical Engineers (ASME) Operation and Maintenance (OM) Code of Record, 2001 through 2003 incorporated addenda. On July 18, 2015, Dominion changed the reference values of the B control building air conditioning booster pump, 3SWP*P2B, prior to determining the cause of the condition which resulted in the pump performing in the Action Range (ISTB-6200(b)) in April 2015. 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 represented a challenge to 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. The reliability of 3SWP*P2B was challenged based upon Dominions change in the pumps reference values contrary to the ASME OM code of record for Millstone Unit 3 which could result in the degradation of the equipment remaining undetected. The finding screened to be of very low safety significance (Green) because the safety function of 3SWP*P2B was not lost based on analysis of design basis flow requirements. The inspectors determined the finding has a cross-cutting aspect in Problem Identification and Resolution, Evaluation, in that the organization failed to evaluate the issue to ensure that resolution addressed causes and extent of conditions commensurate with their safety significance. Specifically, Dominions analysis of the April 2015 pump failures was not thorough enough to understand a new potential failure mode (impeller movement) and how it may impact system performance. |
| 05000333/FIN-2015007-01 | 2015Q2 | FitzPatrick | Failure to Adequately Assess the Impact of SRV Leakage on Operability | The inspectors identified a Green, non-cited violation (NCV) of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion III, Design Control, associated with FitzPatricks failure to adequately assess and control the acceptance criteria specified in engineering analysis in EC-JAF-56258, Operability Input for CR-JAF-2015-01271 SRV G Tailpipe Temperature Increase, which referenced JAF-RPT-03-0056 Operational Leakage Action Levels for Target Rock Two-Stage Safety/Relief Valves. Specifically, FitzPatrick concluded that a 2-stage Target Rock Safety Relief Valve (SRV) was operable with pilot valve leakage provided the leak rate was less than 1000 lbm/hr. This conclusion was not adequately supported by the available industry and plant data on setpoint drift and the references provided. As a result, FitzPatrick did not declare 2-stage Target Rock Pilot valves inoperable when the leak rate exceeded 600 lbm/hr in 2007 and 2009. FitzPatrick entered this issue into the corrective action system (CR-JAF-2015-02850) and is reassessing the appropriate operability criteria. This performance deficiency is more than minor because it adversely affects the equipment performance attribute of the initiating events cornerstone in IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, to limit the likelihood of events that upset plant stability and challenge critical safety functions during power operations by ensuring reactor coolant system (RCS) barrier integrity. This finding screens to Green using IMC 0609, Significance Determination Process, Attachment 4, Initial Characterization of Findings, and IMC 0609, Appendix A, Exhibit 1, Initiating Events Screening Questions, Section A, LOCA Initiators, as the finding could not result in leakage exceeding that of a small break loss-of-coolant accident (LOCA) nor could it have resulted in an interfacing system LOCA. The inspectors determined that this performance deficiency had a crosscutting aspect in human performance, conservative bias, where individuals use decision making-practices that emphasize prudent choices over those that are simply allowable. (H.14) Section 1R17 |
| 05000336/FIN-2015001-02 | 2015Q1 | Millstone | Failure to Replace Defective Fuses in the A EDG Resulting in Generator Failure | The inspectors identified a Green NCV of 10 CFR 50, Appendix B, Criterion XVI, associated with Dominions failure to prevent recurrence of a significant condition adverse to quality, installation of defective fuses in the Unit 2 emergency diesel generators (EDGs) from September 26, 2015, until October 23, 2015. Dominions immediate corrective actions included replacing the defective fuses in both EDGs and assessing the extent of condition in other safety systems. This finding was determined to be more than minor in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, as it represented a challenge to the equipment performance attribute of the Mitigating Systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. This finding screened to be of very low safety significance (Green) because the finding did not represent an actual loss of function of a single train for greater than its allowable outage time. The inspectors assigned a cross-cutting aspect in the Problem Identification and Resolution, Operating Experience, in that Dominion failed to effectively implement relevant internal and external operating experience. |
| 05000423/FIN-2015001-01 | 2015Q1 | Millstone | Failure to Identify Charging and Primary Closed Cooling Water Area Heater Transformers Equipment Environmental Qualification Non-Conformance | The inspectors identified a Green NCV of Title 10 of the Code of Federal Regulations (10 CFR) 50, Appendix B, Criterion XVI, associated with Dominions failure to promptly identify conditions adverse to quality associated with the Millstone Unit 3 Charging System (CHS) and Component Cooling Primary (CCP) area heaters which are required to support operability of the charging system when outside temperature is less than 17F, from September 17, 2014, to February 11, 2015. Dominion completed restoration of the B train CHS and CCP area heaters on February 14, 2015, and has scheduled completion of the A train heater restoration for April 16, 2015. This finding was determined to be more than minor in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, as it represented a challenge to the equipment performance attribute of the Mitigating Systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. This finding screened to be of very low safety significance (Green) as safety function of the charging system was not lost based upon the capability of the nonconforming heaters to maintain charging area temperatures greater than 65F. Inspectors identified a cross-cutting aspect in Human Performance, Procedure Adherence, for Dominions failure to adequately screen the condition adverse to quality upon discovery of heater failure and failure to evaluate heater maintenance history when making changes to heater preventive maintenance frequency. |