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| Quarter | Site | Title | Description | |
|---|---|---|---|---|
| 05000395/FIN-2008004-03 | 2008Q3 | Summer | Licensee-Identified Violation | 10 CFR 55.25 states If, during the term of the license, the licensee develops a permanent physical or mental condition that causes the licensee to fail to meet the requirements of 10CFR 55.21 of this part, the facility licensee shall notify the Commission, within 30 days of learning of the diagnosis, in accordance with 10 CFR 50.74(c). For conditions in which a conditional license (as described in 10 CFR 55.33(b) of this part) is requested, the facility licensee shall provide medical certification on Form NRC 396 to the Commission (as described in 10 CFR 55.23 of this part). Contrary to this, the licensee did not notify the Commission when eleven licensed operators were diagnosed with a permanent physical medical condition within 30 days as required by 10 CFR 55.25. This finding was identified by the licensee in CR-08-00080 and CR-05-03172. This finding was of very low safety significance because, in all cases, the conditions were under control with no impact on the individuals abilities to perform licensed duties |
| 05000395/FIN-2009002-01 | 2009Q1 | Summer | Failure to Effectively Monitor the Performance of the Control Room Normal and Emergency Air Handling System Per the Maintenance Rule | The inspectors identified an NCV of 10 CFR 50.65 (Maintenance Rule) with two examples for failing to demonstrate that the performance of the control room normal and emergency air handling (control room ventilation) system was being effectively controlled through the performance of appropriate preventive maintenance. Specifically, the licensee failed to: 1) properly categorize a control room ventilation system pressure boundary breach due to maintenance activities as a maintenance preventable function failure (MPFF) against the B train, and 2) properly consider the unavailability time incurred by the functional failure against the A train. These failures to adequately assess the Maintenance Rule (MR) implications of a control room ventilation system functional failure resulted in the system not being placed under the goal setting monitoring requirements of 10 CFR 50.65(a)(1). The licensee entered these issues into their corrective action program as CR-08-00944, CR-09- 00107, and CR-09-01056, and placed the control room ventilation system in MR (a)(1) goal setting status. This finding is more than minor because it is similar to the non-minor maintenance rule example 7.b. provided in Manual Chapter 0612, Appendix E, Examples of Minor Issues, which states that violations of Paragraph 10 CFR 50.65(a)(2), failure to demonstrate effective control of performance or condition and not putting the affected structures, systems, and components (SSCs) in (a)(1), are not minor because they necessarily involve degraded SSC performance or condition. This finding was determined to be of very low safety significance (Green) because the incorrect functional failure and unavailability hour assessments did not, by themselves, result in an actual degradation of the barrier function provided for the control room or additional operability or functionality concerns. The finding directly involved the crosscutting area of Human Performance, component of Resources, and aspect of Personnel Training and Qualifications, in that, the licensee engineering staff did not fully understand MR evaluation requirements for systems with common components or the counting of unavailability hours for systems that are out of service for reasons other than a formal tag-out program (H.2.b). (Section 4OA5.2 |
| 05000395/FIN-2009005-01 | 2009Q4 | Summer | Failure to Follow Procedure Results in Inadvertent Loss of Spent Fuel Pool Inventory | A Green self-revealing non-cited violation (NCV) was identified for the failure to comply with TS 6.8.1. As a result of the failure to follow a procedure, approximately 8000 gallons of water was inadvertently transferred from the SFP to the refueling cavity. This issue was entered in the licensees CAP as CR-09-04237.This finding is more than minor because it is associated with the human performance and configuration control attributes of the Barrier Integrity cornerstone and affects the cornerstone objective to provide reasonable assurance that physical design barriers, such as maintaining functionality of the spent fuel pool system, protect the public from radionuclide releases caused by accidents or events. Using NRC Inspection Manual Chapter 0609, Attachment 4, Phase 1 Initial Screening and Characterization of Findings, this finding was determined to be of very low safety significance (Green) because it only represents a degradation of the radiological barrier function provided by the spent fuel pool, in that, since water level did not decrease less than 23 feet above the top of the irradiated fuel and pool temperature only increased by two degrees Fahrenheit, adequate radiological shielding and spent fuel pool cooling margins were maintained. This finding has a cross-cutting aspect in the area of human performance associated with the work practices component because operators failed to focus adequate attention to detail on following procedure steps in the proper sequence (H.4.b). |
| 05000395/FIN-2009005-02 | 2009Q4 | Summer | Failure to Follow a Procedure and Correct Previously Identified Deficiencies with the Operator Workaround Program | A Green NRC-identified finding was identified for the failure to adequately implement a procedure and correct previously identified deficiencies with the licensees operator workaround program. This resulted in operator workarounds and challenges not fully or adequately being assessed, untimely resolution and status reporting of operator workarounds. The licensee initiated Condition Report (CR)-1000079 to address this issue. This finding is more than minor because it was similar to examples 3.j. and 3.k. in Inspection Manual Chapter 0612, Appendix E, Examples of Minor Issues, where significant programmatic deficiencies were identified that could lead to worse errors if left uncorrected. In addition, the finding has the potential to lead to a more significant safety concern in the management and correction of operator workarounds that can have an adverse effect on the functional capability of a mitigating system or that can impact human reliability in responding to initiating events. Using NRC Inspection Manual Chapter 0609, Attachment 4, Phase 1 Initial Screening and Characterization of Findings, this finding was determined to be of very low safety significance (Green) because the failure to follow procedure and correct previously identified operator workaround program deficiencies, by themselves, did not result in an actual loss of operability or functionality, loss of system safety function, actual loss of safety function of a single train for greater than its Technical Specification (TS) allowed outage time, actual loss of safety function of one or more non-TS trains of equipment designated as risk-significant per10CFR50.65 for greater than 24 hours, and was not potentially risk significant due to a seismic, flooding, or severe weather initiating event. This finding has a crosscutting aspect in the area of problem identification and resolution associated with the corrective action program component because operations department personnel failed to take appropriate corrective actions to address previously identified deficiencies with following the operator workaround program procedure (P.1.d). |
| 05000395/FIN-2009005-03 | 2009Q4 | Summer | Control of Electrical Grounding Devices Resulting in Fires in the Turbine Building Non-Safety-Related Switchgear | At approximately 3:42 p.m. on November 22, 2009, with the unit in Mode 5 (Cold Shutdown), the new main transformer was energized for testing following replacement during the refueling outage. The transformer circuit breaker immediately tripped and a loss of all station 7.2 kV balance of plant (BOP) power occurred due to a ground fault condition. Coincident with the BOP power loss, smoke alarms were received on the fire protection panel located in the control room. Shortly thereafter, heavy smoke was identified in both of the 7.2 kV BOP switchgear rooms located in the Turbine Building. The licensee dispatched the onsite fire brigade to the affected locations and contacted the offsite fire departments for support. At 4:00 p.m., the licensee declared a Notice of Unusual Event (NOUE) condition onsite per Emergency Action Level HU2.1, Fire within the Protected Area not extinguished within 15 minutes of detection or explosion within the Protected Area. When the fire brigade responded, they found indications of fires in the 1A, 1B, and 1C 7.2 kV BOP normal incoming breaker cubicles located in the two BOP switchgear rooms. After the initial fires were extinguished, re-flash fires were observed and extinguished by the onsite fire brigade with support from the offsite fire departments. The licensee confirmed that the fire was extinguished at 4:40 p.m. and terminated the NOUE at 6:55 p.m. At the time of the event, the inspectors were onsite and immediately responded to the control room to monitor licensee emergency actions, evaluate the actual/potential impact on safety-related equipment, and notified NRC regional and headquarters management of the event and the status of plant conditions and fire brigade response actions. The inspectors verified that the licensees response to the event was appropriate and consistent with emergency and fire response procedure requirements. The inspectors verified that the NRC reporting requirements for the event were properly implemented and that the licensee entered the issues related to the event into their CAP. The licensee determined that the cause of the fire was the failure to remove ground protection devices that were left in the 1A, 1B, and 1C 7.2 kV BOP normal incoming breaker cubicles earlier in the outage. With the ground devices still installed, a direct path to ground and significant arc flash occurred in each of the three 7.2 kV BOPincoming breaker cubicles when the main transformer was energized. At the end of the inspection period, the inspectors were awaiting the completion of the licensees Corrective Action Review Board review of the root cause evaluation results to understand the potential performance deficiencies. This issue is unresolved pending review of the licensees final evaluation and corrective actions by the inspectors in order to characterize this issue. This unresolved item (URI) is identified as05000395/2009005-03, Control of Electrical Grounding Devices Resulting in Fires in the Turbine Building Non-Safety-Related Switchgear |
| 05000395/FIN-2010002-01 | 2010Q1 | Summer | Licensee-Identified Violation | 10 CFR 50 Appendix B, Criterion XI, Test Control requires, in part, that written test procedures incorporate the requirements and acceptance limits contained in the applicable design documents. Contrary to this, on October 16, 2009, the licensee identified that the acceptance criteria for the TDEFWP were not correct when the TDEFWP failed the full flow surveillance test. As a result, the TDEFWP was declared inoperable. The violation was determined to be of very low safety significance because, when the evaluation was performed, the existing acceptance criteria were coincidentally conservative, and the pump was within the design basis margin limits. The licensee performed calculations and revised the acceptance criteria within the surveillance test procedure. The licensee addressed this issue in the corrective action program as condition report CR-09- 04033 |
| 05000395/FIN-2010002-02 | 2010Q1 | Summer | Licensee-Identified Violation | TS 3.8.1.1 Electrical Power Systems, Alternating Current (AC) Sources for Modes 1-4 requires, in part, that the two separate and independent EDGs shall be loaded to an indicated target value of 4676 kW (between 4600-4700 kW) and maintained for 2 hours during a 24 hour run at least once every 18 months (Surveillance Requirement (SR) 4.8.1.1.2.g.7.a). Contrary to this, on August 12, 2009, the licensee identified during surveillance testing that the B EDG asfound maximum loading was 4575 kW, and B EDG could not be operated within the maximum TS specified load range. As a result, B EDG was declared inoperable. The violation was determined to be of very low safety significance because B EDG was able to meet the design basis limiting, largest short term load (less than two hours) of 4390 kW. The licensee adjusted the fuel rack stop, completed the surveillance test satisfactorily, and revised the mechanical maintenance procedure to address loading measurement instrumentation and the post maintenance test loading range. The licensee addressed this issue in the corrective action program as CR-09-03120 |
| 05000395/FIN-2010003-01 | 2010Q2 | Summer | Inadequate Station Tagout Procedure for Controlling Safety and Non-safety Related Grounding Equipment Results in Loss of All Balance of Plant Power and Switchgear Fires | A Green self-revealing non-cited violation (NCV) of TS 6.8.1.a was identified for the failure to establish adequate procedural tagging controls of safety and nonsafety related electrical ground protection equipment which contributed to the main power transformer being energized while electrical ground protection equipment was still installed in three 7.2 kV Balance of Plant (BOP) switchgear breaker cubicles. This condition resulted in a complete loss of BOP power due to the faults to ground, significant arc flashing, and subsequent fires in each of the three switchgear cubicles requiring onsite and offsite fire brigade response and the declaration of an UE. The finding was entered into the licensees corrective action program as condition report CR-09-05093. The inspectors determined that the licensees failure to develop an adequate station tagout procedure for controlling the configuration of safety and non-safety related ground protection equipment was a performance deficiency that was within the licensees ability to foresee and correct. While this event involved the misconfiguration of ground protection in non-safety-related BOP switchgear, the same station tagout procedural requirements apply to the control of safety-related equipment. This finding is more than minor because the failure to properly control the configuration of safety and non-safety related ground protection electrical equipment, if left uncorrected, would have the potential to lead to a more significant safety concern. In addition, the finding is associated with the protection against external factors 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, in that, the failure to properly control the configuration of the ground protection equipment resulted in fires in three switchgear cubicles requiring onsite and offsite fire brigade response actions and the declaration of an UE. Since this problem occurred while the station was in cold shutdown (Mode 5) with the pressurizer solid and all three reactor coolant pumps initially bumped, NRC Inspection Manual Chapter (IMC) 0609, Significance Determination Process, Appendix G, Shutdown Operations Significance Determination Process, was used to assess the significance of this finding. Using Phase 1 of Appendix G, the finding was determined to be of very low significance (Green) because it did not result in an actual loss of offsite power event nor degrade the licensees ability to cope with such an event since both emergency diesel generators, the dedicated offsite AC power, and alternate AC power sources remained available. This finding involved the cross-cutting area of human performance, the component of resources, and the aspect of complete, accurate and up-to-date procedures, H.2(c), because the licensee failed to establish adequate station tagout procedures for controlling the installation and removal of safety and non-safety related ground protection equipment. (Section 4OA3) |
| 05000395/FIN-2010004-01 | 2010Q3 | Summer | Failure to Notify the Commission of a Change in Medical Status | The inspectors identified a cited violation of 10 CFR Part 55.25, Incapacitation because of disability or illness, for the failure of the facility licensee to notify the Commission of a change in the medical status of one licensed operator within 30 days of learning of the change as required. This issue was entered into the licenseei12s corrective action program as Condition Report CR-10-03348. The failure of the facility licensee to notify the Commission within 30 days of learning of a permanent change in the medical status of a licensed operator as required by 10 CFR 55.25 was a performance deficiency. This performance deficiency was evaluated in accordance with the Enforcement Policy and determined to be a Severity Level IV violation in accordance with Supplement I. This violation is being cited in accordance with the Enforcement Policy Section 2.3.2.a.3 because it was a repetitive violation resulting from inadequate corrective action and was NRC identified. Because this Notice of Violation was evaluated in accordance with Traditional Enforcement, there was no cross-cutting aspect assigned. (Section 1R11.2 |
| 05000395/FIN-2010004-02 | 2010Q3 | Summer | Licensee-Identified Violation | TS 3.6.2.3, Reactor Building Cooling System, and TS 3.6.3, Particulate Iodine Cleanup System, requires, in part, that two independent groups of RBCUs and their associated high efficiency particulate air (HEPA) filter banks shall be operable in Modes 1-4. Contrary to this, due to the use of a non-conservative HEPA filter filtration area factor in the calculation of air flow rates, on April 28, 2010, the licensee identified that RBCUs XAA0001A and XAA0002A had air flow rates slightly below the TS range required for operability between Refuel 16 and 18, and RBCUs XAA0001B and XAA0002B had air flow rates slightly below the TS range for operability between Refuel 16 and 17. The violation was determined to be of very low safety significance because the RBCUs remained capable of performing their design functions with the slight reduction in air flow rates. The licensee replaced the filters and corrected the filtration area factor prior to the end of Refuel 18. The licensee addressed this issue in their corrective action program as CR-09-05126 and CR-10-01783 |
| 05000395/FIN-2010005-01 | 2010Q4 | Summer | Failure to Correct Condition Adverse to Quality Involving Inadequate EDG Engine Driven Pump Preventative Maintenance | The inspectors identified a non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, for the licensees failure to identify and correct a condition adverse to quality following the February 10, 2010, failure of the A Emergency Diesel Generator (EDG) jacket water pump mechanical seal. Specifically, the licensee failed to identify and correct inadequacies in their EDG preventive maintenance program for monitoring engine driven pump seal leakage in accordance with vendor recommendations, leading to subsequent A EDG jacket water seal leakage going unidentified from approximately June 1, 2010, until October 20, 2010. The licensee initiated condition report (CR)-10-03861 and implemented requirements and operator training to conduct proper seal leakage monitoring during subsequent EDG operations. The inspectors determined that the licensees failure to take adequate corrective actions to identify and correct inadequacies in the EDG PM program for monitoring EDG engine driven pump seal leakage in accordance with vendor recommendations was a performance deficiency that was within the licensees ability to foresee and correct. This finding is more than minor because if left uncorrected, the issue would become a more significant safety concern, in that, the potential exists for unidentified engine driven pump seal leakage that could lead to EDG failure. This issue is associated with the equipment performance attribute of the Mitigating System cornerstone and adversely affects the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the failure to take adequate corrective actions to identify inadequacies in the EDG preventive maintenance program for monitoring EDG engine driven pump seal leakage in accordance with vendor recommendations could adversely affect the reliability of the EDGs. This finding was evaluated using Inspection Manual Chapter 0609, Significance Determination Process, Phase 1 Worksheet for mitigating systems. The finding was determined to be of very low safety significance (Green) because it did not actually result in the loss of the EDG system safety function or the loss of function of a single EDG. The cause of this finding was directly related to the problem evaluation cross-cutting aspect in the corrective action program component of the Problem Identification and Resolution area because the licensee did not thoroughly evaluate the February 10, 2010, jacket water pump mechanical seal failure event and identify nonconformance with the vendor recommended visual inspections of engine driven pump seals during EDG operations (P.1(c)) |
| 05000395/FIN-2010005-02 | 2010Q4 | Summer | Licensee-Identified Violation | TS 3.0.4 requires, in part, that when a Limiting Condition for Operation is not met, entry into a mode or other specified condition shall only be made when the associated actions to be entered permit continued operation in the mode for an unlimited period of time. TS 3.7.1.6 requires that each FWIV be operable in Modes 1-3 and the associated ACTIONS for Mode 1 operation do not allow operation for an unlimited period of time. Contrary to the above, on September 25, 2010, due to inadequate procedural guidance, operators did not ensure that one of the three FWIVs air accumulator pressure was above the minimum for operability when Mode 1 was entered from Mode 2. This condition existed for seven minutes until the minimum pressure for operability was attained in the FWIV air accumulator. The violation was determined to be of very low safety significance because of the short duration that pressure was below the minimum for operability and subsequent FWIV testing determined that the FWIV remained capable of performing its design function at the reduced air accumulator pressure. The licensee planned to revise GOP-4A, Power Operation Mode 1 Ascending, to ensure verification that all FWIV actuator pressures are above the minimum pressure for operability prior to allowing entry into Mode 1. The licensee identified and addressed this issue in their corrective action program as CR-10-03766 |
| 05000395/FIN-2011002-01 | 2011Q1 | Summer | None | 10CFR 55.25 states If, during the term of the license, the licensee develops a permanent physical or mental condition that causes the licensee to fail to meet the requirements of 55.21 of this part, the facility licensee shall notify the Commission, within 30 days of learning of the diagnosis, in accordance with 50.74(c). For conditions for which a conditional license (as described in 55.33(b) of this part) is requested, the facility licensee shall provide medical certification on Form NRC 396 to the Commission (as described in 55.23 of this part). Contrary to this, the licensee identified that they did not notify the Commission within 30 days after a licensed operator was diagnosed with a permanent physical medical condition as required by 10 CFR 55.25. This was identified in the licensees CAP as CR 11- 00304 and 11-00031. This finding was of very low safety significance because the licensed operator performs non-licensed shift technical advisor duties and has been inactive during the time in question. |
| 05000395/FIN-2011003-01 | 2011Q2 | Summer | Failure to Adequately Assess and Manage Risk of Switchyard Maintenance Activities During Lowered RCS Inventory Conditions | The inspectors identified a Green non-cited violation (NCV) of 10 CFR 50.65(a)(4), Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, for the failure to perform an adequate risk assessment and implement approved high risk management contingency plans for work in the stations electrical switchyard. Specifically, on April 21, 2011, operations work control personnel failed to adequately assess the impact of work activities in the switchyard involving the use of vehicles, resulting in outage high risk management actions that prohibited the movement of vehicles during lowered reactor coolant system (RCS) inventory conditions from being implemented. Following the inspectors identification of this issue, the licensee adequately assessed and managed the increase in risk for the activities. The issue was entered into the licensees corrective action program as condition report CR-11-01908. The failure to perform an adequate risk assessment and implement high risk evolution contingency plans for work in the stations switchyard was a performance deficiency within the licensees ability to foresee and correct. This finding was associated with the Initiating Events Cornerstone and affected the cornerstone objective for limiting the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown, such as, loss of offsite power (LOOP) due to trucks damaging critical electrical components in the switchyard. The inspectors determined that the finding is more than minor because it was similar to both the more than minor examples 7.e and 7.g in NRC Inspection Manual Chapter (IMC) 0612, Appendix E, Examples of Minor Issues, because the risk assessment for the switchyard work activity failed to consider the impact of vehicle movements resulting in outage high risk management actions that prohibited the movement of vehicles during lowered RCS inventory conditions from being implemented. A Significance Determination Process (SDP), Phase 1 screening determined that the performance deficiency represented an increase in the likelihood of a LOOP during shutdown and therefore the risk was estimated using NRC IMC 0609, Appendix G, Shutdown Operations Significance Determination Process. A Phase 2 SDP risk evaluation was done by a regional senior risk analyst using IMC 0609, Appendix G, Attachment 2. The major assumptions of the analysis were that the plant was in plant operating state (POS-2) in Mode 6, with the RCS vented and the residual heat removal (RHR) system in service for decay heat removal. Time to boil was estimated at 35 minutes with an estimated time to core damage of 8.8 hours. The exposure period was approximately 2.5 hours. The LOOP initiating event likelihood was increased by one order of magnitude due to the impact of the performance deficiency. Multiple (i.e., three) qualified sources of offsite power and both onsite emergency diesel generators were available when the vehicles were moved into the switchyard. Recovery credit for restoration of offsite power was included. The dominant sequence was a LOOP with failure of emergency power sources causing a loss of RHR and failure to recover offsite power or emergency power prior to core damage ensuing. The risk was mitigated by the short exposure period and the availability of mitigating system equipment. The result of the analysis was a core damage frequency risk increase of <1E-6/year, a finding of very low safety significance (Green). The inspectors determined that this finding had a cross-cutting aspect in the area of Human Performance, because personnel did not appropriately plan and coordinate switchyard work activities consistent with nuclear safety by incorporating appropriate outage risk insights and risk management contingency plans |
| 05000395/FIN-2011003-02 | 2011Q2 | Summer | Failure to Perform ISI General Visual Examinations of Containment Moisture Barrier Associated with Containment Liner Leak Chase Test Connection Threaded Pipe Plugs | The inspectors identified a Green NCV of 10 CFR Part 50.55a, Codes and Standards, involving the licensees failure to properly apply Subsection IWE of ASME Section XI for conducting general visual examinations of the metal-to-metal pipe plugs installed in the containment liner channel weld leak chase test connections that provide a moisture barrier to the containment liner seam welds. Following the inspectors identification of this issue, the licensee conducted the visual examinations and found missing pipe plugs and water in four of the leak chase test connection zones. The licensee adequately assessed and corrected the deficiencies prior to entering Mode 4 (Hot Shutdown) to ensure the integrity of containment was maintained. The issue was entered into the licensees corrective action program as condition report CR-11-02834. The failure to conduct a general visual examination of 100 percent of the moisture barriers intended to prevent intrusion of moisture against inaccessible areas of the containment liner at metal-to-metal interfaces which are not seal welded, was a performance deficiency that was within the licensees ability to foresee and correct. This finding was of more than minor significance because the failure to conduct required visual examinations and identify the degraded moisture barriers which allowed the intrusion of water into the four liner leak chase channels, if left uncorrected, could have resulted in more significant corrosion degradation of the containment liner or associated liner welds. The finding was associated with the design control attribute of the Barrier Integrity Cornerstone and affected the cornerstone objective of providing reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, visual examinations of the containment metal liner provide assurance that the liner remains capable of performing its intended safety function. The inspectors used IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 Initial Screening and Characterization of Findings, and determined that the finding was of low safety significance (Green) because it did not represent an actual open pathway in the physical integrity of the reactor containment. A cross-cutting aspect was not identified because the finding does not represent current licensee performance. |
| 05000395/FIN-2011003-03 | 2011Q2 | Summer | Failure to Conduct Adequate Testing of Appendix R Fire Switches | The NRC identified an apparent violation (AV) of the Virgil C. Summer Nuclear Station Operating License Condition 2.C.(18), Fire Protection System, related to the licensee\\\'s failure to implement and maintain in effect all provisions of the approved fire protection program as described in the Final Safety Analysis Report (FSAR). Specifically, the licensee failed to adequately test the isolation function of all 10 CFR 50 Appendix R isolation local control transfer switches ( fire switches ), including the B EDG fire switch, designed to assure isolation of safe shutdown equipment from the control room in the event of a control room evacuation due to a fire. This resulted in the licensee not identifying a wiring discrepancy that had existed in the B EDG fire switch circuitry since original plant startup until its discovery on April 29, 2010, that would have defeated the Appendix R isolation function during a design basis fire event requiring evacuation from the Control Room. The issue was entered into the licensees corrective action program as condition report CR-10-01814. The failure to demonstrate proper Appendix R isolation capability of safe shutdown equipment controlled from remote shutdown locations during surveillance testing of Appendix R fire switches is a performance deficiency that was within the licensees ability to foresee and correct. The inspectors determined that the finding is more than minor because it was associated with both the procedure quality and protection against external events (i.e., fire) attributes of the Mitigating Systems cornerstone and it adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to adequately test Appendix R isolation contacts associated with fire switches contributed to not identifying a wiring discrepancy in the B EDG fire switch circuitry that defeated its Appendix R isolation function. This condition could have led to the improper operation of the switch or prevented the B EDG output breaker from automatically closing during certain fire scenarios due to fire damage of the electrical circuitry. In accordance with NRC IMC 0609, Significance Determination Process, the inspectors performed a Phase 1 screening analysis and determined that since the finding affected the fire protection defense-in-depth strategies involving post fire safe shutdown systems, the finding required a significance evaluation under IMC 0609, Appendix F, Fire Protection Significance Determination Process. Using Appendix F, Attachment 1, Fire Protection SDP Phase 1 Worksheet, the inspectors determined that the category of post fire safe shutdown was affected and the finding required a Phase 2 analysis by a senior reactor analyst. The significance of this finding is to be determined pending completion of the Phase 2 analysis. A cross-cutting aspect was not identified because the finding does not represent current licensee performance. |
| 05000395/FIN-2011003-04 | 2011Q2 | Summer | Inadvertent Safety Injection in Mode 3 Due to Opening C Main Steam Isolation Valve | The inspectors confirmed that the operator response to the event was appropriate and consistent with emergency and abnormal operating procedure requirements. Following the SI actuation, all plant systems functioned as designed and emergency core cooling system water was injected into the RCS. The operators were successful in timely termination of unnecessary injection flows and preventing potential pressurizer overfill and adverse RCS overpressure conditions. The plant was effectively stabilized in Mode 3. The licensee correctly determined that no emergency action level entry condition was reached; however, the event was determined to be reportable to the NRC under the 4 hour non-emergency requirement of 10 CFR 50.72(b)(2) for an emergency core cooling system discharge to the RCS. The licensee reported the notification in a timely manner. Based on interviews with the operators following completion of plant recovery actions, the inspectors noted that the operators had failed to recognize that the main steam line header downstream of the MSIVs had been depressurized when the MSIVs and their bypass valves were closed earlier in the shift. In addition, procedural guidance for stroking the MSIV, such as the stroke test procedure (i.e., STP-130.004D, Rev. 1, Main Steam Isolation Valve Full Stroke Test ), was not formally utilized when the valve was opened at the request of I&C. This procedure contained a signoff action to verify current plant conditions will permit performance of the stroke test, and could have provided an opportunity for the operators to have recognized that the main steam line header was depressuried, had this procedure been utilized. The licensee documented this event in their CAP as CR-11-03001 and planned to submit a LER within 60 days of the event date. At the end of the inspection period, the inspectors were awaiting the completion of the licensees root cause evaluation results to understand and properly characterize the potential performance deficiencies associated with this event. This issue is unresolved pending inspector review of the licensees evaluation, proposed corrective actions, and review of the licensees LER in order to characterize the potential performance deficiencies associated with this event. This unresolved item (URI) is identified as 05000395/2011003-04, Inadvertent Safety Injection in Mode 3 Due to Opening C Main Steam Isolation Valve. |
| 05000400/FIN-2012008-01 | 2012Q2 | Harris | B AND C MSIVs FAIL TO CLOSE DURING SURVEILLANCE TESTING | The inspectors identified an URI associated with issues in the licensees MSIV maintenance and testing. These issues were potential contributing causes to the April 21, 2012, B and C MSIV failure to stroke close. Description: Several issues were identified regarding the licensees MSIV maintenance and testing. Some of the issues identified were: FnIn the last two refueling intervals, maintenance was making minor adjustments to the actuator hydraulic speed control system to decrease the time needed to shut the valves as a result of increasing stroke test closure time results. FnBeginning in 2001, work deficiency documents were initiated due to the MSIVs experiencing difficulty in opening during refueling outage cycling. There had not been any corrective maintenance conducted requiring valve internal disassembly and the licensee had not developed any periodic PMs to visually inspect the condition of valve internals. FnThe valve vendor manual recommended weekly valve partial exercising ten percent of its total stroke in order to assure that the actuator and valve was properly functioning. Prior to 2000, this partial exercising was being performed quarterly. In 2000, the licensee revised their IST program requirements to discontinue quarterly exercising in lieu of the 18-month cold shutdown TS stroke testing that was currently being conducted. FnPrior to the current MSIV failures; the MSIVs had never been tested as part of the licensees AOV program. Summary: The licensees root cause investigation was not completed at the conclusion of the special inspection; the determination as to whether these issues represented performance deficiencies was not completed. Pending completion of the licensees root cause evaluation (RCE) and subsequent NRC review to determine if a performance deficiency exists, disposition of these issues will be tracked via Unresolved Item (URI) 05000400/2012008-01, B and C MSIVs Fail to Close During Surveillance Testing. |
| 05000400/FIN-2012009-01 | 2012Q4 | Harris | Technical Specification Inoperability of MSIVs Due to Failure to Conduct Diagnostic Testing | The inspectors identified a non-cited violation of Technical Specification (TS) 3.7.1.5, Main Steam Line Isolation Valves, due to one or more MSIVs being inoperable for a time greater than the allowed outage time and a plant shutdown was not completed in accordance with the action statement of TS 3.7.1.5. MSIV diagnostic testing in accordance with EGR-NGGC-0205, Air Operated Valve (AOV) Reliability Program, had not been conducted by the licensee. This contributed to the licensee not identifying long-term corrosion/oxidation of the valve piston rings that resulted in the B and C MSIV failure to initially close during stroke time testing on April 21, 2012. The licensee conducted repairs of all three MSIVs and restored them to an operable condition prior to entering Mode 4 following the completion of an ongoing refueling outage. The licensee entered this condition into their corrective action program (CAP) as Nuclear Condition Report (NCR) 531773. The failure to properly classify the MSIVs as risk significant and implement MSIV diagnostic testing in accordance with the AOV program procedure EGR-NGGC-0205 was a performance deficiency (PD). The PD is more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone and affected the cornerstone objectives of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding is also associated with the containment isolation barrier performance attribute of the Barrier Integrity cornerstone and affected the cornerstone objective of providing reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, the failure to conduct periodic diagnostic testing that would have identified long-term internal valve degradation due to unexpected corrosion/oxidation of the valve piston rings in all three MSIVs resulted in two MSIVs failing to initially close during TS stroke time testing on April 21, 2012, and excessive internal friction in all three MSIVs such that they may not have been capable of performing their safety-related closure function during certain design basis events. Using IMC 0609, Appendix A, The Significance Determination Process for Findings At- Power, the inspectors determined there was an actual loss of safety function greater than the TS allowed outage time associated with the finding which required a more detailed risk evaluation. A detailed risk evaluation was performed by a regional senior reactor analyst. The result of the analysis of the risk of the PD was a delta core damage frequency (CDF) of <1E-6/year and a delta Large Early Release Fraction (LERF) of <1E- 7/year, a GREEN finding. No cross-cutting aspect was assigned to this finding because licensee decisions made in regard to classifying the MSIVs in the AOV program were made more than three years ago and therefore, not reflective of current plant performance. |
| 05000400/FIN-2016003-01 | 2016Q3 | Harris | Subsequent Loss of Safety-Related Chilled Water System Results in a Loss of Safety Function | The inspectors opened a URI to facilitate prompt tracking, documentation, and closure of inspection, verification, and resolution activities, associated with the A ESCW chiller failures. On July 15, 2016, the A ESCW chiller tripped on low oil pressure. Licensee investigation identified that oil was leaking from the threaded portion of a brass fitting located between a pressure switch and needle valve associated with PDS-01CY-9428ASA-HI. Upon removal, it was observed that significant radial cracking occurred in the threaded portion of the brass fitting. A like-for-like replacement was installed and the A ESCW chiller was returned to service. One week later, on July 22, 2016, the A ESCW chiller tripped again on low oil pressure. The investigation revealed that the same brass fitting had failed and the A ESCW chiller could not meet its mission time of 30 days of continuous operation in the event of a loss of cooling accident. During this 7-day period, the B ESCW chiller was inoperable for a period of time, which means the ESCW system would not have been able to meet its safety function. The licensees investigation into the cause of the subsequent failure is ongoing. A URI is being opened to determine whether the subsequent failure of the brass fitting was reasonably within the licensees ability to predict and therefore a performance deficiency. This issue is being tracked as URI 05000400/2016003-01, Subsequent Loss of Safety-Related Chilled Water System Results in a Loss of Safety Function. |
| 05000400/FIN-2017002-01 | 2017Q2 | Harris | Evaluate Fire Protection Discrepancies in RHR/CS Pump Rooms | An unresolved item (URI) was identified by the inspectors during the walkdown of the A and B RHR and CS pump rooms, involving the use of unapproved non-fire retardant plastic sheeting to contain contamination on the A RHR piping. Additionally, the inspectors identified that the fire pre-plan for fire brigade response delineates a hose station that did not contain adequate fire hose length.Description: The inspectors identified two issues of concern during the fire protection walkdown of the A and B RHR and CS pump rooms as follows: 1) Use of Unapproved Plastic for Contamination Control: The inspectors noted that an approximately 30 foot section of the A RHR pump suction piping had been wrapped with multiple layers of plastic sheeting materials that included radiation protection yellow Caution Radioactive Materials stamped plastic sheeting overlaid with clear stretch wrap plastic. The section of RHR piping where this plastic was installedincluded the motor-operated RHR suction valves from the containment recirculation sump (valve 1SI-310) and the refueling water storage tank supply (valve 1SI-322). The inspectors were concerned that these valves could be adversely impacted from a potential fire involving this plastic material. The inspectors questioned whether this plastic was fire retardant material or had been evaluated and allowed under the licensees transient combustible control procedure. The licensee subsequently determined that none of the plastic material was fire retardant or met the requirements of National Fire Protection Association (NFPA) 701, Standard Methods of Fire Tests for Flame Propagation of Textiles and Films, and no previous transient combustible evaluation could be found that allowed the use of the non-fire retardant plastic in the RHR pump room. In addition, radiation protection personnel indicated that there could be other areas where this plastic was used since it was a typical practice to use the material to prevent the spread of contamination from leaking piping connections, valves, and valve packing. The licensee subsequently removed the plastic from the A RHR piping and initiated NCR 02132781 to evaluate this issue of concern. 2) Inadequate Fire Hose Length in Hose Station Described in Fire Pre-Plan: During review of the fire pre-plan procedure (FPP-012-02-RAB190-216) for the A and B RHR/CS pump rooms on the RAB 190 elevation, the inspectors noted that the procedure described two fire hose stations intended to be used during fire brigade response for a fire in either of the pump rooms. These two hose stations were the respective hose stations located just inside the access door to each of the two RHR/CS pump rooms. The procedure states that an extra 100 feet of hose would be needed to account for the additional distance for the hose from the opposite train pump room. However, the inspectors identified that even with the extra 100 feet added to the existing 100 feet that is already in each hose station, there would still not be adequate length for this second hose to reach the opposite train pump room with the fire. The inspectors measured the actual distance between the two locations and estimated the hose would have to be over 300 feet in length in order to be effective in fighting a fire in either of the rooms. A separate hose station on the 216 RAB elevation may provide adequate backup coverage. However, the inspectors were concerned that the issue with the fire pre-plan hose station use could cause confusion or pose an unnecessary delay in fire brigade response for a fire in either of the rooms. The licensee subsequently initiated NCR 02134163 to evaluate this issue of concern.Pending completion of additional evaluations needed to determine whether the above issues of concern represented performance deficiencies and if so, whether the performance deficiencies were of more than minor significance, this issue is identified as URI 05000400/2017002-01, Evaluate Fire Protection Discrepancies in RHR/CS Pump Rooms. |
| 05000400/FIN-2017002-02 | 2017Q2 | Harris | B ESCW Chiller Failure to Start | The inspectors opened a URI to facilitate the completion of inspection and determination of whether a performance deficiency was associated with the start failure of the B ESCW chiller on May 13, 2017. Description: On May 13, 2017, while attempting to start the B ESCW chiller, the motor compressor immediately tripped on C phase instantaneous overcurrent relay actuation. The chiller was declared inoperable and immediate troubleshooting was conducted to determine the cause of the trip. The licensees initial investigation did not identify any electrical or mechanical issues with the compressor motor, supply breaker and electrical bus, or other chiller control components. While the calibration of the C phase instantaneous overcurrent relay was checked and found to be within specification, the licensee determined the most probable cause of the trip was an intermittent failure of this relay. The relay was replaced and subsequent post-maintenance testing of the chiller was successfully performed without any other chiller operational problems being identified. The chiller was returned to operability early May 14, 2017, following the completion of this post-maintenance testing. At the end of the inspection period, the licensees investigation into the cause of the start failure had just completed. A URI is being opened for the NRC to review the licensees failure analysis and causal evaluation to determine whether the chiller start failure was reasonably within the licensees ability to predict or prevent and therefore a performance deficiency. This issue is being tracked as URI 05000400/2017002-02, B ESCW Chiller Failure to Start |
| 05000400/FIN-2017003-01 | 2017Q3 | Harris | Incomplete and Inaccurate Emergency Action Level Submittals | The NRC identified a Severity Level (SL ) IV non- cited violation (NCV) of 10 CFR 50.9, Completeness and accuracy of information, for failure to provide complete and accurate information for prior approval of a new emergency action level (EAL) scheme. The documents submitted to the NRC were, Shearon Harris Nuclear Power Plant, Unit 1 Changes to the Emergency Action Level Scheme, dated April 25, 2010, and License Amendment Request to Adopt Emergency Action Level Scheme Pursuant to NEI 99- 01, Revision 6, dated April 30, 2015. The submit ted documents specified the licensee s EAL scheme for Category F Fission Product Barrier EAL, which contained declaration EAL threshold values for the containment high range radiation monitor that were lower than the correct values due to use of a n improper calculation methodology. The calculation methodology that was used was not in accordance with the license. It was used to calculate the loss of fuel clad barrier and potential loss of containment threshold values. The licensee implemented compensatory corrective actions by issuing Standing Instruction 2017 -017 to inform operators and emergency response organization decision- makers of the proper application of the EAL scheme and appropriate threshold values to be implemented. Additionally, the licensee plans to submit a license amendment request to update the EAL scheme. The licensee entered this violation into their corrective action program (CAP) as nuclear condition report (NCR) 02155272. The inspectors evaluated the underlying technical issue and determined that the licensees failure to maintain the effectiveness of its emergency plan was a performance deficiency. The issue was documented as a Green licensee- identified violation (LIV) in Section 4OA7 of this report. The reactor oversight process (ROP) , significance determination process , does not specifically consider the regulatory process impact in its assessment of licensee performance. Therefore, it was necessary to address this violation which impeded the NRCs ability to regulate, using traditional enforcement to adequately deter non- compliance. Using the NRC Enforcement Policy, Section 2.3.11, Inaccurate and Incomplete Information, and Section 6.9, Inaccurate and Incomplete Information or Failure to Make a Required Report, this issue was determined to be a SL IV violation. Though the NRC would have questioned the issue with a request for additional information, it would not have resulted in substantial further inquiry. 3 Additionally, the associated technical violation was determined to be of very low safety significance. Traditional enforcement violations are not assessed for cross -cutting aspects |
| 05000400/FIN-2017003-02 | 2017Q3 | Harris | Review of Removal of the Technical Support Center (TSC) Temporary Diesel Generator | The inspectors conducted a detailed review of NCR 02123373, Emergency Action Level Document Calculation Assumptions. The inspectors chose the sample because the EAL issue initially appeared to be potentially more significant than finally determined. The inspectors evaluated the following attributes of the licensees actions: complete and accurate identification of the problem in a timely manner evaluation and disposition of operability and reportability issues consideration of extent of condition, generic implications, common cause, and previous occurrences classification and prioritization of the problem identification of root and contributing causes of the problem 19 identification of any additional condition reports completion of corrective actions in a timely manner 2. The inspectors conducted a detailed review of NCR 00520918, Loss of Offsite Power Impact on Technical Support Center (TSC). The inspectors chose the sample because it was discovered that on July 17, 2017, the licensee had removed a temporary diesel generator that was intended to provide a back -up reliable power source to the TSC until a permanent solution was implemented. The inspectors evaluated the following attributes of the licensees actions: complete and accurate identification of the problem in a timely manner evaluation and disposition of operability and reportability issues consideration of extent of condition, generic implications, common cause, and previous occurrences classification and prioritization of the problem identification of root and contributing causes of the problem identification of any additional condition reports completion of corrective actions in a timely manner b. Findings 1. Incomplete and Inaccurate Emergency Action Level Submittals Introduction: The NRC identified a Severity Level IV NCV of 10 CFR 50.9 , Completeness and accuracy of information, for failure to provide complete and accurate information for prior approval of a new EAL scheme. The documents submitted to the NRC were, Shearon Harris Nuclear Power Plant, Unit 1 Changes to the Emergency Action Level Scheme, dated April 25, 2010, and License Amendment Request to Adopt Emergency Action Level Scheme Pursuant to NEI 99- 01, Revision 6, dated April 30, 2015. The first submittal to the NRC in 2010 was not complete and accurate in all material respects , and the submittal in 2015 was a missed opportunity to identify the errors made in the first submittal in 2010. Description : On May 10, 2017, Shearon Harris identified the hot operating mode EAL thresholds were calculated incorrectly using a NUREG -0654 methodology vice the required NEI 99- 01 Rev. 6 method, as specified in the current facility licensing basis. When employing the NUREG -0654 methodology to calculate the EAL threshold values, the reactor coolant system (RCS) inventory was assumed to be released at a 50 gallons per minute (gpm) RCS leak rate and activity of 300 micro -Curies per gram (ci/gm) dose equivalent iodine (DEI), over a six -hour period of time. In comparison, when employing the NEI 99- 01 Rev. 6 methodology, the assumption as part of calculating the EAL threshold values was that the entire RCS inventory was released instantaneously at an activity of 300ci/gm DEI. Both of the licensees submittals to the NRC, specified the licensee s EAL scheme for Category F Fission Product Barrier EAL, contained declaration EAL threshold values for the containment high range radiation monitor for loss of fuel clad barrier and potential loss of containment , that were significantly lower than the correct values , due to use of the improper calculation methodology. The submittal dated April 30, 2015, was submitted to provide a complete change to the EAL scheme. This submittal was a missed opportunity by the licensee to identify that the wrong methodology to calculate the EAL threshold values had been used. 20 These submittals were not correct in material content and impacted the NRC s regulatory processes. The NRC evaluated the licensees failure to provide complete and accurate information to determine if there were any unresolved issues. The inspectors concluded that the incomplete and inaccurate information in the license submittal was material to the NRC because, had the NRC staff known the actual methodology used was inaccurate, the staff would have required the licensee to modify the EAL threshold values . The licensee appropriately revised the EAL threshold values utilizing the correct calculation methodology. The licensee issued NC R 02123373, dated May 10, 2017, for EAL thresholds that were calculated without using the correct methodology described in the facility licensing basis. The licensee implemented compensatory corrective actions by issuing Standing Instruction 2017- 017 to inform operators and emergency response organization decision - makers of the proper application of the EAL scheme and revised threshold values to be implemented until a permanent change is made to the license. Additionally, the licensee issued NCR 02155272, dated October 3, 2017, for the incomplete and inaccurate EAL submittal, specifically addressing and resolving the completeness and accuracy issues identified by the inspectors. The final significance determination of the underlying technical issue for the licensees failure to maintain the effectiveness of its emergency plan was documented in NRC Inspection Report 05000400/2017003, Section 4OA7, as a Green LIV. Analysis : The inspectors evaluated the underlying technical issue and determined that the licensees failure to maintain the effectiveness of its emergency plan was a performance deficiency. The issue was documented as a Green LIV in Section 4OA7 of this report. The ROPs significance determination process does not specifically consider the regulatory process impact in its assessment of licensee performance. Therefore, it was necessary to address this violation which impeded the NRCs ability to regulate, using traditional enforcement to adequately deter non- compliance. Using the NRC Enforcement Policy, Section 2.3.11, Inaccurate and Incomplete Information, and Section 6.9, Inaccurate and Incomplete Information or Failure to Make a Required Report , this issue was determined to be a SL IV violation. Though the NRC would have questioned the issue with a request for additional information, it would not have resulted in substantial further inquiry. Additionally, the associated technical violation was determined to be of very low safety significance. Traditional enforcement violations are not assessed for cross -cutting aspects . Enforcement : Section 50.9 of 10 CFR states, in part, that, information provided to the Commission by a licensee shall be complete and accurate in all material respects. Contrary to the above, on April 25, 2010, and on April 30, 2015 , information was submitted by the licensee to the NRC that was not complete and accurate in all material respects. Specifically, the submitted documents specified the licensee s EAL scheme for Category F Fission Product Barrier EAL, contained EAL declaration threshold values for the containment high range radiation monitor , that were lower than the actual correct values , due to use of an improper calculation methodology. This was not in accordance with the license. It was used to calculate the loss of fuel clad barrier and potential loss of containment thresholds values. The licensee implemented compensatory corrective actions by issuing Standing Instruction 2017 -017 to inform operators and emergency response organization decision -makers of the proper application of the EAL scheme and appropriate threshold values to be implemented. Additionally, the licensee plans to submit a license amendment request to update the 21 EAL scheme. Because this violation was not repetitive or willful, and was entered into the licensees CAP as NC R 02155272, it is being treated as a SL IV NCV, consistent with Section 2.3.2 .a of the NRC Enforcement Policy. ( NCV 05000400/2017003- 01, Incomplete and Inaccurate Emergency Action Level Submittal s) 2. Adequacy of Process for Removal of the TSC Temporary Diesel Generator Introduction: The inspectors opened an Unresolved Item (URI) to complete a review of the licensees removal of a temporary diesel generator on July 17, 2017, that was previously installed to provide reliable backup power to the TSC in the event of a Loss of Offsite Power (LOOP) coincident with a Loss of Coolant Accident (LOCA) event. This temporary diesel generator was originally intended to be installed until a reliable backup power source could be implemented under a permanent modification. Description : The licensee initiated NCR 00520918 on March 1, 2012, to address the consequences of a LOOP/LOCA event on the T SC functionality. Since the TSC is designed with two sources of electrical power, both from offsite power sources, it was recognized that a complete loss of offsite power to the TSC could result in long term TSC operational concerns. Specifically, with t he loss of both offsite power sources, the TSC emergency ventilation system, which provides required radiation protection for event response personnel, would be non- functional, as well as other critical TSC equipment following the loss of short -term (~1 -2 hour s) back -up battery power supplies. The inspectors noted that the operability/functionality section of NCR 00520918 stated that the TSC was functional based on the (current) availability of both of the offsite power sources; however, should a LOOP event occur, then the TSC would be considered non -functional since offsite power would be rendered non -functional. This statement demonstrated the licensees understanding of the vulnerability of continued TSC functionality during a LOOP event. In recognition of this vulnerability, the NCR implemented a short -term solution for procuring and installing a temporary diesel generator in late 2012 under modification EC 85350. The inspectors noted that an emergency preparedness change review evaluation was conducted in accordance with 10 CFR 50.54(q) under action request 00568695. This change request stated that it was necessary to provide the infrastructure for an additional reliable power source for the TSC habitability systems. NCR 00520918 stated that the long- term solution was to provide a permanent backup power supply to the TSC , at which time the temporary diesel generator would be removed. While an action item was initiated to install this TSC permanent backup power source under modification EC 85145, the modification was later revised, removing the intended implementation of a permanent backup power source to the TSC. The inspectors were concerned that the TSC could have equipment and habitability issues during design basis LOOP/LOCA events when the normal TSC offsite power would be non- functional. In addition, the inspectors determined that the TSC temporary diesel generator was removed from the site on July 17, 2017, without implementing the originally intended reliable permanent backup power to the TSC and without conducting a 10 CFR 50.54(q) evaluation specific to its removal to demonstrate that this action did not reduce the effectiveness of implementing the emergency plan. The inspectors requested additional information from the licensee related to the documentation, basis, and process used for the removal of the TSC temporary diesel generator, and evidence that the TSC facility would still be capable of performing all of its intended functions during a LOOP/LOCA event. This issue of concern requires more information to 22 determine if a performance deficiency exists, and if the performance deficiency potentially constitutes a violation of regulatory requirements . Pending review of additional information from the licensee, this issue is identified a s URI 05000400/2017003 -02, Review of Removal of the Technical Support Center ( TSC ) Temporary Diesel Generator. |
| 05000400/FIN-2017003-03 | 2017Q3 | Harris | Licensee-Identified Violation | Section 50.54(q)(2) of 10 CFR requires, in part, that a licensee shall follow and maintain the effectiveness of an emergency plan which meets the planning standards of 10 CFR 50.47(b) and the requirements of 10 CFR Part 50, Appendix E . Section 50.47(b)(4) of 10 CFR requires that a standard emergency classification and action level scheme, the bases of which include facility system and effluent parameters, is in use by nuclear facility licensee, and State and local response plans call for reliance on information provided by facility licensees for determinations of minimum initial offsite response measures. Contrary to the above, from April 2010 to May 2017, the licensee failed to maintain the effectiveness of its emergency plan. Specifically, the licensee's emergency classification scheme action levels for Category F Fission Product Barrier EAL , contained declaration threshold values for the containment high range radiation monitor , which were lower than the correct values due to an improper methodology used in calculating the loss of fuel clad barrier and potential loss of containment barrier threshold values and rendered the EALs ineffective. The licensee implemented compensatory actions by issuing Standing Instruction 2017- 017 to inform operators and emergency response organization decision- makers of the proper application of the EAL scheme and appropriate threshold values to be implemented until a permanent change can be made to the license. The issue was entered into the licensees CAP as NCR 02123373. The inspectors evaluated this issue as an ineffective EAL per IMC 0609, Appendix B, Emergency Preparedness Significance Determination Process , Figure 5.4 -1. The inspectors concluded that the violation was of very low safety significance (Green). Although the incorrect EAL would alone render an early EAL classification of a General Emergency (GE) based upon the specific radiation monitor, other EALs would provide a GE classification in an accurate and timely manner aligned with the incorrect threshold values of the containment high range radiation monitor . |
| 05000400/FIN-2018001-01 | 2018Q1 | Harris | Adequacy of Fire Brigade Response During Fire Dril | The inspectors identified an URI during the March 21, 2018, announced fire drill that was observed. The drill involved an electrical failure inside the A transfer panel located in the RAB 286 elevation A cable spread room. The fire scenario assumed the electrical failure caused an explosion and fire in the room. The inspectors noted several performance weaknesses during the drill:The fire brigade leader directed three fire brigade members into the fire hot zone to fight the fire as the attack team. Since there is a 5-member fire brigade, only two fire brigade members remain, one of which is the fire brigade leader (who also serves as the site incident commander (SIC)), to be part of the designated 2-out rescue team, required when fighting internal building fires. This 2-out rescue team is responsible, if necessary, for providing assistance or rescue for any or all of the attack team members. The inspectors were concerned that this fire brigade strategy could result in challenges with fire brigade leader command and control, and with the effectiveness of conducting rescues. The fire brigade leader could be hampered in his primary role of directing a site fire response while serving as a rescue team member. Adding to this complication, in locations where radios are not allowed inside some buildings with electrical sensitive equipment during firefighting, as was the case for this fire drill, it would be difficult for the fire brigade leader to communicate and coordinate with the control room or others during a rescue situation. Regarding the actual rescue activity, its effectiveness could be challenged since a two-person rescue team would be faced with potentially assisting/removing three attack members out of the hot zone. Based on discussions with licensee fire brigade training personnel following the drill, theinspectors learned that this 3-in, 2-out deployment was the current manner in which all internal building firefighting strategies and fire training was based upon.The fire brigade leader allowed the 3-man attack team to enter the fire hot zone with permission to commence firefighting prior to the 2-man rescue team arriving at the fire scenes pre-established incident command post and available for implementing rescue. The inspectors later learned that the rescue team, including the fire brigade leader, had arrived at the incident command post approximately five minutes after the attack team had entered the fire area. This delay involved the fire brigade leader completing his thermal protective clothing dressout in the locker room. The inspectors were concerned that under actual circumstances, if the 2-man rescue team were not ready and prepared to fulfill their rescue responsibilities upon entry of the attack team into the fire hot zone, the effectiveness of the rescue team could be challenged.The inspectors observed that no fire hose or other form of fire suppression was pulled or readily available for the 2-man rescue team to take with them should they have needed to enter the hot zone to rescue the attack team. When questioned about this, the inspectors were told that on the same fire hose that the attack team was using, a 1-1/2 inch gated wye valve had been connected, and the rescue team could have connected another 50-foot, 1-1/2 inch fire hose to it and used that hose as a rescue hose. However, the inspectors determined this was inadequate since to get to this hose connection, the rescue team would have to enter into the hot zone prior to reaching it. In addition, the inspectors learned that the use of this 1-1/2 inch gatedwye valve to create two hose streams for either attack or rescue that essentially splits the available flow capacity through a single 1-1/2 inch hose station nozzlewas allowed in multiple fire pre-plan strategies. At the conclusion of the inspection, the inspectors were continuing to assess whether the use of these gated wye valves had been formally reviewed by the licensee in the past to ensure that the flow capacity of fire hose streams would not be adversely impacted by their use during a fire.Planned Closure Actions: Pending completion of additional evaluations needed to determine whether the above fire brigade issues of concern represented performance deficiencies and if so, whether the performance deficiencies were of more than minor significance, this issue was identified as an unresolved item.Licensee Actions: The licensee initiated an NCR to address the inspectors concerns. In addition, until a more thorough review of their fire brigade program could be performed against their NFPA 805 fire program requirements, an operator standing instruction (#18-009, Fire Brigade 2-Out Response) was developed and implemented. This standing instruction directed the following specific fire brigade required actions:The brigade attack team will consist of two fire members to ensure the fire brigade SIC is not normally utilized as one of the 2-out members. If a runner is needed based on the fire area, the SIC may serve as a 2-out member, but this should be the exception.The 2-out members will establish a ready method of suppression that is accessible outside the fire zone. This should be the identified backup hose in the fire pre-plan. This hose does not need to be charged but should be flaked out and ready for use.The attack team will not enter the fire area, except when search and rescue is necessary, until the 2-out team is in the area with the suppression method ready for use.The inspectors determined that the licensees interim actions were adequate to ensure the fire brigade response would be effective if called upon pending resolution of the issues. Corrective Action Reference: NCR 02194468NRC Tracking Number: URI 05000400/2018001-01 |
| 05000400/FIN-2018002-01 | 2018Q2 | Harris | Failure to Promptly Identify and Correct a Condition Adverse to Quality For a Through-Wall Leak in the ESW Screen Wash Piping | An NRC-identified Green NCV of Title 10 Code of Federal Regulations (CFR) 50, Appendix B, Criterion XVI, Corrective Actions, was identified for the licensees failure to promptly identify and correct a condition adverse to quality involving through-wall leakage in the B train ESW screen wash piping. Specifically, on April 30, 2018, operators failed to initiate a work request or condition report after security personnel reported through-wall leakage in the B train ESW screen wash piping. No further follow-up or corrective actions were taken until May 3, 2018, when NRC inspectors identified the same through-wall piping leakage during a plant walkdown inspection and reported the degraded condition. |
| 05000400/FIN-2018002-02 | 2018Q2 | Harris | Inadequate Fire Brigade Performance Assessment of Announced Fire Drill | An NRC-identified Green NCV of 10 CFR 50.48(c) and National Fire Protection Association (NFPA) Standard 805, Section 3.4.3, Training and Drills, was identified for the licensees failure to adequately assess the fire brigade performance during an announced fire drill conducted March 21, 2018. Specifically, the inspectors identified several fire brigade performance deficiencies, improvement items, and lessons learned that were not identified and documented in the licensees corrective action program during the fire drill critique as required by the licensees fire drill administrative control procedure. |
| 05000400/FIN-2018002-03 | 2018Q2 | Harris | Failure to Adequately Document Changes to the Emergency Plan | The inspectors identified multiple examples of a Severity Level IV (SL-IV) NCV of 10 CFR 50.54(q)(3), for changes to the licensees radiological emergency plan (E-Plan) associated with protective action recommendation (PAR) procedures and emergency response equipment that failed to demonstrate that the changes would not reduce the effectiveness of the E-Plan. Specifically, the licensee did not provide an adequate analysis to demonstrate that the removal of the sheltering in-place PARs was not a reduction in effectiveness of the E-Plan. Additionally, the licensee did not perform an analysis demonstrating that the removal of a temporary diesel generator providing a backup source of power to the Technical Support Center (TSC) did not reduce the effectiveness of the E-Plan. |
| 05000400/FIN-2018002-04 | 2018Q2 | Harris | Failure to Implement Adequate Steam Generator Blowdown Demineralizer Control Procedures | A self-revealing Green NCV of Technical Specifications (TS) 6.8.1.a, Procedures and Programs, was identified for licensees failure to establish and implement adequate steam generator blowdown demineralizer control operating procedures resulting in exceeding secondary water chemistry Action Level 3 criteria for impurities in the steam generators. Specifically, the licensee did not implement adequate isolation valve controls between the demineralizer resin regeneration system and the feedwater system during resin regeneration activities. This open path allowed leakage of sulfates and chlorides into the feedwater system. The level of these impurities exceeded the secondary chemistry Action Level 3 threshold and resulted in an unplanned shutdown. |
| 05000400/FIN-2018002-05 | 2018Q2 | Harris | Failure to Follow Secondary Water Chemistry Plan for Elevated Levels of Secondary Water Impurities | An NRC-identified Green NCV of TS 6.8.4.c, Secondary Water Chemistry, was identified for the licensees failure to follow secondary water chemistry control requirements in accordance with procedure CSD-CP-HNP-0002, Harris Secondary Water Chemistry Strategic Plan. . Specifically, the licensee remained at 100% power for approximately 10 hours after entering secondary water chemistry Action Level 3 due to elevated chlorine and sulfates chemical impurity concentrations, which was contrary to the procedure requirements to downpower the unit to below 5% power as quickly as safe plant operation permits. This unit downpower delay allowed additional time for the chemical impurities to adversely affect the steam generators. |
| 05000400/FIN-2018002-06 | 2018Q2 | Harris | Failure to Implement Viable Compensatory Actions with Seismic Monitoring System Out of Service for Planned Preventive Maintenance | An NRC-identified Green NCV of 10 CFR 50.54(q)(2) was identified for the licensees failure to follow and maintain the effectiveness of its emergency plan that meets the requirements of the risk-significant emergency planning standard 10 CFR 50.47(b)(4). Specifically, the licensee failed to implement viable compensatory actions while conducting planned preventive maintenance that rendered both seismic monitoring systems unavailable for 53.5 hours resulting in a loss of emergency assessment capability for declaring a Notification of Unusual Event under Emergency Action Level (EAL) HU2.1 for a seismic event. |
| 05000400/FIN-2018002-07 | 2018Q2 | Harris | Minor Violation | A minor, self-revealing violation of TS 6.8.1.a, Procedures and Programs,was identified for failure to follow procedure AD-OP-ALL-0200, Clearance and Tagging. On April 7, 2018, while the plant was in Mode 3 at 0 percent power, the licensee isolated breaker DP-1A-1 circuit 28 in accordance with clearance OPS-1-18-5015-DEH MODS-0093. Isolating this breaker caused an unexpected auto start signal for both motor driven auxiliary feedwater (MDAFW) pumps for a loss of last running main feed pump despite the 1B main feedwater pump still being in operation. Both MDAFWs started and operators manually secured the 1B main feedwater pump to maintain proper feedwater flow to the steam generators. TS 6.8.1.a, requires, in part, that written procedures be implemented covering activities referenced in Regulatory Guide 1.33, Revision 2, dated February 1978, including safety-related activities carried out during operation of the reactor plant. Procedure AD-OP-ALL-0200, Section 5.5, step 4, states Clearance impacts must be evaluated to ensure that effects on systems and components outside of the boundary are identified and are acceptable, or properly dispositioned. Contrary to this requirement, the licensee did not identify that the isolation of breaker DP-1A-1 circuit 28 would cause the MDAFWs to auto start in Mode 3 when developing clearance OPS-1-18-5015-DEH MODS-0093. Screening: The violation is minor because the impact to the plant was minimal; the unit was in Mode 3 throughout the event, the reactor remained subcritical, and feedwater flow to the steam generators was not lost. Enforcement: Because the performance deficiency is minor, it will not be subject to enforcement action in accordance with the NRCs Enforcement Policy. The licensee entered this issue into their CAP as NCR 02196873. The associated LER is closed. |
| 05000400/FIN-2018003-01 | 2018Q3 | Harris | Failure to Implement Adequate Periodic Exercising of Turbine Trip Solenoid Operated Valves | A self-revealing Green finding was identified for the licensees failure to establish and implement adequate preventive maintenance (PM) for exercising the turbine electro-hydraulic auto-stop trip (AST) solenoid operated valves (SOVs) in accordance with procedure AD-EG-ALL-1202, Preventive Maintenance and Surveillance Testing Administration. As a result of the failure to exercise the SOVs at the weekly vendor recommended frequency, three of the four SOVs experienced mechanical binding (sticking) which rendered the turbine emergency trip system incapable of tripping the main turbine within the time response requirements of Technical Specifications. |
| 05000413/FIN-2011002-02 | 2011Q1 | Catawba | Follow-up for NOED 11-2-002 | An unresolved item (URI) was identified for NOED 11-2-002. The inspectors reviewed NOED 11-2-002 and related documents to determine the accuracy and consistency with the licensees assertions and implementation of the licensees compensatory measures and commitments which included deferring non-essential surveillances and other maintenance activities on the 1A DG, the turbine-driven AFW pump, the Standby Shutdown System and switchyard, and posting a dedicated operator available to throttle key AFW valves that supply flow to the steam generators. Additional inspection is required to conduct a review of the LER, root cause, and planned corrective actions. This URI is identified as URI 05000413/2011002-02, Follow-up for NOED 11-2-002. |
| 05000413/FIN-2011004-01 | 2011Q3 | Catawba | Failure to Adequately Implement Tagout Procedures | A self-revealing finding was identified for the licensees failure to adequately implement their administrative tagout procedure resulting in the isolation of main feedwater while Unit 1 was in Mode 4. The licensees corrective actions included revisions to operations administrative procedures and incorporation of lessons learned from the event into operator training. The performance deficiency was more than minor because it was associated with the Initiating Events cornerstone attribute of configuration control and adversely affected the cornerstone objective in that the isolation of main feedwater caused the CA system to autostart. The finding was determined to be of very low safety significance (Green) because no checklist criteria were met that required a phase 2 analysis and there was no loss of the decay heat removal safety function. The cause of this finding was related to the cross-cutting aspect of the need to keep personnel appraised of the operational impact of work activities as described in the Work Control component of the Human Performance cross-cutting area because the scope and plant impact of the tagout was not adequately understood by operations personnel responsible for implementation due to inadequate turnover and review (H.3(b)). |
| 05000413/FIN-2011004-02 | 2011Q3 | Catawba | Licensee-Identified Violation | TS 3.8.1 condition G.1 required that Unit 1 shall have restored operability to the 1B DG within 72 hours or be in Mode 3 within six additional hours. Contrary to the above, from 10:32 a.m., on February 26, 2011, until 2:54 p.m., on February 27, 2011, the licensee failed to comply with the required action of TS 3.8.1 condition G.1 to be in Mode 3. The inspectors determined that the violation was not greater than very low safety significance (Green) because the unavailability time incurred to perform the governor replacement did not exceed the TS allowed outage time of 72 hours. The issue is documented in the licensees corrective action program as PIP C-11- 1407. |