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| Site | Quarter | Title | Description | |
|---|---|---|---|---|
| 05000249/FIN-2017003-01 | Dresden | 2017Q3 | Granted Notice of Enforcement Discretion 173001: LCO 3.1.7 Required Action B.1 per TS 3.1.7, Standby Liquid Control System | Inspection Scope The inspectors reviewed the licensees response to and assessment of a through- wall leak that developed on the Unit 3 SLC A pump discharge piping . Specifically, on September 12, 2017, during a system operational pressure test, licensee personnel observed a through- wall leak from the forged body of a 1.5 stainless steel pipe T in the Unit 3 SLC system. The affected component is a part of the ASME Code Class 2 boundary. Due to the piping being ASME Code Class 2, it was required to be immediately isolated in accordance with Technical Requirements Manual 3.4.a, Structural Integrity. Isolating this piping resulted in both trains of the Unit 3 SLC system becoming inoperable as the leak was unisolable from both pumps. With both trains inoperable, the licensee entered Limiting Condition for Operation ( LCO ) 3.1.7, Required Action B.1 which requires the restoration of at least one train of SLC within 8 hours. 15 The inspectors examined the sites actions to uncover the issue with the Unit 3 SLC system , their actions to address the issue once it was identified, and their compensatory actions associated with the receipt of the Notice of Enforcement Discretion ( NOED ). The inspectors also reviewed licensee documents to verify that information contained in the NOED request was accurate. Inspection activities included gathering additional information regarding the licensees bases for requesting the NOED; examining the sites decision -making process for the issue; reviewing the licensees condition evaluation; observing the licensees compensatory actions; and evaluating the licensees operability determination. To correct this issue and exit the NOED, the licensee completed replacement of the affected Unit 3 pipi ng and connections, satisfactorily tested the replaced components, and declared the Unit 3 SLC system operable. Documents reviewed are listed in the Attachment. This event follow up review constituted one sample as defined in IP 71153 05. b. Findings Introduction : The inspectors opened an unresolved item associated with a potential noncompliance with TS 3.1.7 Required Action B.1 that occurred on September 12, 2017. NOED 17 3001 was granted by the NRC staff agreeing not to enforce compliance with the TS completion time for an additional 35 hours. Description : On September 10, 2017, with the Unit 3 SLC system in standby operation, an equipment operator performing rounds noted sodium pentaborate crystallization build -up under piping insulation. The licensee removed the insulation from the potential leak location, and noted a dry sodium pentaborate stain on the back of a forged piping T on the 1.5 stainless steel discharge line of the A SLC pump. The licensee Shift Manager made an immediate operability determination of operable based on the dry nature of the stain and its location being on a forged body , and not at a connection or weld location. The licensees initial evaluation surmised the stain was historical in nature and was from an adjacent valve packing leak. In the event that further investigation of the stain indicated a through -wall leak, the licensee investigated American Society of Mechanical Engineers ( ASME ) code compliant permanent and temporary repair options, to include the construction of an Engineered Clamp. This method was eventually dismissed as supports required for the clamp would have been impractical based on system configuration. On September 12, 2017, the licensee cleaned the stain off of the piping T and performed a visual inspection for leakage with the system at full operating pressure. During this test, a leak was observed emanating from the body of the piping T. Due to the leak occur ring within the ASME Code Class 2 boundary, the licensee was required to isolate it in accordance with Technical Requirements Manual 3.4.a, Structural Integrity. Isolating this piping resulted in both trains of the Unit 3 SLC system becoming inoperable, and therefore the licensee entered LCO 3.1.7, Required Action B.1, with an 8 hour required action. With a through wall leak discovered and the plant in a short duration shutdown LCO, the licensee implemented a repair plan for a permanent piping replacement and requested a NOED from the NRC to complete repairs prior to entering Required Action C.1 and C.2, which require placing the Unit in Mode 3 (hot shutdown) and Mode 4 (cold shutdown) within 12 and 36 hours , respectively. The NRC granted a NOED for an additional 35 hours at 5:46 p.m. on September 12, 2017. Consistent with NRC policy, the NRC agreed not to enforce 16 compliance with the specific TSs in this instance, but will further review the cause(s) that created the apparent need for enforcement discretion to determine whether there is a performance deficiency, if the issue is more than minor, or if there is a violation of requirements. This issue will be tracked as an unresolved item. (Unresolved Item 05000249/2017003 01, Granted Notice of Enforcement Discretion 17 3001: LCO 3.1.7 Required Action B.1 per TS 3.1.7, Standby Liquid Control System ) |
| 05000461/FIN-2017002-01 | Clinton | 2017Q2 | Failure of Operators to Meet Time Critical Operator Actions | Green . The inspectors identified a finding of very low safety significance and an associated non -cited violation of Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the failure to assure that applicable regulatory requirements and the design basis was correctly translated into specifications, drawings, procedures, and instructions and that design control measures provided for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculation al methods, or by the performance of a suitable testing program . Specifically, the licensee failed to assure/validate operators were able to complete the standby liquid control time critical action for an anticipated transient without a scram specified in their licensing documents. The licensee entered this issue into their CAP as AR 03980202. As corrective actions, the licensee determined the scram choreography required to complete the time critical action in the specified time, initiated a standing order to inform the operating crews, processed a procedure change for the anticipated transient without scram choreography and performed an evaluation to determine the impact of initiating the standby liquid control system at 172 seconds. The performance deficiency was determined to be more than minor because the finding was associated with the procedure quality 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. Specifically, with the operators initiating standby liquid control at 172 seconds instead of 120 seconds, the accident analysis calculations were required to be re- performed to assure the accident analysis requirements were met. The finding was screened against the Mitigating Systems cornerstone and determined to be of very low safety significance because the inspectors were able to answer all of the associated screening questions No. The inspectors determined that this finding is not indicative of current performance and therefore did not assign a cross -cutting aspect. |
| 05000324/FIN-2017001-02 | Brunswick | 2017Q1 | Failure to Control a Temporary Fire Ignition Source Near the Unit 2 Standby Liquid Control Pump Motor and Cables | Green . An NRC- identified Green NCV of License Condition 2.B.(6), Fire Protection Program, was identified for the licensees failure to adequately control fire ignition sources in the Unit 2 standby liquid control (SLC) pump ar ea in accordance with licensee procedure AD -EG -ALL -1523, Temporary Ignition Source Control. Specifically, between January 7, 2017, and January 13, 2017, a temporary electric portable heater was energized 2 feet from an SLC pump motor without continuously attending the temporary ignition source or obtai ning a continuous fire watch. The licensees c orrective actions included turning off the heater and removing it from near the SLC pumps. This issue was entered into the licensees CAP as NCR 2091736. The inspectors determined that the licensees failure to control fire ignition sources in accordance with licensee procedure AD -EG -ALL -1523, was a performance deficiency. The finding was more than minor because it was associated with the Protection Against External Events attribute (i.e. fire) of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the temporary ignition source could have affected a nearby safety -related SLC pump motor and cables, which provide a shutdown mitigation function. The finding was screened using NRC IMC 0609, Appendix F, Fire Protection Significance Determination Proc ess, dated September 20, 2013. Using IMC 0609, Appendix F, Attachment 1, Fire Protection SDP Phase 1 Worksheet, dated September 20, 2013, the findi ng was assigned to the Fire Prevention and Administrative Controls category because the portable heater is part of the plants combustible materials control program. Proceeding to Task 1.3.1 of IMC 0609, Appendix F, Attachment 1, the inspectors determined the finding was of very low safety significance (Green), because even if one train of SLC had been inoperable, the reactor was able to reach and maintain safe shutdown. This finding had a cross cutting aspect in the area of human performance associated wi th the teamwork aspect because individuals failed to effectively communicate and coordinate their activities to ensure that the temporary heaters were energized following prescribed fire protection control measures and written instructions. (H.4) |
| 05000341/FIN-2017001-02 | Fermi | 2017Q1 | Failure to Maintain Adequate SLC Storage Tank Boron Concentration | Green . A finding of very low safety significance with an associated Non- Cited Violation of TS 3.1.7, Standby Liquid Control (SLC) System, was self -revealed when the licensee measured the boron concentration in the SLC storage tank and discovered the concentration was below the minimum requirement of 8.5 percent. Specifically, the licensee failed to adequately monitor and identify a decreasing trend in SLC storage tank sodium pentaborate concentration concurrent with known dilution of the SLC storage tank during pump and valve testing. The licensee entered this violation into its corrective action program for evaluation and identifi cation of appropriate corrective actions and restored the SLC sodium pentaborate concentration to within TS limits. The finding was of more than minor safety significance because it was associated with the Equipment Performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, a lower than allowable sodium pentaborate concentration affected the SLC systems ability to shut down the reactor during a design basis event. The finding was determined to be a licensee performance deficiency of very low safety significance during a detailed Significance Determination Process review since the delta core damage frequency ( CDF ) was determined to be less than 1.0E 6/year. The inspectors concluded this finding affected the cross -cutting area of human performance and the cross -cutting aspect of resources. Specifically, the licensee failed to ensure equipment and procedures were adequate to support nuclear safety . Th is issue would have been avoided if the system monitoring plan was trending tank level via a pressure indicator . Also, chemistry had no administrative limits in their procedure to add boron prior to the minimum TS limit was reached and the system engineer was not a reviewer on the routine surveillance procedure and was not trending the concentration as a backup. (IMC 0310, H.1 ) |
| 05000440/FIN-2016004-04 | Perry | 2016Q4 | Failure to Notify the NRC within Eight Hours of a Non-Emergency Event that Could Have Prevented the Fulfillment of a Safety Function | Severity Level IV. The inspectors identified a Severity Level IV NCV of Title 10 of the Code of Federal Regulations (10 CFR) 50.72(b)(3)(v)(A) and (D), for the licensees failure to report to the NRC within eight hours, an event or condition that could have prevented the fulfillment of a safety function. The licensees evaluation of this condition, where both trains of the standby liquid control (SLC) system had been inoperable simultaneously, determined that it was not a reportable event. However, the inspectors determined that as described in NUREG 1022, Event Reporting Guidelines 50.72 and 50.73, Revision 3, Section 3.2.7, the licensee had failed to make a non-emergency eight hour report as required by 10 CFR 50.72(b)(3)(v)(A) and (D). The licensee submitted the eight-hour report on December 30, 2016, and entered this issue into the corrective action program (CAP) as CR 201700098. The failure to make an applicable non-emergency eight-hour event notification report within the required time frame was determined to be a performance deficiency. The inspectors determined that traditional enforcement was applicable to this issue because it impacted the NRC's regulatory process. In accordance with Section 2.2.2.d, and consistent with the examples included in Section 6.9.d.9 of the NRC Enforcement Policy, this violation was screened as a Severity Level IV violation that was more than minor. In accordance with IMC 0612, because this violation involved traditional enforcement and does not have an underlying technical violation that would be considered more-than-minor, a cross-cutting aspect was not assigned to this violation. |
| 05000298/FIN-2016008-01 | Cooper | 2016Q3 | Possible Failure to Ensure that the Assumptions in the Engineering Analysis Remain Valid | As part of the transition to a performance-based, risk-informed fire protection program, the licensee adopted the requirements of NFPA 805. NFPA 805 requires the following in Section 2.6: Monitoring. A monitoring program shall be established to ensure that the availability and reliability of the fire protection systems and features are maintained and to assess the performance of the fire protection program in meeting the performance criteria. Monitoring shall ensure that the assumptions in the engineering analysis remain valid. The team reviewed selected samples of equipment monitored by the licensee using Procedure 3-CNS-DC-357, NFPA 805 Monitoring Program, Revision 0, to ensure that the licensees program properly implemented the requirements of NFPA 805, Section 2.6. The team also reviewed Engineering Report Number ER2015-002, NFPA 805 Fire Protection Monitoring Program, Revision 2. The team observed that for components used in the fire probabilistic risk assessment, the unavailability time for those components was monitored using the existing maintenance rule monitoring program. These components included the: Control rod drive pumps Core spray pumps Emergency diesel generators Emergency station service transformer Startup station service transformer High pressure core spray pump Instrument air compressors Residual heat removal pumps Standby liquid control pumps Service water pumps The team noted that the action levels for availability in the maintenance rule monitoring program were greater than the assumptions in the fire probabilistic risk assessment. With this observation, the team questioned the licensee as to whether this met the requirement in NFPA 805 to maintain the assumptions in the engineering analysis. The licensee informed the team that they had performed a sensitivity analysis to determine the significance of monitoring at a higher level of unavailability via the maintenance rule. This analysis determined an increase in core damage frequency for the additional unavailability time that could be accrued above the assumption for availability in the fire probabilistic risk assessment and up to the maintenance rule monitoring value for unavailability. This increase in core damage frequency was then determined to be acceptable if it did not exceed 1.0E-6/year. The team noted that for an individual component this screening criterion would not exceed more than 2 percent of the licensees baseline fire core damage frequency. The team was aware that some particular aspects of the monitoring program were being discussed between the industry and the NRCs Office of Nuclear Reactor Regulation during periodic public meetings which discussed Frequently Asked Question 10-0059, NFPA 805 Monitoring. The monitoring program and the sensitivity analysis approach used by the licensee are enveloped in these discussions. The team determined that additional information is required to determine if a performance deficiency exists. Specifically, the team needed to determine if the licensees action to set the action levels for the availability of some plant components at the components maintenance rule monitoring values and the performance of a riskinformed sensitivity analysis in an attempt to ensure that the assumptions in the engineering analysis remained valid would be an acceptable approach. Judgment on the suitability of this approach is pending further resolution of the monitoring program during discussions of Frequently Asked Question 10-0059, NFPA 805 Monitoring. The licensee entered this issue of concern into the corrective action program as Condition Report CR-CNS-2016-05109. This issue of concern is being treated as Unresolved Item 05000298/2016008-01, Possible Failure to Ensure that the Assumptions in the Engineering Analysis Remain Valid. |
| 05000388/FIN-2016001-01 | Susquehanna | 2016Q1 | Failure to Assess and Manage Risk of Maintenance Activities for a SLC System Flow Surveillance | The inspectors identified a Green NCV of 10 CFR 50.65(a)(4) because Susquehanna did not adequately assess the risk of performing maintenance in accordance with station procedures. Specifically, Susquehanna did not assess the risk of performing a standby liquid control (SLC) system flow surveillance in conjunction with having the D emergency diesel generator (EDG) unavailable and therefore did not specify appropriate risk management actions (RMAs). Susquehanna entered the issue into the CAP as CR-2016-04137. The inspectors determined that this performance deficiency is more than minor because it was associated with the Human Performance attribute of the Mitigating Systems cornerstone and affected the cornerstone objective to ensure the availability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Additionally, the finding is similar to example 7.e. in NRC IMC 0612 Appendix E, Examples of Minor Issues. This example states, in part, that failure to perform an adequate risk assessment when required by 10 CFR 50.65 (a)(4) is not minor if the overall elevated plant risk would put the plant into a higher licensee-established risk category or would require, under plant procedures, RMAs or additional RMAs. In this case, the combination of the D EDG maintenance and SLC flow surveillance resulted in changing risk to Yellow which required additional RMAs in accordance with station procedures. The inspectors evaluated the finding using IMC 0609 Appendix K, Maintenance Risk Assessment and Risk Management SDP. The inspectors and the Region I senior resident analyst used Appendix K, Flowchart 1, Assessment of Risk Deficit, and determined that the inadequate risk assessment was of very low safety significance (Green). The basis for this determination was that the short duration of the actual planned maintenance activities (3.5 hours) associated with the SLC unavailability results in less than E-9 calculated incremental core damage probability deficit (ICDPD) using Susquehannas risk model. Since the resultant ICDPD is below 1 E-8 threshold, the finding was determined to be Green. This finding was determined to have a cross-cutting aspect in the area of Human Performance, Work Management in that Susquehanna did not appropriately incorporate insights from probabilistic risk assessments into the daily work activities (H.5). Specifically, Susquehanna did not appropriately assess the risk of performing maintenance activities as specified in station procedures. |
| 05000219/FIN-2015004-01 | Oyster Creek | 2015Q4 | Preconditioning of the Standby Liquid Control Relief Valves | The inspectors identified an NCV of 10 Code of Federal Regulations (CFR) 50, Appendix B, Criterion XI, Test Control, because Exelon conducted unacceptable preconditioning of the standby liquid control (SLC) relief valves prior to American Society of Mechanical Engineers (ASME) code testing. Specifically, Exelon performed a SLC system functional test prior to performing the SLC relief valve as-found testing. Exelons immediate corrective actions included completing the as-found test prior to the functional test. Exelon entered this issue into their corrective action program (CAP) as issue report 2566036 to track the resolution of the issue. The performance deficiency is more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone and affects the cornerstone objective of ensuring availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Additionally, if left uncorrected, the performance deficiency could have the potential to lead to a more significant safety concern. Specifically, completion of the functional test prior to the replacement of the SLC relief valves masks the actual as-found condition by solidifying the valve internals. As a result, the as-found condition of the SLC relief valves have not been conducted and in the worst case scenario, could open below the design setpoint, which would divert flow back to the liquid poison tank instead of into the vessel to shut down the reactor during an anticipated transient without scram (ATWS) condition. The inspectors evaluated the finding using IMC 0609, Attachment 4, Initial Screening and Characterization of Findings, and determined the finding was of very low safety significance (Green) because the structure, system or component (SSC) maintained its operability. The finding has a cross-cutting aspect in the area of Problem Identification and Resolution, Evaluation because Exelon did not thoroughly evaluate issues to ensure that resolutions address causes and extent of conditions commensurate with their safety significance. Specifically, Exelon did not evaluate the effect of performing the SLC system functional test prior to conducting the ASME code as-found test on the SLC relief valves. |
| 05000397/FIN-2015004-02 | Columbia | 2015Q4 | Licensee-Identified Violation | Technical Specification 5.4.1.a, Procedures, requires, in part, that written procedures be established, implemented, and maintained covering the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, dated February 1978. Paragraph 9.a of Regulatory Guide 1.33, Appendix A, requires, in part, written procedures for performing maintenance that can affect the performance of safety-related equipment. The licensee established Procedures ISP-MS-Q901, RPS, Reactor Water Level Low, Level 3 Div 1 CFT/CC, Revision 10, and PPM 10.24.34, PM Calibration Test Barton Differential Indicating Switch, Revision 13, to meet the Regulatory Guide 1.33 requirements when performing maintenance on safety-related Barton main steam level indicating switches. Contrary to the above, prior to June 25, 2015, the licensee failed to maintain written procedures for performing maintenance that can affect the performance of safety-related equipment. Specifically, the licensee failed to include instructions in Procedures ISP-MS-Q901 or PPM 10.24.34 for setting the mechanical stop inside Barton main steam level indicating switches. Subsequently, the mechanical indicator in the switches for MS-LIS-24A and MS-LIS-24C became mechanically bound on the rubber stop within the switch when the level was raised off-scale high during the refueling outage. The licensee implemented corrective action by inserting a half scram signal to comply with technical specifications, calibrating the affected switches including steps to set the mechanical stop, and initiating a condition report. The finding represented a loss of safety system function for reactor water level low (level 3) scram signals and for shutdown cooling isolation logic. Because the finding affected mitigating equipment during at-power and shutdown operations, the inspectors assessed the finding in both the Inspection Manual Chapter (MC) 0609, Appendix A, Significance Determination Process for At-Power Findings, and MC 0609, Appendix G, Shutdown Operations Significance Determination Process. Using Exhibit 2 of MC 0609, Appendix A, and Exhibit 3 of MC 0609, Appendix G, inspectors determined that the finding required a detailed risk evaluation for the at-power portion of the finding and a Phase 2 evaluation for the shutdown portion of the finding because the finding represented a loss of safety-system function. A Region IV senior reactor analyst determined the issue was of very low safety significance (Green) and represented a total change to the core damage frequency of 4.4E-7/year. The dominant sequences were anticipated transients without scram and shutdown loss of inventory. For the at-power exposure, risk was mitigated by the use of the standby liquid control system and recirculation pump trips for the anticipated transients without scram. For the shutdown exposure, risk was mitigated by automatic injection by an emergency core cooling system pump for the losses of inventory. This issue was entered into the licensees corrective action program as AR 332078. |
| 05000259/FIN-2014004-04 | Browns Ferry | 2014Q3 | Inadequate NPSH Calculations for Standby Liquid Control Pumps | The NRC identified a Green non-cited violation (NCV) of 10 CFR Part 50 Appendix B, Criterion III, Design Control, for the licensees failure to maintain adequat control measures for verifying or checking the adequacy of design of the Standby Liqui Control (SLC) system. Specifically, the licensees calculations and system testing wer both inadequate to demonstrate that the SLC system could meet design requirement under all required operating conditions. The licensee entered this in their CAP as PE 920418 and initiated corrective actions to perform a modification to the SLC system an update design calculations. The inspectors determined that the licensees failure to maintain adequate control measures for verifying or checking the adequacy of design of the SLC system as required by 10 CFR 50, Appendix B, Criterion III, Design Control, was a performance deficiency (PD). Specifically, the licensees calculations and system testing were both inadequate to demonstrate that the SLC system could meet design requirements under all required operating conditions. The PD was more than minor because it affected the Mitigating Systems Cornerstone attribute of Design Control, and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, there was not an adequate method for ensuring the capability of the design of the SLC system following a design basis accident. The inspectors screened this finding in accordance with IMC 0609, Appendix A, Significance Determination Process, Exhibit 2-Mitigating Systems Screening Questions, dated June 19, 2012, and determined the finding was of very low safety significance (Green) because the design deficiency did not result in a loss of operability or functionality. The inspectors determined that no cross cutting aspect was applicable because this finding was not indicative of current licensee performance and occurred more than three years ago. |
| 05000324/FIN-2014004-04 | Brunswick | 2014Q3 | Failure to Correct SLC Tank Level Indication Degradation | An NRC-identified Green finding of Licensee Procedure AD-PI-ALL-0100, Corrective Action Program (CAP), was identified for the failure of the licensee to identify and correct a condition adverse to quality with the Unit 2 standby liquid control (SLC) control room level indicator. Specifically, between February 25, 2012, and August 17, 2014, the licensee failed to identify and correct three clogged SLC tank level indicators before th indicators failed. The licensees corrective actions included cleaning out the SLC tank level indicator bubbler and evaluating the adequacy of the preventative maintenance associated with this indicator. The licensee entered this issue into the CAP as NCRs 704327 and 704593. The inspectors determined that the failure of the licensee to identify and correct the clogged SLC tank level indicators before the indicators failed was a performance deficiency. The finding was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone and affects the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, this resulted in the instrument reading a higher tank level than actual due to the flow restriction in the bubbler tube, and the inoperability of the instrument. Using IMC 0609, Appendix A, issued June 19, 2012, the SDP for Findings At-Power, the inspectors determined the finding was of very low safety significance (Green) because the finding did not affect the design or qualification of a mitigating structure, system and component (SSC), the finding did not represent a loss of system and/or function, the finding did not represent an actual loss of a function of a single train for greater than the technical specifications (TS) allowed outage time, the finding did not represent an actual loss of a function of one or more non-TS trains of equipment, and did not screen as potentially risk-significant due to a seismic, flooding, or severe weather initiating event. The finding has a cross-cutting aspect in the area of human performance associated with the work management attribute because the licensee failed to implement a process of planning, controlling, and executing work activities such that nuclear safety is the overriding priority. The licensee failed to have the work process include the identification and management of risk commensurate to the work and the need for coordination with different groups. Specifically, the licensee failed to identify and manage the risk of the SLC tank level indicator bubbler clogging issue. (H.5) |
| 05000263/FIN-2014003-01 | Monticello | 2014Q2 | Inadequate Standby Liquid Control Quarterly Pump and Valve Test Due to Proceduralized Unacceptable Preconditioning | The inspectors identified a finding of very low safety significance and a non-cited violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, on May 7, 2014, for the licensees failure to ensure that activities affecting quality were prescribed by documented procedures of a type appropriate to the circumstances. Specifically, the site changed Procedure 025502III, SBLC (standby liquid control) Quarterly Pumps and Valve Test, to include allowances for starting the safety-related SBLC pumps and adjusting a throttle valve to achieve the desired pump discharge pressure prior to performance of in-service testing, actions which, without evaluation, constituted unacceptable preconditioning. The inspectors determined that the licensees failure to ensure the SBLC pump and valve test surveillance procedure was appropriate to the circumstances was a performance deficiency requiring evaluation. The inspectors screened the performance deficiency and determined that the issue was more than minor because it adversely impacted the Mitigating Systems Cornerstone attribute of Procedure Quality, and affected the cornerstone objective to ensure the availability, reliability, and capability that respond to initiating events to prevent undesirable consequences (i.e., core damage). In addition, if left uncorrected, it had the potential to lead to a more significant safety concern. Specifically, proceduralizing actions which could constitute unacceptable preconditioning, such as manipulating the physical condition of a structure, system or component (SSC) before or during TS surveillance or ASME Code testing, could mask the actual as-found condition of the SSC and result in an inability to verify the operability of the SSC. The inspectors determined that this finding was of very low safety significance because each question listed in IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, was answered No. The inspectors concluded that this finding was cross-cutting in the Human Performance, Change Management aspect, because the licensee did not use a systematic process for evaluating and implementing change so nuclear safety remains the overriding priority. Specifically, revising procedures to allow the SBLC pump to be started for test configuration flow adjustments immediately prior to a surveillance test, without an evaluation of preconditioning acceptability, could mask the ability to detect degraded equipment performance. |
| 05000259/FIN-2014007-01 | Browns Ferry | 2014Q1 | Failure to Identify the Root Cause of the Failure of the 1B Standby Liquid Control Pump Breaker | An NRC identified non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, was identified for the licensees failure to adequately identify the root cause for a significant condition adverse to quality as defined in NPG-SPP-22.302 Revision 1, Corrective Action Program Screening and Oversight. Specifically, the licensee initially failed to identify the root cause of the failure of the 1B Standby Liquid Control (SLC) Pump breaker that resulted in the equipment exceeding the Technical Specification Limiting Condition for Operation. The issue was documented in the licensees corrective action program as Service Request (SR) 851718. This performance deficiency was more than minor since it adversely affected the Reactor Safety Mitigating Systems cornerstone objective of availability and reliability of affected equipment. Specifically, the failure to determine the cause of a crack in the breakers phase arc chute that fatigued over time impacted the ability to assign effective corrective actions to prevent recurrence and challenges the reliability of the safety-related equipment to provide required reactivity control capability when required for accident mitigation. The inspectors evaluated the risk of this finding using Manual Chapter 0609, Appendix A, Significance Determination Process (SDP) for Findings at Power. This determination was based on the evaluation that the inoperable equipment did not concurrently affect a single reactor protection system (RPS) trip signal to initiate a reactor scram, nor did it involve control manipulations that unintentionally added positive reactivity or result in a mismanagement of reactivity by operators. The finding had a cross-cutting aspect in the area of Problem Identification and Resolution, in the component of Evaluation, since the licensee failed to thoroughly evaluate issues to ensure that resolutions address causes and extent of conditions commensurate with their safety significance (P.2). |
| 05000354/FIN-2014002-03 | Hope Creek | 2014Q1 | Failure to Follow Procedure Resulting in the Potential Inoperability of a Safety-Related System | A self-revealing Green NCV of TS 6.8.1.a, Procedures and Programs, was identified for PSEGs failure to follow procedure HC.OP-SO.BH-0001, Standby Liquid Control (SLC) System Operation, when restoring the SLC system after routine maintenance. Specifically, the licensee failed to adequately coordinate the restoration of the SLC system using the work control document (WCD) and the SLC system operating procedure which led to an incorrect SLC system lineup causing the inadvertent addition of demineralized (DI) water to the SLC storage tank. As a result, PSEG had to determine the immediate and prompt operability of the SLC system and enter the associated 8 hour SLC Technical Specification Action Statement (TSAS). PSEGs corrective actions include restoring the SLC tank concentration, briefing the operating crews on proper WCD turnover process, and addressing operator gaps in the SLC system operation that may have adversely affected the timeline and the inaccuracy of the immediate operability calculation method. The performance deficiency was determined to be more than minor because it was associated with the configuration control attribute of the Mitigating System cornerstone, and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, failing to follow procedure leading to configuration control issues could have rendered a safety-related system inoperable. This performance deficiency was also similar to examples 3.j and 3.k of NRC IMC 0612, Appendix E, in that the addition of 80 gallons of DI water to the SLC tank created a reasonable doubt of operability of the SLC system. The inspectors determined the finding to be of very low safety significance (Green) in accordance with IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, dated June 19, 2012. Using Exhibit 2, the inspectors determined that the finding screened as very low safety significance (Green) because although the SLC tank boron concentration was diluted, the SLC system was still capable of providing sufficient negative reactivity to shut down the reactor. The inspectors determined that the contributing cause that provided the most insight into the performance deficiency was associated with the cross-cutting aspect of Human Performance, Work Management, because PSEG failed to implement a process of planning, controlling, and executing work activities such that nuclear safety is the overriding priority. |
| 05000263/FIN-2013005-02 | Monticello | 2013Q4 | SBLC Discharge Pressure Procedural Limits Exceed | The inspectors identified a finding of very low safety significance and associated NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, when the licensee failed to accomplish activities affecting quality in accordance with instructions, procedures, or drawings. Specifically, licensee personnel failed to abide by procedural requirements for pump discharge pressure limitations contained in Procedure 0255-02-III, SBLC Quarterly Pump and Valve Tests, when they imprecisely controlled the 11 standby liquid control (SBLC) flow control valve during the test. This led to the halting of the SBLC test while the equipment condition was evaluated and resulted in the validity of the inservice test (IST) data being brought in to question. The licensee re-performed the test for the 11 SBLC pump; stood down the workers involved; increased operational oversight of the test; evaluated the condition of the equipment; performed a human performance event review; and included communication of the error as part of a site-wide stand down. This issue was entered into the licensees corrective action program (CAP 1401816). The inspectors determined that the licensees failure to abide by SBLC procedural limitations was a performance deficiency, because it was the result of the failure to meet the requirements of 10 CFR 50, Appendix B, Criterion V; the cause was reasonably within the licensees ability to foresee and correct; and should have been prevented. The inspectors screened the performance deficiency per Inspection Manual Chapter (IMC) 0612, Power Reactor Inspection Reports, Appendix B, and determined that the issue was more than minor because, if left uncorrected, it had the potential to lead to a more significant safety concern. Specifically, if pressure limitations had been further exceeded, the discharge relief valve would have lifted, which could result in inoperability of the 11 SBLC pump until repair or replacement of the relief valve. In addition, inadequately performing the SBLC surveillance and IST testing could have the potential to mask degraded conditions associated with the pump. The inspectors applied IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, to this finding. The inspectors utilized Exhibit 2, Section A, Mitigating Systems, to screen the finding. The finding was determined to have very low safety significance because the inspectors answered No to all four questions. The inspectors determined that the contributing cause that provided the most insight into the performance deficiency was associated with the cross-cutting area of Human Performance, having work practices components, and involving aspects associated with using human error prevention techniques during performance of work activities. |
| 05000387/FIN-2013004-02 | Susquehanna | 2013Q3 | Failure to Assess and Manage Risk of Maintenance Activities | The inspectors identified a Green NCV of 10 CFR 50.65(a)(4) because PPL did not adequately assess the risk of performing maintenance in accordance with station procedures. Specifically, PPL did not specify appropriate risk management actions (RMAs) while performing a standby liquid control (SLC) system flow surveillance in conjunction with having the E emergency diesel generator (EDG) unavailable. PPLs immediate corrective actions included entering the issue into their CAP as condition reports (CRs) 1721928 and 1781929, communicating the issue to applicable station personnel, and revising the risk assessment for use in future performance of the maintenance activities. The performance deficiency is more than minor because it affected the Human Performance attribute of the Mitigating Systems cornerstone objective to ensure the availability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). The item is similar to example 7.e. in NRC IMC 0612 Appendix E, Examples of Minor Issues. This example states, in part, that failure to perform an adequate risk assessment when required by 10 CFR 50.65 (a)(4) is not minor if the overall elevated plant risk would require, under plant procedures, RMAs or additional RMAs. In this case, the SLC flow surveillance was required to be screened as high operational risk due to the short duration limiting condition of operation (LCO) entry and medium or high operational risk due to changing risk to Yellow when performed in conjunction with the E EDG unavailability. Both of these categories required additional RMAs in accordance with station procedures. In accordance with IMC 0609.04, Initial Characterization of Findings, and IMC 0609, Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process, the inspectors determined that this finding is of very low safety significance (Green) because the performance deficiency was associated with RMAs only and the incremental core damage probability was < 1E-6 and the incremental large early release probability was < 1E-7. This finding was determined to have a cross-cutting aspect in the area of Human Performance, Work Control in that PPL failed to appropriately plan work activities by not incorporating risk insights. Specifically, PPL did not appropriately assess the risk of performing maintenance activities by including required risk manage actions as specified in station procedures. |
| 05000298/FIN-2013009-01 | Cooper | 2013Q1 | Failure to Maintain Seismic Qualification of Standby Liquid Control System | The team identified a Green violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to assure that design basis requirements associated with the standby liquid control (SLC) system test tank were correctly translated into procedures. As a result, the licensee failed to maintain the tank empty as required to meet seismic design requirements. The violation is cited because the licensee failed to restore compliance in a reasonable time following documentation of the issue as a non-cited violation in NRC Inspection Report 05000298/2012002, issued May 10, 2012 (ML12131A674). The licensee entered these issues into its corrective action program for resolution as Condition Report CR-CNS-2013-01962, CR-CNS-2013-02027, and CR-CNS-2013-02328. The failure to maintain design control of the standby liquid control system was a performance deficiency. This performance deficiency was of more than minor safety significance because it was associated with the design control attribute of the mitigating systems cornerstone and it adversely affected cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensees failure to implement procedures to ensure the SLC test tank remained in a seismically qualified condition resulted in an inability to provide reasonable assurance of operability following a seismic event. Using Inspection Manual Chapter 0609, Appendix A, Exhibit 2, the team determined that the finding was of very low safety significance (Green) because it was a design deficiency that did not result in the loss of functionality. This finding had a cross-cutting aspect in the area of human performance associated with the decision-making component because the licensee failed to adopt a requirement to demonstrate that a proposed action was safe in order to proceed rather than a requirement to demonstrate it was unsafe in order to disapprove the action. |
| 05000298/FIN-2013009-02 | Cooper | 2013Q1 | Failure to Notify the NRC within Eight Hours of a Nonemergency Event | The team identified a Severity Level IV non-cited violation of 10 CFR 50.72, Immediate Notification Requirements for Operating Nuclear Power Reactors, for the licensees failure to make a required report to the NRC. After the licensee determined that the standby liquid control test tank could not meet Seismic Class I requirements unless empty, the team discovered that the tank was full. The licensee immediately drained the tank and implemented a compensatory action to maintain it empty. However, the licensee failed to recognize that because the compensatory measure was required to provide a reasonable assurance of operability, the as-found condition of the SLC systemwith the test tank fullrendered both trains of the system inoperable. Because this could have prevented the fulfillment of the SLC systems safety function, the licensee was required to report the condition to the NRC within eight hours of discovery. After identification, the licensee entered this issue into its corrective action program and made a late report to the NRC, restoring compliance with the regulation. The failure to make a required report to the NRC within the required time was a performance deficiency. The team determined that traditional enforcement applied to this violation because the violation impeded the regulatory process. Specifically, the NRC relies on the licensee to identify and report conditions or events meeting the criteria specified in regulations in order to perform its regulatory oversight function. Assessing the violation in accordance with Enforcement Policy, the team determined it to be of Severity Level IV because it involved the licensees failure to make a report required by 10 CFR 50.72 (Enforcement Policy example 6.9.d.9). Because this was a traditional enforcement violation with no associated finding, no cross-cutting aspect is assigned to this violation. |
| 05000440/FIN-2013002-03 | Perry | 2013Q1 | Failure to Follow Procedures for Conducting a Standby Liquid Control System Surveillance | A self-revealed finding of very low safety significance and associated non-cited violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified when the licensee failed to correctly implement procedures for testing safety-related equipment. Specifically, the licensee failed to correctly implement prerequisite steps in a surveillance instruction, causing the standby liquid control (SLC) pump \'A\' plunger pot drain valves to be left open, contrary to procedure. The licensee entered the finding into the corrective action program as Condition Report 2013-00114 and took immediate action to close the valves when leakage was discovered from the drain valve tailpipes. The inspectors determined that the failure to correctly complete the prerequisite steps in surveillance instruction (SVI)-C41-T2001-A was a performance deficiency which resulted in a water spill in containment, an associated lockup of the rod control and information system (RCIS), and required the licensee to enter two off-normal instructions (ONIs). The performance deficiency was determined to be more than minor, and thus a finding, using Inspection Manual Chapter (IMC) 0612, Appendix E, Examples of Minor Issues, dated August 11, 2009, because it is similar to Example 4.b and resulted in an unexpected, Inhibit Rod Motion RCIS OOS, alarm and caused the operating crew to enter ONI-C11-1, Inability to Move Control Rods. The finding was evaluated for significance using IMC 0609, Attachment 0609.04, dated June 19, 2012, and IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, dated June 19, 2012. In answering no to C. Reactivity Control Systems, questions 1, 2, and 3, the inspectors determined that the finding was of very low safety significance because the finding did not affect a reactor protection system trip signal, did not add positive reactivity, nor did it result in the mismanagement of reactivity by an operator. The finding has a cross-cutting aspect in the area of human performance associated with the work practices component, in that licensee personnel failed to use human error prevention techniques, such as holding a pre-job briefing, self and peer checking, and proper documentation of activities. Specifically, the operation to position the plunger pot drain valves on the \'A\' and \'B\' SLC pumps was not coordinated by the field supervisor in accordance with the SVI and operations personnel proceeded in the face of uncertainty or unexpected circumstances. |
| 05000458/FIN-2012005-02 | River Bend | 2012Q4 | Inadequate Procedures for Lubrication of the Standby Liquid Control Pump Motor Bearings | The inspectors identified a non-cited violation of Technical Specification 5.4.1.a for not establishing appropriate lubrication procedures for the standby liquid control pump motor bearings. Specifically, the station incorrectly used the Electrical Power Research Institute (EPRI) guidance for maintenance procedure by adding twice the amount of grease required. This issue was entered into the licensees corrective action program as Condition Report CR-RBS-2012-05573. The failure to establish appropriate lubrication procedures is a performance deficiency. This performance deficiency is more-than-minor and is therefore a finding because if left uncorrected, it has the potential to lead to a more significant safety concern. Specifically, if the work instructions were not corrected, future work activities that grease the motor bearings in accordance with those work orders would over-grease the bearings, which may result in common-cause failures of standby motors. In accordance with NRC Inspection Manual Chapter 0609, Attachment 4, Initial Characterization of Findings, and NRC Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process for Findings At Power, Exhibit 2, Section A.1, this finding screened as very low safety significance (Green). Specifically, the finding is a deficiency that affected the qualification of the standby liquid control pump motors; however, the systems maintained their operability. Because the most significant causal factor of the performance deficiency was station personnel and management failing to fully evaluate the previously identified inadequate lubrication of motors, this finding has a problem identification and resolution cross-cutting aspect associated with the corrective action program component |
| 05000219/FIN-2012005-01 | Oyster Creek | 2012Q4 | Failure to Follow Inspection and Torquing of Bolted Connection Procedure | The inspectors identified a Green non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, because Exelon did not properly implement procedural controls to ensure adequate thread engagement for standby liquid control (SLC) squib valve spool piece flanges. Specifically, SLC squib valve flanges were installed with inadequate thread engagement (stud was not flush with the nut), as required by Exelons maintenance procedures. Exelons corrective actions included declaring the system inoperable, entering the issue into the corrective action program (IR 1444861 and 1444862) and immediately replacing the existing bolts with bolts of an appropriate length such that projection through the nut was at least flush. The performance deficiency was more than minor because if left uncorrected the inadequate thread engagement would have the potential to lead to a more significant safety concern. Specifically, Exelons evaluation stated that the SLC squib valve spool piece flanges would not have been able to perform their design function under all seismic conditions when the system was required to be operable. In consultation with the Region I senior reactor analyst, the inspectors reviewed this condition using IMC 0609, Attachment G, Shutdown Operations Significance Determination Process. As the condition occurred during the refueling outage and was identified and corrected before Exelon started up the Oyster Creek reactor, and only existed during the outage when SLC was not required to be operable (November 16 27, 2012), the issue screened to very low safety significance (Green). This finding has a cross-cutting aspect in the area of Problem Identification and Resolution, Corrective Action Program, because Exelon did not take appropriate corrective actions to address safety issues and adverse trends in a timely manner, commensurate with their safety significance and complexity. Specifically, Exelon did not take appropriate corrective actions, such as replacing bolts during the refueling outage with longer bolts, after the NRC identified a similar concern on the same SLC squib valve spool piece flanges in September 2012 (IR 1417726). |
| 05000416/FIN-2012004-02 | Grand Gulf | 2012Q3 | Failure to Follow Procedure Results in Inadequate Operability Determination | The inspectors identified two examples of a non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, regarding the licensees failure to follow the requirements of Procedure EN-OP-104, Operability Determinations. Specifically, for Condition Report CR-GGN-2012-09690, which documents an oil leak on the standby liquid control pump B, and for Condition Report CR-GGN-2012-09889, which documents degraded bolts on a flanged connection on standby service water B piping, the licensee failed to validate that operability evaluations completed for prior non-conforming conditions bounded the conditions documented in the new condition reports. As immediate corrective actions, the licensee re-performed the evaluations and established an adequate basis for operability for the conditions described in the two condition reports listed above. The licensee entered this issue into their corrective action program as CR-GGN-2012-09735 and CR-GGN-2012-10664. The finding was more than minor because if left uncorrected, not performing operability determinations in accordance with procedure could lead to a more significant safety concern. Specifically, if a condition renders a safety related system inoperable and because of this performance deficiency the licensee incorrectly determines that the system is operable, then this performance deficiency could result in a safety related system remaining inoperable for a long period of time. Using NRC Inspection Manual Chapter 0609, Attachment 4, Initial Characterization of Findings, the inspectors determined that the issue affected the Mitigating Systems Cornerstone. In accordance with NRC Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings at Power, the inspectors determined that the issue has very low safety significance (Green) because although it affected the design or qualification of a mitigating system, the system maintained its operability. The finding had a cross-cutting aspect in the problem identification and resolution area, corrective action program component because the licensee failed to properly evaluate for operability conditions adverse to quality |
| 05000298/FIN-2012007-06 | Cooper | 2012Q2 | Failure to Incorporate all Design and Technical Data Available into the Operability Determinations for the Standby Liquid Control Tank and Test Tank | The team identified a Green noncited violation, with two examples, of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, which states, in part, Activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. or shall include appropriate quantitative or qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished. Specifically, prior to April 4, 2012, the licensee did not follow the requirements of Cooper Nuclear Station Operations Manual Administrative Procedure 0.5.0PS, Operations Review of Condition Reports/Operability Determination, Section 6 Prompt Determination, Step 6.1.1.6. This step requires the use of Attachment 3, Item 3, which addresses design basis assumptions, descriptions, calculations, or values used in the Cooper Nuclear Station Updated Safety Analysis Report shall be used to ensure all aspects of the condition are addressed. For two, separate, Prompt Operability Determinations, one for the standby liquid control test tank, and the second one for the standby liquid control tank, the licensee had not considered the effect of vertical seismic loading in their calculation as identified in the Updated Safety Analysis Report (Table -3-7 page C-3-73). These findings were entered into the licensee\'s corrective action program as Condition Reports CR-CNS-2012-001214, CRCNS- 2012-001232, CR-CNS-2012-001651, CR-CNS-2012-001918 and CR-CNS-2012- 01962. The team determined that the failure to follow the requirements of Cooper Nuclear station Operations Manual Administrative Procedure 0.5.0PS, Operations Review of Condition Reports/Operability Determination, Step 6.1.1.6, was a performance deficiency. 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 of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. In accordance with NRC Inspection Manual Chapter 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, the issue was determined to have very low safety significance (Green) because it \'Nas a design deficiency confirmed not to result in loss of operability or functionality. Specifically, the licensee revised the associated calculations to include the correct required standards, with acceptable results. This finding was determined to have a crosscutting aspect in the area of problem identification and resolution associated with the corrective action program component because the licensee failed to properly classify, prioritize, and evaluate for operability and reportability, conditions adverse to quality . |
| 05000298/FIN-2012003-04 | Cooper | 2012Q2 | Failure to Maintain Design Control of the Standby Liquid Control System and Sumps Credited in the Internal Flooding Analysis | The inspectors identified two examples of a non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, associated with the licensees failure to: (1) assure that the applicable seismic design basis requirements associated with the standby liquid control system storage tank was correctly translated into the plant design to ensure that the standby liquid control system would remain operable following a seismic event and; (2) maintain design control of sumps credited in the stations internal flooding analysis. These issues were entered into the licensees corrective action program as Condition Reports CR-CNS-2012-01918 for the standby liquid storage tank and CR-CNS-2012-02414, CR-CNS-2012-02509, CR-CNS-2012-02510, CR-CNS-2012-02752, and CR-CNS-2012-02767 for the oil absorbent bags. The licensees failure to maintain design control of the standby liquid control system and sumps credited for the stations internal flooding analysis was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the design control attribute of the Mitigating Systems Cornerstone, and affected the associated cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences, and is therefore a finding. The inspectors evaluated the finding using Inspection Manual Chapter 0609.04, Phase 1 Initial Screening and Characterization of Findings. The inspectors determined that the finding is of very low safety significance (Green) because the finding: (1) was not a design or qualification issue confirmed not to result in a loss of operability or functionality; (2) did not represent an actual loss of safety function of system or train; (3) did not result in the loss of one or more trains of nontechnical specification equipment; (4) did not screen as potentially risk significant due to seismic, flooding, or severe weather initiating event. The finding was determined to have a cross-cutting aspect in the area of problem identification and resolution associated with the corrective action component because: (1) the licensee failed to thoroughly evaluate concerns with seismic analysis of the standby liquid control system such that the resolution addresses causes an extent of conditions, as necessary, during the development of NEDC 12-015; and (2) the licensee had the opportunity in 2010 and early 2012 during reviews of the internal flooding analysis to identify that oil absorbent bags contained in the sumps credited in the internal flooding analysis did not contain an analysis and were an unapproved modification. |
| 05000237/FIN-2012008-02 | Dresden | 2012Q1 | Failure to Conduct Adequate Post Installation and Maintenance Inspections on Standby Liquid Control System Components | The inspectors identified a finding of very low safety significance (Green) and associated NCV of 10 CFR Part 50, Appendix B, Criterion X, Inspection, for the licensees failure to perform adequate post-installation and post-maintenance inspections on standby liquid control (SBLC) heat tracing and pumps. Specifically, the licensee failed to verify that heat tracing on the SBLC system components was properly installed and later failed to verify that thermal insulation was properly replaced following maintenance on the SBLC pumps, which led to thermal degradation of the explosive material in the squib valves. The licensee entered this issue into their corrective action program and replaced the 3B squib valve. The inspectors determined that the finding was more than minor because the finding was associated with the Mitigating Systems cornerstone attribute of equipment performance and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). The finding was of very low safety significance based on a Phase III Significance Determination Process Analysis. This finding had a cross-cutting aspect in the area of problem identification and resolution, operating experience because the licensee did not properly implement vendor operating experience. |
| 05000298/FIN-2012002-04 | Cooper | 2012Q1 | Failure to Maintain Design Control of Standby Liquid Control System | The inspectors identified a non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, associated with the licensees failure to assure that the applicable design basis requirements associated with the standby liquid control system test tank were correctly translated into the plant design to ensure that the standby liquid control system would remain operable following a seismic event. The licensee entered this deficiency into their corrective action program for resolution as CR-CNS-2012-01214, CR-CNS-2012-01224, CR-CNS-2012-01232, and CR-CNS-2012-01651. The licensee subsequently performed station calculation NEDC 12-015 Standby Liquid Control Test Tank Seismic Evaluation that determined that the standby liquid control system would be operable following a seismic event with the standby liquid control system test tank full. The licensees failure to maintain design control of standby liquid control system was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the design control attribute of the Mitigating Systems Cornerstone, and affected the associated cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences because there were questions as to whether or not the standby liquid control system would remain functional during a seismic event. The inspectors evaluated the finding using IMC 0609.04 Phase 1 Initial Screening and Characterization of Findings. The inspectors determined that the finding is of very low safety significance (Green) because the finding: (1) was not a design or qualification issue confirmed not to result in a loss of operability or functionality; (2) did not represent an actual loss of safety function of system or train; (3) did not result in the loss of one or more trains of nontechnical specification equipment; (4) did not screen as potentially risk significant due to seismic, flooding, or server weather initiating event. This finding did not have a cross-cutting aspect because the most significant contributor did not reflect current licensee performance |
| 05000293/FIN-2011003-01 | Pilgrim | 2011Q3 | Transient Combustible Loading in SLC Room in Excess of the Fire Hazards Analysis Limit | The inspectors identified a Green NCV of License Condition 3.F of the Pilgri facitity Operating License (DPR-35) for the failure to evaluate transient combustible fir loading in the Standby Liquid Control (SLC) room. Specifically, Entergy did not evaluat the acceptability of transient combustibles that had been moved into the SLC room whic were in excess of the allowed combustible loading discussed in the Fire Hazards Analysis Entergy immediately walked down the area, established compensatory measures, an completed a transient combustibles evaluation. Entergy has since removed the transien combustibles from the area The inspectors determined that the failure to evaluate the transient combustibles was mor than minor based on a similar example described in Inspection Manual Chapter 0612 \\\"Power Reactor Inspection Reports,\\\" Appendix E, \\\"Examples of Minor lssues,\\\" Section 4k Specifically, the fire loading exceeded the Fire Hazard Analysis assumption and was no evaluated for acceptability. The finding is also associated with the Protection Agains External Events attribute of the Mitigating Systems cornerstone and could have adversel affected the cornerstones objective to ensure the availability of systems that respond t events to prevent undesirable consequences (i.e,, core damage). Specifically, a fire in th SLC room could affect the availability of the SLC system to respond to an event. IMC 0609 \\\"significance Determination Process,\\\" Appendix F, \\\"Fire Protection Significanc Det,ermination Process,\\\" was used to evaluate the significance of the finding. The safet significance of the finding was determined to be very low because the degradation facto was low; that is, the transient combustible evaluation process subsequently identified nearl the same level of fire protection effectiveness and reliability for the SLC room as it woul have if the degradation had not been present This finding had a cross-cutting aspect in the Human Performance cross-cutting area Work Control component; in that, Entergy did not coordinate work activities to ensure th interdepartmental coordination necessary to assure plant and human performance Specifically, the refueling organization did not notify fire protection engineering to ensure a evaluation of the\\\'transient combustible loading was completed for the SLC room (H.3(b)) (Section 1R05) |
| 05000373/FIN-2010006-01 | LaSalle | 2011Q1 | Supporting Structure for Standby Liquid Control System Test Tank Non-Functional During Postulated Design Basis Earthquake (DBE) | The team identified a finding of very low safety significance and an associated NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to have an adequate calculation to demonstrate the seismic qualification of the standby liquid control (SBLC) system test tanks. Specifically, the licensee could not ensure that the Units 1 and 2 SBLC test tanks, if filled with water, would not collapse and damage nearby safety-related components during a design basis event. The licensee entered this finding into their corrective action program and drained the water from the SBLC test tanks to restore seismic qualification. The team determined that this finding was more than minor because it was associated with the Mitigating Systems cornerstone attribute of equipment performance and affected the cornerstone objective of ensuring the availability of the SBLC system to respond to initiating events to prevent undesirable consequences (i.e., core damage). This finding was determined to be of very low safety significance (Green) utilizing the Risk-Assessment Standardization Project Handbook based on the frequency of seismic events. The finding did not have a cross-cutting aspect because it was not reflective of current performance. |
| 05000341/FIN-2010005-02 | Fermi | 2010Q4 | Standby Liquid Control Test Tank Operability | The inspectors identified an unresolved item (URI) for past operability of the standby liquid control (SLC) system and for the adequacy of the procedures utilized to perform the periodic SLC pump test. Specifically, the inspectors identified that the demineralized water in the SLC test tank had not been drained following each periodic test of the SLC pumps as a legacy condition. Further, they noted the SLC test tank could affect the SLC system operability following a seismic event, if there was still demineralized water remaining in the test tank. The SLC system is designed to provide the capability of bringing the reactor to a subcritical condition with the reactor in the most reactive, xenon free state without taking credit for control rod movement. The SLC system is classified as a seismic category I system. The SLC testing subsystem, which is designed to periodically test the two SLC pumps, includes the SLC test tank, some valves and piping. The SLC test tank is described in the USFAR as seismic category II/I. Therefore, it is a non-safety-related component within a safety-related envelope; and while not required to maintain its operability, it must not impact the category I portions of the system. To test the SLC pumps, demineralized water is put into the test tank, the SLC tank remains isolated, and the SLC pumps are lined up and locally started to recirculate the demineralized water through the SLC testing subsystem. The inspectors questioned whether the demineralized water in the SLC test tank was drained following the periodic test. Further, they questioned whether the SLC test tank could affect the SLC system operability following a seismic event, if there was still demineralized water remaining in the test tank. The plant procedure (24.139.02) used to periodically test the SLC pumps, as required by TS 3.1.7, did not require draining of the SLC test tank following testing. The procedure did not incorporate the General Electric maintenance instruction guidance to drain the test tank following pump testing. As an interim measure, the SLC test tank was drained of demineralized water, and the SLC pump testing procedure was revised to include guidance to drain the SLC test tank following testing. The initial operability evaluation provided by engineering concluded that the mounting of the SLC test tank would remain in place, and it would not impact the adjacent safety-related equipment. However, there are several outstanding technical questions regarding the evaluation. Engineering will revise the evaluation of past operability. Then the inspectors will review the revised operability evaluation to determine final resolution of this issue. Because the licensee is performing an engineering analysis of the SLC test tank mounting, this issue will be carried as an unresolved item in this report (URI 05000341/2010005-02, Standby Liquid Control Test Tank Operability). |
| 05000440/FIN-2010005-05 | Perry | 2010Q4 | Seismic Stability of Standby Liquid Control Test Tank | On November 8, 2010, the inspectors conducted a review of the quarterly pump and valve test for the standby liquid control system. Information from operating experience concerning seismic stability of similar SLC systems at other sites was incorporated in the review. The SLC system at other sites was determined to be not seismically stable with water in the tank, and the system operation at the other sites had been modified to involve only filling the test tank with water to support the actual conduct of a test. Perry subsequently directed draining of the test tank while an evaluation was conducted. The licensee conducted a detailed couple analysis of the tank, including the attached piping, to determine tank stability at both a 75 percent and 100 percent filled with water condition. The report, completed on December 8, 2010, determined that the tank would withstand a design basis faulted event. Regional specialist inspectors reviewed the evaluation and generated questions that have been asked of the licensee concerning the analysis. At the conclusion of the inspection period the inspectors and the licensee were continuing discussions regarding the seismic stability of the SLC test tank. Pending the results of additional discussions and additional information, this will remain open as an unresolved item (URI). |
| 05000397/FIN-2010005-04 | Columbia | 2010Q4 | Failure to Perform Engineering Evaluation to Determine Seismic Qualification of Safety-related Equipment | The inspectors identified a noncited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure to follow Procedure PPM 10.2.53, Seismic Requirements for Scaffolding, Ladders, Man-Lifts, Tool Gang Boxes, Hoists, Metal Storage Cabinets, and Temporary Shielding Racks, Revision 26. Specifically, the position of equipment was required to meet specific criteria to prevent damage to safety-related equipment during a seismic event. Contrary to this procedure, the inspectors identified that equipment was positioned adjacent to safety-related equipment without a supporting engineering evaluation. The inspectors notified the main control room personnel, who directed an equipment operator to immediately position the 55 gallon drum away from the standby liquid control system. This issue has been placed in the licensees corrective action program as Action Request/Condition Report 230872. This finding was more than minor because it was a human performance error which affected the Mitigating Systems Cornerstone objective to ensure the availability and reliability of systems that respond to initiating events to prevent undesirable consequences. The finding was determined to be of very low safety significance because it was not a design or qualification deficiency; it did not result in the loss of a system safety function; it did not represent the loss of a single train for greater than technical specification allowed outage time; it did not represent a loss of one or more non-technical specification risk-significant equipment for greater than 24 hours; and it did not screen as potentially risk significant due to seismic, flooding, or severe weather. A cross-cutting aspect in the human performance area with a work control component was identified in that Energy Northwest failed to appropriately plan work, resulting in job site conditions which may have impacted plant components (H.3.a). |
| 05000259/FIN-2010004-05 | Browns Ferry | 2010Q3 | Licensee-Identified Violation | TS LCO 3.1.7, Standby Liquid Control (SLC) System, in part required that two SLC subsystems be operable in Modes 1, 2, and 3 with an allowed outage time of 7 days for one inoperable SLC subsystem, or place the unit in Mode 3 within 12 hours and Mode 4 within 36 hours. However, during a routine TS required quarterly surveillance test, the licensee discovered that 3B SLC Pump would not start due to the improper engagement of the 480 VAC breaker racking sleeve. This resulted in 3B SLC subsystem being inoperable from April 7 to April 20, 2010, without the licensee taking the required TS 3.1.7 actions. The TS violation was entered into the licensees CAP as PER 225949. Even though the finding represented an actual loss of safety function of a single train of SLC for greater than its TS allowed outage time, the finding was determined to be of very low safety significance (Green) because the risk significance from the Browns Ferry SDP Phase 2 pre-solved table was green. |
| 05000237/FIN-2010003-03 | Dresden | 2010Q2 | Undocumented Technical Basis for change to EOP ATWS Mitigation Strategy | During the conduct of one of the dynamic simulator scenarios, the inspectors identified an unresolved item related to procedure implementation. 15 Enclosure During one of the dynamic simulator scenarios, conditions were simulated during an Anticipated Transient Without Scram (ATWS) that required the operating crew to lower reactor pressure vessel (RPV) water level in accordance with emergency operating procedure DEOP 400-5, Failure to SCRAM. The purpose of lowering RPV water level is to reduce core inlet sub-cooling and thus reduce the potential for power oscillations. DEOP 400-5, directs the operators to Terminate and Prevent all injection flow into the RPV except for flow from the CRD and Standby Liquid Control (Boron) systems. Contrary to the BWR Owners Group (BWROG) Emergency Procedure Guidelines (EPG) and Severe Accident Guidelines (Revision 2) which states that failure to completely stop RPV injection flow (with the exception of CRD, RCIC, and Standby Liquid Control) would delay the reduction in core inlet sub-cooling, thus increasing the potential for flux oscillations the crew was observed to implement this step in accordance with the licensees expectations, by decreasing the FWLC SETPOINT to -40 inches in incremental steps, such that the set point was always less than actual level. Using this method, feedwater flow was not actually stopped but level was dropped to -35 inches in approximately 1.5 minutes. When asked why the licensees procedural steps deviated from the BWROG EPG, the licensee stated that the deviation was necessary to prevent the loss of the Main Condenser heat sink (bypassing the Group 1 Isolation interlocks is performed in parallel and cannot be completed quick enough to prevent isolation of the Main Steam lines if flow is terminated completely). The BWROG EPG states that reducing reactor power and preventing power oscillations is of greater importance than preventing loss of the main condenser. Technical Specification 5.4.1 requires, in part, that written procedures/instructions be established, implemented, and maintained covering the emergency operating procedures required to implement the requirements of NUREG-0737, Clarification of TMI Action Plan Requirements, and NUREG-0737, Supplement 1, as stated in GenericLetter 82-33. NUREG-0737 and the associated Supplement 1 requires licensees to analyze transients and accidents, prepare emergency procedure technical guidelines, and develop symptom-based emergency operating procedures based on those technical guidelines. The BWROG EPG provides the technical basis for the development of the emergency operating procedures used by BWR licensees. Licensees are permitted to deviate from the BWROG guidelines provided they document the technical basis for the deviation. When asked to provide justification for the deviation from the BWROG EPG, the licensee was unable to do so. The licensee has initiated an engineering evaluation to provide the necessary basis for the deviation. This issue is an URI pending further NRC review and completion of the licensees actions to provide the necessary documentation to support the deviation: (URI 05000237/2010003-03; 05000249/2010003-03, Undocumented Technical Basis for Change to EOP ATWS Mitigation Strategy) |
| 05000373/FIN-2010002-01 | LaSalle | 2010Q1 | Failure to Maintain Design Control of SBLC system | The inspectors identified a finding of very low safety significance for the licensees failure to ensure the standby liquid control (SBLC) system could mitigate the consequences of all design basis anticipated transient without scram (ATWS) events. Specifically, the licensee lowered SBLC pump discharge relief valve set pressure to a value where a successful relief valve surveillance test result could be achieved, but SBLC system pressure attained during certain ATWS events would result in lifting the relief valve, which redirects the required sodium pentaborate solution away from the reactor. A NCV of 10 CFR 50, Appendix B, Criterion III, Design Control, was also identified for failure to maintain the design basis of the SBLC system to bring the reactor from rated power to a cold shutdown condition at any time in core life as described in the Updated Final Safety Analysis Report (UFSAR).The inspectors determined that the finding was more than minor because it affected the Mitigating Systems Cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. In addition, the finding affected the attribute of design control in the area of plant modifications. Specifically, by changing the set pressures of the SBLC relief valves, the licensee created the possibility that an SBLC train would not be capable of injecting neutron absorber solution into the reactor to accomplish the above stated design specification under certain accident conditions. The finding was determined to be of very low safety significance using the SDP Phase 3. As part of their corrective actions, the licensee adjusted the relief valve setpoints and is performing a detailed root cause on the set pressure drift phenomenon and the maintenance and testing practices performed by licensee personnel on the relief valves in question |
| 05000237/FIN-2009007-02 | Dresden | 2009Q4 | Unit 2 SBLC Tank Thickness Calculation Errors | A finding of very low safety-significance (Green) and associated Non-Cited Violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, was identified by the inspectors for the failure to accurately translate the design bases for the Standby Liquid Control (SBLC) tank into specifications, drawings, procedures, and instructions. Specifically, the SBLC tank wall thickness used in a design basis calculation was incorrect. The licensee initiated IR 983037 to address deficiencies in the calculation. The finding was determined to be more than minor because the finding was associated with the mitigating systems cornerstone attribute of design control and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the design basis calculations did not demonstrate that the tank will remain available following design basis seismic events. This finding is of very low safety-significance (Green) because it did not result in a loss of operability. The inspectors did not identify a cross-cutting aspect associated with this finding as it was not indicative of current performance. |
| 05000333/FIN-2009005-02 | FitzPatrick | 2009Q4 | Standby Liquid Control Performance Demonstration Not in Accordance with 10 CFR 50.65(a)(2). | The inspectors identified an NCV of 10 CFR Part 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, because Entergy staff did not demonstrate that the performance of the standby liquid control (SLC) system had been effectively controlled through the performance of appropriate preventive maintenance and did not monitor against licensee-established goals in accordance with 10 CFR 50.65(a)(1). Entergy initiated CR-JAF-2009-03994 and CR-JAF-2009-04017 to address the issues and classified the SLC system as (a)(1) due to the repetitive maintenance preventable failures and the incomplete corrective actions related to increasing the PM frequency from every two months to once a month. The inspectors determined the finding is more than minor because it affected the equipment performance attribute of the Mitigating Systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (Le., core damage). Specifically, plant operators rely on the SLC tank level indication in the control room for performing actions required by emergency operating procedures and the availability of this indication was affected. The inspectors determined the significance of the finding using IMC 0609.04, Phase 1 -Initial Screening and Characterization of Findings. The finding was determined to be of very low safety significance (Green) because it was not a design or qualification deficiency; did not represent a loss of system safety function; and did not screen as potentially risk-significant due to external initiating events. Specifically, the loss of control indication did not render the SLC system incapable of injecting borated water into the reactor coolant system, and operators remained capable of measuring the level of the SLC tank locally using manual dipping. The inspectors determined this finding had a cross-cutting aspect in the area of problem identification and resolution within the CAP component because Entergy personnel did not address an adverse trend in the SLC tank level indication in a timely manner. (P.1(d) |
| 05000293/FIN-2009005-03 | Pilgrim | 2009Q4 | Inadequate Surveillance Procedure Resulting in Failed Standby Liquid Control Train | A self-revealing, non-cited violation (NCV) of very low safety significance (Green) of Technical Specification (TS) 5.4.1, Procedures, was identified for inadequate procedural guidance which resulted in repeated lifting of the A Standby Liquid Control (SBlC) system relief valve and the subsequent failure of the A SBlC system. Specifically, the SBlC system test procedure did not provide precautions or identify methods to avoid exceeding the pressure set point of the system relief valve during testing. The issue was entered into the corrective action program and the surveillance procedure was revised to add cautions against exceeding 1300 psig and to reduce the test pressure window upper limit. In addition, if 1350 psig is exceeded, a condition report must be written to evaluate the impact on the system. Corrective actions are also planned to increase the relief valve design set point and to replace the test throttle valve with one more suited to adjusting system pressure. The performance deficiency was that Entergy did not specify adequate test controls to ensure that SBLC system relief valve set points were not challenged during test performance. This led to repeated relief valve lifts which over time contributed to the degradation of the relief valve that rendered the A SBLC train inoperable. The inspectors determined that the finding was more than minor because the finding was associated with the Procedure Quality attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone\'s objective to ensure the availability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, one train of SBLC was unavailable for several days. Using Inspection Manual Chapter 0609, Significance Determination Process, Attachment0609.04, Phase 1-lnitial Screening and Characterization of Findings, the inspectors determined that the finding is of very low safety significance because it is not a design or qualification deficiency, did not represent a loss of system safety function, did not represent an actual loss of a single train for greater than its TS allowed outage time and was not made risk significant because of external events. This finding has a crosscutting aspect in the Human Performance cross-cutting area, Resources component, because Entergy did not provide complete procedures. Specifically, the procedure did not include precautions and/or techniques to avoid exceeding the relief valve set point during testing. H.2(c |
| 05000373/FIN-2009004-01 | LaSalle | 2009Q3 | Failure to Decalre SBLC System Inoperable During Surveillance Testing | The inspectors identified a finding of very low safety significance and an associated NCV of Technical Specification (TS) 5.4.1, Procedures, for the failure to provide adequate procedural guidance to operations personnel when performing the quarterly SBLC operability test on unit 2. Specifically, operations personnel performingLOS-SC-Q1, SBLC pump operability test, did not posses appropriate procedural guidance while performing this test and, as a result, did not declare both trains for the Standby Liquid Control (SBLC) system inoperable and did not enter the associated limiting condition for operation (LCO) action statements as required per TSs. The inspectors determined that the finding was more than minor because it was associated with the procedure quality attribute of the Mitigating Systems Cornerstone, and it affected the cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, operations personnel would not have been able to return SBLC to a standby configuration if needed in case of an anticipated transient without a scram (ATWS) in 120 seconds as required by the design basis. The finding was determined to be of very low safety significance using the SDP Phase 2. This finding was also related to the cross-cutting area of Human Performance (resources) because the procedure used for this evolution was inaccurate in that it provided improper guidance to maintain SBLC operability provided that a dedicated operator was briefed and stationed locally. The licensee entered this issue into the corrective action program. Corrective actions taken by the licensee included the future revision of procedure LOS-SC-Q1 to remove the statement that indicates that the system can be maintained operable during the surveillance and to include an emergency restoration attachment with steps to quickly return the system to its standby configuration if required in case of an ATWS. |
| 05000293/FIN-2009004-03 | Pilgrim | 2009Q3 | Failure of the A Standby Liquid Control Train | An unresolved item (URI) was opened related to the failure of the Standby Liquid Control (SBLC) A pump relief valve during system testing. The performance deficiency cannot be determined until the definitive causers) of the issue are known. On July 10, 2009, during the quarterly surveillance on the A SBLC train, the pump relief valve, PSV-1105A, lifted and failed to reseat, which diverted flow such that the system could not meet its TS acceptance criteria. The train was declared inoperable, the relief valve was replaced, and the system was restored to service on July 12, 2009. This issue has been entered into Pilgrim\'s CAP (CR-PNP-2009-03088) and an apparent cause evaluation (ACE) was conducted. However, Entergy has determined that the ACE may not definitively address the causers) of the SBLC train failure. The inspectors require Entergy\'s final ACE in order to evaluate whether or not a performance deficiency exists.URI 05000293/2009004-03, Failure of the A Standby Liquid Control Train |
| 05000458/FIN-2009004-04 | River Bend | 2009Q3 | Failure to Ensure Standby Liquid Control System Test Tank Remained Drained | The inspectors identified a Green noncited violation of Technical Specification 5.4.1.a for the failure of operations personnel to provide adequate procedural guidance to preclude water intrusion into the nonseismically qualified standby liquid control system test tank which resulted in the degradation of both trains of the standby liquid control system. The licensee entered this issue into their corrective action program as Condition Report CR-RBS-2009-3862. The failure to provide appropriate procedures to keep the standby liquid control test tank drained is a performance deficiency. The finding is more than minor because it affects the protection against external events attribute of the mitigating systems cornerstone objective to ensure the availability, reliability, and capability of systems responding to initiating events to prevent undesirable consequences. The inspectors determined that the finding was of very low safety significance because the finding was not a design or qualification deficiency, did not represent a loss of a system/train safety function, and did not screen as potentially risk significant due to external events. This finding has a crosscutting aspect in the area of problem identification and resolutions corrective action program because the licensee failed to take appropriate corrective actions to address safety issues and adverse trends in a timely manner, commensurate with their safety significance and complexity. Specifically, the licensee failed to address the cause of inadvertent water intrusion into the standby liquid control test tank in a timely manner to prevent the common mode failure of both trains of standby liquid control (P.1(d)) |
| 05000237/FIN-2009003-02 | Dresden | 2009Q2 | Failure to Have a Procedure to Sample and Establish Administrative Controls for pH in the Torus | The inspectors identified a finding of very low safety significance involving a Non-Cited Violation of Technical Specification 5.4.1 for the failure to include essential information in procedures CY-AB-120-310, Suppression Pool/Torus Chemistry, and CY-DR-120-31, Suppression Pool/Torus Chemistry, to ensure torus pH values were above 5.6 in support of the radiological consequence dose analyses as described in Regulatory Guide 1.183, Alternative Radiological Source Terms for Evaluating Design Basis Accidents at Nuclear Power Reactors. As corrective actions, the licensee changed procedures CY-AB-120-310 and CY-DR-120-31 to include essential information for sampling the torus and revised the methodology for calculating torus pH. Using IMC 0612, Appendix E, Examples of Minor Issues, issued on September 20, 2007, and Appendix B, Issue Screening, issued on December 4, 2008, the inspectors determined that this finding was more than minor because there was reasonable doubt on the operability of the standby liquid control system and its ability to maintain torus pH above 7 following a loss of coolant accident and because of significant programmatic deficiencies in the licensees corrective action program. The inspectors also determined that this finding impacted the Barrier Integrity objective to provide reasonable assurance that physical design barriers (i.e., containment) protect the public from radionuclide releases caused by accidents or events. The failure to maintain adequate procedures addressing torus pH sampling resulted in a condition where there was reasonable doubt of the operability of the standby liquid control system. The inspectors completed a Phase 1 significance determination on this issue using IMC 0609, Significance Determination Process, Attachment 4, Table 4a, dated January 10, 2008. The inspectors determined that this finding only represented a degradation of a radiological barrier function and therefore screened as Green. This finding was related to the cross-cutting issue of problem identification and resolution (corrective action program) because the licensee did not take appropriate corrective actions to address safety issues in a timely manner. P.1(d) |
| 05000458/FIN-2009002-05 | River Bend | 2009Q1 | Licensee-Identified Violation | Technical Specification 3.1.7 requires, in part, that two standby liquid control subsystems shall be operable. Contrary to the technical specification requirement, from March 14, 2003, to October 28, 2008, the standby liquid control system was not capable of performing its design safety function to limit suppression pool particulate iodine to evolve into airborne iodine. In accordance with NRC Inspection Manual Chapter 0612, Appendix B, \"Issue Screening,\" the inspectors determined that the failure to drain the test tank, maintaining the seismically qualified configuration, was a licensee performance deficiency. The issue was more than minor because it was similar to Example 3.a in Manual Chapter 0612, Appendix E, and it met the not minor if requirement because changes were required in the procedure to correctly resolve the seismic concerns. The inspectors evaluated the issue using the Significance Determination Process (SDP) Phase 1 Screening Worksheet for the Initiating Events, Mitigating Systems, and Barriers Cornerstones provided in Manual Chapter 0609, Attachment 4, \"Phase 1 Initial Screening and Characterization of Findings. The inspectors determined that this finding affected the Mitigating Systems Cornerstone and that the finding screened as potentially risk significant to a seismic initiating event because assuming that the tank completely failed, affecting the nearby pumps and electrical equipment, the loss would degrade both trains of the multi-train standby liquid control system. Therefore, a Phase 3 analysis was conducted by a senior reactor analyst in accordance with Manual Chapter 0609, Appendix A, Determining the Significance of Reactor Inspection Findings for At-Power Situations. In accordance with Manual Chapter 0609, Appendix A, the analyst performed a Phase 3 assessment of the risk contributions from a seismic initiator using insights and/or values provided by the Risk Assessment of Operational Events Handbook, Volume 2, External Events. Assumptions: To evaluate the change in risk caused by this performance deficiency, the analyst made the following assumptions: a. The River Bend Station SPAR model, Revision 3.45 and a spreadsheet evaluation of the River Bend seismic hazard represented appropriate tools for evaluation of the subject finding. b. The standby liquid control system test tank had remained full of water during power operations for approximately 5 years. c. Given Assumption b. the appropriate exposure period is one year, representing the most recent assessment period was used for exposure to this failure. d. The standby liquid control system test tank would only have failed during a seismic event. Therefore only seismic initiators, seismically-induced initiators, and independent failures occurring simultaneously with seismic events were evaluated. e. The failure of the standby liquid control system would affect the core damage frequency if the seismic event occurred simultaneously with an anticipated transient without scram because the failure would impact the systems function to shut down the reactor. f. The failure of the standby liquid control system would affect the core damage frequency if the seismic event also resulted in a loss of coolant accident because the failure would impact the systems function to control suppression pool chemistry. g. The likelihood of a seismic event equal to or larger than 0.5g peak ground acceleration occurring within 24 hours of an independent plant initiator is approximately 4E-10. h. A seismic event smaller than 0.5g peak ground acceleration is not likely to affect plant operations at River Bend Station. i. Given Assumptions g and h, the probability that a seismic event large enough to affect the plant occurs at the same time as an unrelated plant initiator is inconsequential to this analysis. j. The seismic hazard vector for River Bend Station provided in Table 4A-1 of the Risk Assessment of Operation Events Handbook, Volume 2, External Events, Revision 1.01, is appropriate for evaluation of the subject finding. Analysis: In accordance with Assumptions e, f and i, the analyst determined that, for the subject performance deficiency to affect the core damage frequency, a seismic event must either occur at the same time as an anticipated transient without scram, or result in a loss of coolant accident (LOCA). As such, the analyst evaluated the subject performance deficiency by determining each of the following parameters for any seismic event producing a given range of median average spectral acceleration \"a\" (SE(a)): • The frequency of the seismic event SE(a) (eSE(a)); • The probability that a LOCA occurs during the event (PLOCA-SE(a)); • The probability that an independent LOCA occurs (PINIT-SE(a)); and • The probability of an ATWS occurring (PATWS-SE(a)). The frequency of a seismically induced demand on the SLC system (eSLC-SE(a)) can then be quantified as follows: eSLC-SE(a) = eSE(a) * (PLOCA-SE(a) + PINIT-SE(a) + PATWS-SE(a)) Given that each range a was selected by the analyst specifically to be independent of all other ranges, the total frequency of an induced demand, eSLC, can be quantified by summing the eSLC-SE(a) for each range evaluated as follows: 1.0 ACDF = O eSLC-SE(a) a=.05 over the range of SE(a). Results: The resulting value, quantified in a spreadsheet, was 5.4 x 10-7. The analyst noted that this conditional probability is significantly higher than a best estimate because the method used was to assume that the failure of the standby liquid control system was guaranteed following a failure of the test tank and that the failure of the standby liquid control system always resulted in core damage. Both these assumptions are known to be bounding. Therefore, this finding was of very low risk significance. Entergy documented this issue in Condition Report RBS-2008-06244. This item is further discussed in Section 4OA3.3 |
| 05000220/FIN-2009002-03 | Nine Mile Point | 2009Q1 | Failure to Properly Standby Liquid Control System Surveillance | A self-revealing non-cited violation (NCV) of Technical Specification (TS) 5.4, Procedures, was identified on January 30, 2009, when operators did not align the Unit 2 Division 2 Standby Liquid Control (SLC) system in accordance with the surveillance procedure and establish a pump discharge flow path. As a result, following pump start, the pump discharge relief valve lifted due to high system pressure and the valve subsequently required replacement due to excessive seat leakage. As immediate corrective action for this event, the SLC pump was secured and the system was returned to its normal standby alignment to support further testing. The issue was entered into the corrective action program (CAP) as condition report(CR) 2009-548.The finding was more than minor because it was associated with the human performance attribute of the Mitigating Systems cornerstone and adversely affected the associated cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors determined that the finding was of very low safety significance because the finding was not a design or qualification deficiency, did not represent a loss of a system/train safety function, and did not screen as potentially risk significant due to external events. This finding had a cross-cutting aspect in the area of human performance because the operators did not effectively use human error prevention techniques such as pre-job briefing, self and peer checking, and proper documentation of activities (H.4.a per IMC 0305) |
| 05000440/FIN-2008006-03 | Perry | 2008Q2 | Standby Liqui9d Control Storage Tank Seismic Calculations Deficiencies | A finding of very low safety significance and associated NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, was identified by the inspectors for the failure to identify and correct errors and discrepancies in seismic qualification documents for the Standby Liquid Control (SLC) storage tank. Subsequent licensee evaluation indicated that stresses in the critical SLC tank components will remain within the acceptance limits. The finding was determined to be more than minor because the lack of design control during the design modification for the SLC tank could affect its availability during a design basis seismic and hydrodynamic event. The finding screened as Green because it was a design deficiency that did not result in actual loss of safety function. This finding does not have a cross-cutting aspect because it is not indicative of current performance. (Section 1R21.3.b(3) |
| 05000341/FIN-2007006-02 | Fermi | 2007Q4 | Undocumented Technical Basis for Change to EOP | During one of the dynamic simulator scenarios, conditions were simulated during an Anticipated Transient Without Scram (ATWS) that required the operating crew to lower reactor pressure vessel (RPV) water level in accordance with emergency operating procedure (EOP) 29.100.01, Sheet 1A, RPV Control-ATWS. The purpose of lowering RPV water level is to reduce core inlet sub-cooling and thus reduce the potential for power oscillations. EOP 29.100.01, Sheet 1A, directs the operators to Terminate and Prevent all injection flow into the RPV except for flow from the CRD, Reactor Core Isolation Cooling (RCIC), and Standby Liquid Control (Boron) systems. Contrary to the BWR Owners Group (BWROG) Emergency Procedure Guidelines (EPG) and Severe Accident Guidelines (Revision 2) which states that failure to completely stop RPV injection flow (with the exception of CRD, RCIC, and Standby Liquid Control) would delay the reduction in core inlet sub-cooling, thus increasing the potential for flux oscillations the crew was observed to implement this step (FSL-10), in accordance with the licensees expectations, by turning OFF the low pressure Emergency Core Cooling Systems (ECCS) and Standby Feedwater pumps, reducing High Pressure Coolant Injection flow to 0 gpm, and reducing (i.e., NOT stopping) Feedwater system flow so that level decreased in a controlled manner. When asked why the licensees procedural steps deviated from the BWROG EPG, they stated that the deviation was necessary to allow time for bypassing of interlocks to prevent the loss of the Main Condenser heat sink, and to prevent dropping water level below the top of active fuel. The BWROG EPG states that reducing reactor power and preventing power oscillations is of greater importance than preventing loss of the main condenser. Technical Specification 5.4.1 requires, in part, that written procedures/instructions be established, implemented, and maintained covering the emergency operating procedures required to implement the requirements of NUREG-0737, Clarification of TMI Action Plan Requirements, and NUREG-0737, Supplement 1, as stated in Generic Letter 82-33. NUREG-0737 and the associated Supplement 1 required licensees to analyze transients and accidents, prepare emergency procedure technical guidelines, and develop symptom-based emergency operating procedures based on those technical guidelines. The BWROG EPG provides the technical basis for the development of the emergency operating procedures used by BWR licensees. Licensees are permitted to deviate from the BWROG guidelines provided they document the technical basis for the deviation. When asked to provide justification for the deviation from the BWROG EPG, the licensee was unable to do so. The licensee has initiated action (CARD 07-28195), through their corrective action program, to provide the necessary basis for the deviation. This issue is an Unresolved Item (URI) pending further NRC review and completion of the licensees actions to provide the necessary documentation to support the deviation: URI 05000341/2007006-02, Undocumented Technical Basis for Change to EOP ATWS Mitigation Strategy. |