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05000277/FIN-2012003-012012Q2Peach BottomInadequate Test Control to Demonstrate RCIC System Design Basis Start-up Response TimeThe inspectors identified a NCV of very low safety significance of Title 10 Code of Federal Regulation (CFR) 50, Appendix B, Criterion XI, Test Control, because Exelon conducted unacceptable pre-conditioning of the reactor core isolation cooling (RCIC) system during response time testing. The performance deficiency was related to Exelons surveillance test (ST) procedure which required cold startup of RCIC to reach the rated pump discharge pressure and flow rate within 50 seconds. Exelon procedures required a 72 hour standby period between pump starts to ensure the pump cold start design criteria are satisfied without pre-conditioning. On numerous occasions, when the pump design parameters were not reached in less than 50 seconds on the first attempt, control room operators would routinely perform a second start attempt within a short period of time, typically less than one hour, to adjust the RCIC pump controls and attain the design values in less than or equal to 50 seconds. Exelon performed an extent of condition review of Units 2 and 3 RCIC cold start test data to ensure the current pump, valve, and flow results satisfied the response time testing requirements. The violation was entered into the corrective action program (CAP) as issue report (IR)1364066. The performance deficiency was more than minor because it was similar to IMC 0612, Appendix E, Examples of Minor Issues, example 2.a. Specifically, the RCIC cold start ST procedure was not implemented adequately to ensure that the RCIC pump design discharge pressure and flow were reached within the 50 second requirement on the first attempt. 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 all of the mitigating system barrier questions in Table 4.a resulted in a no response. The finding included a cross-cutting aspect in the area of Work Practices, Human Performance component, because Exelon did not effectively communicate expectations regarding procedural compliance and personnel following procedures. Specifically, Exelon took credit for the Unit 2 ST performed on April 7, 2011, which started and shutdown RCIC three times in less than 72 hours to satisfy the response time testing acceptance criteria. On January 20, 2011, the same test was performed for Unit 3, when the RCIC system was run two times prior to satisfying the acceptance criteria. Exelon did not identify the unacceptable pre-conditioning of the RCIC system start-up time for either test because personnel did not follow the In-service Testing (IST) Program Corporate Technical Position procedure.
05000277/FIN-2012003-022012Q2Peach BottomLicensee-Identified ViolationTS LCO 3.3.5.1, Condition E, requires that one inoperable channel of CS system bypass valve instrumentation be restored to operable in seven days, and, if the redundant emergency core cooling system initiation capability is inoperable, the supported feature(s) must be declared inoperable within one hour. Additionally, TS LCO 3.5.1, Condition I, requires that with two CS subsystems inoperable, LCO 3.0.3 be entered immediately. Contrary to the above, the A and D CS pump bypass valve instrumentation were both inoperable on April 18, 2012, for a period of time greater than one hour, the supported features were not declared inoperable, and LCO 3.0.3 was not immediately entered. Specifically, following discovery of the A CS pump bypass instrument inoperability during ST on April 18, 2012, the D CS pump bypass instrument was discovered to be inoperable on April 19, 2012. PBAPS determined that it was likely that the D CS instrument was also inoperable April 18, 2012, and therefore this event was reportable (see section 4OA3.3). Following successful recalibration, both switches were returned to an operable status on the day of their respective surveillance testing. The inspectors determined that this event screens to Green using the Table 4a screening criteria in Attachment 4 of IMC 0609, SDP, because there was no loss of the CS system safety function. Because this finding is of very low safety significance, and has been entered into Exelon\'s CAP under IR 1355773, this violation is being treated as a Green NCV consistent with the NRCs Enforcement Policy.
05000277/FIN-2012003-032012Q2Peach BottomADS SRV Actuator Diaphragm Thread Seal LeakOn September 25, 2011, while Peach Bottom Unit 3 was shut down for a scheduled refueling outage, Exelon personnel performed a routine ST on the Unit 3 71B SRV. The valve exceeded the maximum allowable leak rate for the pneumatic actuation controls associated with its ADS function, and Exelon declared SRV 71B inoperable. Exelon determined that the cause of the excessive leak rate was a failure of the 71B SRV actuator diaphragm thread seal, as a result of thermal degradation of the SRV actuator diaphragm thread seal material. The seal had been replaced during a November 2010 maintenance outage and, at that time, the SRV had passed its ST. Because no other leak testing had occurred since November 2010 (because the plant had been operating and the SRV is inside primary containment), Exelon could not assure that the SRV had been operable since the completion of the last successful leak test. Accordingly, Exelon concluded that it had not met the requirements of TS 3.5.1, Action E.1, which requires that, with one ADS valve inoperable, the licensee must return the valve to operable status within 14 days or be in Mode 3 within 12 hours. Exelon replaced the degraded 71B SRV thread seal on September 26, 2011, and the valve passed a subsequent leak test. Exelon also entered the 71B SRV failure into the CAP (IR 1268076), and, in accordance with 10 CFR 50.73(a)(2)(i)(B), submitted LER 11-003 to report to the NRC this condition prohibited by TSs. When inspected by Exelon maintenance personnel, Exelon identified that the thread seal had indications of being dry and brittle. Subsequent review by Exelon engineering personnel determined that the apparent cause of the seal leakage was the result of thermal degradation of the thread seal material. The NRC reviewed the licensees evaluation and actions related to this matter and concluded that the degraded seal condition was not caused by improper maintenance practices. Also, trend data did not indicate a potential degradation in that the same seal material had been used at PBAPS Units 2 and 3 for the last 20 years with no other failures. Further, the NRC considered that the 71B seal leakage would not have been detectable during normal plant operations, since it only occurred when the valve was actuated. Consequently, the NRC concluded that the inoperability of the 71B SRV was not within Exelons ability to foresee and correct, and therefore, did not identify any performance deficiency associated with the violation. The inspectors assessed the risk associated with the issue by using IMC 0609, Appendix G, Shutdown Operations SDP. The inspectors screened the issue, and evaluated it using Checklist 6 of IMC 0609, Appendix G, Attachment 1. SRV 71B is one of five PBAPS Unit 3 ADS reactor vessel relief valves. In order to perform the ADS system safety function, four of the five ADS SRVs are required to function. The four other ADS SRVs passed the leakage test, and would have been capable of depressurizing the reactor pressure vessel for design basis events. Therefore, during the period the 71B SRV was inoperable, the overall ADS safety function was maintained. As a result, this issue would screen as very low safety significance Because it was not reasonable for the licensee to be able to foresee and prevent the thread seal material degradation, or to have made the 71B SRV inoperability decision at an earlier time, the inspectors determined that no performance deficiency exists. Because no performance deficiency was identified, no enforcement action is warranted for this violation of NRC requirements in accordance with the NRCs Enforcement Policy. Further, because licensee actions did not contribute to this violation, it will not be considered in the assessment process or the NRCs Action Matrix.
05000354/FIN-2011008-012011Q1Hope CreekInadequate Corrective Actions for EHC Turbine Valve ProceduresThe inspectors identified a finding of very low safety significance (Green) because PSEG did not correct turbine valve test and maintenance procedure deficiencies. Specifically, PSEG closed out notification 2043100 within their corrective action program without performing the actions to resolve the procedure deficiencies as required by PSEG corrective action procedures. PSEG entered this issue into their corrective action program as notifications 20494248 and 20495156 to evaluate the corrective actions needed to address the issue. The finding was determined to be more than minor because the deficiency was associated with the procedure quality attribute of the Initiating Events cornerstone and adversely impacted the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during power operations. The inspectors evaluated the finding using IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, Table 4a, for the Initiating Event cornerstone. Specifically, because the finding did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions will not be available, the finding was determined to be of very low safety significance (Green). This finding had a cross-cutting aspect in the area of problem identification and resolution because PSEG did not take appropriate corrective actions to address safety issues in a timely manner, commensurate with their safety significance and complexity. Specifically, corrective actions outlined in notification20413100 to resolve procedural deficiencies were not completed.
05000247/FIN-2011002-012011Q1Indian PointMain Steam System Configuration Control Procedure Not Adequate to Ensure Closure of MS-55DThe inspectors identified a Green NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, because Entergy procedure 2-COL-18.1, Main Steam and Reheat System, was not adequate to ensure closure of main steam isolation valve (MSIV) bypass stop valve MS-55D. Specifically, between April 10, 2010 and September 12, 2010, procedure 2-COL-18.1 did not provide adequate instructions to operators to ensure MS-55D was closed, which resulted in MS-55D being left partially open, and unable to isolate the 24 steam generator (SG) during accident conditions. Entergy personnel took immediate corrective actions to close MS-55D. This issue was entered into Entergys CAP as condition reports (CRs) IP2-2010-05694 and IP2-2010-06745. This finding is more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone and affects the cornerstone objective to ensure the availability and reliability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage). Specifically, the inadequate procedure resulted in the manual 3-inch MSIV bypass stop valve MS-55D for the 24 SG being left partially open for approximately five months. Based on NRC senior reactor analyst review, it was determined that operators could have isolated the other three SGs with their MSIVs and steamed them to remove decay heat and depressurize the plant using their atmospheric dump valves, while isolating the 24 SG further down the main steam system at the turbine bypass and stop valves. Therefore, using IMC 0609.04, Phase 1 - Initial Screening and Characterization of Findings, the inspectors determined this finding was of very low safety significance (Green) because the finding did not result in a loss of the safety function given the operators ability to isolate the other SGs and the 24 SG with the turbine bypass and stop valves. Additionally, the finding was not potentially risk significant due to a seismic, flooding, or severe weather initiating event. The inspectors determined there was no cross-cutting issue associated with the finding because the performance deficiency did not reflect Entergy\'s current performance. Specifically, the procedure change occurred more than three years ago and was outside the current assessment period.
05000247/FIN-2011002-032011Q1Indian PointEntergy Personnel Did Not Identify a Leak on the 25 Service Water Pump PipingThe inspectors identified a Green NCV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, because Entergy personnel did not promptly identify and correct an adverse condition related to a service water (SW) pipe leak. Specifically, on October 29, 2010, NRC inspectors identified a leak on the base weld of the 25 SW pipe vacuum breaker which required subsequent evaluation and repair by Entergy personnel to restore operability of the 25 service water pump (SWP). This issue was entered into Entergys CAP as CR IP2-2010-6620. This finding 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 the reliability and capability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage). Specifically, the 25 SW pipe weld leak challenged the capability and the reliability of the SWP, and the pump was declared inoperable by Entergy personnel to conduct repairs. Using IMC 0609.04, Phase 1 - Initial Screening and Characterization of Findings, the finding was determined to have very low safety significance (Green) because the finding was not related to a design or qualification deficiency, did not represent a loss of system safety function, and the finding 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 problem identification and resolution associated with the CAP attribute because Entergy personnel did not implement a CAP with a low threshold for identifying issues, specifically, identifying a leak on the 25 SWP piping.
05000247/FIN-2011002-022011Q1Indian PointNotification Process for State/Local Authorities During a Simulator ScenarioFollowing the emergency declaration of an Alert by operators during a simulator drill scenario on January 25, 2011, the operators entered emergency plan implementing procedure IP-EP-210, Central Control Room, Attachment 9.1, Shift Manager/Plant Operations Manager (Emergency Director) Checklist. The IPEC Emergency Plan, Section E, Notification Methods and Procedures, paragraph 1.b.5, requires in part that an immediate notification (within 15 minutes) of an Alert is made by the Shift Manager or his designee to the New York State and Westchester, Rockland, Putnam, and Orange Counties. The emergency plan implementing procedure checklist directs the Shift Manager to complete a New York State (NYS) Radiological Emergency Data Form and have a control room Offsite Communicator email and fax the data form to the offsite authorities. The Offsite Communicator must then confirm receipt of the information by offsite authorities. NRC regulations, specifically 10 CFR 50.47(b)(5), require in part that procedures have been established for notification, by the licensee, of State and local response organizations. The drill scenario simulated one county not being present during the initial notification call via the radiological emergency communication system (RECS). The Offsite Communicator provided the event notification to NYS and the counties that were present on the line. The NRC inspectors observed that during the drill the Offsite Communicator did not implement additional communication measures to ensure the county, not present during the initial notification, received the event notification via fax. The inspectors observed that not affirming receipt of the notification by the county would not be consistent with IPEC Emergency Plan Section E in ensuring the licensee notifies all state and local authorities. The inspectors also observed that Entergy evaluators did not address this issue during the simulator scenario critique. The inspectors questioned Entergy personnel regarding their views during the simulator scenario and the expected operator response. The inspectors concluded additional information is required from Entergy staff related to their assessment regarding the adequacy of the procedure IP-EP-210, Attachment 9.1 and operator training with regard to the implementation of that procedure. Prior to completion of this inspection, Entergy personnel revised the Control Room Initial Notification Checklist (Form EP-4) to provide direction to operators in the event initial notifications are not able to be completed for required state and local authorities.
05000338/FIN-2010005-062010Q4North AnnaLicensee-Identified Violation10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, states, in part, that activities affecting quality shall be prescribed by documented procedures. Contrary to this, the licensee identified that they failed to adequately prescribe procedure, VPAP-0905, Insulation Control Program, Revision 5, for adequate control of insulation work to avoid critical components. Consequently, the 2J EDG was rendered inoperable and unavailable when the governor drain petcock was inadvertently opened during replacement of insulation on the exhaust manifold. This issue is in the licensees CAP as CR403015, 2-EE-EG-2J governor oil inadvertently drained during insulation work.
05000338/FIN-2010005-042010Q4North AnnaFailure to Promptly Correct Conditions Adverse to Quality for Valve Actuator DiaphragmsA non-cited violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, was identified by the inspectors for two examples of the failure to promptly identify and correct a condition adverse to quality present in the actuator diaphragms of 1-CH-HCV-1200C, letdown orifice isolation, and 1-RC-PCV-1456, reactor coolant system (RCS) pressurizer power operated relief valve (PORV). The licensee entered these problems into their corrective action program as condition reports 355000 and 387916. The inspectors determined that the failure to promptly correct conditions adverse to quality for 1-CH-HCV-1200C and 1-RC-PCV-1456 was a performance deficiency (PD). The NRC Enforcement Manual allows for the grouping of multiple examples of the same violation during an inspection period and the assignment of an issue to that example which is most significant. The inspectors determined that the second example, involving 1-RC-PCV-1456, was the more significant issue. The inspectors reviewed IMC 0612, Appendix B and determined the finding was more than minor because it affected the Barrier Integrity cornerstone objective of providing reasonable assurance that physical design barriers (e.g. RCS) protect the public from radionuclide releases caused by accidents or events. Specifically, the pressurizer PORVs provide protection to the RCS by preventing brittle fracture at low temperature conditions and protect RCS integrity at high temperature conditions. The inspectors reviewed IMC 0609, Attachment 4 and determined that since the finding involved a degradation of the Barriers Cornerstone, specifically the RCS barrier, a phase 3 analysis was required. The NRCs SPAR model was utilized to assess the risk significance of the finding modeling the impact of an increased likelihood of failing-to-open. The analyst calculated new failure probabilities for the Unit 1 PORVs (1-RC-PCV-1455C/1456) based on actual/observed failures of the valves. The analyst confirmed that the other valves affected by the performance deficiency (e.g., loop drain valves) were of negligible risk significance and were not included in the North Anna SPAR model. The dominant sequences were transients where a loss of the Condensate Storage Tank occurs and one/both of the PORVs fail to open when called upon, in order to initiate feed and bleed, subsequently leading to core damage. The analyst determined that the risk increase in core damage frequency was <1E-6 per year, a finding of very low safety significance, Green. The cause of this finding involved the cross-cutting area of problem identification and resolution, the component of corrective action program, and the aspect of implementation of corrective action (P.1(d)), because the licensee failed to correct the safety issue that existed with 1-RC-PCV-1456 in a timely manner, commensurate with its safety significance and complexity.
05000338/FIN-2010005-022010Q4North AnnaInadequate Corrective Action for Fatigued Fuse Clips in Safety-Related BreakersA Green, non-cited violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, was identified by the NRC for failure to promptly identify an correct a condition adverse to quality regarding fatigued fuse clips associated with safety-related breakers. The licensee entered this problem into their corrective action program as condition report 400128. The inspectors determined that the failure to promptly initiate corrective actions for fatigued fuse clips was a performance deficiency (PD) which resulted in two safetyrelated breaker failures. The inspectors reviewed IMC 0612, Appendix B, and determined the PD was more than minor because it impacted the mitigating systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences, and the related attribute of design control for the initial structure, system, component design. In accordance with NRC Inspection Manual Chapter (IMC) 0609, Significance Determination Process, the inspectors performed a Phase 1 analysis and determined that the finding was of very low significance because the finding was not a design deficiency, did not represent a loss of safety function and did not screen as potentially risk significant due to a seismic, flooding or severe weather initiating event. This finding involved the cross-cutting area of problem identification and resolution, the component of the corrective action program, and the aspect of thorough evaluation of problems such that resolutions address extent of condition, P.1(c), because the licensee failed to initiate adequate corrective actions to address extent of condition for fatigued fuse clips.
05000338/FIN-2010005-032010Q4North AnnaInadequate Design Control Measures for Field Changes Affecting Station Battery CablesThe inspectors identified a non-cited violation of 10 CFR 50, Appendix B, Criterion III, Design Control, for the failure to ensure that design control measures for field changes impacting the support of station battery cables were commensurate with those applied to the original design requirements. The licensee entered this problem into their corrective action program as condition report 358461. The inspectors determined that the failure to adhere to the requirements of Criterion III for field changes involving the support of station battery cables was a performance deficiency (PD). This PD had a credible impact on safety due to an increase in battery post loading not analyzed by the vendor for a seismic event impacting the unsupported cables. The PD was more than minor, because it impacted the mitigating systems cornerstone objective to ensure the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences and the related attribute of design controls due to changes made to battery cable supports which created a condition adverse to quality. In accordance with NRC Inspection Manual Chapter (IMC) 0609, Significant Determination Process, the inspectors performed a Phase 1 analysis and determined that the finding was of very low significance (Green) because the design deficiency did not result in the loss of functionality. The finding had no cross-cutting aspects because it is not indicative of current licensee performance.
05000338/FIN-2010005-052010Q4North AnnaFailure to Maintain PM Procedures for Circuit Breakers Current with Industry Information and OEA Green, self-revealing finding was identified for the failure to maintain a preventative maintenance (PM) procedure for circuit breakers current with industry information and operating experience (OE), as required by procedure, DNAP-2001, Equipment Reliability Process, Revision 0. The licensee entered this problem into their corrective action program as condition report 331819. The failure to maintain an adequate preventive maintenance (PM) procedure led to an age related failure of a motor starter (main contactor) causing a fire in safetyrelated breaker cubicle J1 of motor control center (MCC) 1J1-2S which supplied power to the D control rod drive mechanism cooling fan, 01-HV-F-37D. The failure to establish an adequate PM task for testing the main contactor of a circuit breaker to ensure that it is in good operating condition and will operate reliably until the next scheduled maintenance was determined to be a performance deficiency. Significance Determination Process (SDP) phase 1 screening of the finding was performed and the finding was determined to increase the likelihood of a fire external event and required a phase 3 SDP evaluation. A phase 3 SDP analysis was performed by a regional SRA in accordance with Inspection Manual Chapter 0609 Appendix F, NUREG /CR -6850 as amended by NUREG/CR -6850 supplement 1, with the NRC North Anna SPAR risk model used to determine the conditional core damage probability (CCDP) for the fire scenarios. The dominant sequence was a fire in MCC1J1-2S damaging MSIV cables resulting in a reactor trip transient with failure of high pressure recirculation and residual heat removal due to fire effects leading to core damage. The evaluation concluded that the core damage frequency (CDF) increase of the potential fire scenarios was characterized as of very low safety significance (Green). This finding involved the cross-cutting area of problem identification and resolution, the component of OE, and the aspect of implementation and institutionalization of OE through changes to station processes and procedures (P.2(b)), because the licensee failed to incorporate existing industry OE to ensure procedural guidance was adequate for testing of the main contactor.
05000244/FIN-2010009-022010Q4GinnaInadequate Translation of NPSH Design Limits into EOPsThe team identified a finding of very low safety significance involving a non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion III, Design Control. Specifically, Constellation had not correctly translated residual heat removal (RHR) pump net positive suction head (NPSH) operating limits into emergency operating procedures. Emergency operating procedure ES-1.3, Transfer to Cold Leg Recirculation, included criteria for aligning the discharge of the RHR pump to the suction of the safety injection pump under post-accident sump recirculation conditions which had not been adequately analyzed for RHR pump NPSH. Constellation entered the issue into their corrective action program to address the inconsistency between the design analysis and procedure and performed a review to ensure the RHR pump remained operable with respect to NPSH margin. The finding was determined to be more than minor because it was associated with 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, design control measures had not ensured consistency between the design analysis assumptions and the operating procedure to ensure adequate RHR pump NPSH margin when aligned to the safety injection (SI) pump during sump recirculation. The team evaluated the finding in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1- Initial Screening and Characterization of Findings, Table 4a for the Mitigating Systems Cornerstone. The team determined the finding was of very low safety significance because it was a design deficiency confirmed not to result in a loss of operability. The team did not identify a cross-cutting aspect with this finding because it did not represent current performance. The discrepancy between the design analysis and procedure occurred outside of the timeframe which reflects current performance.
05000244/FIN-2010009-012010Q4GinnaInadequate Evaluation of Breaker Coordination for Amptector Type LSG Trip Unit Discriminator FeatureThe team identified a finding of very low safety significance involving a non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion III, Design Control. Specifically, Constellation had not verified the adequacy of their design with respect to the impact of the installed Amptector type LSG trip unit discriminator feature on breaker coordination. The discriminator circuit design had not been evaluated to ensure the 480V load center bus motor control center (MCC) feeder breakers would maintain coordination and be capable of maintaining power to downstream safety-related components in response to design basis events such as seismic or steam line break transients. Constellation entered the issue into their corrective action program to evaluate the adequacy of their design and ensure the feeder breakers remained operable. The finding was determined to be more than minor because the finding was associated with the Mitigating Systems Cornerstone attribute of design control and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of the 480V busses to respond to initiating events to prevent undesirable consequences. The team evaluated the finding in accordance with Inspection Manual Chapter (IMC) 0609, Significance Determination Process, Attachment 0609.04, Phase 1-lnitial Screening and Characterization of Findings, Table 4a for the Mitigating Systems Cornerstone. The team determined the finding was of very low safety significance because it was a design deficiency confirmed not to result in a loss of operability. The team did not identify a cross cutting aspect with this finding because this was an old design issue and therefore was not reflective of current performance.
05000289/FIN-2010009-022010Q3Three Mile IslandMSSV Design Basis Calculations InaccurateThe inspectors identified a Green NCV of 10 CFR 50, Appendix B, Criterion III, \"Design Control,\" associated with MSSV capacity calculations revised in 1988 to support a power, uprate amendment. The MSSV capacity calculations erroneously referenced the as-purchased capacity instead of the as-built capacity when determining if there was sufficient blowdown capacity following the power uprate. When the correct value was used, the calculation showed that the MSSVs did not have sufficient capacity. This is the calculation of record for this system and is the basis for the TS requirements that all MSSVs are required to be operable or a power penalty must be assessed. During the inspection, Exelon was able to demonstrate that the MSSVs did have the required capacity and the American Society of Mechanical Engineers (ASME) code safety function to protect the Main Steam System piping and once through steam generator (OTSG) integrity had never actually been iost. The issue was placed in the CAP. A License Amendment Request (LAR) is also being developed which will replace the calculation of record. Using an incorrect value for actual MSSVs relief capacity was a performance deficiency which was reasonably within the licensee\'s ability to foresee and prevent. This performance deficiency was more than minor because it affected the Design Control Aspect of the Mitigating Systems Cornerstone Objective of ensuring the operability, availability, and reliability of systems designed to mitigate transients and prevent core damage. The issue was also compared to the examples in NRC IMC 0612, Appendix E, \"Examples of Minor Issues.\" The issue was similar to example 3j which states, \"The violation of 10 CFR 50 Appendix B Criterion III is more than minor if the engineering calculation error results in a condition where there is now a reasonable doubt on the operability of a system or component.\" The team assessed this finding in accordance with NRC IMC 0609, Attachment 4, Phase 1 - \"Initial Screening and Characterization of Findings,\" and determined that it was of very low safety significance (Green) since it was determined that the error did not actually result in a loss of the system\'s safety function. The issue did not meet all the criteria to be considered as an old design issue because it was not a licensee-identified issue. This finding was determined to not have a cross-cutting issue because the performance deficiency occurred in 1988 and was not indicative of current licensee performance.
05000289/FIN-2010009-042010Q3Three Mile IslandPotential Concern Regarding TMI\'s Internal and External Flood Protection Barriers and Mitigation StrategiesThe team identified that Exelon was not meeting the requirements of USFSAR Section 2.6.5 and of 10 CFR 50.65 because TMI did not have an effective program to monitor the condition of flood seal penetrations into safety-related structures. This has been a long-standing issue for several years. However, a formal penetration seal inspection and evaluation program was only established in October 2009 and the initial round of seal inspections had not been completed. Considering the age of the flood seal components could be beyond the qualified lifetime, this program may not be adequately identifying degrading and non-conforming conditions which could impact the operability of safety-related equipment during a design basis flooding event. As a result, the NRC has opened an UnreSOlved Item (URI) related to this concern. The inspectors identified a potential concern regarding TMl\'s internal and externai flood protection barriers and mitigation strategies. Specificaily, TMI has not implemented an effective program for identifying, maintaining, inspecting, or repairing flood barriers to ensure that internal and external flooding risks are effectively managed and to verify that safe shutdown equipment is not subjected to damage from internal and external flood events. Monitoring of safety-related SSCs, as weil as non-safety-related components whose failure could prevent a SSC from fulfiiling their safety function, is required by 10 CFR 50.65. The inspectors questioned Exelon about the controls in place to verify, inspect and maintain ail openings below probable main flood elevation (309 foot level) that are potential leak paths (ducts, pipes, conduits, cable trays, seismic gaps, flood seals, non return flood protection check valves, watertight seismic gaps, etc.) in order to meet the commitments detailed in TMI UFASAR Section 2.6.5. However, Exelon was not able to demonstrate which barriers are credited as flood barriers, what the design and specified materials are, what the expected qualified life of the barriers is, nor the condition of ail the credited barriers. The team concluded that not having an effective program to monitor the condition of flood penetration seals for safety-related structures was a performance deficiency that was reasonably with in Exelon\'s ability to foresee and prevent. Since Exelon has not yet completed their initial evaluation of the flood seals at TMI, the team was unable to evaluate the potential impacts of this issue. Exelon intends to complete the initial inspections and report the results to the NRC by October 31, 2010. Subsequent to the completion of the PI&R inspection, Exelon issued Event Notification (EN) 46194 on August 23, 2010, describing that flood barriers needed to protect safety-related equipment in the TMI Auxiliary Building were identified to be missing or never instailed. The inspectors determined that issues concerning the internal and external flood programs at TMI, including flood barriers design, inspections, maintenance, and repairs, is an unresolved item pending further NRC review of Exelon\'s initial inspection and safety assessment.
05000289/FIN-2010009-032010Q3Three Mile IslandMultiple MSSVs test failures due to improper evaluation of Operating ExperienceA self-revealing Green NCV of TMI Technical Specification (TS) 3.4.1.2.3 was identified for having greater than three main steam safety valves (MSSVs) inoperable for greater than the allowed outage time with reactor power greater than 5%. MSSV testing prior to the 2009 refueling outage identified that six MSSVs failed the lift point test and were subsequently declared inoperable. All six valves failed by lifting above the ASME limit of +/- 3% of designed setpoint. Five of these six valves exhibited signs of oxide binding, a known failure mechanism for MSSVs and each of the valves had been refurbished during the 2007 refueling outage. Exelon had fleet and industry information about the oxide binding failure mechanism available in 2006 at the time the refurbishment method was selected for the 2007 TMI outage. This refurbishment method included a decision to machine hone the MSSV seat to a mirror finish. This decision created the conditions for oxide binding and resulted in each of the valves failing their lift tests and being declared inoperable when tested in 2009. Exelon has changed its refurbishment process to preclude this error in the future, refurbished all of the affected valves, submitted a required licensee event report (LER), and entered the issue into the CAP. The decision in 2006 to machine hone the MSSV seat to a mirror finish, which established the conditions for oxide binding, was a performance deficiency that was within Exelon\'s ability to foresee and prevent due to available operational experience. This performance deficiency is more than minor because it affected the Equipment Performance Aspect of the Mitigating Systems Cornerstone Objective of ensuring the operability, availability, and reliability of systems designed to mitigate transients and prevent core damage. The team assessed this finding in accordance with IMC 0609, Attachment 4, Phase 1 - \"Initial Screening and Characterization of Findings,\" and determined that it was of very low safety significance (Green) since it did not result in a loss of any system safety function. This finding was determined to not have a cross-cutting aspect because the performance deficiency occurred in 2006 and was no longer indicative of current licensee performance. Specifically, Exelon made changes to their MSSV refurbishment program in 2008 which implemented the available OE, prior to discovery of the 2009 failures.
05000289/FIN-2010009-012010Q3Three Mile IslandDeficient Extent Of Condition Evaluation for a 2007 \'B\' EDG Scavenging Air Box Gasket Leak Which Affected the Reliability and Availability of the \'A EDGThe inspectors identified a finding of very low safety significance (Green) involving a NCV of 10 CFR Part 50, Appendix B, Criterion XVI, \"Corrective Action,\" for a deficient evaluation of a failed \'B\' emergency diesel generator (EDG) scavenging air box gasket in April 2007. The deficient evaluation resulted in ineffective corrective actions to identify and correct an improper application of the same type of gasket material in the \'A\' EDG (EG-Y-1A) scavenging air box gasket. As a result, on June 3, 2010, the \'A\' EDG scavenging air box gasket failed during performance of a monthly surveillance test run. Corrective action included replacing the gasket with the original design, entering the issue into the CAP, and conducting a root cause analysis (RCA). The inspectors determined the deficient extent of condition review of the April 2007, \'B\' EDG scavenging air box gasket failure was a performance deficiency. This performance deficiency is more than minor because it affected the Equipment Performance Aspect of the Mitigating Systems Cornerstone Objective of ensuring the operability, availability, and reliability of systems designed to mitigate transients and prevent core damage. Specifically, this finding reduced the reliability of, and resulted in additional unplanned unavailability for, the \'A\' EDG. The team assessed this finding in accordance with NRC IMC 0609, Attachment 4, Phase 1 - \"Initial Screening and Characterization of Findings,\" and determined that it was of very low safety significance (Green) since it did not result in a loss of any system safety function. The issue has a cross-cutting aspect in the area of problem identification and resolution, because Exelon had identified in 2007 that a y\" inch Gore-TexTM gasket had not been specifically authorized by an engineering change report (ECR) to be used in the EDGs scavenging air box application (IR 616514 and 6266457). However, Exelon did not evaluate the issue such that extent of condition was properly considered and the cause was properly resolved for the \'A\' EDG (P.1(c)).
05000338/FIN-2010004-072010Q3North AnnaFailure to Maintain PM Procedures for Circuit Breakers Current with Industry Information and OEA self-revealing finding was identified for the failure to maintain a preventative maintenance (PM) procedure for circuit breakers current with industry information and operating experience (OE), as required by procedure, DNAP-2001, Equipment Reliability Process, Revision 0. The licensee entered this problem into their corrective action program as condition report 331819. The inspectors determined that the failure to maintain PM procedures for circuit breakers current with industry information and OE was a performance deficiency (PD). This PD had a credible impact on safety due to an original equipment main contactor which was in service for approximately 35 years, and subsequently experienced a coil failure with a consequent fire. The PD was more than minor because it could be reasonably viewed as a precursor to a significant event based on fire development leading to the loss of other safety-related equipment. In accordance with NRC Inspection Manual Chapter 0609, Significance Determination Process, the inspectors performed a Phase 1 analysis and determined the finding required a Phase 3 analysis by a regional senior reactor analyst. The significance of this finding is to-be-determined (TDB) pending completion of a phase 3 evaluation. This finding involved the cross-cutting area of corrective action, the component of the OE, and the aspect of implementation and institutionalization of OE through changes to station processes and procedures, P.2(B), because the licensee failed to incorporate existing industry OE to ensure procedural guidance was adequate for testing of the main contactor. (Section 4OA5.4)
05000338/FIN-2010004-022010Q3North AnnaFailure to Promptly Correct a Condition Adverse to Quality for Valve Actuator DiaphragmsAn apparent violation (AV) of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, was identified by the inspectors for two examples of the failure to promptly identify and correct a condition adverse to quality present in the actuator diaphragms of 1-CH-HCV- 1200C, letdown orifice isolation, and 1-RC-PCV-1456, reactor coolant system (RCS) pressurizer power operated relief valve (PORV). The licensee entered these problems into their corrective action program as condition reports 355000 and 387916. The inspectors determined that the failure to promptly correct conditions adverse to quality for 1-CH-HCV-1200C and 1-RC-PCV-1456 was a performance deficiency (PD). The NRC Enforcement Manual allows for the grouping of multiple examples of the same violation during an inspection period and the assignment of an issue to that example which is most significant. The inspectors determined that the second example, involving 1-RC-PCV-1456, was the more significant issue. The inspectors reviewed IMC 0612, Appendix E and determined the PD was more than minor, because it was similar to examples 4d and 4f in that the failure to correct a condition adverse to quality led to the inoperability of the component. The inspectors also reviewed IMC 0612, Appendix B and determined the finding was also more than minor because it affected the Barrier Integrity cornerstone objective of providing reasonable assurance that physical design barriers (e.g. RCS) protect the public from radionuclide releases caused by accidents or events. Specifically, the pressurizer PORVs provide protection to the RCS by preventing brittle fracture at low temperature conditions and protect RCS integrity at high temperature conditions. The inspectors reviewed IMC 0609, Attachment 4 and determined that since the finding involved a degradation of the Barriers Cornerstone, specifically the RCS barrier, a phase 3 analysis was required. The significance of this finding is to be determined pending completion of the phase 3 evaluation. The cause of this finding involved the cross-cutting area of problem identification and resolution, the component of corrective action program, and the aspect of implementation of corrective action, P.1(d), because the licensee failed to correct the safety issue that existed with 1-RC-PCV-1456 in a timely manner, commensurate with its safety significance and complexity. (Section 4OA2.2
05000354/FIN-2010007-012010Q2Hope CreekLicensee-Identified ViolationThe following violation of very low safety significance (Green) was identified by the licensee and is a violation of NRC requirements which meets the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as a Non-Cited Violation (NCV).Hope Creek operating license condition 2.C.(7), Fire Protection, requires, in part, that PSEG Nuclear LLC implement and maintain in effect all provisions of the approved fire protection program as described in the Updated Final Safety Analysis Report for the facility. Contrary to this requirement, on December 2, 2009, the licensee identified that the degree of physical separation specified in the UFSAR for redundant trains of safe shutdown equipment was not met. Specifically, it was discovered that a postulated fire in either of two reactor building fire areas could have resulted in the loss of both trains of chilled water system pumps and thereby causing the loss of room cooling to several areas. The issue was entered into the corrective action program as notification 20442958and reported to the NRC in Licensee Event Report (LER) Number 2009-006, Post-fire Safe Shutdown Analysis Error. The inspectors reviewed the licensee\'s corrective actions and found them to be acceptable. The finding is of very low safety significance because the event would not have resulted in the immediate loss of any safe shutdown equipment and actions could have been taken to open doors and to provide supplemental cooling fans.
05000244/FIN-2010006-012010Q2GinnaFailure to Take Adequate Corrective Actions for Elevated Chlorides in the A EDG Jacket Water Heat ExchangerThe team identified an NRC-identified finding of very low safety Significance associated with a non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion XVI, \"Corrective Action,\" in that rneasures were not established to assure that a condition adverse to quality was prornptly identified and corrected. Specifically, after Ginna identified that monthly samples of the emergency diesel generator (EDG) jacket water system were not being taken and analyzed for chlorides and fluorides, a sample was not taken and analyzed for approximately five months. Additionally, after the analysis indicated that the chlorides were over twice the procedural limit, Ginna did not increase the chloride sampling frequency, did not take action to retum the chlorides to within specifications, and did not complete an analysis for long term effects on the EDG as required by chemistry procedure CH-138, \"Closed Cooling Water Systems Chemistry Optimization Plan,\" Revision 1. Ginna\'s corrective actions included evaluating the degradation of the A EDG jacket water due to the elevated chloride level in the A EDG jacket water heat exchanger exceeding 90 days and developing a plan to reduce the chloride level to within specification. This finding is more than minor because if left uncorrected, elevated chloride levels in the A EDG jacket water system could lead to a more significant safety concern. Specifically, elevated chlorides in the A EDG jacket water heat exchanger could lead to degradation of the jacket water heat exchanger through stress corrosion cracking and impact the reliability of the A EDG. This finding is associated with the Mitigating Systems Cornerstone and affects the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). The team determined that the finding was of very low safety significance (Green), because it was not a design or qualification deficiency confirmed not to result in loss of operability; did not result in a loss of safety function; and did not screen as potentially risk significant due to a seismic, flooding, or a severe weather initiating event. This finding has a cross-cutting aspect in the area of problem identification and resolution because Ginna did not take appropriate actions to address the elevated chloride level in the A EDG jacket water system (P.1 (d) per IMC 0310).
05000338/FIN-2009005-032009Q4North AnnaUnits 1 and 2 Station Battery Cable Installation IssuesA URI was identified by the inspectors relating to an issue involving the installation of cabling associated with the emergency DC bus station batteries for each of the 4 channels on Units 1 and 2. On November 17, 2009, the licensee initiated CR358461 for NRC-identified issues relating to installation of cabling associated with the emergency DC bus station batteries for each of the 4 channels on Units 1 and 2. Specifically, the cables did not appear to meet vendor installation requirements for the cables such that the battery posts do not bear the load. The licensee completed an operability determination, OD000347, which used the Seismic Qualification Utility Group process to determine the batteries were operable but not fully qualified; however, the inspectors review of this document has not been completed. Additionally, licensee engineering evaluation of their installation relative to vendor requirements is also ongoing. The inspectors require additional information from the licensee to determine if there is a performance deficiency which is greater that minor. This issue is identified as URI05000338, 339/2009005-03, Units 1 and 2 Station Battery Cable Installation Issues.
05000338/FIN-2009005-062009Q4North AnnaLicensee-Identified ViolationTS 5.4.1.a, requires in part, that written procedures shall be established per Regulatory Guide 1.33, Appendix A, of which part 6 requires procedures for combating emergencies and other significant events such as acts of nature. Contrary to this, on October 13, 2009, the licensee failed to adequately establish procedure, 0-AP-41, Severe Weather Conditions, Revision 44, such that the SWVH missile shield doors were properly secured. This issue was identified in the licensees CAP as CR346333. A regional Senior Reactor Analyst performed a Phase 3 evaluation under the Significance Determination Process and concluded that the finding was of very low safety significance (Green). The dominant accident sequence involved a postulated tornado causing a non-recoverable Loss of Offsite Power and four of the six Service Water Pumps on site failing due to the performance deficiency. Then operators failed to switch to the Lake to Lake cooling mode. This resulted in a loss of all service water which caused a loss of all cooling to the RCP seals. A seal LOCA ensued without RCS makeup capability since service water provided the ultimate cooling capability for the High Head Safety Injection/Charging pumps. Consequently, core damage happened. For the equipment that failed as a consequence of the performance deficiency no recovery was assumed. Also, an exposure period of eight months was used for the evaluation
05000338/FIN-2009005-042009Q4North AnnaDevelopment of Work OrdersA URI was identified by the inspectors relating to an issue involving the development of WOs relating to specific job steps. On November 24, 2009, the licensee initiated CR359447 for NRC-identified issues relating to the development of WOs and respective job steps. Specifically, the inspectors noted that WO 59102015102 contained job steps to perform the work and referenced no maintenance procedure. The inspectors determined that WOs are developed per work management administrative procedure, WM-AA-100, Work Management, Revision 4, which allows the use of job steps in lieu of a maintenance procedure. However, the inspectors also noted that WM-AA-100 does not require the same level of technical review as administrative procedure, VPAP-0502, Procedure Process Control, Revision 49, requires for supplemental work instructions. The licensee does not expect to complete their evaluation until February, 2010.The inspectors require additional information from the licensee to determine if there is a performance deficiency which is greater that minor. This issue is identified as URI05000338, 339/2009005-04, Development of Work Orders.
05000220/FIN-2009005-012009Q4Nine Mile PointTwo APRMs Inoperable Contrary to Procedure RequirementA self-revealing non-cited violation (NCV) of Technical Specification (TS) 604, Procedures, was identified when Unit 1 operators removed average power range monitor(APRM) 18 from service for maintenance while APRM 14 was inoperable due to a detector malfunction, contrary to a prerequisite of the APRM 18 maintenance procedure. Operators did not use a readily available control room indication of APRM 14, which showed that the instrument was malfunctioning, when verifying that it was operable. As immediate corrective action, APRM 14 was placed in bypass. The failed local power range monitor (LPRM) input that was causing the malfunction was identified and placed in bypass, and APRM 14 was returned to service. The issue was entered into the corrective action program (CAP) as condition report (CR) 2009-7943.The finding was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding was of very low safety significance because it 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. The finding had a cross-cutting aspect in the area of human performance, work practices, because operators did not utilize all available information when verifying that APRM 14 was operable, and thereby did not satisfy a procedure requirement prior to proceeding with the APRM 18 maintenance activity (HA.b per IMC 0305).
05000220/FIN-2009005-022009Q4Nine Mile PointFailure to Implement the Operator Workaround Program During 2009An NRC-identified finding was identified on November 19,2009, when inspectors determined the NMPNS Operator Workaround program had not been implemented at Unit 1and Unit 2 in accordance with Nuclear Administration Instruction NAI-REL-02, Control of Operator Workarounds, Burdens and Interests, Revision 07, during the year 2009. As a result, determinations of operational encumbrances that constituted workarounds, burdens, and interests, had not been made by the Unit Workaround Coordinators, lists of these items had not been maintained, and quarterly aggregate reviews of their impact on the ability of operators to perform their duties had not been performed during that period. As corrective action, NMPNS performed a review of work orders that were opened during 2009, and were coded as being operator workarounds or burdens, to identify existing operator workarounds and burdens. An evaluation of that information was performed, which concluded that the station had not been in an unrecognized increased risk condition as a result of the cumulative effects of all workarounds and burdens. The issue was entered into the corrective action program (CAP) as condition report (CR) 2009-8395.The finding was more than minor because the NRC considers licensee identification of operator workaround problems at an appropriate threshold, and implementation of follow-on actions that focus and progress corrective actions to completion, to be an important aspect of problem identification and resolution, as discussed in IP 71152, Identification and Resolution of Problems. The failure to implement the operator workaround program, if left uncorrected, had the potential to increase the likelihood of operator errors during normal and off-normal conditions and lead to a more significant safety concern. The finding had across-cutting aspect in the area of human performance, decision-making, because the roles and authorities of the Operator Workaround Coordinators for Units 1 and 2 were not effectively communicated during the personnel turnover that occurred at the beginning of2009, and therefore were not implemented as designed during the year 2009 (H.1.a per IMC 0305).
05000338/FIN-2009005-052009Q4North AnnaInadequate Procedure Results in Excess Letdown Heat Exchanger LeakageA Green, self-revealing, non-cited violation of TS 5.4.1a was identified for the failure to adequately establish procedural requirements for component cooling (CC)water flow through the Unit 1 excess letdown heat exchanger (Hx) which resulted in a cracked Hx tube and excessive reactor coolant system (RCS) leakage when placing the Hx in service. The licensee entered this problem into their corrective action program as condition report 354523.This finding had a credible impact on safety due to continuous, excessive CC flow through the excess letdown Hx which caused a tube crack that allowed excessive intersystem leakage from the reactor coolant system (RCS) at approximately 60 gallons per minute for the 4 minutes in which the excess letdown heat exchanger was in service. The finding was more than minor because if left uncorrected it would have the potential to result in a more significant event involving multiple tube cracks with consequent leakage exceeding the capacity of a charging pump. In accordance with NRC inspection manual chapter (IMC) 0609, Significant Determination Process, the inspectors performed a phase 1 analysis and determined the finding required a phase 2 analysis by a regional senior reactor analyst (SRA) due to the finding resulting in RCS leakage that exceeded TS limits. The finding resulted in an intersystem leak from the RCS system into the CC system when the excess letdown Hx was placed into service; however, an intersystem LOCA was not addressed in the pre-solved risk table, therefore a phase 3analysis was performed by the SRA in accordance with the guidance of NRC IMC 0609, Appendix A. The SDP phase 3 risk evaluation resulted in a risk increase for the finding of less than 1E-6 for core damage frequency and less than 1E-7 for large early release frequency. The dominant sequence was an RCS leak into the CC system due to tube leakage in the excess letdown Hx when excess letdown was initiated, coupled with a failure of the charging function and a failure to isolate the leakage. Therefore, the finding was characterized as of very low safety significance (Green). The risk was low due to the magnitude of the leakage, which was less than the makeup capability of 1 charging pump, the availability of charging pumps to mitigate the leakage, and the high probability of accomplishing letdown isolation given the multiple operator cues and time availability. The finding had no cross-cutting aspects due to its legacy nature
05000321/FIN-2008005-012008Q4HatchFailure to Report a Reportable ConditionA NRC-identified violation of 10 CFR 50.72, Immediate Notification Requirements for Operating Nuclear Power Reactors, and 10 CFR 50.73, Licensee Event Report System, was identified when the licensee did not recognize the loss of all three main control room (MCR) air handling units (AHUs) was a reportable condition. Consequently, the licensee failed to make an eight hour report as required by 10 CFR 50.72 and submit a licensee event report (LER) within 60 days as required by 10 CFR 50.73. This violation does not apply to Unit 1 because it was in a refueling outage and the AHUs were not required to be operating. This violation has been entered into the licensees CAP as CR 2008111957. Failure to recognize the loss of the MCREC system safety function was reportable is a performance deficiency. This finding was evaluated using traditional enforcement because it had the potential for impacting the NRCs ability to perform its regulatory function of event assessment. The inspectors determined this finding was a SL IV violation because the failure to report this condition did not substantively impact the Agency\'s regulatory responsibilities and the Agency would not have responded in a significantly different manner had the information been properly reported. This finding had the cross-cutting aspect of evaluating for reportability in the area of Problem Identification and Resolution (P.1(c)) because the licensee evaluated reportability only for the entry into TS LCO 3.0.3. (Section 4AO5)
05000321/FIN-2008005-032008Q4HatchLicensee-Identified ViolationTechnical Specification 5.7.1.a requires, in part, that each high radiation area, in which the intensity of radiation is > 100 mrem/hr but < 1000 mrem/hr, measured at 30 cm from the radiation source or from any surface the radiation penetrates, shall be barricaded and conspicuously posted as a high radiation area. Contrary to the above, on October 14, 2008, the licensee was transferring Unit 1 condensate phase separator resin to the vendors equipment for receiving the resin; however, the licensee did not barricade nor conspicuously post the areas that contained the pipes used for transferring the resin as a high radiation area. Licensee evaluations performed after the event showed that the intensity of radiation was >100 mrem/hr but <1000 mrem/hr measured at 30 cm from the pipe surfaces in those areas. This finding was entered in the licensees corrective action program as Condition Report 2008110421. This finding is of very low safety significance because there was no evidence of unauthorized worker entry into the area and no unexpected /unintended radiation exposures to licensee personnel
05000321/FIN-2008005-022008Q4HatchLicensee-Identified Violation10 CFR 50.73(a)(2)(i)(B) requires in part that the licensee shall report any condition which was prohibited by technical specifications. Contrary to this, on May 19, 2008, the licensee determined that pressure boundary leakage resulting from a weld failure in an instrumentation sensing line was discovered on March 8, 2005, and not reported. This issue was entered in the licensees corrective action program under CR 2008103067. This finding is of very low safety significance because the leak was very small and within the RCS leakage accident analysis
05000321/FIN-2008004-012008Q3HatchLicensee-Identified Violation10 CFR 50 Appendix B Criterion V, Instructions, Procedures, and Drawings states in part that Activities affecting quality shall be prescribed by documented instructions, procedures, ..... appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures,... Contrary to this on March 1, 2007, the licensee determined both the inboard and outboard drywell floordrain sump isolation valves failed their LLRT due to foreign material intrusion. This finding is of very low safety significance because the overall penetration leakage was small compared to the primary containment volume. This finding was entered in the licensees corrective action program under CR 2007102669
05000321/FIN-2008004-022008Q3HatchLicensee-Identified Violation10 CFR 50, Appendix B, Criterion III, Design Control states, in part, that the design control measures shall provide for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculation methods, or by the performance of a suitable testing program. Contrary to the above, the licensee did not adequately evaluate, or use other means to demonstrate, that the RHRSW flow control valves operating in the normal flow regimes would not cause cavitation and subsequent vibration such that the RHRSW piping hangers would remain functional. This finding is of very low safety significance because a subsequent operability determination demonstrated that there was no loss of RHRSW system safety function capability. This finding was entered into the licensees corrective action program as CR2008101568
05000335/FIN-2008008-012008Q3Saint LucieLicensee-Identified Violation10 CFR Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires 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, and drawings. On December, 27, 2007, operations Component Cooling Water (CCW) system valve, TCV-14-4B failed its quarterly stroke time surveillance. The cause of this failure was attributed to the installation of an o-ring not designed for the application. This installation of an unapproved o-ring was a deviation from the requirements of site procedure QI-8-PR/PSL-1. This violation is of very low safety significance because it did not result in actual loss safety function for the B Train ICW for greater than its Technical Specification allowed outage time
05000335/FIN-2008006-012008Q3Saint LucieLicensee-Identified Violation10 CFR Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires 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, and drawings. On December, 27, 2007, operations Component Cooling Water (CCW) system valve, TCV-14-4B failed its quarterly stroke time surveillance. The cause of this failure was attributed to the installation of an o-ring not designed for the application. This installation of an unapproved o-ring was a deviation from the requirements of site procedure QI-8-PR/PSL-1. This violation is of very low safety significance because it did not result in actual loss safety function for the B Train ICW for greater than its Technical Specification allowed outage time.
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