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05000316/FIN-2018003-01Cook2018Q3Misaligned Heater Level Column Valves Leads to Manual Reactor TripA self-revealed, Green finding was identified when the operators manually tripped the Unit 2 reactor in response to a hi-hi level in the Left Moisture Separator Drain Tank. On May 6, 2018, the Unit 2 reactor was at approximately 12 percent power following a startup at the conclusion of the spring 2018 refueling outage. While the station continued to make preparations to start the main turbine and synchronize with the grid, the moisture separator drain tank hi level alarm was received and remained standing for the better part of the shift. The drain tank collects condensed steam and water from the moisture separator reheater and associated high pressure turbine exhaust lines and routes it either to the condenser or #4 feedwater heaters. The day shift operators were hesitant to continue on with starting the main turbine until the cause of the alarm could be determined. Due to a series of miscommunications between day shift, night shift, the outage control center, and personnel performing troubleshooting, the night shift crew believed it was acceptable to continue with the turbine startup with the alarm still standing. The turbine was synchronized to the grid and power was stabilized at approximately 29 percent power with the alarm in for most of the turbine startup and synchronization. The alarm cleared for a period of time at 29 percent power, but then returned along with the hi-hi drain tank level alarm. Per the alarm response procedures, the operators tripped the reactor and main turbine to protect the turbine from excessive water in the system. Later investigation by the site revealed that the level columns for the #4 feedwater heaters had been left isolated following work and testing associated with the replacement of the #5 feedwater heaters. While the Operations Department had completed a valve lineup on the system per their startup procedures, which put the level columns in service, the Projects Department had not finished all of the work on the heaters at the time the lineup was performed. As a result, workers subsequently isolated the columns to complete testing after the Operations lineup was complete. A step in the Projects test procedure EC51366TP001 directed workers to specifically inform the operators that the level columns were isolated following testing and that the system was ready to be lined up per operations procedures. However, the workers did not provide that detail, and simply stated that the test was complete. As a result, operations did not know the valves had been taken out of alignment. Contributing to the issue, the outage schedule did not provide any logic ties to ensure all work was complete on the heaters before allowing operations to do their valve lineups. With the level columns isolated during startup, the #4 heaters indicated an erroneous level. This resulted in the operators believing that the heaters were at a normal operating level when in fact, they were full. Therefore, when the operators (per procedure) opened a high pressure turbine exhaust valve to the 4A heater, this created a pathway for water to flow from the #4 heaters, through the high pressure turbine exhaust lines, and into the moisture separator drain tank. The excessive flow of water caused the hi and hi-hi alarms in the drain tank which then led to the reactor/turbine trip.
05000400/FIN-2018003-01Harris2018Q3Failure to Implement Adequate Periodic Exercising of Turbine Trip Solenoid Operated ValvesA 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.
05000247/FIN-2018003-04Indian Point2018Q3Inadequate Procedure for Turbine Startup Caused a Reactor TripA 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.
05000331/FIN-2018002-01Duane Arnold2018Q2Inappropriate Procedural Guidance Resulted in Loss of Scram Function and Failure to Enter Technical Specification Limiting Condition for OperationThe inspectors identified a finding of very low safety significance (Green) and a non-cited violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure to have procedures appropriate to the circumstance for testing the main steam isolation valve (MSIV) and turbine stop valve (TSV) closure functions. Specifically, STP 3.3.1.117, MSIV Functional Test, and STP 3.3.1.119, Main Turbine Stop and Combined Intermediate Valves Test, directed the use of a reactor protection system test box which disabled the MSIV and the TSV closure automatic reactor scram functions while testing specific combinations of MSIVs and TSVs and failed to require entry into appropriate Technical Specification Limiting Condition for Operation action statements.
05000530/FIN-2017003-01Palo Verde2017Q3Failure to Initiate Corrective Actions for Thermography TestsThe inspectors reviewed a self-revealed, Green finding for the licensees failure to initiate corrective actions to address elevated temperature measurements identified during thermography inspections of the Unit 3 Phase C main transformer control cabinet. As a result, an extended loss of cooling to the Phase C main transformer resulted in a manual trip of the main turbine and a reactor power cutback. This issue was entered into the licensees corrective action program under Condition Report 17-09022, and the licensee took immediate actions to reinsert and tighten a loose wire associated with the transformer cooling control circuitry. The inspectors determined that the failure to follow procedure 37TI-9ZZ01, Thermography Inspection of Plant Components, Revision 8, Step 4.5.10.1 to initiate a condition notification report following the identification of elevated temperatures during thermography inspections is a performance deficiency. This performance deficiency is more than minor, and therefore a finding, because it was associated with the configuration control attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions duringshutdown as well as power operations. Specifically, the failure to initiate corrective actions following the identification of the hot spot on the Unit 3 Phase C main transformer 4-8 contactor resulted in a reactor power cutback that upset plant stability. Using NRC Manual Chapter 609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, Exhibit 1, Initiating Events Screening Questions, the finding screened as having very low safety significance (Green) because the deficiency resulted in a reactor trip, but mitigation equipment remained unaffected. The inspectors determined this finding had a cross-cutting aspect in the area of problem identification and resolution, identification, in that the licensee failed to identify issues completely, accurately, and in a timely manner in accordance with the corrective action program. Specifically, on three occasions in 2016 and 2017, the licensee collected data indicating potential loose connections at the 4-8 contactor, but failed to recognize and communicate the data in accordance with the corrective action program (P.1).
05000387/FIN-2017002-03Susquehanna2017Q2Follow -Up of Events and Notices of Enforcement DiscretionInspection Scope For the plant event listed below, the inspectors reviewed and/or observed plant parameters, reviewed personnel performance, and evaluated performance of mitigating systems. The inspectors communicated the plant events to appropriate regional personnel, and compared the event details with criteria contained in IMC 0309, Reactive Inspection Decision Basis for Reactors, for consideration of potential reactive inspection activities. As applicable, the inspectors verified that Susquehanna made appropriate emergency classification assessments and properly reported the event in accordance with 10 CFR Parts 50.72. The inspectors reviewed Susquehannas follow - up actions related to the events to assure that Susquehanna implemented appropriate corrective actions commensurate with their safety significance. Unit 1, reactor scram due to transient initiated by an inadvertent loss of main turbine electrohydraulic control system control power due to a maintenance error . b. Findings No findings were identified.
05000281/FIN-2016004-02Surry2016Q4Inadequate Design Change Post Maintenance Testing Causes Water Intrusion into Station Service Transformer and a Reactor TripA self-revealing finding was identified because the test requirements section of the station service transformer (SST) design change (DC) was not comprehensive in that it did not test that the isolated phase bus ducting terminal boxes were constructed to prevent water intrusion into the boxes. This was discovered during a significant rainfall event partially caused by Hurricane Matthew, which filled up the A SST terminal box with water and eventually shorted the A phase of the main generator causing a Unit 2 main generator, main turbine, and subsequent reactor trip on October 9, 2016. As corrective action, sealant was applied to the SST terminal boxes on all seams and bolt holes; and weep holes with drain assemblies were installed on each box. This issue was documented in the licensees CAP as CR 1049987. The inspectors reviewed Inspection Manual Chapter (IMC) 0612, Appendix B, Issue Screening, dated September 7, 2012, and determined the PD was more than minor because it was associated with the design control attribute of the Initiating Events Cornerstone, and it adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Using IMC 0609.04, Initial Characterization of Findings, Table 2, dated October 7, 2016, the finding was determined to affect the Initiating Events Cornerstone. The inspectors screened the finding using Manual Chapter 0609, Appendix A, SDP for Findings at-Power, dated June 19, 2012, and determined that it screened as Green because although the deficiency did cause a reactor trip, it did not cause a loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. This finding has a cross-cutting aspect in the Operating Experience aspect of the Problem Identification and Resolution area, P.5, because the licensee did not evaluate and implement relevant external operating experience.
05000461/FIN-2016003-02Clinton2016Q3Exceeded Technical Specification Allowed Outage Time for Main Turbine Bypass SystemThe inspectors identified a finding of very low safety significance and an associated NCV of Technical Specification 3.7.6, Main Turbine Bypass System, for the licensees failure to meet the limiting conditions for operation and complete the associated required actions after making a deficient change to the turbine bypass valve surveillance testing frequency. Specifically, with the main turbine bypass system inoperable and without the Core Operating Limits Report (COLR) limits for thermal power, minimum critical power ratio (MCPR), and linear heat generation rate (LGHR) with the main turbine by pass system inoperable applied, thermal power was not reduced to less than 21.6 percent of rated thermal power within six hours. The licensee entered this issue into their corrective action program as AR 02690657. The licensee restored compliance by applying the COLR limits for reactor thermal power, MCPR and LGHR. The inspectors determined the failure to meet the limiting conditions for operation and complete the associated required actions prior to the end of the specified completion times was a performance deficiency. The performance deficiency was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding was screened against the Mitigating Systems cornerstone and determined to be of very low safety significance because all of the associated questions in IMC 0609, Appendix A, were answered no. The inspectors determined this finding affected the cross-cutting area of human performance, in the aspect of change management, where leaders use a systematic process for evaluating and implementing change so that nuclear safety remains the overriding priority because the licensees change management process was not fully utilized by senior management when evaluating and implementing a change to the turbine bypass valve surveillance testing frequency. (H.3)
05000346/FIN-2016003-03Davis Besse2016Q3Licensee-Identified Violation

Plant TS 3.3.16, Anticipatory Reactor Trip System (ARTS) Instrumentation, requires that three ARTS channels for the main turbine trip function be maintained operable with the unit operating in Mode 1 above 45 percent power, and three ARTS channels for the SFRCS / main feed pump trip function be maintained operable with the unit operating in Mode 1 at any power. While this TS provides actions and allowed outage time for a single inoperable ARTS channel, there are no provisions for more than a single ARTS channel being simultaneously inoperable. The provisions of TS Limiting Condition for Operation 3.0.3, therefore, apply when more than one ARTS channel is inoperable at the same time, and require that actions be initiated within 1 hour from the onset of the condition to 

Be in Mode 3 within 7 hours
Be in Mode 4 within 13 hours; an
Be in Mode 5 within 37 hours

As discussed in Section 4OA3.5 of this report, contrary to the requirements of TS 3.3.16, all four ARTS channels were bypassed and inoperable for both the main turbine and SFRCS functions for a period of approximately 15 hours on May 910, 2016. The objective of the Mitigating Systems Cornerstone of Reactor Safety is to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Key attribute associated with this objective are human performance and configuration control. In accordance with NRC IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, the inspectors determined that the violation was of more than minor significance in that it had a direct impact on this cornerstone objective. Specifically, plant operators in failing to adequately implement applicable operating procedures allowed the unit to enter into a mode of operation with less that the required three channels of ARTS operable and available. Using Exhibit 2 Mitigating Systems Screening Questions, the inspectors determined that a detailed risk analysis by the NRC Region III SRA was required since the issue involved the inoperability of more than one channel of ARTS, a condition for which there is no allowed outage time specified in TS 3.3.16. The SRA used the Davis-Besse SPAR Model, Version 8.19, and SAPHIRE, Version 8.1.4, for the calculation of the change in CDF for the issue. The following assumptions were made in the analysis: 

The exposure time for the issue was conservatively assumed to be 15 hours

from 3:24 p.m. on May 9, 2016, when the unit entered Mode 1 and the TS 3.3.1 for the ARTS became applicable to 5:52 a.m. on May 10, 2016, when the ART bypass switches were returned to the normal/enabled state; an 

With the ARTS SFRCS function bypassed, the SFRCS input to the ARTS t

provide a reactor trip signal was bypassed. Since the ARTS is not modeled i the SPAR model, it was very conservatively assumed that the RPS automati trips were bypassed during the 15hour exposure time, and only a manua reactor trip was available The result was a change in CDF of 7.6E7 events per year. The dominant core damage sequence was a transient initiating event with a failure of plant operators to manually trip the reactor, along with a failure of plant operators to initiate emergency RCS boration. Based on the detailed risk evaluation, the inspectors determined that the violation was of very low safety-significance (Green). As discussed in Section 4OA3.5 of this report, the licensee had entered this issue into their CAP as CR 201606563. In addition to the commissioning of a formal root cause evaluation, licensee corrective actions included the issuance of an operations standing order to require periodic walk downs of all control room panels by on-watch control room operators in pairs to ensure a comprehensive understanding of plant status awarenes and enhancements to applicable operating procedures.

05000423/FIN-2016008-04Millstone2016Q3Licensee-Identified ViolationLER 05000423/2014-002-00 (Unit 3) describes an unanalyzed condition in which Dominion identified DC motor control circuits were unfused. Specifically, Dominion did not provide overcurrent protection for wiring associated with 125 V DC control circuits for non-safety related main turbine emergency lube oil and main generator emergency seal oil pumps to prevent wires from overheating due to fire induced faults and excessive currents flowing through the cable. With enough current flowing through the cable, the potential existed that the overloaded motor control wiring could damage adjacent control circuit wiring for components which are needed to achieve and maintain post-fire safe shutdown for a fire in several fire areas (turbine battery switchgear area, cable spreading room, instrument rack room, control room). This condition could result in a loss of the associated safe shutdown components or a secondary fire in another fire area. The failure to protect safe shutdown cables from the effect of postulated fires was a performance deficiency. This performance deficiency was a violation of Millstone Power Station, Unit 3, Renewed Facility Operating License Condition 2.H, which requires, in part, post-fire safe shutdown cables remain free of the effects of fire induced cable faults during postulated fires. Contrary to the above, Dominion identified they failed to meet this requirement and the condition existed since initial construction. The issue was more than minor because it was associated with the protection against external events (fire) attribute 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. The team determined that the finding was of very low safety significance (Green), based on IMC 0609, Appendix F, Fire Protection Significance Determination Process, Phase 2 screening criteria. The finding screened to Green based upon, task number 2.3.5, because the affected cables were routed in alternate shutdown fire areas that are continually manned or protected by detection and automatic suppression systems. Remaining fire areas are protected by detection systems, automatic suppression systems or rely on manual firefighting activities. Additionally, the cable construction is IEEE 383 (thermoset) which decreases the likelihood of inter-cable and intra-cable interactions. Based on a team walkdown, the team determined that the main turbine emergency lube oil and main generator emergency seal oil pump cable routing was not routed near a credible fire ignition source in the affected fire areas. Because this finding is of very low safety significance and had been entered into Dominions corrective action program (CR541983), this violation is being treated as a Green, licensee-identified NCV consistent with the NRCs Enforcement Policy.
05000336/FIN-2016008-03Millstone2016Q3Licensee-Identified ViolationLER 05000336/2014-002-00 (Unit 2) describes an unanalyzed condition in which Dominion identified DC motor control circuits were unfused. Specifically, Dominion did not provide overcurrent protection for wiring associated with 125 V DC control circuits for a non-safety related main turbine emergency lube oil pump to prevent wires from overheating due to fire induced faults and excessive currents flowing through the cable. With enough current flowing through the cable, the potential existed that the overloaded motor control wiring could damage adjacent control circuit wiring for components which are needed to achieve and maintain post-fire safe shutdown for a fire in several fire areas (turbine battery room, cable vault, plant equipment operator meeting area, control room). This condition could result in a loss of the associated safe shutdown components or a secondary fire in another fire area. The failure to protect safe shutdown cables from the effect of postulated fires was a performance deficiency. This performance deficiency was a violation of Millstone Power Station, Unit 2, Renewed Facility Operating License Condition 2.C.(3), which requires, in part, post-fire safe shutdown cables remain free of the effects of fire induced cable faults during postulated fires. Contrary to the above, Dominion identified they failed to meet this requirement and the condition existed since initial construction. The issue was more than minor because it was associated with the protection against external events (fire) attribute 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. The team determined that the finding was of very low safety significance (Green), based on IMC 0609, Appendix F, Fire Protection Significance Determination Process, Phase 2 screening criteria. The finding screened to Green based upon, task number 2.3.5, because the affected cables were routed in alternate shutdown fire areas that are continually manned or protected by detection and automatic suppression systems. Remaining fire areas are protected by detection systems, automatic suppression systems or rely on manual firefighting activities. Additionally, the cable construction is IEEE 383 (thermoset) which decreases the likelihood of inter-cable and intra-cable interactions. Based on a team walkdown, the team determined that the main turbine emergency lube oil pump cable routing was not routed near a credible fire ignition source in the affected fire areas. Because this finding is of very low safety significance and had been entered into Dominions corrective action program (CR541980), this violation is being treated as a Green, licensee-identified NCV consistent with the NRCs Enforcement Policy.
05000334/FIN-2016002-03Beaver Valley2016Q2Failure to Appropriately Utilize Multiple and Diverse Indications Results in Plant TransientA self-revealing finding of NOP-OP-1002, Conduct of Operations, was identified for FENOCs failure to adequately implement operator fundamentals. Specifically, operators did not appropriately utilize multiple and diverse indications when making the decision to isolate electro-hydraulic control (EHC) to a Unit 1 main turbine governor valve. This resulted in an unanticipated reactor power reduction of 2.7 percent. FENOCs immediate corrective actions included re-opening the governor valve, verifying proper system response, and entering this issue into their corrective action program (CAP) as CR 2015-08263. The performance deficiency is more-than-minor because if left uncorrected, the performance deficiency had the potential to lead to a more significant safety concern. Additionally, example 4.b from IMC 0612 Appendix E details that a performance deficiency is more-than minor if it causes a reactor trip or other transient. This finding was determined to be of very low safety significance (Green) since it did not cause both a reactor trip and the loss of mitigation equipment relied upon to transition the plant to a stable shutdown condition. This finding has a cross-cutting aspect in Human Performance, Challenge the Unknown, because individuals did not consult the system expert when confronted with an unexpected condition (H.11).
05000311/FIN-2016002-03Salem2016Q2Inadequate Work Order Planning Results in Main Generator AVR STV Relay TripA Green, self-revealing finding (FIN) was identified against MA-AA-716-010, Maintenance Planning Process, Revision 18, when PSEG work orders (WOs) did not specify the appropriate procedure to perform satisfactory modification testing of the main generator automatic voltage regulator (AVR) protective relay (model STV1). Consequently, the relay actuated below its design setpoint on February 4, 2016, resulting in an automatic trip of the Unit 2 main turbine and reactor. PSEG entered the issue in their Corrective Action Program (CAP) and performed a root cause evaluation (RCE), replaced the failed STV1 relay with a properly tested relay, verified other STV relays were appropriately tested as an extent of condition, and initiated an action to revise Laboratory Testing Services (LTS) department relay test procedures to ensure all applicable acceptance criteria will be incorporated. The inspectors determined that a performance deficiency existed because PSEG WOs did not specify the appropriate procedure to perform satisfactory modification testing of the main generator AVR protection relay. This issue was more than minor since it was associated with the procedure quality attribute of the Initiating Events cornerstone and adversely impacted its objective to limit the likelihood of events that upset plant stability (turbine and reactor trip) and challenge critical safety functions. Using IMC 0609, Attachment 4 and Appendix A, Exhibit 1, the inspectors determined that this finding was of very low safety significance, or Green, since mitigating equipment relied up to transition the plant to stable shutdown remained available. The finding had a cross-cutting aspect in the area of Human Performance, Work Management, in that the PSEG did not adequately implement the work process to coordinate with engineering and maintenance departments as needed to appropriately plan the STV1 relay modification test WO.
05000353/FIN-2016001-05Limerick2016Q1Main Turbine Digital Electrohydraulic Control System Modification Failed to Revise the Plant Startup ProcedureA self-revealing Green NCV of LGS Unit 2 technical specification 6.8.1 was identified because Exelon failed to maintain a plant startup procedure. Specifically, the implementing procedure for normal plant startup from hot shutdown or cold shutdown to rated power was not maintained when a modification to the Unit 2 turbine electrohydraulic control system was performed and required changes to the plant startup procedure were not identified and implemented. Exelon initiated issue report (IR) 2602637, revised the startup procedure to properly incorporate the software changes made at the factory acceptance test, validated the software changes that were made were technically correct, trained all operators on the new procedural changes, and reviewed operating procedures for extent of condition. This finding is more than minor because it is associated with the procedure quality attribute of the initiating events cornerstone and affected the objective to limit the likelihood of events that upset plant stability during power operations. Specifically, the procedure directed actions intended in the software for rapid reactor depressurization that resulted in a reactor trip. Using IMC 0609, Significance Determination Process, Appendix A, Exhibit 1, Initiating Events Screening Questions, the inspectors determined that this finding was of very low safety significance (Green) because the finding did not cause both a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. Specifically, although the finding caused a Level 8 trip of the feedwater pumps followed by a reactor trip, the rate of water injection from the condensate pumps was sufficient when the reactor was tripped to safely shutdown and operators were able to reset the feedwater pumps. The inspectors determined that this finding has a cross-cutting in the area of Human Performance, Change Management, because leaders did not use a systematic process for implementing the modification so that nuclear safety remained the overriding priority.
05000370/FIN-2015004-01Mcguire2015Q4Failure to Report Unit 2 Unplanned Valid Auxiliary Feedwater Actuation in Mode 4An NRC identified Severity Level (SL) IV non-cited violation (NCV) of 10 CFR 50.72(b)(3)(iv)(A) was identified for the licensees failure to make a required NRC event notification within eight hours for an unplanned valid actuation of the auxiliary feedwater (CA) system. The unplanned valid actuation occurred during main turbine and main feedwater pump safety injection (SI) train trip function testing with Unit 2 in Mode 4 on October 7, 2015. The licensee entered this issue into their corrective action program and subsequently reported this CA actuation to the NRC on October 15, 2015. The failure to submit an event notification to the NRC within eight hours of occurrence of an unplanned valid CA system actuation in accordance with 10 CFR 50.72(b)(3)(iv)(A) was a performance deficiency (PD). Since the failure to submit an event report within the time requirements may impact the ability of the NRC to perform its regulatory oversight function, this PD was dispositioned under the traditional enforcement process and was determined to be a SL IV violation. Because this SL IV violation was not repetitive or willful, and did not have an underlying technical violation that would be considered more-than-minor, a cross-cutting aspect was not assigned to this violation.
05000281/FIN-2015004-04Surry2015Q4Inadequate Procedure Causes Main Turbine and Reactor TripA self-revealing Green NCV of Surry TS 6.4.A.7 was identified because Unit 2 tripped during performance of 2-OP-TM-001, Turbine Generator Startup to 20% - 25% Turbine Power, on July 21, 2015. An inadequate procedure allowed the main turbine (MT) governor valves to open rapidly during MT overspeed protection controller (OPC) testing, increasing MT first stage pressure above the P-2 and P-7 reactor protection system (RPS) permissive step points, and subsequently causing a reactor trip. Specifically, 2-OP-TM-001 did not have the minimum level of information needed to ensure that there was no speed error between MT speed and the setter position before initiating the OPC test. This allowed the test to be conducted with a speed error that caused the governor valves to open rapidly at the end of the test and subsequently cause a reactor trip. This issue was documented in the licensees CAP as CR 1003328. The inspectors concluded that the failure of the licensee to have the minimum level of information needed to ensure task critical actions in 2-OP-TM-001 and for operators to avoid error traps in conducting the MT OPC test, as required by Dominion procedure SPAP-0504, was a PD. Using IMC 0612, Appendix B, Issue Screening, dated September 7, 2012, the inspectors determined that the performance deficiency was more than minor because it was associated with the procedural quality attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset stability and challenge critical safety functions during shutdown as well as power operations. Using IMC 0609.04, Initial Characterization of Findings, Table 2, dated June 19, 2012; the finding was determined to affect the Initiating Events Cornerstone. The inspectors screened the finding using IMC 0609, Appendix A, SDP for Findings at-Power, dated June 19, 2012, and determined that it screened as Green because the deficiency did not involve the complete or partial loss of a support system that contributes to the likelihood, or cause, an initiating event and affected mitigation equipment. This finding has a cross-cutting aspect in the documentation aspect of the human performance area, H.7, because the licensee did not create a complete procedure for testing the MT overspeed protection.
05000293/FIN-2015010-01Pilgrim2015Q3Inadequate Procedures for Placing Main Turbine in ServiceThe inspectors identified a self-revealing Green non-cited violation of Technical Specification 5.4.1, Procedures, because Entergy did not provide adequate procedures in that appropriate operator actions to recover systems and components important to safety were not included within operating procedures 2.1.1, Startup from Shutdown, and 2.2.93, Main Condenser Vacuum System, as well as abnormal operating procedure 2.4.36, Decreasing Condenser Vacuum. Corrective actions include, in part, for Entergy engineers to establish operational limits for the offgas system, to include the factors of reactor power, air in-leakage, sea water system alignment, status of the augmented offgas system, status of the main turbine, and sea water inlet temperature, and to incorporate these limitations into site procedures. Entergy entered this issue into their corrective action program as condition report CR-PNP-2015-5197. This finding was more than minor because it was 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 as well as power operations. Additionally, this performance deficiency is similar to example 4.b in IMC 0612, Appendix E, Examples of Minor Issues, in that it contributed to a reactor trip. The inspectors evaluated the finding using IMC 0609, Appendix A, Exhibit 1, Initiating Events Screening Questions. The inspectors determined this finding was of very low safety significance (Green) because it did not cause a loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. This finding had a cross-cutting aspect in the area of Human Performance, Design Margins, because Entergy did not operate equipment within design margins. Specifically, Entergy staffs lack of awareness of the limitations of offgas system during startup and while placing the main turbine in service resulted in operators establishing conditions that were outside those limitations.
05000400/FIN-2015003-03Harris2015Q3Failure to Implement Adequate Corrective ActionsA self-revealing green finding was identified for failure to implement adequate corrective actions for the repeated failure of PS-4175, low pressure steam inlet crossover pressure switch in accordance with licensee procedure AD-PI-ALL-0100, Corrective Action Program. Specifically, on multiple occasions the licensee failed to install a pressure switch rated for design conditions on the Main Turbine which led to an unplanned reactivity addition, when PS-4175 failed open. The licensee entered this into their corrective action program (CAP) as action request (AR) 755621 and took immediate actions to reduce power to less than 100 percent. Reactor power reached a maximum value of 100.5 percent. Failure to implement adequate corrective action for the repeated failure of pressure switch PS- 4175 in accordance with licensee procedure AD-PI-ALL-0100 was a performance deficiency. The performance deficiency was determined to be more than minor because if left uncorrected the performance deficiency had the potential to lead to a more significant safety concern. Specifically, if not for the manual actions taken by the operators to insert control rods, the reactivity addition would have continued and would have ultimately resulted in a reactor trip on high neutron flux. Using IMC 0609, Significance Determination Process Attachment 4, Initial Characterization of Findings, and Appendix A, The SDP for Findings At-Power, (June 19, 2012), the inspectors determined the finding was a contributor as a Transient Initiator to the Initiating Events cornerstone. The inspectors determined the finding was of very low safety significance (Green) because it did not result in a reactor trip and it did not cause the loss of any mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. The inspectors concluded the finding was associated with the design margins aspect (H.6) of the human performance cross-cutting area since the licensee repeatedly failed to install a pressure switch adequate for the operating conditions.
05000346/FIN-2015003-01Davis Besse2015Q3Flow Accelerated Corrosion Model Not Maintained In Accordance with Industry Standards and GuidanceA self-revealed finding of very low safety significance was identified for the licensees failure to maintain an adequate flow accelerated corrosion (FAC) program in accordance with station procedures and applicable industry guidance. Specifically, an incorrect restriction orifice size entered into the FAC program software in the late 1980s significantly underestimated the wear rate of a section of moisture separator reheater (MSR) piping that ultimately failed causing control room operators to conduct a rapid power reduction and manual reactor trip and declare an unusual event in accordance with the station's emergency plan. The failed section of piping had not been previously inspected in accordance with industry guidance and station procedures, and the incorrect FAC program software inputs had never been validated. This finding was associated with the Initiating Events Cornerstone of reactor safety and was of more than minor significance because it directly impacted 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. The inspectors evaluated the finding using IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power. Using Exhibit 1, which contains the screening questions for the Initiating Events Cornerstone of Reactor Safety, the inspectors determined a detailed risk evaluation was required because the finding was a transient initiator that resulted in both a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition (i.e., the loss of the main condenser as a heat sink and the loss of main feedwater). The inspectors contacted the NRC Region III Senior Reactor Analyst (SRA) to perform a detailed risk evaluation. The assumed core damage sequence used by the SRA was that the MSR pipe break occurs, followed by either main steam isolation valve (MSIV) failing to close, followed by any of four in-series main turbine stop valves (SVs) and control valves (CVs) failing to close. Mathematically, the change in core damage frequency (CDF) was estimated at: CDF = 1 (event occurs) x (9.51E-4 + 9.51E-4) x 4 x 1.5E-3 x 1.5E-3 = 1.71E-8/yr The SRA concluded the risk associated with this performance deficiency was, therefore, of very low safety significance (Green). Because the causes for the finding stemmed from deficiencies going back several years or more, the inspectors concluded that the finding represented a latent issue not necessarily indicative of present licensee performance. As a result, no cross cutting aspect was assigned to this finding.
05000483/FIN-2015003-01Callaway2015Q3Failure to Conduct Simulator Testing and Maintenance In Accordance with ANSI/ANS-3.5-2009The inspectors identified a finding with four examples for failing to conduct and evaluate simulator performance testing in accordance with the standards of ANSI/ANS-3.5-2009. Specifically, the licensee failed to do the following: set the instantaneous main turbine load reduction to 50 percent as supported by design basis data in the 2014 performance of Transient (11), Maximum Design Load Rejection include the evaluation of parameter pressurizer temperature in the 30 percent, 50 percent, and 80 percent power Steady-State Performance Test as specified in accordance with the standard, Appendix B, Section B.3.1 include the evaluation of parameter secondary heat balance data in the 30 percent, 50 percent, and 80 percent power Steady-State Performance Test as specified in accordance with the standard, Appendix B, Section B.3.1 replicate the dynamic functioning of annunciators on the simulator panels used during normal, abnormal, off-normal, and emergency evolutions, or to identify and correct noticeable differences in accordance with the standard, Sections 4.2.1.2 and 4.2.1.4 The licensee initiated corrective action documented in Callaway Action Requests 201504760, 201504759, 201504418, and 201504355. The licensees failure to conduct and evaluate performance testing in accordance with the ANSI/ANS-3.5-2009 standard as endorsed by Regulatory Guide 1.149, Revision 4, was the performance deficiency. The performance deficiency is more than minor because it adversely impacted the human performance attribute of the Mitigating Systems Cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Additionally, if left uncorrected, the performance deficiency could have become more significant in that not correcting noticeable differences between the simulator and the reference plant can both leave the potential for negative training of licensed operators and call into question the ability to conduct valid licensing examinations with the simulator. Using Manual Chapter 0609, Significance Determination Process, Attachment 4, Tables 1, 2, and 3 worksheets; and the corresponding Appendix I, Licensed Operator Requalification Significance Determination Process (SDP), Flowchart Block #14, the finding was determined to have very low safety significance (Green) because it dealt with deficiencies associated with simulator testing, modification, and maintenance and there was no evidence that the plant-referenced simulator does not demonstrate the expected plant response or have uncorrected modeling and hardware deficiencies related to the examples. The examples supporting this finding involved actions taken with the simulator testing and maintenance program before the present performance period. Therefore, no cross-cutting aspect is assigned to the finding.
05000388/FIN-2015002-05Susquehanna2015Q2Loss of Main Condenser Vacuum When Transitioning Steam Seals to Auxiliary SteamA self-revealing finding of very low safety significance (Green) and associated NCV of SSES Unit 2 TS 5.4.1, Procedures, was identified because Susquehanna incorrectly implemented procedures for operation of the auxiliary steam and main turbine steam sealing systems. Specifically, on April 10, 2015, while Unit 2 was being shut down for a RFO, operators secured main turbine steam seals resulting in degraded main condenser vacuum. The degraded main condenser vacuum resulted in a main turbine trip, which caused an automatic reactor scram from approximately 37% power. Susquehanna restored main condenser vacuum by reestablishing steam seals, performed off-normal and emergency operating procedures to stabilize the plant post-scram and entered the issue into the corrective action program (CAP) as CR-2015-09890. The finding was more than minor because it was associated with the Human Performance attribute of the Initiating Events cornerstone and affected its objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, not understanding the impact of securing auxiliary steam to the main turbine steam seals resulted in the degradation of main condenser vacuum, automatic trip of the main turbine and associated reactor scram. The inspectors evaluated the finding in accordance with IMC 0609, Appendix A "The SDP for Findings At-Power," Exhibit 1, for the Initiating Events cornerstone, dated June 19, 2012. The inspectors determined the finding was of very low safety significance (Green) because it did not cause a reactor trip and the loss of mitigation equipment. Specifically, though a reactor scram occurred, operators were able to restore main condenser vacuum prior to MSIV closure and the main condenser and reactor feed pumps remained functional during the event. This finding has a cross-cutting aspect in the area of Human Performance, Avoid Complacency, because Susquehanna did not implement appropriate error reduction tools. Specifically, operators did not effectively implement human error prevention tools (e.g. pre-job briefing, stop-think-act-review) in accordance with station processes.
05000282/FIN-2015002-05Prairie Island2015Q2Licensee-Identified ViolationTitle 10 CFR Part 50, Appendix R, requires, in part, that safe shutdown equipment and systems for each fire area shall be known to be isolated from associated non-safety circuits in the fire area so that hot shorts, open circuits, or shorts to ground in the circuit will not prevent operation of the safe shutdown equipment. The isolation of these associated circuits from the safe shutdown equipment shall be such that a postulated fire involving the associated circuits will not prevent safe shutdown. On August 8, 2014, the licensee identified an Appendix R non-compliance in that the emergency bearing oil pumps were not properly isolated (fuse protected) from safe shutdown equipment, in accordance with 10 CFR Part 50, Appendix R. As a result, an overload condition in the emergency bearing oil pump circuitry could result in a fire that damages other cabling and prevents the licensee from achieving safe shutdown following a fire. The inspectors reviewed this issue and determined that the improper fuse protection was part of the initial plant design. Specifically, the design philosophy in the late 1960s was to maximize the reliability and availability of the emergency bearing oil pumps to protect the main turbines. The potential impact that this design philosophy had on fire protection of safe shutdown equipment was also not recognized as 10 CFR 50, Appendix R, did not exist until the early 1980s. The licensee documented this issue in CAP 1442220. The licensee also implemented hourly fire watches in the impacted fire areas to ensure that any potential fires were identified prior to it impacting safe shutdown capability. Section 9.1 of the NRC Enforcement Policy allows the NRC to exercise enforcement discretion for certain fire protection related non-compliances identified as a result of a licensees transition to the new risk-informed, performance-based fire protection approach included in 10 CFR 50.48(c) and for certain existing non-compliances that reasonably may be resolved by compliance with 10 CFR 50.48(c) as long as certain criteria are met. This risk-informed, performance-based approach is referred to as NFPA 805, Performance-Based Standard for Fire Protection for Light Water Reactor Electric Generating Plants. In 2005, the licensee submitted a letter of intent to transition to 10 CFR 50.48(c). This licensee submitted a license amendment request to the NRC for review and approval in September 2012. The inspectors reviewed the remaining criteria included in Section 9.1 of the NRC Enforcement Policy and concluded that the licensee had met the criteria. Specifically, the licensee entered the noncompliance into the CAP as CAP 1442220, implemented compensatory fire watches in the area and the noncompliance was not willful. In addition, this issue would not have been identified under normal surveillance or quality assurance activities. Lastly, a regional SRA reviewed an analysis performed by the licensee to show that the risk of the condition was less than high safety significance (i.e., less than red). The licensee identified the cable routing for the six cables of concern (three for each unit) and the fire scenarios where an initial fire could cause a secondary fire in a separate fire area due to the inadequate fusing of the emergency bearing oil pumps. The licensees evaluation assumed that a secondary fire would be limited to the cable tray that contained the faulted cable and would not propagate beyond that tray. The licensee cited NFPA 805 FAQ13005, Close-out of Fire Probabilistic Risk Assessment Frequently Asked Question 13005 on Cable Fires Special Cases: Self-Ignited and Caused by Welding and Cutting, that provided similar guidance for self-ignited cable fires as the basis for the assumption. The SRA consulted with NRC Headquarters staff and concluded that the FAQ guidance did not specifically apply to cable fires resulting from inadequate fusing. However, there currently is no available method for estimating the likelihood and extent of a secondary cable fire caused by inadequate fusing. Given the lack of an acceptable method, the SRA also performed a walk down of the control cable routing to observe the potential for secondary fires to impact additional targets. In all cases, there did not appear to be a significant potential for a secondary fire to damage additional targets beyond the cable tray of interest. The licensee provided other reasons why secondary fire damage would be limited, such as existing fire detection and suppression systems and the fact that the cables are thermoset rather than thermoplastic material. The SRA determined that the likelihood of significant secondary fire spread for these particular scenarios was low. The licensee also determined that some scenarios did not impact any unique targets. For those scenarios, there was no change in risk due to the inadequate fusing. For scenarios that did have the potential for additional target damage from a secondary fire, the licensee calculated the change in risk of this condition. The change in risk was determined to be less than 1E4/yr. The dominant fire scenarios involved a fire starting in the fire area 18 with a secondary fire propagating to either Fire Area 58, 31, or 32. Because each of the criteria listed in Section 9.1 of the NRC Enforcement Policy was met, the NRC concluded that enforcement discretion should be granted for this issue. No enforcement action will be documented unless the licensee fails to address this non-compliance after completing their transition activities.
05000285/FIN-2015001-01Fort Calhoun2015Q1Failure to Conduct and Evaluate Simulator Testing In Accordance with ANSI/ANS-3.5-2009The inspectors identified a Green finding with four examples for failing to conduct and evaluate simulator performance testing in accordance with the standards of ANSI/ANS-3.5- 2009. Specifically, the licensee failed to do the following: - Set initial reactor power at 15 percent in accordance with plant design for all performances between 1990 and 2014 of Transient (6), "Main Turbine Trip from Maximum Power Level That Does Not Result in Immediate Reactor Trip" - Set the instantaneous main turbine load reduction to 1 0 percent as supported by design basis data in the 2014 performance of Transient (11), "Maximum Design Load Rejection" - Evaluate the results of the 100 percent power Steady-State Performance Test using the correct acceptance criteria in accordance with the standard, Appendix 8, Section 8.1.1 - Evaluate all transient test results versus acceptance criteria 4.1.4(1) in accordance with the standard, Appendix 8, Section 8.1.2 After NRC identification of the transient test issues, licensee evaluation revealed that the initial conditions for Transients (5) and (1 0) were in error as well. The licensee initiated corrective action documented in condition reports 2014-14190, 2014-14208, and 2015-02547. The licensee's failure to conduct and evaluate performance testing in accordance with the ANSI/ANS-3.5-2009 standard as endorsed by Regulatory Guide 1.149, Revision 4, was the performance deficiency. Per licensee Procedure TQ-AA-306, "Simulator Management," the licensee uses ANSI/ANS-3.5-2009 as the standard for their simulator testing. The performance deficiency is more than minor because if left uncorrected, the performance deficiency could have become more significant in that not completing the required simulator testing correctly can lead to not detecting and correcting errors in the simulator so it actually models the plant correctly. This can both leave the potential for negative training of licensed operators and call into question the ability to conduct valid licensing examinations with the simulator. Using Inspection Manual Chapter (IMC) 0609, "Significance Determination Process," Attachment 4, Tables 1 and 2 worksheets, and the corresponding Appendix I, "Licensed Operator Requalification Significance Determination Process (SOP)," Flowchart Block No.14, the finding was determined to have very low safety significance (Green) because it dealt with deficiencies associated with simulator testing, modification, and maintenance and there was no evidence that the plant-referenced simulator does not demonstrate the expected plant response or have uncorrected modeling and hardware deficiencies. This finding has a cross-cutting aspect in the change management area of human performance, associated with leaders using a systematic process for evaluating and implementing change so that nuclear safety remains their overriding priority. There were efforts on-site to change to the 2009 version of the standard as early as 2011, but the efforts were rescinded by plant management in December 2011 for unknown reasons. When they officially switched from the 1985 to the 2009 version of the standard (on March 1, 20 13), there is no evidence an effective change management plan was implemented. Efforts to transition between the testing and maintenance requirement differences were complicated by lack of allocating necessary resources to support this effort. There was minimal simulator staffing during the extended plant outage (April2011 to December 2013), and no effective plan to deal with knowledge management to compensate for simulator employee turnover. Internal audits in May 2014 and October 2014 found numerous issues with their simulator testing and configuration management program, many of which could have been averted or addressed earlier with an effective transition plan in place (H.3).
05000374/FIN-2015001-03LaSalle2015Q1COLR Revision Potentially Created Non-Conservative Technical SpecificatAs part of the overall review of the Unit 2 Jet Pump Plug issue (described in greater detail in Section 4OA2.4 of this report), the inspectors reviewed the changes made to the Unit 2 COLR, Cycle 16, Revisions 1 and 2. The inspectors assessed the changes with respect to their potential impact on the current licensing basis, i.e., TSs and regulations such as 10 CFR 50.36. In Revision 1 of LaSalles Unit 2 Cycle 16 COLR, the licensee introduced a new section in the form of an Appendix, entitled Operating Limits for Lost Jet Pump Plug Seals Mitigation Strategy. This appendix states The following limits apply while the jet pump plug peripheral bundle blocked orifice condition exists. Specifically, item 4 entitled Other Requirements, states in part that All equipment must be in-service. This includes the EOOS (equipment out-of-service) assumed in the Base Case mentioned in Footnote 1 of COLR Section 10 EXCEPT LPRMs (local power range monitors) and TIPOOS (traversing in-core probe out-of-service) (...) In the event of an EOOS, take action in accordance with TS 3.2.2 ACTION statements. Those TS actions were to Reduce THERMAL POWER to < 25% RTP (rated thermal power) within a 4-hour completion time. The equipment referenced in the COLR Section 10 Base Case that have associated TS LCOs are safety relief valves (SRVs) (LCOs 3.4.4 and 3.5.1) and turbine bypass valves (TBVs) (LCO 3.7.7). LCO 3.4.4 states The safety function of 12 SRVs shall be OPERABLE. Unit 2 has a total of 13 SRVs, so this LCO essentially allows one SRV to be OOS indefinitely with no further action required; however, since the COLR created a new operational restriction to prohibit any SRVs from being OOS in order to maintain the unit in an analyzed condition, the inspectors questioned the apparent non-conservatism that the COLR created for LCO 3.4.4. Specifically, under an identical condition of 1 SRV OOS, the COLR would have required the unit to downpower to less than 25 percent power, while the TSs would have allowed continuous operation at full power. LCO 3.5.1 states (...) the Automatic Depressurization System (ADS) function of six safety/relief valves shall be OPERABLE. Unit 2 has a total of 7 ADS SRVs, so this LCO essentially allows one ADS SRV to be OOS indefinitely with no further action required; however, since the COLR created a new operational restriction to prohibit any SRVs from being OOS in order to maintain the unit in an analyzed condition, the inspectors questioned the apparent non-conservatism that the COLR created for LCO 3.5.1. Specifically, under an identical condition of 1 ADS SRV OOS, the COLR would have required the unit to downpower to less than 25 percent power, while the TSs would have allowed continuous operation at full power. LCO 3.7.7 states The Main Turbine Bypass System shall be OPERABLE. OR LCO 3.2.2, MINIMUM CRITICAL POWER RATIO (MCPR), limits for an inoperable Main Turbine Bypass System, as specified in the COLR, are made applicable. The Cycle 16 COLR Base Case was analyzed to allow 2 TBVs to be OOS without taking any further action or incurring any operational penalty; however, since the COLR created a new operational restriction to prohibit any TBVs from being OOS in order to maintain the unit in an analyzed condition, the inspectors questioned the apparent non-conservatism that the COLR created for LCO 3.7.7. Specifically, under an identical condition of 2 TBVs OOS, the COLR would have required the unit to downpower to less than 25 percent power, while the TSs would have allowed continuous operation at full power. This issue is considered a URI pending additional internal discussion with the NRC Office of Nuclear Reactor Regulation to seek guidance on whether the above examples classify as LCOs and further, how NRC Administrative Letter 9810 may apply.
05000272/FIN-2014005-02Salem2014Q4Failure to Implement Procedures during Shutdown Results in ESF ActuationThe inspectors identified a Green NCV of TS 6.8.1, Procedures and Programs, when PSEG operators did not implement the procedure steps to trip the main turbine, and manually initiate auxiliary feedwater (AFW), during shutdown for a refueling outage on October 19, 2014. Consequently, operator response to degrading equipment conditions resulted in an unplanned manual reactor trip and coincident AFW actuation. PSEGs immediate corrective actions included conducting crew performance reviews documented as part of the post-trip review by the sites Plant Operations Review Committee (PORC), and subsequent coaching of operator performance. The inspectors determined PSEGs failure to trip the main turbine and establish AFW flow on October 19, in accordance with (IAW) abnormal and shutdown procedures, constituted a performance deficiency. The finding was more than minor because it was associated with the Human Performance attribute of the Initiating Event cornerstone, and adversely affected its objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, not following procedures in response to the 1B main power transformer (MPT) challenges resulted in an unplanned manual reactor trip and coincident Engineered Safety Features (ESF) AFW system actuation. In accordance with IMC 0609, Attachment 4, and Exhibit 1 of Appendix A, the inspectors determined that this finding is of very low safety significance, or Green, because the finding did not cause both a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. The inspectors determined that this finding had a cross-cutting aspect in the area of Human Performance, Procedure Adherence, because PSEG operators did not follow procedures in response to degrading 1B MPT conditions during shutdown for a refueling outage on October 19.
05000416/FIN-2014004-02Grand Gulf2014Q3Failure to Implement Corrective Actions Leads to Automatic Plant ScramThe inspectors reviewed a self-revealing finding for the licensee's failure to follow procedure EN-LI-102, "Corrective Action Process, Revision 12, which requires the licensee to appropriately complete assigned corrective actions within the prescribed time frame. On March 29, 2014, with Grand Gulf Nuclear Station operating at 87 percent power, a capacitor in a multiplier module of the main turbine overspeed protection circuit failed, causing the load reject relay to actuate. The main turbine control valves closed and an automatic actuation of the reactor protection system occurred, resulting in a plant scram. The root cause analysis noted that a corrective action initially assigned in 2007 in association with a single point vulnerability review was not completed in the prescribed time frame. The corrective action required that the module in question, which contained a single point vulnerability, either be rebuilt so as to reduce the probability that an age-related failure capable of triggering the vulnerability would occur, or replaced with a new design that eliminated the vulnerability altogether. The licensee entered this issue into the corrective action program under Condition Report CR-GGN-2014-03131. Immediate corrective actions following the scram included replacing the failed module with a spare module that had been visually inspected and functionally checked. Long term corrective actions include replacing the module with a component that does not exhibit single point vulnerability. The licensee's failure to follow procedure by failing to appropriately complete assigned corrective actions was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it was associated with the equipment performance attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective, in that it increased the likelihood of those events that upset plant stability and challenge critical safety functions during power operations. Using NRC Inspection Manual Chapter 0609, Attachment 4, "Initial Characterization of Findings," dated June 19, 2012, the inspectors determined that the issue affected the Initiating Events Cornerstone. Using Inspection Manual Chapter 0609, Appendix A, "The Significance Determination Process for Findings At-Power," dated June 19th, 2012, the finding was determined to be of very low safety significance (Green) because the finding did not contribute to both the likelihood of a reactor trip and the likelihood that mitigating equipment would not be available. The finding was a latent issue and is not reflective of present licensee performance; therefore, no cross-cutting aspect was assigned.
05000458/FIN-2014301-01River Bend2014Q1Failure of the Plant Referenced Simulator to Demonstrate Expected Plant Response with Four ExamplesTitle 10 CFR Part 55.46(c)(1), Plant-Referenced Simulators, states, in part, A plant referenced simulator used for the administration of the operating test...must demonstrate expected plant response to operator input and to normal, transient, and emergency conditions to which the simulator has been designed. Contrary to this, Operators were unable to open the main steam isolation valves because the River Bend Station simulator did not correctly model the differential pressure across the main steam isolation valves. Because of this, the job performance measure had to be rejected and another developed. This modeling deficiency was entered into the licensees corrective action program as Condition Report CR-RBS-2014-965. On multiple occasions, the River Bend Station simulator randomly initiated a main turbine runback when plant conditions did not warrant this action. After unsuccessful attempts were made to resolve this modeling deficiency, the applicants were briefed to ignore this event should it occur. This modeling deficiency was entered into the licensees corrective action program as Condition Reports CR-RBS-2014-965 and CR-RBS-2014-1496. The River Bend Station simulator initiated a control rod drift during a scenario where plant conditions did not support this response. After identification, the licensee entered the issue into the licensees corrective action program as Condition Report CR-RBS-2014-1496. These failures of the plant-referenced simulator to demonstrate expected plant response during conditions to which the simulator has been designed to respond was a performance deficiency. The finding was more than minor because it is associated with the human performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring availability, reliability, and capability of systems needed to respond to initiating events to prevent undesired consequences. Specifically, the incorrect simulator response could adversely affect the operating crews ability to assess plant conditions and take actions in accordance with approved procedures. In accordance with NRC Inspection Manual Chapter 0609, Significance Determination Process, Phase 1 Worksheets, and the associated Appendix I, Licensed Operator Requalification Significance Determination Process (SDP), Block 15, the finding was determined to be of very low safety significance because the deficient simulator performance did not negatively impact operator performance in the actual plant during a reportable event. Following the operating test, it was discovered the modeling deficiencies were introduced as part of a simulator upgrade more than ten years ago and therefore, are not considered to be a reflection of current performance. The hardware failure associated with the main steam line pressure gauge was determined to have no actual operator impact and was not a generic training issue. Therefore, this finding has no cross-cutting aspect associated with it.
05000387/FIN-2014002-01Susquehanna2014Q1Adequacy of Compensatory Measures to Restore Technical Specification OperabilityAn Unresolved Item (URI) was identified because additional NRC review and evaluation is needed to determine whether implementation of a compensatory measure to restore TS operability required NRC approval prior to implementation and to subsequently determine whether a violation of 10 CFR 50.59, Changes, Tests and Experiments was more than minor. During a review of a prompt operability determination addressing the inadvertent closure of a main turbine CV, inspectors questioned whether a compensatory measure specified to maintain compliance with TS required NRC approval prior to implementation. Specifically, to address the degraded condition, PPL implemented a compensatory measure of crediting plant equipment not previously credited in the UFSAR to restore and maintain operability in accordance with TSs 3.2.2, Minimum Critical Power Ratio and 3.2.3, Linear Heat Generation Rate. PPL did not perform an evaluation of this change as required by 10 CFR 50.59(d)(1). On July 10, the number 3 main turbine CV on Unit 1, XV-10150C, slowly drifted close while operating at 100 percent rated thermal power (RTP). In response to the issue, the electro-hydraulic control system opened CVs 1, 2 and 4 to maintain reactor pressure stable. Operators reduced power to approximately 96 percent RTP. Operators also generated CR 1724394 and assessed the condition for operability. PPL performed a prompt operability determination and assessed, in part, the potential affect the degraded condition had on the power distribution limits. Specifically, PPL determined, during discussions with the fuel vendor, that the thermal limits were affected by the number 3 CV being closed. Specifically, with the number 3 CV closed, the steam relieving capacity of the main steam system was below assumed values in the transient analysis for a Recirculation Flow Controller Failure (RFCF). The RFCF is one of the limiting events used to develop the flow-based Minimum Critical Power Ratio and Linear Heat Generation Rate thermal limits. To compensate for this and restore operability per TSs 3.2.2 and 3.2.3, PPL specified crediting the reactor recirculation motor-generator set high speed electrical and mechanical stops to limit the maximum flow assumed in the transient analysis. Consistent with Inspection Manual Part 9900 Technical Guidance, Operability Determinations & Functionality Assessments for Resolution of Degraded or Nonconforming Conditions Adverse to Quality or Safety and the PPL 50.59 Resource Manual, Revision 6, PPL considered this compensatory measure a change to the facility and assessed whether the change required prior NRC approval in accordance with NDAP-QA-0726, 10 CFR 50.59 and 10 CFR 72.48 Implementation, and PPLs 50.59 Resource Manual. PPL determined the change did not require evaluation under 10 CFR 50.59 and documented this on a 50.59 Screening Determination. In part, this was based on answering no to the question does the proposed activity involve a change to an SSC that adversely affects an FSAR described design function. The basis for this determination was that the reactor recirculation motor-generator set high speed electrical and mechanical stops are not credited in the FSAR transient analysis and, therefore, have no design function. PPL considered the effect on the design function of the fuel assemblies to not fail during normal operation and anticipated operational occurrences and determined that the compensatory measure ensures that the requirement of the design function is met. PPL concluded that the change did not adversely affect any of the design functions for the fuel. Inspectors reviewed the 50.59 screening determination and questioned the basis of PPLs conclusion that an evaluation of the change was not required. Specifically, the change had the effect of creating a new design function for the reactor recirculation motor-generator set high speed electrical and mechanical stops to limit flow during a RFCF event. Additionally, a failure of these components could preclude the design function of the fuel from being met. The resource manual provides a definition of adverse effects which states, in part: Changes that would introduce a new type of accident or malfunction with a different result would screen in. If a proposed change would reduce the reliability of a design function, this change should be screened in because there is an adverse effect on a design function. Changes to SSCs that are not explicitly described in the FSAR can have the potential to affect SSCs that are explicitly described in the FSAR and thus may require a 10 CFR 50.59 Evaluation. If for the larger FSAR described SSC, the change affects a FSAR described design function or an evaluation demonstrating that intended design functions will be accomplished, then a 10 CFR 50.59 Evaluation is required. In this case, the introduction of a new design function for the components and reliance on these components to function to ensure a design function of the fuel was met had an adverse effect by introducing a new potential malfunction that could result in the design function not being met. Therefore, inspectors determined that PPL should have answered Yes to the screening question Does the proposed activity involve a change to an SSC that adversely affects an FSAR described design function. PPL also should have evaluated whether the change needed prior NRC approval in accordance with 10CFR 50.59(d)(1). Inspectors determined that the issue was a performance deficiency, however, could not determine whether the change would ever have ultimately required NRC approval. Therefore, in accordance with the NRC Enforcement Policy, inspectors could not determine whether the performance deficiency was more than minor. PPL entered the issue into the CAP as CR-2014-09397 and initiated actions to evaluate the change in accordance with 10 CFR 50.59(d)(1). Pending completion of PPLs 50.59 evaluation and review by inspectors, this is a URI.
05000277/FIN-2013004-02Peach Bottom2013Q3Failure to Conspicuously Post and Lock/Guard a HRA on the Unit 3 Turbine Deck ScaffoldThe inspectors identified a NCV of very low safety significance of Technical Specification (TS) 5.7.2 because Exelon did not control the access point to a Locked High Radiation Area (LHRA). The performance deficiency (PD) was related to not controlling access to a Unit 3 LHRA. The LHRA became accessible when temporary scaffold was built on the south shield wall between the electrical generator and the main turbine. On August 19, the inspectors identified a permanent ladder from the top of the north side of the shield wall to the turbine deck floor that could allow access to the LHRA. Radiation Protection (RP) procedure RP-AA-460, Controls for High and LHRA, Revision 24, provides guidance for the control of high radiation areas (HRAs). By the procedure definition of accessible area, the area was accessible after the scaffold was built, and no tools or other exceptional measures were needed to gain access. The violation was entered into Exelons corrective action program (CAP) as action request (AR) 01548397. The PD was more than minor because it is associated with the cornerstone attribute of Program and Process (RP controls), and negatively affected the Occupational Radiation Safety cornerstone objective to ensure the adequate protection of the worker health and safety from exposure to radiation from radioactive material during routine civilian nuclear power operation. There was also an example of this PD in example 6.g. of IMC 0612, Appendix E, Examples of Minor Issues. This example concludes that the issue is more than minor because actual dose rates in excess of the posting requirements existed in the area. LHRAs are required to be posted and controlled properly to avoid unnecessary worker exposure. The finding was evaluated using the Occupational Radiation Safety SDP and was determined to be of very low safety significance (Green) because it was not related to As Low As is Reasonably Achievable (ALARA) planning, it did not involve an overexposure, did not constitute a substantial potential for overexposure, and the ability to access dose was not compromised. The finding included a cross-cutting aspect in the area of Work Controls, Human Performance component, because Exelon did not appropriately plan the work activities and identify the potential job site conditions (radiological hazards) associated with building scaffold next to a LHRA wall.
05000285/FIN-2013008-27Fort Calhoun2013Q2Continuous Monitoring Capability of Post Accident Main Steam Radiation Monitor RM-064The team identified an unresolved item associated with post accident radiation monitor RM-064. Specifically, the team is concerned about the capability of the monitor to provide representative measurements due to the system configuration, and this could represent a failure to ensure continuous effluent monitoring of the main steam lines following a steam generator tube rupture accident. Following the Three Mile Island Accident in March 25, 1979, licensees were required to ensure all potential effluent release points from nuclear power plants were equipped with high range radiation monitors. In particular, NUREG-0737, Section II.F.1.1 requires in part; that for pressurized water reactors such as FCS, Unit 1, steam release points be monitored for noble gases, and that indication of the activity must be monitored and recorded continuously. In addition Section II.F.1.1 requires the monitors shall be capable of functioning both during and following an accident. System designs shall accommodate a design-basis release and then be capable of following decreasing concentrations of noble gasses. In addition, the monitoring system shall be capable of obtaining readings at least every 15 minutes during and following an accident. . The team identified an unresolved item associated with post accident radiation monitor RM-064. Specifically, the team is concerned about the capability of the monitor to provide representative measurements due to the system configuration, and this could represent a failure to ensure continuous effluent monitoring of the main steam lines following a steam generator tube rupture accident. By application dated March 9, 1984, the licensee requested an amendment to the stations technical specifications in response to the Commissions Generic Letter 83-37, NUREG-0737 Technical Specifications. The generic letter, which was issued in November 1, 1983, advised licensees to submit new technical specifications for NUREG-0737 items, including Section II.F.1.1, Noble Gas Effluent Monitors (II.F.1.1). The stations potential post-accident steam release points include the main steam relief valves, the atmospheric dump valve, and the steam driven AFW pumps steam turbine. To comply with the high range radiation monitoring requirements, the licensee installed noble gas effluent monitors including, radiation monitor RM-064. Per USAR Section 11.2.3.11, RM-064, the post-accident main steam line monitor, is an off-line monitor designed to measure the steam activity by sampling steam from the two steam headers via two isolation valves HCV-921 and HVC-922. The monitor is placed in service in the event of a steam generator tube rupture. The monitor is capable of sampling steam from both steam headers and the recorded data from this monitor can then be utilized to quantify effluents released through the main atmospheric dump valve, the main steam safety valves, and the AFW pump turbine. Radiation monitor RM-064 is located in the turbine building next to Room 81. - 223 - The team noted that the design basis accident analysis contained in USAR, Section 14.14, Steam Generator Tube Rupture Accident, required the licensee to assume a coincident reactor trip and a loss of off-site power. Due to the assumed simultaneous loss of off-site power with the reactor trip, the reactor is cooled down by releasing steam via the main steam safety valves and atmospheric dump valve, creating a direct release path to the environment. In addition, due to the loss of off-site power, the normal condenser off-gas radiation monitor becomes un-available due to the loss of condenser vacuum. This leaves radiation monitor RM-064 as the only monitor available to measure radioactivity in the main steam lines. The analysis assumes all activity released from the faulted steam generator ceases when it is isolated by plant operators 2 hours after the event. The design of the FCS main steam line monitor is provided in MR-FC-79-190C, Post Accident Main Steam Line High Range Radiation Monitor RM-064, Revision 0, dated June 4, 1982. The station has two 28 inch diameter headers leading to the main turbine. Each main steam line is provided with six main steam safety valves each having different lift set-points. The pipe connecting these valves is 2.5 inches in diameter. The pipe connecting to the atmospheric dump valve is 3 inches in diameter. The sample line to radiation monitor RM-064 is 3/8 inch in diameter. This line is located upstream of the main steam isolation valves, in Room 81 of the auxiliary building. The distance from the main steam header to the actual location of radiation monitor RM-064 (outside Room 81) is over sixty feet long, while the main steam safeties and steam dump valve, are within 12 feet away from the main steam headers. The team reviewed the USAR, main steam drawings, applicable calculations, and interviewed engineers and operators to identify the design basis requirements for radiation monitor RM-064 and to verify it was capable of performing its intended functions. On The team also determined that for the B steam generator header the location of the 3/8 inch sample line leading to radiation monitor RM-064 was installed downstream of three of the main steam safety valves, including the lowest lift set-point valve. For the A steam generator header, the 3/8 inch sample line was located downstream of two of the safety valves but upstream of the lowest lift set point relief. Due to the location of the sample lines being downstream of the safety valves, the difference in pipe sizing between the lines to the monitor (3/8 inch), the main steam safety valves (2.5 inch), and the atmospheric dump valve (3 inch) and the distance from the main steam header to the monitor, the team questioned how the licensee assured a representative measurement would be obtained during and after a steam generator tube rupture accident. The team informed the licensee of their concerns and the licensee initiated Condition Reports CR 2013-04442, 2013-05515, and 2013-06267, to capture these concerns in the CAP. February 27, 2013, the team performed a walkdown of radiation monitor RM-064 and the steam lines. Because radiation monitor RM-064 is normally isolated, the team questioned how long it would take operators to put the monitor in service, and how the licensee met the requirement of continuous monitoring. During subsequent evaluations the licensee determined that there was not an established time requirement for operators to put radiation monitor RM-064 in service. - 224 - The licensee performed a simulator dry run with licensed operators to estimate the time required to place the monitor in service. During this simulated event, it took operators approximately 23 minutes to put the monitor in service, thus indicating that there could be an unmonitored release to the environment for at least 23 minutes following a steam generator tube rupture accident. Regarding the representative sample concern, engineers determined that without a sophisticated computer model it could not be definitely shown that the degree of turbulent mixing in the steam lines is sufficient to equalize the concentrations of radioactive gasses and entrained particulates downstream of the main steam safety valves where the lines connecting to radiation monitor RM-064 were located. The licensee issued Condition Report CR 2013-10507 requesting a detailed calculation to address this concern. The team determined this condition has existed since the time radiation monitor RM-064 was installed in February 1983, until February 27, 2013, when the issue was identified by the team. An engineering technical evaluation was then performed under Condition Report CR 2013-04442, based on existing radiological analysis Calculation FC06820 used for the steam generator accident analysis (USAR 14.14). This technical evaluation removed many of the conservative assumptions included in Calculation FC06820. Based on this basic evaluation and using engineering judgment, the licensee determined that there would be sufficient mixing and adequate concentration to provide a representative radiation measurement. The team concluded that further review is necessary in order to properly evaluate and disposition this issue. This issue is identified as URI 05000285/2013008-27, Continuous Monitoring Capability of Post Accident Main Steam Radiation Monitor RM- 064.
05000341/FIN-2013009-01Fermi2013Q2Failure to Implement Foreign Material Exclusion Procedure Requirements Adversely Affected the Reliability of the Main Turbine Generator and Caused a Reactor ScramA finding of very low safety significance was self-revealed from an event that resulted in a reactor scram. The licensee failed to correctly implement its foreign materialexclusion procedure following a reactor scram on September 30, 2009. The scram was caused by a turbine trip which was caused by the presence of a very small metallic particle (foreign material) that had bored into a main generator stator bar over time and created a hole that allowed hydrogen cooling gas to leak into the stator cooling water system. The ineffective corrective actions resulted in a second reactor scram for the same cause on November 7, 2012. Because the main turbine generator is not safety-related, no violation of regulatory requirements was identified. The licensee implemented appropriate mitigation actions until a permanent corrective action involving replacement of the generator or a modification to the existing stator design can be implemented. The finding was of more than minor significance because this issue was associated with the Equipment Performance attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective of limiting the likelihood of events that upset plant stability and challenge critical safety functions during power operations. Specifically, inadequate foreign material exclusion controls coupled with a stator design that allows magnetized particles to be trapped in between the stator bars resulted in a reactor scram following development of a hydrogen leak through a stator bar. The finding was of very low safety significance because the issue: (1) did not involve a loss-of-coolant accident initiator; (2) did not cause a reactor trip AND the loss of mitigation equipment; (3) did not involve the complete or partial loss of a support system that contributes to the likelihood of, or cause, an initiating event AND affect mitigation equipment; and (4) did not increase the frequency of a fire or internal flooding initiating event. The inspector did not identify a cross-cutting aspect related to this finding.
05000352/FIN-2013003-03Limerick2013Q2Failure to Follow Partial Procedure Change ProcessA self-revealing Green finding of TS 6.8, Procedures and Programs , was identified because Exelon personnel did not implement procedure use and adherence requirements when operators changed the scope of work for surveillance testing of main turbine stop and control valves. This resulted in a reactor protection system automatic scram on April 16, 2013. This issue was identified in the Exelon CAP as IRs 1503749 and 1525552. The failure of station operators to follow the partial procedure performance process during the performance of two TS required surveillances was a performance deficiency that was reasonably within Exelons ability to foresee and correct and could have been prevented. The performance deficiency was also contrary to Exelons procedure use and adherence requirements. This finding was more than minor because, if improper implementation of the partial procedure performance process is left uncorrected, the performance deficiency would have the potential to lead to a more significant safety concern such as a more severe plant transient or engineered safeguard system actuation or malfunction. Additionally, this issue is similar to example 4.b in IMC 0612, Appendix E, Examples of Minor Issues, in that the procedural error resulted in a reactor scram or other transient. The finding was determined to be self-revealing because it was revealed through the receipt of a scram signal during performance of a surveillance test which required no active and deliberate observation by Exelon personnel. The finding was determined to be of very low safety significance (Green) in accordance with Appendix G of IMC 0609, Shutdown Operations Significance Determination Process, because the finding did not require a quantitative assessment. A quantitative assessment was not required because the finding did not increase the likelihood of a loss of reactor coolant system inventory or degrade the ability to recover decay heat removal if it was lost. This finding had a cross-cutting aspect in the area of Human Performance, Decision Making, because Exelon did not ensure that personnel made safety-significant or risk-significant decisions using a systematic process to ensure that safety is maintained (H.1(a)). Specifically, the partial procedure performance process was not properly implemented which resulted in plant conditions that were improper for the next evolution. This resulted in a reactor protection system automatic scram on April 16, 2013.
05000482/FIN-2013003-04Wolf Creek2013Q2Failure to Update Station Procedures and Train Operators Regarding the Effects of Implemented Design Changes to the Main Turbine Control SystemA Green self-revealing non-cited violation of Technical Specification 5.4.1.a was identified for failure to properly update operating procedures and train operators on the effects of a recently installed modification. Specifically, procedures were not adequately revised to provide guidance for operating the new Westinghouse Ovation digital turbine controls. As a result, operators shifted operating modes at a power level that caused an 11 percent power increase due to the combined characteristics of the steam control valves and the turbine control unit. Additionally, operators were trained to shift control modes at low power levels, where minor transients occurred, but were not restricted from performing the shift at high power levels, where the transient could be more significant. This issue was entered into the licensees corrective action program under Condition Report 68711. Failure to update station operating procedures to provide adequate guidance for design changes, and failure to adequately train operators on those implemented design changes is a performance deficiency. The performance deficiency is more than minor because it affected the design control, procedure quality, and human performance attributes of the Initiating Events cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Using Inspection Manual Chapter 0609, Appendix A, Checklist 1, Initiating Events Screening Questions, the inspectors determined that the finding was of very low safety significance (Green) because the finding did not result in a reactor trip coincident with the loss of mitigation equipment. The inspectors determined that this finding had a cross-cutting aspect in the area of human performance area of work control, because the licensee did not appropriately communicate and coordinate during activities in which interdepartmental coordination was necessary to assure plant and human performance. Specifically, Wolf Creek did not communicate and coordinate to ensure that procedure guidance and operator training adequately conveyed the operational impacts of shifting turnine control modes at different power levels.
05000285/FIN-2013010-01Fort Calhoun2013Q2Failure to Establish Main turbine Load Change ProcedureThe NRC identified a non-cited violation of Technical Specification 5.8.1.a for failure to establish, implement, and maintain a procedure recommended in Regulatory Guide 1.33, Revision 2, Appendix A. Specifically, the licensee failed to establish a procedure for changing load on the Main Turbine as required by Section 2.f, Changing Load or Load Follow. The licensee entered this into their corrective action program as Condition Report 2013-08572. Failure to comply with technical specifications is a performance deficiency. The finding is more than minor because it adversely affects the Procedure Quality attribute of the Initiating Events Cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Using the Initiating Events Screening Questions in Manual Chapter 0609, Appendix A, Exhibit 1, the finding was determined to not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions would not be available; therefore, the finding is of very low safety significance. This finding was determined to have a cross-cutting aspect in the area of human performance, associated with resources, because the licensee failed to ensure that procedures are available and adequate to assure nuclear safety. Specifically, the licensee did not establish a quality procedure for changing load on the Main Turbine as recommended by Regulatory Guide 1.33, Revision 2, Appendix A.
05000259/FIN-2012004-03Browns Ferry2012Q3Automatic Reactor Scram Due to Inadequate Testing of Current TransformerA self-revealing finding (FIN) was identified for the licensees failure to adequately test a Unit 3 main turbine generator current transformer (CT) as required by TVA-NQA-PLN89-A, Nuclear Quality Assurance Plan which resulted in the improper wiring of the CT. The licensee switched the CT leads to correct the input to the main transformer relay, adequately tested all other new Unit 3 relays, implemented a transition plan to incorporate the protective relay group into the nuclear organization, and planned post startup monitoring for the Unit 1 and 2 digital differential protective relays. The licensee entered this issue into their corrective action program as PER 558183. This finding was determined to be more than minor because it was associated with the Design Control attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective to limit the likelihood of those events that upset plant stability. Specifically, the failure to adequately test a Unit 3 main turbine generator CT directly contributed to a reactor scram of Unit 3. The significance of the finding was evaluated using Phase 1 of the Significance Determination Process (SDP) in accordance with Inspection Manual Chapter 0609 Attachment 4 and was determined to be of very low safety significance (Green) because it did not contribute to both a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. The cause of this finding was directly related to the cross-cutting aspect of Supervisory and Management Oversight in the Work Practices component of the Human Performance area, because the supervisors failed to ensure proper procedure quality, procedure usage, worker qualification, and proper work preparation associated with the protective relay groups work activities such that nuclear safety was supported.
05000254/FIN-2012003-03Quad Cities2012Q2Failure to Identify Design Deficiency in Vendor ProductA self-revealed finding of very low safety significance with an associated NCV of Technical Specification (TS) 3.7.7, Main Turbine Bypass Valves System, was identified on April 18, 2012, when an unplanned reactor scram occurred during generator voltage regulator testing. Inspectors subsequently determined the licensee had failed to identify elimination of a time delay that changed how the system responded to a load reject with no turbine trip during vendor design documentation review for the digital electro-hydraulic control (DEHC) system modification implemented in 2006. Failure to perform the review with the rigor required by CC-AA-103-1003, Owners Acceptance Review of External Engineering Technical Products, is a performance deficiency entered into the licensees corrective action program (CAP) as Issue Report (IR) 1355763. This finding resulted in exceeding the allowed out-of-service time for TS 3.7.7, Main Turbine Bypass System, on at least eleven occasions between the two units since the modifications were installed. The finding was determined to be more than minor because the performance deficiency adversely affected the Reactor Safety - Initiating Events Cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions. In this circumstance, the Design Control attribute of the cornerstone was adversely impacted when unintended consequences were introduced during a modification. Using IMC 0609, Attachment 4, Table 4a, Initiating Events Cornerstone, Transient Initiators, inspectors determined that the performance deficiency did not contribute to the likelihood of both a reactor trip and unavailability of mitigation equipment since the main steam safety and relief valves are the credited pressure mitigation equipment and were unaffected by the event. Therefore, this finding screens as Green, or very low safety significance. The inspectors did not identify a cross-cutting aspect for this performance deficiency since it occurred during the DEHC modification review in 2006 and was considered a legacy issue.
05000327/FIN-2012003-02Sequoyah2012Q2Turbine Throttle Valve Reactor Trip Function DegradedThe inspectors identified a Green NCV of Unit 1 TS 6.8, Procedures & Programs, for the licensees failure to provide adequate procedures for maintenance and surveillance activities involving the main turbine throttle valves and the associated solid state protection system (SSPS) function which provides a reactor trip on turbine trip signal. The failure to include applicable torque requirements for set screws associated with the limit switch lever arm assembly resulted in one of the four turbine throttle valve position limit switches being in an inoperable condition such that the SSPS function of reactor trip on turbine trip, which involves a four-out-of- four logic, was inoperable and could not have functioned if required. This issue was entered into the licensees corrective action program as Problem Evaluation Reports (PERs) 419594 and 518647 The finding was determined to be greater than minor because it was associated with the procedure quality 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. Specifically, the finding resulted in the inability of the SSPS to provide the required reactor trip signal upon closure of all four turbine throttle valves above 50 percent RTP. Using Inspection IMC 0609, Significance Determination Process, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, the finding was determined to be of very low safety significance (Green) since the trip is not credited in any Updated Final Safety Analysis (UFSAR) Chapter 15 accident analysis and the redundant reactor trip on turbine trip function that is based on low auto stop oil pressure was unaffected. The cause of this finding was determined to have a cross-cutting aspect in the area of Human Performance, Resources component, and the aspect of complete and accurate procedures and work packages. The procedures for performing maintenance and surveillance activities associated with the turbine throttle valves and associated SSPS function were not adequate to assure nuclear safety due to the failure to include applicable torque requirements for the components associated with the valve limit switch assembly.
05000327/FIN-2012007-01Sequoyah2012Q1Reactor Trip Due to Improper Preferred Inverter MaintenanceA self-revealing finding was identified for the licensees failure to properly implement work procedures during the performance of a preventive maintenance (PM) activity associated with the Unit 1 Preferred Inverter. The improper performance of selected steps with the system in an inappropriate configuration to support the activity caused an electrical transient and loss of the preferred power board which resulted in a turbine trip and automatic reactor trip. The licensee entered this issue into their corrective action program as PER 405141 and implemented corrective actions to include guidance for operations supervisory review of work documents prior to returning equipment to service. The inspectors reviewed IMC 0612, Appendix B and determined that the finding was more than minor because it adversely impacted the human performance attribute of the initiating events cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, it resulted in sudden closure of all main turbine governor valves from 100% power, which ultimately led to an automatic reactor trip. The inspectors reviewed IMC 0609, Attachment 4 and determined that the finding was of very low safety significance (Green) because it did not contribute to both the likelihood of a reactor trip and the likelihood that mitigating systems would not be available. This finding was determined to have a cross-cutting aspect in the area of human performance, the component of work control, and the aspect of work activity coordination, H.3(b), due to the failure to appropriately coordinate this work activity consistent with nuclear safety. Specifically, the necessary interdepartmental communication and coordination between operations and maintenance work groups was inadequate to assure proper performance and accomplishment of the work activity in accordance with the procedure, including establishing proper plant conditions to support the work activity as well as understanding the potential operational impact of the proposed maintenance.
05000315/FIN-2012002-01Cook2012Q1Failure to Install a Grommet Seal on the Main Turbine Thrust Bearing ProbeOne self-revealed finding of very low safety significance was identified for the failure to install a grommet seal on the main turbine thrust bearing probes as required by a site design standard, VTD-SKFI-0001, Eddy Probe Systems Technical Manual, during the Unit 1 2009 turbine failure restoration project. Consequently, oil migrated into the thrust bearing probe conduit, which contributed to a main turbine trip and resultant automatic reactor trip on September 7, 2011. For corrective actions, the licensee separated the main turbine thrust bearing probe cables into separate conduits; wrapped the cables in additional shielding and insulation to prevent signal coupling; and installed sealing glands on the main turbine thrust housing to eliminate oil intrusion into the conduits. This issue was entered into the licensees corrective action program (CAP) as Action Request (AR) 2011-10107. One self-revealed finding of very low safety significance was identified for the failure to install a grommet seal on the main turbine thrust bearing probes as required by a site design standard, VTD-SKFI-0001, Eddy Probe Systems Technical Manual, during the Unit 1 2009 turbine failure restoration project. Consequently, oil migrated into the thrust bearing probe conduit, which contributed to a main turbine trip and resultant automatic reactor trip on September 7, 2011. For corrective actions, the licensee separated the main turbine thrust bearing probe cables into separate conduits; wrapped the cables in additional shielding and insulation to prevent signal coupling; and installed sealing glands on the main turbine thrust housing to eliminate oil intrusion into the conduits. This issue was entered into the licensees corrective action program (CAP) as Action Request (AR) 2011-10107.
05000416/FIN-2012002-02Grand Gulf2012Q1Manual Reactor Scram Caused by Failure to Ensure the Main Steam Supply Valve to Reactor Feed Pump Turbine B was Full OpenThe inspectors reviewed a Green self-revealing finding for the failure to ensure the correct position (full open) of the main steam supply valve 1N11-F014B to reactor feed pump turbine B, which resulted in a manual reactor scram due to decreasing reactor water level. During plant shutdown activities to begin refueling outage 18, the at-the-controls operator manually scrammed the reactor from approximately 23 percent rated thermal power due to the decreasing reactor water level. Water level in the reactor was decreasing because valve 1N11-F014B was not fully open, and because pressure in the main steam lines had been reduced when the crew opened turbine bypass valves to begin cooling the main turbine. With valve 1N11-F014B less than fully open and reduced steam pressure, the operating feed pump wasnt able to maintain water level. After the scram, reactor core isolation cooling and reactor feed pump turbine A were used to restore water level. The licensee plans to repair valve 1N11-F014B during the current refuelling outage. The licensee entered this issue into their corrective action program as condition report CR-GGN-2012-01838. The finding is more than minor because it is associated with the Initiating Events Cornerstone attribute of human performance and affected the associated cornerstone objective to limit the likelihood of those events that upset plant stability and that challenge critical safety functions during power operations. Using Inspection Manual Chapter 0609.04, Phase 1 - Initial Screening and Characterization of Findings, the inspectors concluded that the finding contributed to both the likelihood of a reactor trip and the likelihood that mitigation equipment would not be available. The inspectors, in consultation with the regional senior reactor analyst, performed a Phase 2 estimation using the pre-solved work sheets for Grand Gulf Nuclear Station. The inspectors determined by entering the power conversion system column that the finding was of very low safety significance (Green). This result was validated by the senior reactor analyst using the current revision of the plant-specific SPAR model. The inspectors determined the finding has a cross-cutting aspect in the area of human performance associated with the decision-making component because the operating staff proceeded with the start up of the reactor feed pump B with the main steam supply valve 1N11-F014B in an unknown position.
05000458/FIN-2012002-09River Bend2012Q1Failure to Properly Fabricate and Install the mid-Standard Turbine Shaft BrushThe inspectors reviewed a self-revealing finding regarding the improper fabrication of a turbine shaft grounding brush that resulted in turbine trip and subsequent reactor scram. The licensee identified the improper fabrication of a turbine shaft grounding brush as the cause of a spurious main turbine over-speed trip signal from an electrical discharge from the turbine shaft. This issue was entered into the licensees corrective action program as Condition Report CR-RBS-2012-9053. Failure to fabricate the turbine shaft grounding brush in accordance with vendor instructions is a performance deficiency. The finding was more than minor because it was associated with the equipment performance attribute of the initiating events cornerstone and affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the improperly fabricated grounding brush resulted in a turbine trip and subsequent reactor scram. The inspectors reviewed the finding using IMC 0609, Appendix A, Significance Determination of Reactor Inspection Findings for At-Power Situations. Based on the Phase 1 screening of the finding, the inspectors determined that the finding was of very low safety significance (Green) because it did not affect loss of coolant accident initiators, did not contribute to increasing the likelihood of both an initiating event and affecting mitigating equipment, and did not increase the likelihood of a fire or flood. The apparent cause of the performance deficiency was the failure in 2004 to appropriately perform a post maintenance test for the turbine shaft grounding brush modification. Therefore the inspectors did not identify a cross-cutting aspect because the performance deficiency is not reflective of the licensees current performance
05000440/FIN-2012002-01Perry2012Q1Reactor Manual Scram Associated With Inadequate Maintenance Risk EvaluationA self-revealed finding of very low safety significance (Green) and an associated NCV of 10 CFR 50.65(a)(4) was identified for failure to assess and manage risk associated with maintenance activities. Specifically, the licensee planned and conducted maintenance on a stator water cooling system pressure gauge on March 1, 2012, as a lower risk evolution than required, and conducted the maintenance online despite several decision points which indicated that this maintenance should have been conducted with the unit offline. When performed on line, the activity caused a reactor scram. The licensee entered the issue into the corrective action program as Condition Report 2012-03231. The finding was evaluated using IMC 0612, Appendix E, Examples of Minor Issues, and was determined to be more than minor because it is similar to Example 7.e and resulted in a reactor scram. Additionally, the performance deficiency impacted the Human Performance attribute of the Initiating Events Cornerstone, and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during power operations. In accordance with IMC 0609, Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process, a Region III Senior Reactor Analyst performed an analysis of the risk deficit for the unevaluated condition associated with work on a stator water system pressure gauge resulting in a reactor scram. The Perry Standardized Plant Analysis Risk (SPAR) model version 8.15 and SAPHIRE version 8.0.7.18 was used to calculate an Incremental Core Damage Probability Deficit (ICDPD). The result was an ICDPD of less than 7E-8. The dominant core damage sequences involved: (1) loss of the main condenser, failure of suppression pool cooling, failure of containment spray, failure of the power conversion system, failure of containment venting, and failure of late injection; and (2) failure of the reactor protection system to shutdown the reactor with failure of the recirculation pumps to trip. In accordance with IMC 0609, Appendix K, because the calculated ICDPD was not greater than 1E-6, the finding was determined to be of very low safety significance. This finding was associated with a cross-cutting aspect in the Work Planning (H.3(a)) component of the Human Performance cross-cutting area because the licensee did not incorporate appropriate risk insights into the development of the work package. Specifically, the licensee did not evaluate, during the planning phase of the work preparation, for the impact of re-installation of the pressure gauge and the potential for a pressure spike; a spike which caused a sustained runback of the main turbine generator with a resultant required action by the operators to manually scram the reactor.
05000352/FIN-2011004-03Limerick2011Q3Test Equipment Interference Resulting in Reactor ScramA Green, self-revealing NCV of 10 CFR Part 50, Appendix B, Criterion XI, Test Control, occurred when Exelon did not adequately assess the potential impacts of test equipment on turbine trip circuitry. This resulted in an automatic reactor scram of Unit 1 when the main turbine high reactor water level trip relay inadvertently energized during a surveillance test on June 3, 2011. This test is a quarterly surveillance, designed to verify proper operation of the Digital Feed Water Level Control System (DFWLCS) which initiates a turbine trip on high reactor level. The DFWLCS has a 1 out of 2 twice logic to energize the trip relay, so each channel is tested separately to eliminate the possibility of inadvertent actuation. As an additional precaution, the surveillance procedure contains steps for the technician to verify the other channels are free of closed trip contacts prior to beginning the test. Exelon used a Simpson 260 Volt/Ohm Meter (VOM) to perform this verification by demonstrating a nominal voltage difference between each side of the contact and station ground. During this verification step, Exelon inadvertently established a direct current loop from station ground, to the floating battery ground from the 125V power supply, to the trip circuit. This completed the circuit, energized the main turbine high reactor water level trip relay, which tripped the main turbine and caused the reactor to scram. Exelon revised the test procedure to change the requirements for test instrumentation to prevent this from recurring and entered the issue into the corrective action program as IR 1224283. The inspectors determined that the performance deficiency was more than minor in accordance with IMC 0612, Appendix B, Issue Screening, because it was associated with the Equipment Performance attribute of the Initiating Events cornerstone and affected the objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during power operation. Specifically, by not considering the impact of maintenance and test equipment (M&TE) during multiple revisions of the surveillance procedure, Exelon failed to recognize a vulnerability which could lead to a plant transient. In accordance with IMC 0609, Attachment 4, Phase 1 - Initial Screen and Characterization of Findings, the finding was determined to be of very low safety significance (Green) because the finding did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions would not be available. The inspectors determined that this performance deficiency did not reflect current performance, as the last revision to the surveillance procedure that affected M&TE requirements was greater than three years ago. As a result, the inspectors did not assign a cross-cutting aspect to this finding.
05000254/FIN-2011004-03Quad Cities2011Q3Non-Safety Related Main Steam Modification FailureNRC inspectors identified a finding of very low safety significance when analysis performed for installation of a small bore instrument sensing line modification for Unit 1 main turbine thermal performance testing did not include all applicable stresses as required by the USA Standards B31.1.0-1967 Code. On June 13, 2011, that line failed, resulting in an emergency downpower and reactor scram. The issue was incorporated into the corrective action program (CAP) as IR 1227884. Immediate corrective actions removed the leaking sensing lines on Unit 1 and permanently plugged the pipe penetrations. The performance deficiency was more than minor because it affected the Initiating Events Cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during power operations as described in IMC 0612, Appendix B. The key attribute impacted was design control for plant modifications. The inspectors performed a SDP phase 1 screening for the finding using IMC 0609, Table 4a, and answered all of the questions No. Therefore, the finding screened as very low safety significance, or Green. Inspectors determined that a significant contributor to this finding was the failure of the individual and supervisor performing the acceptance review of the contractor generated modification to engage the appropriate engineering expertise to evaluate the adequacy of the modification design before the modification was implemented. As a result, inspectors identified this issue as cross-cutting in the area of Human Performance - Work Practices in that the licensee did not ensure supervisory and management oversight of work activities, including contractors, such that nuclear safety was supported
05000483/FIN-2011003-06Callaway2011Q2Failure to Correctly Implement a Plant Safety System Test ProcedureA self-revealing noncited violation of Technical Specification 5.4.1.a, Procedures, was identified when the licensees failure to correctly follow a test procedure resulted in a negative reactivity excursion due to excessive boration. On May 27, 2011, with the Callaway Plant at 100 percent power, maintenance was in progress to perform a functional test of the plants safety system trip actuating devices. During the test the instrument maintenance technicians failed to place the mode selector switch in the test position. This resulted in switching the charging pump suction from the volume control tank to the refueling water storage tank. The inadvertent actuation resulted in a reactivity excursion that required lowering main turbine power and reactor power to about 92 percent. The crew stabilized the plant and returned critical parameters to their normal control bands. The licensee entered this issue in the corrective action program as Callaway Action Request 201104451. This finding is more than minor because it was associated with the configuration control attribute of the Initiating Events Cornerstone and affected the associated cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during power operations. Using Manual Chapter 0609.04, Phase 1 - Initial Screening and Characterization of Findings, this finding was determined to be of very low safety significance since it did not contribute to both the likelihood of a reactor trip and the likelihood that mitigating equipment or functions will not be available. This finding had a crosscutting aspect in the area of human performance associated with the work practices component because the instrument maintenance technicians failed to adequately use human error prevention techniques, such as self- and peer-checking to ensure that work activities are performed safely.
05000306/FIN-2011003-03Prairie Island2011Q2Unit 2 Reactor Trip during Severe WeatherAn unresolved item (URI) was identified due to the licensees root cause investigation remaining in progress at the conclusion of the inspection period. On May 9, 2011, the area surrounding Prairie Island was experiencing an extended severe thunderstorm with significant lightning. Following a large lightning strike, Unit 2 automatically shut down from 100 percent power due to a trip of the main turbine. The inspectors were in the control room when the reactor trip occurred. The inspectors observed the response of the operating crew to ensure that the crew was adhering to plant procedures. The inspectors also observed equipment parameters available in the control room to ensure that the reactor and the associated equipment responded as expected following the reactor trip. There were no findings in these areas. The inspectors reviewed documentation regarding the status of the electrical grid and substation maintenance work history to determine the direct cause of the trip. The licensee preliminarily determined that the reactor trip was caused by a deficiency in electrical substation maintenance activities performed by Xcel Energy employees not associated with Prairie Island. This deficiency was corrected prior to Unit 2 startup activities. However, the licensees root cause investigation was ongoing at the conclusion of the inspection. As a result, the inspectors determined that this issue should be considered an URI pending the review of the licensees root cause investigation report and the proposed corrective actions
05000220/FIN-2011003-01Nine Mile Point2011Q2Inadequate Procedural Guidance for Main Turbine and Generator Maintenance ActivitiesA Green self revealing finding for inadequate procedural guidance was identified. The inadequate procedural guidance resulted in a May 2,2011 Nine Mile Unit 1 scram due to a turbine trip. NMPNS determined that the turbine tripped when the main turbine master trip solenoid (MTS) actuated due to pressure fluctuations caused by a combination of leaking oil supply fittings to the MTS; binding of the secondary speed relay linkages, and main shaft tuOe oil disCharge pressure fluctuations. These degraded conditions occurred because the governing work control documents and procedures that were implemented during the spiing 2O1i refuel outage contained inadequate detail and guidance. NMPNS correltive actions included repairing the degraded components and initiating actions to revise the procedures. This 1nding is more than minor because it affected the procedure quality attribute of the Initiating Events Cornerstone objective of limiting the likelihood of those events that upset plant stibility and challenge critical safety functions during shutdown as well as power operations. The finding was of very low safety significance because it did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions will not be available. This finding has a cross-cutting aspect in the area of human performance in that NMPNS did not ensure that complete and accurate and upto-date design documentation and procedures were available to implement turbine maintenance during the spring 2Q11 refuel outage.
05000387/FIN-2011002-05Susquehanna2011Q1lnadequate Maintenance Procedure Results in Steam Leak and Manual ScramA self-revealing finding of very low safety significance (Green) was identified when PPL personnel did not have adequate procedures to perform maintenance on a threaded connection on the \'5C\'feedwater heater (FWH) extraction steam bleeder trip valve, (BTVX 0245C. Specifically, existing maintenance procedures did not ensure that a threaded vent plug was reinstalled properly following maintenance. As a result, on January 25,2011, the threaded plug was ejeqted from the vent hole resulting in a steam leak that was un-isolable without removing thb main turbine from service. The steam leak caused malfunctions of non-safety-relatdd electrical systems and ultimately led to a manual reactor scram by control room operators. PPL entered this issue in their CAP as condition report CR 1346952. The finding was more than minor because thd finding was associated with the Initiating Events cornerstone attribute of Equipment Performance, and affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during power operatiofr. Specifically, failure of the pipe plug resulted in an un-isolable steam leak that ultirnately led to a manual scram. The inspectors evaluated the finding using IMC 0609, Attachment 4, lnitial Screening and Characterization of Findings, and determined the finding did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions would not be available. In this case, the main condenser was available as mitigation equipment once the turbine was tripped and the leak was isolated. Consequently, the finding is of very low safety significance This finding is related to the crosscutting area of Human Performance , because PPL did not ensure that personnel, equipment, procedures, and other resources were available and adequate to assure nuclear safety. Specifically, PPL did not ensure that complete, accurate and up to- date procedures were available to reinstall a threaded plug on a BTV in the FWH extraction steam line. (H.2(c))
05000259/FIN-2011002-04Browns Ferry2011Q1Failure to Identify Adverse Trend Resulted in Reactor ScramA self-revealing finding (FIN) was identified for the licensees failure to adequately evaluate and take the required actions established by site standards to address an adverse system performance trend that had degraded below acceptable levels associated with the main generator exciter air coolers. Specifically, the licensee failed to identify that main generator exciter air cooler differential temperatures exceeded the licensee-defined limit of 10F, and did not initiate a PER as required by the licensees procedural guidance, Nuclear Engineering Department Procedure (NEDP) -20, Conduct of the Engineering Organization, Section 3.1, System Performance Monitoring. Subsequent licensee corrective actions included installing vents on the exciter air coolers to minimize air binding, establishing a process and frequency for venting the exciter air coolers, and increasing engineering supervisory oversight of the system monitoring process. The licensee captured this issue in the corrective action program as PER 301505. This finding is greater than minor because it is associated with the Human Performance attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective to limit the likelihood of those events that upset plant stability. Specifically, the finding resulted in a Unit 3 manual reactor scram due to elevated main turbine bearing vibrations caused by excessive main generator exciter air cooler differential temperatures. The significance of the finding was evaluated using Phase 1 of the significance determination process in accordance with the Inspection Manual Chapter (IMC) 0609 Attachment 4, and was determined to be of very low safety significance (Green) because it did not contribute to both the likelihood of a reactor trip and the likelihood that mitigating equipment or functions were not available. The cause of this finding was directly related to the cross-cutting aspect of Corrective Action Program Implementation in the Corrective Action Program component of the Problem Identification and Resolution area, because the licensee failed to identify the adverse trend of excessive differential temperatures between the exciter air coolers in a timely manner and enter it into the corrective action program.
05000458/FIN-2010004-06River Bend2010Q3Inadequate Maintenance Results in Unplanned Opening of Main Turbine Bypass ValveA self-revealing finding of very low safety significance (Green) was identified when turbine bypass valve number 1 opened unexpectedly causing the reactor to exceed 100 percent core thermal power. Operators promptly lowered core thermal power to 90 percent to preserve margin to fuel thermal limits. A failed power supply and inadequate calibration and testing of the steam bypass and pressure regulation system and electro-hydraulic control system caused the event. Corrective actions include replacing system power supplies and revising applicable calibration and test instructions. The licensee entered this issue into their corrective action program as Condition Report CR-RBS-2010-03343. This finding was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, technical specification mitigation equipment (main turbine bypass system, end-of-cycle recirculation pump trip function, and rod block instrumentation functions) became inoperable. Using Manual Chapter 0609, Significance Determination Process, Phase 1 Worksheet, the inspectors determined that the finding was of very low safety significance (Green) because the finding did not represent an actual loss of safety function of the system or train; did not result in the loss of one or more trains of nontechnical specification equipment; and did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The inspectors determined that this finding did not represent current licensee performance because the preventative maintenance schedule and calibration procedure were developed and approved over two years ago. Therefore, no crosscutting aspect was assigned to this finding (Section 1R20)
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