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05000339/FIN-2017001-012017Q1North AnnaInadequate Design Control of 2 -RC- P-1C Piping SupportsGreen . A self -revealing Green NCV of 10 CFR 50, Appendix B, Criterion III, Design Control, was identified for the failure to correctly translate applicable regulatory requirements and the design basis into specifications, drawings, procedures, and instructions . Specifically, the licensee failed to include the pipe support (2 -FPH -CH- 416- 11) in the scope of design change (DC) NA -13- 01059, Unit 2 Reactor Coolant Pump Seal Replacement, which resulted in a large mean stress on the socket weld due to the 1.5- inch controlled bleed- off line piping not being properly aligned in the downstream pipe support, and therefore not allowing for the thermal growth of the reactor coolant system (RCS). As a result of the large mean stress, a crack initiated at a small defect (lack of fusion) in the toe of the socket weld and propagated through the weld due to normal cyclic vibration from the Unit 2 C reactor coolant pump (RCP). This finding was entered into the licensee's corrective action program as Condition Report (CR) 1043540. The finding was more than minor because it was associated with the design control attribute of the Initiating Events and Barrier Integrity cornerstones and adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radio- nuclide releases caused by accidents or events. Specifically, the inadequate design control of the piping support following Unit 2 RCP Seal Replacement resulted in an un-isolable through wall leak in the controlled bleed- off line piping and was identified as RCS pressure boundary leakage. The inspectors evaluated the finding in accordance with Manual Chapter 0609.04, Initial Characterization of Findings, Table 2, dated October 7, 2016, and the inspectors screened the finding using Inspection Manual Chapter (IMC) 0609, Appendix A, Significance Determination Process (SDP) for Findings at -Power, dated June 19, 2012. The finding screened out in the review of the Barrier Integrity cornerstone as the performance deficiency ( PD ) was not related to pressurized thermal shock ; therefore , the finding will be addressed under the Initiating Events cornerstone. Since the issue affected multiple cornerstones and because the licensee classified the leakage as RCS pressure boundary leakage, the NRC performed a detailed risk evaluation for the PD. The detailed risk evaluation was performed by a regional SRA in accordance with the NRC IMC 0609 Appendix A utilizing the NRC North Anna SPAR model. The PD was modeled as an increase in the small loss of coolant accident frequency given a failure of the RCP seal. The dominant sequence was a rupture in the controlled bleed off line leading to a small loss of coolant accident due to RCP seal failure with failure of 3 containment sump recirculation leading to loss of core heat removal and core damage. The risk was mitigated by the RCP seal failure probability and the remaining mitigation. The detailed risk evaluation estimated that the PD resulted in an increase in core damage frequency of < 1.0 E -6/year, a GREEN finding of very low safety significance. The finding had a cross -cutting aspect in the area of human performance, work management H.5, because the licensee failed to include the pipe support (2-FPH -CH- 416 -11) in the scope of the design change by engineering information bulletin (EIB) # N10 -002 requirements
05000338/FIN-2017001-022017Q1North AnnaChemical Addition System Outside of Technical Specification Due to Excessive Unseating Thrust on MOVsa. Inspection Scope The LER documented that North Anna failed to maintain the full design bases functionality of its Sodium Hydroxide (NAOH) injection for both units as required by TS 3.6.8. The inspectors reviewed the LER and the associated corrective action document (CR 1029674) to verify the accuracy and completeness of the LER and the appropriateness of the licensees corrective actions. The inspectors also reviewed the LER and CR to identify any licensee performance deficiencies associated with the issue. b. Findings Description: On March 9, 2016, with Unit 1 (U1) at 100 percent power in Mode 1 and Unit 2 (U2) in Mode 6 for a scheduled refueling outage, 2-QS-MOV-202B failed to stroke open during testing due to excess unseating thrust. An extent of condition review and engineering evaluation determined that 2-QS-MOV-202A maintained its safety function. An extent of condition review and engineering evaluation of the U1 valves determined that 1-QS-MOV-102B maintained its function but 1-QS-MOV-102A did not. While only one of the valves is needed in order for the system to perform its safety function, TS 3.6.8 requires both valves to function in order to be considered operable. A failure of these valves would result in a loss of redundant safety function and inability to perform an emergency operating procedure or to prevent mitigating the consequences of accidents that would result in potential offsite exposure in excess of 10 CFR Part 100 limits. These valves were originally installed in September 2010 (U1) and September 2011 (U2). These valves are stroked every refueling outage per the IST and monitored by the motor operated valve (MOV) program every six refueling outages. The licensees investigation determined that all appropriate testing per the MOV program and design changes have been applied. No previous failure of these valves were identified. No human errors were found during initial valve set up or maintenance and no design errors were identified. The licensees apparent cause evaluation (ACE) concluded that the cause of 2-QS-MOV-202B exhibiting excessive unseating thrust, resulting in a failure to open during functional testing, was due to mechanical binding internal to the valve body and/or actuator. This was also considered to be the cause for the excessive unseating thrust exhibited in 1-QS-MOV-102A. Valves 2-QS-MOV-202A and 1-QS-MOV-102B also exhibited mechanical binding, but not to the same degree and did not fail. The licensee implemented corrective actions to ensure the chemical addition tank isolation MOVs do not bind again, Design Changes (DC NA-16-00023 for U1 and DC NA-16-00021 for U2) were implemented to change the actuator gear set to provide more unseating capability for the valves. In addition, the valve stroke was changed to position limit switch controlled verses torque controlled seating, allowing valve seating to be adjusted to lighter loads providing even more margin. As an interim compensatory measure, these valves will be stroked every six months in addition to every cold shutdown. Stroking the valves verifies capability and reduces the pull-out-force required for the next stroke. Valve stroke frequency will be reviewed based on data collection and may support revision to the operability determination currently in place for Units 1 and 2. Based on review of the licensees ACE, the historical industry operating experiences, and previous MOV test data and IST stroke time data, the inspectors determined that there was no performance deficiency associated with this issue because the cause of failed the TS surveillance tests was not reasonably within the licensees ability to foresee and correct. Enforcement: The inspectors determined a violation of TS occurred because of failure to maintain the full design basis functionality of the Chemical Addition System. North Anna TS Limiting Condition for Operation (LCO) 3.6.8 requires the Chemical Addition System to be operable when in Modes 1, 2, 3 and 4. The associated action statement requires, in part, that with the Chemical Addition System inoperable, Restore Chemical Addition System to OPERABLE status within 72 hours and if Required Action and associated Completion Time is not met, the unit be in Hot Standby within 6 hours and in Cold Shutdown within 84 hours. Contrary to the above, on March 9, 2016, the licensee determined that the Chemical Addition System was inoperable on U1 for more than 72 hours while the unit was in Modes 1, 2, 3 and 4; and U1 was not placed in Hot Standby within 6 hours and in Cold shutdown within 84 hours. Later, through an extent of condition review, the licensee concluded that the U2 Chemical Addition System was also inoperable. Although a violation of the TS occurred, the violation was not reasonably foreseeable and preventable by the licensees QA measures or management controls. Therefore, the violation of TS 3.6.8 was not associated with a licensee performance deficiency. The inspectors concluded that the violation would normally be considered at Severity Level III in accordance with Enforcement Policy section 6.1.c. However, the inspectors utilized available risk-informed tools to more accurately assess the safety significance of this issue. Since the chemical addition system is considered a part of containment system, the inspectors evaluated this issue in accordance Manual Chapter 0609.04, Initial Characterization of Findings, Table 2, dated October 7, 2016 and the finding was determined to adversely affect the Barrier Integrity Cornerstone. The inspectors screened the finding using Inspection Manual Chapter (IMC) 0609, Appendix A, Significance Determination Process (SDP) for Findings at-Power, dated June 19, 2012, and determined that the finding screened as low safety significance (Green) because it did not represent an actual open pathway in the physical integrity of reactor containment (valves, airlocks, etc.), containment isolation system (logic and instrumentation), and heat removal components; and it did not involve an actual reduction in function of hydrogen igniters in the reactor containment. This issue represented a degradation of the radiological barrier function provided for the reactor building. However, because the violation was not associated with a licensee performance deficiency and it was not avoidable by reasonable licensee QA measures or management controls, the NRC is exercising enforcement discretion (EA-17-007) in accordance with Section 3.10 of the Enforcement Policy. The violation will not be considered in the assessment process or the NRCs Action Matrix. This issue was documented in the licensees corrective action program as CR1029674.
05000382/FIN-2016008-022016Q4WaterfordFailure to Perform Operability Determinations for Nonconforming ConditionsThe team identified a Green non-cited violation of 10 CFR Part 50, Appendix B,Criterion V, Instructions, Procedures, and Drawings, that occurred when the licensee failed on two occasions to perform an operability determination for a nonconforming condition affecting numerous safety-related components. Following receipt of information from a vendor that more than 124 relays potentially installed in safety-related applications did not conform to quality requirements, licensee personnel failed to perform an operability evaluation. Later, during a Part 21 evaluation for the potential defect, the evaluator noted that an operability determination was needed, but failed to initiate the appropriate processes. After discussion with the team, the licensee documented this condition in Condition Report CR-WF3-2016-07710, declared the affected components operable, but degraded, and initiated actions to restore full qualification.Failures to perform an operability determination following identification of a nonconforming condition as required by station procedures were two examples of a performance deficiency.This performance deficiency was more-than-minor because it was associated with the design control attribute of the Mitigating Systems Cornerstone and adversely affected the objective of ensuring the availability, reliability, and capability of systems that respond to initiating events. Using Inspection Manual Chapter 0609, Appendix A, dated June 19, 2012,the team determined that this finding was of very low safety significance (Green) because it did not represent the actual loss of function of any system or train. The finding has an identification cross-cutting aspect in the problem identification and resolution cross-cuttingarea because licensee personnel failed to recognize a nonconforming condition as a condition adverse to quality (P.1).
05000382/FIN-2016008-032016Q4WaterfordFailure to Include Appropriate Quantitative Acceptance Criteria for the Reconstituted Feedwater/Emergency Feedwater Monitoring Plan Associated with Steam Generator Replacement Induced VibrationThe team identified a finding of very low safety significance and associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensees failure to include appropriate quantitative accept an cecriteria for determining that important activities have been satisfactorily accomplished. Specifically, the licensees reconstituted feedwater and emergency feedwater system monitoring plan, which was created to monitor both systems vibrations following the sites steam generators replacement, did not include a range for acceptable vibration levels for all The team identified a finding of very low safety significance and associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensees failure to include appropriate quantitative acceptance criteria for determining that important activities have been satisfactorily accomplished. Specifically, the licensees reconstituted feedwater and emergency feedwater system monitoring plan, which was created to monitor both systems vibrations following the sites steam generators replacement, did not include a range for acceptable vibration levels for all
05000382/FIN-2016008-012016Q4WaterfordFailure to Control Nonconforming PartsThe team identified a Green non-cited violation of 10 CFR Part 50,Appendix B, Criterion XV, Nonconforming Materials, Parts, or Components, which occurred when the licensee failed to dedicate commercial-grade relays for use insafety-related applications. After receiving information from a vendor that more than124 relays potentially installed in safety-related applications did not conform to quality assurance standards, the licensee failed to take appropriate steps to accept these Commercial-grade relays as basic components. After discussion with the team, the licensee documented this condition in Condition Report CR-WF3-2016-07710 and initiated actions to ensure compliance with quality assurance requirements. The failure to dedicate commercial-grade relays used asor intended for use asbasic components (in safety-related applications) as required by plant procedures and by10 CFR Part 21 was a performance deficiency. This performance deficiency wasmore-than-minor because it was associated with the design control attribute of the Mitigating Systems Cornerstone and adversely affected the objective of ensuring the availability,reliability, and capability of systems that respond to initiating events. Using Inspection Manual Chapter 0609, Appendix A, dated June 19, 2012, the team determined that this finding was of very low safety significance (Green) because it was a deficiency affecting the design or qualification of a structure, system, or component, and operability was maintained.The finding has a conservative bias cross-cutting aspect in the human performance cross cutting area because licensee personnel improperly rationalized the adequacy of the nonconforming components to perform their safety-related functions (H.14). Because this performance deficiency was also a violation that impacted the regulatory process, in that the licensee accepted a change to plant design without appropriate evaluation and notification, it was also evaluated for traditional enforcement. The team determined that the violation was Severity Level IV because it was similar to several examples in Section 6.5.d of the NRC Enforcement Policy.
05000382/FIN-2016008-042016Q4WaterfordDeparture from Approved Method to Determine Steam Generator Internal Loads During Main Steam Line BreakThe team identified a Severity Level IV non-cited violation of 10 CFR 50.59(c)(2),Changes, Tests, and Experiments, for the licensees failure to obtain a license amendment prior to implementing a proposed change, test, or experiment that would result in a departure from a method of evaluation described in the final safety analysis report (as updated) used in establishing the design bases or in the safety analyses. Specifically, the licensee departed from their approved CEFLASH-4A methodology to determine steam generator internal differential loads caused by a main steam line break to an unapproved TRANFLOW methodology. In response to this issue, the licensee entered the issue into the corrective action program as Condition Report CR-WF3-2016-07639 and initiated actions to prepare a new evaluation under current regulatory guidelines or to submit a license amendment request to the NRC.The licensees failure to obtain a license amendment prior to implementing a change that resulted in a departure from a method of evaluation described in the final safety analysis report (as updated) used in establishing the design bases or in the safety analyses, as required by 10 CFR 50.59(c)(2) was a violation. In accordance with the NRC Enforcement Manual, violations of 10 CFR 50.59 are not processed through the Reactor Oversight Process significance determination process because this violation potentially impacted the ability of the NRC to perform its regulatory oversight function. Therefore, this violation was processed through traditional enforcement examples of Section 6.1 of the NRC Enforcement Policy. This violation was more-than-minor because there was a reasonable likelihood that the change would require NRC review and approval prior to implementation, similar to the more-than-minor example of a change in requirements in the NRC Enforcement Manual,Appendix E, Minor Violations Examples, dated September 9, 2013. In accordance with the NRC Enforcement Policy, the significance determination process was used to inform the significance of the failure to obtain a license amendment prior to implementing a proposed change. The departure from the original CEFLASH-4A method to the TRANFLOW method to determine differential loads on steam generator internal structures following a main steam line break event was associated with the design control attribute of the Barrier Integrity Cornerstone and adversely affected the objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. In accordance with Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012,Exhibit 1, Initiating Events Screening Questions, the issue screened as having very low safety significance (Green) because the issue would not result in the complete or partial loss of a support system that contributes to the likelihood of an initiating event, or result in the steam generators violating accident leakage performance criterion. Since the violation was determined to be Green in the significance determination process, the traditional enforcement violation was determined to be a Severity Level IV violation, consistent with the example in paragraph 6.1.d(2) of the NRC Enforcement Policy. Traditional enforcement violations are not assessed for cross-cutting aspects.
05000382/FIN-2013004-012013Q3WaterfordFailure to Make a Report Required by 10 CFR 21.21The team identified a violation of 10 CFR 21.21 that occurred when the licensee failed to submit a report or interim report on a deviation in a basic component within 60 days of discovery. The failure of the licensee to adequately evaluate deviations in basic components and to report defects is a performance deficiency. The NRCs significance determination process (SDP) considers the safety significance of findings by evaluating their potential safety consequences. This performance deficiency was of minor safety significance. The traditional enforcement process separately considers the significance of willful violations, violations that impact the regulatory process, and violations that result in actual safety consequences. Traditional enforcement applied to this finding because it involved a violation that impacted the regulatory process. Supplement VII to the version of the NRC Enforcement Policy that was in effect at the time the violation was identified provided as an example of a violation of significant regulatory concern (Severity Level III), An inadequate review or failure to review such that, if an appropriate review had been made as required, a 10 CFR Part 21 report would have been made. Based on this example, the NRC determined that the violation met the criteria to be cited as a Severity Level III violation. However, because of the circumstances surrounding the violation, including the removal from service of the affected components by an unrelated manufacturers recall, the severity of the cited violation is being reduced to Severity Level IV. Cross-cutting aspects are not assigned to traditional enforcement violations.
05000348/FIN-2009007-022009Q4FarleyLicensee-Identified ViolationTS 3.8.6 requires that battery cell parameters for Train A and Train B Auxiliary Building and Service Water Intake Structure (SWIS) batteries shall be within the limits of Table 3.8.6-1. TS SR 3.8.6.2 requires battery cell parameters to be verified to meet TS Table 3.8.6-1. If one or more required batteries with one or more battery cell parameters are not within Category B, TS 3.8.6 Action statements are required to verify battery cell parameters meet Table 3.8.6-1 Category C limits (> 2.02 V) once per 7 days thereafter and to restore battery cell parameters to Category B limits (> 2.08 V) within 31 days. Contrary to the above, between February 11 and May 7, 2008, Unit 2 Auxiliary Building B-Train Battery Cell number 33 was 2.06 V which was below TS Table 3.8.6-1 limits and the licensee failed to restore Cell number 33 float voltage to Category B limits within 31 days as required per TS 3.8.6 Action statements. The licensee entered this condition into their CAP as CR 2009105768. This finding was evaluated against NRC SDP Phase 1 screening worksheets and determined to be of very low safety significance (Green) because the battery cell was above the 2.02 V Category C limits during the entire period and therefore, the battery remained available to perform its safety function during the affected period
05000280/FIN-2009006-012009Q4SurryFailure to Demonstrate Effective Preventive Maintenance of Safety Injection Check Valves Nor Set Goals and Monitor Under 10CFR50.65(A)(1)The inspectors identified a Green non-cited violation (NCV) of 10 CFR 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Plants, for failure to demonstrate effective preventive maintenance of Unit 1 low head safety injection (LHSI) cold leg check valves in accordance with 10CFR50.65(a)(2) and not establish goals and monitor against those goals in accordance with 10CFR50.65(a)(1). The finding is more than minor because it affected the Barrier Integrity cornerstone objective of providing reasonable assurance that physical design barriers (e.g., reactor coolant system (RCS)) protect the public from radionuclide releases caused by accidents or events. Specifically, the finding affected the LHSI cold leg check valves, which provide an isolation barrier from the high pressure RCS when the SI System is in standby to ensure that the integrity of the reactor RCS boundary is maintained. The finding is also associated with the cornerstone attribute of reactor coolant system equipment and barrier performance. The inspectors determined that this performance deficiency was a separate consequence of the degraded performance associated with the LHSI cold leg check valves. Because of this characterization, the inspectors determined that this issue should not be processed through the Significance Determination Process. Therefore, in accordance with the guidance in NRC Inspection Procedure 71111.12, Appendix D, this issue was determined to be a maintenance rule Category II finding and is of very low safety significance (Green). Based on the assessment performed by the team on the current licensees implementation of 10CFR50.65, the results of the licensees extent of condition review for this finding, and because this finding occurred on November 18, 2007, the team determined that this finding was not indicative of current licensee performance and, therefore, no Cross Cutting Aspect was assigned to this issue. This issue was entered in the licensees CAP as CR02560. The licensee restored compliance by establishing goals and monitoring the system performance against those goals in accordance with 10CFR50.65(a)(1)
05000400/FIN-2009006-012009Q4HarrisFailure to Preclude Repetition of a Significant Condition Adverse to Quality for Both Containment Spray Additive System Eductors Being Outside of the Technical Specification Flow BandThe team identified a non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, \"Corrective Action,\" for the licensees failure to identify the cause and take corrective actions to preclude repetition of a significant condition adverse to quality for both containment spray additive system eductors being outside of the technical specification flow band. Specifically, between July 2009 and the present, the violation occurred when Eductor A was found three times and Eductor B was found once outside of the Technical Specification 3.6.2.2 flow band. This issue was previously identified as a significant condition adverse to quality in January 2008, but the corrective actions taken failed to preclude repetition. The licensee entered this issue into the corrective action program as nuclear condition report 356873. The licensee took immediate corrective actions to throttle the eductor flow to within the band, and is developing corrective actions to preclude repetition. The finding is more than minor because it is associated with the design control attribute of the Barrier Integrity Cornerstone and affects the cornerstone objective of providing reasonable assurance that physical design barriers, such as the iodine scrubbing capability of the containment spray additive system eductors, will protect the public from radionuclide releases caused by accidents or events. Using Manual Chapter 0609.04, \"Phase 1 Initial Screening and Characterization of Findings,\" the finding was determined to have a very low safety significance because it did not represent a degradation of the radiological barrier function provided for the control room, auxiliary building, or spent fuel pool; the finding did not represent a degradation of the barrier function of the control room against smoke or a toxic atmosphere; the finding did not represent an actual open pathway in the physical integrity of reactor containment; and the finding did not involve an actual reduction in function of the hydrogen igniters in the reactor containment. The finding had a cross-cutting aspect in the area of problem identification and resolution associated with the corrective action program because the licensee did not thoroughly evaluate problems such that the resolutions address causes and extent of conditions, as necessary, and for significant problems, conduct effectiveness reviews of corrective actions to ensure that the problems are resolved (P.1(c)) (Section 4OA2.a(3)(i))
05000348/FIN-2009007-012009Q4FarleyInadequate Procedure for the B train SSPS System TestingA self-revealing violation of 10 CFR 50 Appendix B, Criterion V Instructions, Procedures, and Drawings, was identified for an inadequate procedure for testing the B train solid state protection system (SSPS) (FNP-1- STP-33.3). While Unit 1 was in Mode 5 and N31 source range instrumentation was tagged out and unavailable, the licensee performed step 5.6.1.1B of FNP-1- STP-33.3, resulting in N32 source range instrument being de-energized. Procedure FNP-1-STP-33.3 inadvertently de-energized the only operable source range instrument for Unit 1. TS 3.3.1 required a minimum of one source range neutron flux monitor with the plant in this condition. When the licensee recognized this condition, they immediately restored power to N32 and exited the TS action. The licensee initiated condition report (CR) 2009105672 to address this issue. The issue was more than minor because it was associated with the procedure quality 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 (i.e., core damage). Specifically, the SSPS procedure resulted in a total loss of source range instrumentation during testing. This affected the safety function of source range neutron flux indication in Mode 5. This finding was assessed using the Phase 1 and 2 Shutdown Operations screening worksheet of the SDP and was determined to require a Phase 3 analysis because the finding involved a loss of source range monitors while shutdown. This finding was determined to be of very low safety significance because the dominant sequence is a boron dilution event and de-energizing the source range for less than a minute would not prevent an operator from taking the necessary actions to address potential boron dilution. No cross-cutting issue was identified. (Section 4OA2.a.(3))
05000400/FIN-2009006-022009Q4HarrisFailure to Correct a Condition Adverse to Quality Involving a Main Steam Isolation Valve Degrading Trend Before Valve FailureThe team identified a non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, \"Corrective Action,\" for the licensees failure to correct a condition adverse to quality in a timely manner. Specifically, between May 27, 1997 and September 29, 2007, Main Steam Isolation Valve 82 close stroke time exhibited a condition adverse to quality for a trend degrading towards the technical specification limit, without sufficient corrective actions to prevent failure. This resulted in Main Steam Isolation Valve 82 exceeding the five-second stroke time limit required in Technical Specification 3.7.1.5. The licensee entered this issue into the corrective action program as nuclear condition report 358464. This finding is more than minor because it is associated with the containment barrier performance attribute of the Barrier Integrity Cornerstone and affects the cornerstone objective of providing reasonable assurance that physical design barriers, such as the main steam isolation valve radiological release barrier required for a steam generator tube rupture, protect the public from radionuclide releases caused by accidents or events. Using Manual Chapter 0609.04, \"Phase 1 Initial Screening and Characterization of Findings,\" the finding was determined to have a very low safety significance because it did not represent a degradation of the radiological barrier function provided for the control room, auxiliary building, or spent fuel pool; the finding did not represent a degradation of the barrier function of the control room against smoke or a toxic atmosphere; the finding did not represent an actual open pathway in the physical integrity of reactor containment; and the finding did not involve an actual reduction in function of the hydrogen igniters in the reactor containment. This finding had a cross-cutting aspect in the area of human performance associated with decisionmaking because the licensee did not use conservative assumptions so that safety-significant decisions were verified to validate underlying assumptions and identify unintended consequences (H.1.(b)) (Section 4OA2.a(3)(ii))
05000259/FIN-2009006-012009Q3Browns FerryStandby Gas Treatment Subsystem A Inoperable Beyond the Technical Specification Allowed Outage TimeA Green, self-revealing, non-cited violation (NCV) of Technical Specification (TS) limiting condition for operation (LCO) 3.6.4.3, Standby Gas Treatment (SGT) System, was identified for the licensees failure to comply with the LCO required actions for one inoperable SGT subsystem due to an inadequate investigation to ensure the systems operability, on November 30, 2008, following a loss of power to one of the three relative humidity heaters. This issue was entered into the corrective action program as Problem Evaluation Report 174597. The cause of the failure of the heater was a failed relay. The relay was replaced and the system was restored to service on June 20, 2009. The finding is similar to example 2a in Inspection Manual Chapter (IMC) 0612, Appendix E, Examples of Minor Issues, in that the example performance deficiency is not minor if Technical Specification limits were exceeded. In accordance with IMC 0612, Appendix B, Issue Screening, the finding is greater than minor significance because it was associated with the Barrier Integrity cornerstone attribute of Human Performance and adversely affected the cornerstone objective of maintaining the radiological barrier functionality of Standby Gas Trains. Although the licensee ultimately was able to demonstrate that the SGT system could perform its safety function without the charcoal beds and associated heaters, compliance with SGT TS was a prerequisite to providing reasonable assurance that the SGT can protect the public from radionuclide releases caused by accidents or events. 10 CFR 50.36 defines TS limiting conditions for operation as the lowest functional capability or performance levels of equipment required for safe operation of the facility. The SGT TS LCO requirement was not met and therefore the cornerstone objective for functionality as described in the TSs, was not maintained. In accordance with IMC 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, the finding is determined to be of very low risk significance because the finding only represented a degradation of the radiological barrier function provided by the SGT system. Because this finding is of very low safety significance and has been entered in licensees corrective action program, the violation is being treated as a non-cited violation. The cause of this finding was directly related to the crosscutting aspect of thorough evaluation of identified problems in the problem identification and resolution area, because the licensee failed to properly classify, prioritize and evaluate the operability of the SGT system when the heater loss of power annunciator was received (P.1(c)).
05000327/FIN-2009006-012009Q3SequoyahFailure to Promptly Correct a Condition Adverse to Quality Associated with Out-of-Train Maintenance ControlsThe NRC identified a Green non-cited violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, for the licensees failure to promptly correct a condition adverse to quality by failing to implement corrective actions to address deficient out-of-train maintenance controls during opposite train work weeks. This contributed to entry into a short term shutdown action statement and a Notice of Enforcement Discretion (NOED). The failure to implement corrective action to provide guidance for controlling out-of-train maintenance was entered into the licensees corrective action program as PER 177665. This finding was determined to be greater than minor because it was associated with the Barrier Integrity Cornerstone attribute of barrier performance, and on September 25, 2008, adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers such as the control room protect plant operators and plant controls. The finding was evaluated using Phase 1 of the At- Power Significance Determination Process, and was determined to be of very low safety significance (Green) because the finding only represented a degradation of the radiological barrier function provided for the control room. The finding was assigned a cross-cutting aspect in the corrective action program component of the problem identification and resolution area because, although the licensee had identified deficient controls for out-of-train maintenance, corrective actions were not taken to address the issue in an adequate and timely manner, commensurate with safety significance and complexity. (P.1(d)). (Section 4OA2.a.(3)
05000269/FIN-2009006-012009Q3OconeeFailure to Provide Margin Between the LPI Relief Valve Set Point and the Peak Discharge Pressure of the LPI SystemA self-revealing, non-cited violation (NCV) of 10 CFR 50 Appendix B, Criterion III, Design Control, was identified for failure to provide sufficient margin between the peak discharge pressure of the low pressure injection (LPI) system and the relief valve setpoint for the Unit 3 B-train LPI cooler (3LP-37). This resulted in the inadvertent opening of 3LP-37 during LPI startup for decay heat removal on April 25, 2009. The licensee entered the issue into the corrective action program and revised the applicable operating procedure to provide additional margin during LPI startup for decay heat removal. The failure to provide sufficient margin between the LPI relief valve set point and the peak discharge pressure of the LPI system upon startup was a performance deficiency. The finding was more than minor because, if left uncorrected, it would have the potential lto lead to a more significant safety concern, specifically for loss of inventory if the relief valve failed to reseat. Additionally, the finding was associated with the Initiating Events cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown, primarily inventory control. The finding was of very low safety significance (Green) because it met the availability requirements set forth in IMC 0609, Appendix G, Shutdown Operations SDP, which verified that the licensee was maintaining an adequate mitigation capability for shutdown operation. The cause of the finding had a cross-cutting aspect in the area of human performance. It was directly related to the licensee not conducting effectiveness reviews of safety-significant decisions to verify the validity of the underlying assumptions, identify possible unintended consequences, and determine how to improve future decisions aspect of the decision-making component. Specifically, licensee calculation OSC-5616, reviewed and revised in 2008, identified a possible unintended consequence that 3LP-37 could lift during LPI pump start. This was not incorporated into plant procedures to prevent future relief valve lifts. Additionally, with the assumption that the relief setpoint for 3LP-37 was low, the licensee started the LPI system during the3EOC24 outage under the same conditions that 3LP-37 lifted during the 3EOC23 outage
05000259/FIN-2009006-022009Q3Browns FerryLicensee-Identified ViolationThe following Green violation of very low safety significance was identified by the licensee and is a violation of NRC requirements which met the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for disposition as a NCV. 10 CFR 50, Appendix B, Criterion II requires, in part, that the licensee shall establish a quality assurance program and the program shall be documented by written policies, procedures and instructions and be carried out in accordance with those policies, procedures and instructions. SPP 6.1, Work Order Process Initiation, specifies that PERs should be generated for all corrective maintenance work orders. Contrary to this, the licensee failed to implement SPP-6.1, in that several hundred corrective maintenance work orders did not get associated PERs as directed in the procedure. The team determined that this issue was of very low safety significance because none of these corrective maintenance work orders resulted in an operability issue due to the failure to write PERs.
05000327/FIN-2009006-022009Q3SequoyahInadequate Scopng of SSCs Used in EOPs into the Maintenance Rule ProgramOn April 11, 2008, PER 142050 was initiated by the licensee to address an NRC identified Non-Cited Violation (NCV) 05000327, 328/2008003-001, Gland Seal Steam Header Isolation Valve not scoped in Maintenance Rule. One of the corrective actions for this PER was to develop a position paper detailing the basis, background, analysis, and recommendations for adding the Main Steam Isolation Valve (MSIV) backup function into the MR program. As part of this position paper, the licensee performed an extent of condition review that stated, in part, ...for those SSCs previously excluded, the functions would need to be identified and classified... Based on a review of CAP documents the team concluded that there were no open corrective action items to ensure that those SSCs whose use was called out in EOPs were promptly identified and scoped into the MR program as appropriate. Additionally, based on a review of licensee MR program documents and EOPs, the team concluded that although the steam dumps were used in EOP-3 to cool down the Reactor Coolant System (RCS) during Steam Generator Tube Rupture (SGTR) event, no corresponding function for the steam dumps was found in TI-4, Maintenance Rule Performance Indicator Monitoring, Trending, and Reporting 10 CFR 50.65. On July 24, 2009, as a result of the teams concern related to the scoping of EOP SSCs into the MR program, the licensee initiated PER 177211 to evaluate how SSCs that are used to mitigate accidents or transients listed in the EOPs, meet the scope requirements of 10 CFR 50.65. The team concluded that in order to properly evaluate and disposition this issue, additional inspection would be required to understand both the scope of the SSCs involved and the potential impact to the plant that may have occurred as a result of the failure to scope those SSCs into the MR program. The inspection team identified no immediate safety concern because, although there was evidence that the steam dumps were not scoped in the MR program as required, component performance was otherwise being maintained through the use of an established preventive maintenance program and there was no direct evidence that steam dump performance or material condition was being adversely impacted by the failure to scope the steam dumps within the MR program. This issue was identified as URI 05000327, 328/2009006-002, Inadequate Scoping of SSCs Used in EOPs into the Maintenance Rule Program
05000390/FIN-2009006-022009Q2Watts BarFailure to Follow Plant Procedures for Canceling Preventive MaintenanceA self-revealing NCV of Technical Specification 5.7.1 was identified for the licensees failure to follow plant procedures which resulted in the failure of the Unit 1 Shield Building Vent Radiation Monitor System, an effluent radiation monitor. The inspectors determined the licensees failure to follow site procedures for PM cancellation was a performance deficiency and a finding. The inspectors reviewed Inspection Manual Chapter (IMC) 0612 and determined that the finding is more than minor because the finding is associated with the plant facilities/equipment and instrumentation attribute (reliability of process radiation monitors) of the radiation safety cornerstone (public radiation safety) and adversely affected the cornerstone objective of ensuring adequate protection of public health and safety from exposure to radioactive materials released into the public domain as a result of routine civilian use. The finding was assessed using the IMC 0609, Appendix D, Public Radiation SDP, and because there was no failure to implement the effluent program, the finding was determined to be of very low safety significance (Green). No cross-cutting aspect was assigned to this finding because the direct cause was not considered indicative of current performance
05000390/FIN-2009006-012009Q2Watts BarFailure to Promptly Correct a Condition Adverse to Quality Associated with the \'A\' Shutdown Boardroom ChillerA self-revealing non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion XVI was identified for failure to take timely and effective corrective action to maintain the capillary line to the Essential Raw Cooling Water (ERCW) condenser water temperature control valve (1-TCV-67-158) filled with water to ensure operability of the A Shutdown Boardroom chiller. The licensee vented the line, returning the chiller to service, and entered the issue into their CAP. The finding is more than minor because it affects the Mitigating Systems Cornerstone objective of ensuring the availability of the A Shutdown boardroom chiller, which is a system that responds to initiating events. It is also associated with the cornerstone attribute of equipment availability and reliability. This finding was assessed using the Phase 1 screening worksheet of the SDP and determined to be of very low safety significance (Green) because it did not result in an actual loss of safety function of a single train for greater than the Technical Specification (TS) allowed outage time and was not potentially risk-significant due to external events. This finding has a cross-cutting aspect in the Work Control component of the Human Performance area (H.3(b)), because the licensee failed to properly prioritize the compensatory maintenance activities to support safety system operability of an operable but degraded system
05000259/FIN-2008007-022008Q4Browns FerryLicensee-Identified Violation10 CFR 50, Appendix B, Criterion II requires, in part, that the licensee shall establish a quality assurance program and the program shall be documented by written policies, procedures and instructions and be carried out in accordance with those policies, procedures and instructions. Nuclear Quality Assurance Plan, TVA-NQA-PLN89-A, revision 18, dated November 30, 2007, section 10.2.5, QA Trending, specifies that trend analysis shall be performed on adverse conditions and quality indicators associated with QA verification activities and trend results shall be used to identify adverse trends that need increased management attention. Contrary to this, quality assurance policies and procedures were not carried out, in that, during a special review, the licensee documented in PER 152810 an adverse trend associated problems with General Electric type AK-2A-15 and AK-2A-25 circuit breakers trip units. Although 15 PERs had been issued in 15 months for trip unit problems, the licensees normal trending program had failed to detect this adverse trend. This issue was of very low safety significance, in that, licensees evaluations determined that due to various mitigating circumstances, i.e., a redundant breaker maintained the safety function, that the safety function was not lost
05000259/FIN-2008007-012008Q4Browns FerryFailure to Identify an Adverse Trend for Vibration-induced, failed or Degraded Unit 2 and 3 RHR Hx SW Outlet FCVsAn NRC-identified, Green, non-cited violation of 10 CFR 50, Appendix B, Criterion II, Quality Assurance Program, was identified for the licensees failure, between April 2000 and January 2008, to carry out the Nuclear Quality Assurance Plan policy in that trend analysis performed on adverse conditions did not result in trend results which identified vibration-induced, failed or degraded residual heat removal (RHR) heat exchanger (Hx) service water (SW) outlet flow control valves (FCVs) as an adverse trend that needed increased management attention. Between April 2000 and January 2008, there were 17 instances of failed or degraded Unit 2 and 3 RHR Hx SW outlet FCVs due to vibration-induced damage entered into the licensees corrective action program (CAP). This issue has been identified in the licensees CAP as PER 159606. Corrective actions associated with the vibration-induced damage included actions to replace Units 2 and 3 RHR Hx SW outlet FCVs with the same valves used on Unit 1 and to reconfigure all three units with a smaller bypass valve around the RHR Hx SW outlet FCVs. This finding was more than minor because it affected the Mitigating System cornerstone objective of ensuring the reliability of systems that respond to initiating events to prevent undesirable consequences and the cornerstones attribute of equipment performance. Using the Significance Determination Process, the finding was determined to be of very low safety significance due to the RHR Hx SW outlet FCV occurrences, in which the RHR Hx SW outlet FCVs would not perform their safety function, did not represent an actual loss of a safety function of a single RHR SW train for greater than its Technical Specification allowed outage time. The cause of this finding was directly related to the Trend Performance in the CAP cross-cutting aspect of the Problem Identification and Resolution cross-cutting area, in that, the licensee failed to properly assess information in their CAP to identify the common cause problem of vibration-induced degraded and inoperable RHR Hx SW outlet FCVs.(P.1(b)). (Section 4OA2.f
05000348/FIN-2008006-032008Q2FarleyELU Test Failures Were Not Documented in CRS as Required by ProcedureThe team identified a non-cited violation of Farley Unit 2 Operating License Condition 2.C.(6), for the licensees failure to fully implement test control requirements incorporated in approved plant procedures associated with the periodic testing of emergency lighting units. As a consequence, condition reports (CRs) were not initiated as required, when battery conductance measurements did not meet acceptance criteria. The finding was entered into the licensees corrective action program as Condition Report 2008103290. This issue is a performance deficiency because the licensee did not properly document ELU test failures on CRs for trending and evaluation in accordance with the surveillance test procedures. The finding involved systems or components (i.e., emergency lights) required for post-fire safe shutdown of the reactor. The finding is greater than minor because it is associated with the reactor safety Mitigating Systems cornerstone attribute of protection against external factors (i.e., fire) and it affects the cornerstone attribute of ensuring reliability and capability of systems that respond to initiating events. The team determined that this finding was of very low safety significance (Green) because the operators had a high likelihood of completing the task using flashlights, which operators are directed to carry with them by procedure while performing local actions
05000348/FIN-2008006-022008Q2FarleyAreas Where Omas Are Performed DID Not Have Elus InstalledThe team identified a non-cited violation of Farley Unit 2 Operating License Condition 2.C.(6), for the licensees failure to fully implement the approved fire protection program, in that emergency lighting units (ELUs) were not installed in all areas where local operator manual actions were required to support post-fire safe shutdown. Specifically, the team determined that there were no ELUs installed to illuminate the front panels of the Reactor Coolant Pump (RCP) switchgear, located in the Train A switchgear room, where post-fire safe shutdown local operator manual actions were required to trip the RCP 4160 Volt alternating current breakers. The finding was entered into the licensees corrective action program under Condition Reports 2008103335, 336, and 337. The finding is greater than minor because it is associated with the reactor safety Mitigating Systems cornerstone attribute of protection against external factors (i.e., fire) and it affects the cornerstone attribute of ensuring reliability and capability of systems that respond to initiating events. Specifically, the finding adversely affected the ability to perform local operator manual actions required to achieve and maintain safe shutdown conditions following a fire in the cable spreading room. The inspectors assessed the finding using IMC 0609, Appendix F, Fire Protection Significance Determination Process. The team determined that this finding was of very low safety significance (Green) because the operators had a high likelihood of completing the task using flashlights, which operators are directed to carry with them by procedure while performing local actions
05000348/FIN-2008006-012008Q2FarleyFire Procedure Credits Unreliable IndicationThe team identified a non-cited violation of Technical Specification 5.4.1, Procedures, in that Units 1 and 2 post-fire safe shutdown abnormal operating procedures AOP 28.1, Fire or Inadvertent Fire Protection System Actuation in the Cable Spreading Room, and AOP 28.2, Fire in the Control Room, credited diagnostic instrumentation that would have been potentially unreliable due to fire damage from a postulated fire in the control room or cable spreading room. The finding was entered into the licensees corrective action program as Condition Report 2005103665. This issue is a performance deficiency because the safe shutdown procedure relies on an indication which was not protected from fire damage. The finding is more than minor because it is associated with the procedure quality attribute of the Mitigating Systems cornerstone and it affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors assessed the finding using Inspection Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process. The finding was assigned a low degradation rating because it was determined to be a minor procedural deficiency that is compensated by operator experience or familiarity. Because the finding was assigned a low degradation rating, the team determined that this finding was of very low safety significance (Green)
05000280/FIN-2008002-022008Q1SurryFailure to Follow Start-up Procedure which resulted in Leaving Loose Fibrous Insulation in ContainmentAn NRC-identified, non-cited violation (NCV) of very low safety significance was identified for the failure to follow start-up procedure 1-GOP-1.7, revision 2, Unit Startup, RCS Heat Up from Ambient to HSD, which resulted in leaving loose fibrous insulation in containment. This finding is greater than minor because it is associated with the mitigating systems cornerstone attribute of equipment performance and affected the cornerstone objective of ensuring the availability and reliability of systems that respond to initiating events to prevent undesirable consequences. Using the IMC 0609, \"Significance Determination Process,\" Phase 1 Worksheets, the finding is determined to have very low safety significance (Green) since it only affected the mitigating systems cornerstone and did not represent a loss of system safety function. The cause of this finding had cross-cutting aspects associated with work practices of the Human Performance area in that the licensee did not provide the appropriate oversight of contractors conducting the containment walk downs (H.4.c). The finding was entered into the corrective action program as Condition Report 02564. Corrective actions to remove the fibrous material from containment prior to startup and to establish the extent of condition and potential impact on Unit-2 were adequate. (Section 4OA5
05000280/FIN-2008002-032008Q1SurryLicensee-Identified Violation10 CFR part 50.65(a)(4), requires, in part, that before performing maintenance activities, the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activity. Contrary to the above, on February 4, 2008, the licensee tagged out and drained the emergency switchgear room ventilation coolers 1-VS-AC-6 and 2-VS-AC-6, rendering them inoperable, without properly assessing the risk. The components were erroneously thought to be included in the recently added chilled water piping replacement risk term. The licensee recognized the error on February 4, 2008, prior to releasing work. The omitted components were selected in the Safety Monitor program and risk for both units increased to a slightly elevated (Yellow) risk condition. In accordance with Manual Chapter (MC) 0612, Appendix E, example 7.e, the issue is more than minor. The finding was evaluated per MC 0609, Appendix K, and found to be of very low safety significance (Green) because the change in risk had existed for only a short period of time prior to being corrected and the necessary compensatory actions were in-place. This finding was entered into the licensees corrective action program as CR 090374
05000280/FIN-2008002-042008Q1SurryLicensee-Identified ViolationSurry Power Station (SPS) Operating License Condition 3.I states, in part, that the Licensee shall implement and maintain in effect the provisions of the approved fire protection program as described in the Updated Final Safety Analysis Report. Branch Technical Position (BTP) Chemical Engineering Branch (CMEB) 9.5-1, which incorporated the guidance of Appendix A to BTP Auxiliary Systems Branch (ASB) 9.5-1 and the technical requirements of Appendix R to 10 CFR Part 50, established the regulatory and licensing requirements for the fire protection program at SPS. Section 9.10.1 of the UFSAR states, in part, Compliance with these criteria is contained in the following documents: Fire Protection Program document. Section 6.1.o of VPAP-2401, Fire Protection Program, Rev. 28, states that penetration seals must provide equal or greater fire rating than that of the fire barrier. Contrary to the above, the licensee failed to have any sealant providing a fire rating in two fire penetrations in the block walls that separate the Unit 1 and Unit 2 Main Control Room HVAC rooms (Fire Area 5) from the north stairwell (Fire Area 68). This violation is of very low safety significance because the violation did not affect ignition frequencies, detection, or suppression system performance. This issue was entered into the licensees corrective action program as CR 090704
05000280/FIN-2008002-012008Q1SurryLoss of thermal barrier cooling due to a failure to follow proceduresA self-revealing finding of very low safety significance that constituted a non-cited violation (NCV) of Technical Specification 6.4.D was identified. Licensee personnel failed to follow procedure 2-IPM-CC-F-207A and caused cooling water flow to the thermal barrier of the Unit 2 Reactor Coolant Pump (RCP) 1A to be isolated for approximately 15 minutes. The finding was entered into the corrective action program as Condition Report 093555. Licensee corrective actions included re-opening the valve, restoring cooling flow to the thermal barrier, and providing training station wide on procedure adherence. The failure to follow procedure 2-IPM-CC-F-207A was a performance deficiency. The finding is more than minor because it is associated with the human performance attribute of the Initiating Event Cornerstone, and adversely affected the cornerstones objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions. The finding, evaluated per the SDP in IMC 0609, Appendix A, is of very low safety significance (Green) because the finding would not have resulted in exceeding the Technical Specification limit for RCS leakage, due to operation of the RCP seal injection system. This finding has a cross-cutting aspect in the area of human performance work practices (H.4.b) because personnel failed to follow a written and approved procedure. (Section 1R22
05000280/FIN-2007005-072007Q4SurryControl of Heavy LoadsThe inspectors identified that the licensee failed to incorporate a heavy load lift analysis into their UFSAR. Failure to update the UFSAR to reflect aspects of heavy load lifts involving the reactor vessel head and include information from a reactor vessel head drop analysis was a violation of 10 CFR 50.71(e). The NRC has found industry uncertainty regarding the licensing bases for handling of reactor vessel heads, and as a result issued EGM 07-006, Enforcement Discretion for Heavy Load Handling Activities, on September 28, 2007. NEI has informed NRC of industry approval of a formal initiative that specifies actions each plant will take to ensure that heavy load lifts continue to be conducted safely and that plant licensing bases accurately reflect plant practices. The NRC staff believes implementation of the initiative will resolve uncertainty in the licensing bases for heavy load handling, and enforcement discretion related to the uncertain aspects of the licensing basis is appropriate during the implementation of the initiative. During inspection of heavy load lifts, the inspectors determined that the licensee implemented interim actions prior to the specified lifts in accordance with the industry initiative, thereby meeting the following criteria to warrant enforcement discretion: 1) The licensee had neither a single-failure-proof crane nor a load drop analysis (generic or plant-specific) that bounded the planned lifts with respect to load weight, load height, and medium present, so the licensee conducted the head lift at the minimum practicable height and flooded the refueling cavity with water during the head movement to limit the maximum potential impact velocity of the head. The licensee maintained the bottom of the head less than 15 feet above the refueling cavity water surface when the head was lifted above the guide studs. Once the cavity was fully flooded (greater than 23 feet above the reactor vessel flange), the reactor vessel head was allowed to be lifted more than 15 feet above the water surface as necessary to lift the head above immovable structures around the refueling cavity. 2) Included the movement of heavy loads as a configuration management activity in administrative controls established to implement 10 CFR50.65(a)(4). Therefore, consistent with EGM 07-006, we are exercising enforcement discretion for the above violation in accordance with Section VII.B.6 of the NRC Enforcement Policy and are not issuing enforcement action for the violation.
05000280/FIN-2007005-042007Q4SurryFibrous Material Left in Unit 1 ContainmentOn 11/28/07, during Unit 1 Containment Close-out walkdown, the inspectors identified that loose bat insulation had been placed in a 15\' X 5\' penetration in the \'C\' Loop Room. The insulation had not been found by the licensee during their containment readiness verification walkdown. When the inspectors notified the licensee, they removed two 55 gallon bags which were approximately 45 lbs of fibrous insulation. This issue was documented in the corrective action program as Condition Report CR025641. The walkdown was performed by the inspectors to verify that the containment walkdown conducted by the licensee was in accordance with procedural requirements. Later investigation found that the insulation had been there for a number of years. The inspectors reviewed the affected start-up procedure, 1-GOP-1.7 Rev 2, Unit Startup, RCS heatup from ambient to HSD and determined that even though the procedure had several steps in attachment 3 to ensure containment was clear of debris and fibrous material, the associated licensee walkdown failed to reveal the presence of the loose insulation. The licensee performed a more thorough walkdown of containment and verified that no other loose material was present. The issues associated with the fibrous material left in containment and the effects on the containment sump are identified as an unresolved item (URI) pending additional inspection and review from the NRC. This URI is designated 05000280/2007005-04, Fibrous Material left in Unit 1 Containment.
05000261/FIN-2007007-012007Q4RobinsonInadequate Separation and Protection of CST Level Instrument Cables and Equipment Required for SSD in Fire Area G1, FZ 25AThe team identified a noncompliance with 10 CFR 50, Appendix R, Section III.G.2, for the licensees failure to ensure that one train of redundant Condensate Storage Tank (CST) level indication was free of fire damage in FA G1, FZ 25A. Additionally, the team identified the lack of full area coverage of automatic fire detection and suppression systems for Fire Area G1. The violation meets the criteria of NRC Enforcement Policy, Interim Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48) for enforcement discretion. For a fire in FA G1, FZ 25A, procedure DSP-015, Hot Shutdown From the Control Room with a Fire in the Turbine Building, would be utilized to safely shutdown the plant from the MCR. Step 35 directs the operator to check CST level less than 10%. The licensees SSA credits instrument LT-1454A, CST level indication, as being available to the operators in the MCR for a fire in FA G1, FZ 25A. This provides an indication to the operators of when to align Service Water (SW) backup to Auxiliary Feedwater (AFW) water supply. This alternate alignment needs to be performed because the inventory in the CST could be depleted in approximately 2 hours. The team identified that instrument LT-1454A was not protected for a fire in FA G1, FZ 25A and would not be available as specified in operator response procedure DSP-015. Once this issue was identified, it was entered into the licensees corrective action program (CAP) as NCR 00252232. Compensatory measures were put in place prior to the inspectors leaving the site. DSP-015 was later revised to align SW backup to AFW water supply 105 minutes into the event if CST level indication is not available. Additionally, the team identified the lack of full area coverage of automatic fire detection and suppression systems for FA G1, Turbine Building, Fire Zones 25 A, B, C, E, F, and G. In Supplemental Safety Evaluation Report (SSER) dated September, 17, 1986, the NRC granted the licensee an exemption from the technical requirements of 10 CFR 50, Appendix R Section III.G.3, for six FZs located in this FA where fire detection and fixed suppression systems had not been installed throughout the area under consideration. Each of the fire zones under consideration at that time (1986) contained redundant trains of normal safe shutdown systems; however, alternative safe shutdown capability electrically independent from the zones would be available to be used to achieve and maintain safe shutdown. In a letter dated May 31, 2001, Carolina Power and Light (CP&L) notified the NRC that the completion of an analysis in 1998, had resulted in re-designation of Fire Area G1 from a 10 CFR 50, Appendix R Section III.G.3 area to Section III.G.2 area. Consequently, NRC-granted exemptions to 10 CFR 50, Appendix R Section III.G.3, were no longer necessary for the re-designated areas which now met the requirements of 10 CFR 50, Appendix R Section III.G.2. The inspectors review of the licencees safety evaluation screening associated with the plant area re-designation (ESR 00- 00042, Revision 0) found that the licensee reviewers inappropriately determined that no new exemptions were required to satisfy Appendix R requirements. In a letter dated September 5, 2001, the NRC acknowledged the intent of the May 31, 2001 CP&L letter to share review findings. According to CP&L, HBR2 were now in compliance with 10 CFR 50, Appendix R, Section III.G.2 and no additional licensing action was anticipated from NRC. During walk downs of Fire Area G1, the team identified that Fire Zones 25B, C, E, F, and G of the Turbine Building lacked full area fire detection and automatic fire suppression. A portion of Fire Zone 25A had fire detection located on a suspended ceiling but, no automatic fire suppression was installed within this area. This portion of Fire Zone 25A is the Radiologically Controlled Area Entry during plant outages but is utilized as a security operations and locker area during normal plant operation. A large portion of FA G1 lacked full area automatic fire detection and automatic fire suppression capability as required by 10 CFR 50, Appendix R, Section III.G.2, nor had the licensee requested exemptions from any technical requirements of the fire protection rule. This issue was entered into the licensees CAP as NCR 252199.
05000261/FIN-2007007-022007Q4RobinsonOperator Actions During Performance of DSP-002 did not Provide Sufficient Direction to Ensure that the DS Bus Remains EnergizedThe team identified a noncompliance with 10 CFR 50, Appendix R, Section III.L.3 for the licensees failure to ensure that the Dedicated Shutdown (DS) Bus remains energized for a postulated fire in FA A5, FZ 22. The violation meets the criteria of NRC Enforcement Policy, Interim Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48) for enforcement discretion. For a fire in FA A5, FZ 22, procedure DSP-002, Hot Shutdown Using the Dedicated/Alternate Shutdown System, would be utilized to safely shutdown the plant from the dedicated shutdown control stations. Step 4 of DSP-002 dispatches an operator to energize the DS Bus by performing Attachment 9. Step 2 of the attachment directs the operator to determine if the DS Bus is energized by offsite power. If the DS Bus is de-energized, then the operator is directed to energize the DS Bus by the Dedicated Shutdown Diesel Generator (DSDG). If the DS Bus is energized by offsite power, then the operator is directed to de-energize 4kV buses 1, 2 and 4 and 480V Bus 3 and then close the alternate feed to MCC-5. At this point in the procedure, performance of Attachment 9 would be complete and the operator would be free to leave the area and assist other operators. The team determined that if a loss of offsite power occurred subsequent to the performance of Attachment 9, there was no continuing procedural guidance directing the operators to later energize the DS Bus with the DSDG. This issue was further complicated because there would be no indication of the subsequent loss of offsite power to the operators absent someone checking the status of offsite power on the Ds bus.
05000413/FIN-2007007-062007Q3CatawbaLetdown Valve 2NV015BCatawba Unit 2 Operating License Condition 2.C.(5), requires that the licensee implement and maintain in effect all provisions of the approved FPP as described in the UFSAR, as amended, for the facility and as approved in the SER through Supplement 5. BTP CMEB 9.5-1, which incorporated the guidance of Appendix A to BTP ASB 9.5-1 and the technical requirements of Appendix R to 10 CFR 50, established the regulatory and licensing requirements for the FPP at CNS. The CNS FPP was reviewed against and approved for conformance with BTP CMEB 9.5-1 in the SER through Supplement 5. BTP CMEB 9.5-1, Item C.5.b.1, requires that fire protection features be provided that are capable of limiting fire damage so that one train of systems necessary to achieve and maintain hot standby conditions from either the control room or emergency control station(s) is free from fire damage. BTP CMEB 9.5- 1, Item C.5.b.2 requires one redundant train to be protected from fire damage by one of three specified methods. Contrary to the above, on June 25, 2004, the inspectors identified that the licensee failed to provide fire protection features to protect control circuits and cables associated with letdown valve 2NV015B. This condition has existed since original construction. This finding is also applicable to Unit 1. Pursuant to the Commissions Enforcement Policy and NRC Manual Chapter 0305, under certain conditions fire protection findings at nuclear power plants that transition their licensing bases to 10 CFR 50.48(c) are eligible for enforcement and ROP discretion. The Enforcement Policy and ROP also state that the finding must not be evaluated as a finding of high safety significance (Red). Because the licensee committed, prior to December 31, 2005, to adopt NFPA 805 and change their fire protection licensing bases to comply with 10 CFR 50.48 (c), the NRC is exercising enforcement discretion for this issue in accordance with the NRC Enforcement Policy, Interim Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48). Specifically, this issue would have been expected to be identified and addressed during the licensees transition to NFPA 805, was entered into the licensees corrective action program and will be corrected, was not willful, and was not associated with a finding of high safety significance. The licensee entered this issue into the CAP as PIP report C-04-04276. The licensee has provided new guidance to the operators in the fire response procedure (AP/045) to use the reactor head vents in the event that neither normal letdown nor excess letdown are available to maintain the pressurizer level between 25 percent and 92 percent.
05000413/FIN-2007007-052007Q3CatawbaCharging Pump Mini-Flow Valves 2NV202B and 2NV203AOperating License Condition 2.C.(5), for Units 1 and 2, requires that the licensee implement and maintain in effect all provisions of the approved FPP as described in the UFSAR, as amended, for the facility and as approved in the SER through Supplement 5. BTP CMEB 9.5-1, which incorporated the guidance of Appendix A to BTP ASB 9.5-1 and the technical requirements of Appendix R to 10 CFR 50, established the regulatory and licensing requirements for the FPP at CNS. The CNS FPP was reviewed against and approved for conformance with BTP CMEB 9.5-1 in the SER through Supplement 5. BTP CMEB 9.5-1, Item C.5.b.1, requires that fire protection features be provided that are capable of limiting fire damage so that one train of systems necessary to achieve and maintain hot standby conditions from either the control room or emergency control station(s) is free from fire damage. BTP CMEB 9.5- 1, Item C.5.b.2 requires one redundant train to be protected from fire damage by one of three specified methods. Contrary to the above, on June 25, 2004, the inspectors identified that the licensee failed to provide fire protection features to protect control circuits and cables associated with charging pump mini-flow valves NV202B and NV203A on Units 1 and 2. This condition has existed since original construction. Pursuant to the Commissions Enforcement Policy and NRC Manual Chapter 0305, under certain conditions fire protection findings at nuclear power plants that transition their licensing bases to 10 CFR 50.48(c) are eligible for enforcement and ROP discretion. The Enforcement Policy and ROP also state that the finding must not be evaluated as a finding of high safety significance (Red). Because the licensee committed, prior to December 31, 2005, to adopt NFPA 805 and change their fire protection licensing bases to comply with 10 CFR 50.48(c), the NRC is exercising enforcement discretion for this issue in accordance with the NRC Enforcement Policy, Interim Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48). Specifically, this issue would have been expected to be identified and addressed during the licensees transition to NFPA 805, was entered into the licensees corrective action program and will be corrected, was not willful, and was not associated with a finding of high safety significance. The licensee entered this issue into the CAP as PIP report C-04-04276. The licensee revised the fire response procedure AP/045 to incorporate contingency actions for local valve operation to restore isolated flow paths and to increase seal injection flow to restore minimum flow. A new caution statement was added to the procedure to warn the operator not to run a charging pump for more than 3 hours with less than 35 gpm flow through the pump. A new step was added to the procedure to require the operator to verify operating charging pump has 60 gpm minimum flow by looking at charging flow, SI valves open or pump mini-flow valves open. A note was also added to inform the operators of alternate locations of charging and seal injection flow indication. The long term corrective actions will be determined as part of the reconstitution project.
05000413/FIN-2007007-032007Q3CatawbaThe Licensees Original Associated Circuits Analysis Failed to Identify Circuits Whose Failure Could Prevent the Proper Performance of SSD Equipment in Fire Areas 12, 13, 36 and 37Operating License Condition 2.C.(5), for Units 1 and 2, requires that the licensee implement and maintain in effect all provisions of the approved FPP as described in the UFSAR, as amended, for the facility and as approved in the SER through Supplement 5. BTP CMEB 9.5-1, which incorporated the guidance of Appendix A to BTP ASB 9.5-1 and the technical requirements of Appendix R to 10 CFR 50, established the regulatory and licensing requirements for the FPP at CNS. The CNS FPP was reviewed against and approved for conformance with BTP CMEB 9.5-1 in the SER through Supplement 5. BTP CMEB 9.5-1, Item C.5.b.1, requires that fire protection features be provided that are capable of limiting fire damage so that one train of systems necessary to achieve and maintain hot standby conditions from either the control room or emergency control station(s) is free from fire damage. BTP CMEB 9.5- 1, Item C.5.b.2 requires one redundant train to be protected from fire damage by one of three specified methods. Proper coordination and selective tripping of fuses and breakers on associated circuits is an acceptable method for meeting the requirements. Contrary to the above, on May 17, 2007, the licensee identified train B cables (CA581 and IRE761) located in train B Fire Areas with associated breakers that were not coordinated from a selective tripping standpoint. As a consequence, a fire-induced failure of associated circuits CA581 (in the AFW pump turbine control panel room) or IRE761 (in the 577 elevation train A electrical penetration room) could result in the loss of SSD power sources EDF or EDP, respectively. This condition has existed since original construction. This issue was entered into the licensees CAP as PIP C-07- 02458. No enforcement action is required for the above noncompliance because pursuant to the Commissions Enforcement Policy and NRC Manual Chapter 0305, under certain conditions fire protection findings at nuclear power plants that transition their licensing bases to 10 CFR 50.48(c) are eligible for enforcement and reactor oversight process (ROP) discretion. The Enforcement Policy and ROP also state that the finding must not be evaluated as Red. Because the licensee committed, prior to December 31, 2005, to adopt NFPA 805 and change their fire protection licensing bases to comply with 10 CFR 50.48(c), the NRC is exercising enforcement discretion for this issue in accordance with the NRC Enforcement Policy, Interim Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48). Specifically, this issue was licensee identified as a result of its initiative to adopt NFPA 805, it was entered into the licensees corrective action program and will be corrected, was not likely to have been previously identified by routine licensee efforts, was not willful, and was not associated with a finding of high safety significance. The licensee entered this issue in their CAP under PIP C-07-02458 and implemented 1-hour roving fire watches as compensatory measures in the FAs.
05000266/FIN-2005017-012005Q3Point BeachLicensee's failure to self-identify the untimely declaration of an Alert classification during an August 2002 emergency preparedness (EP) drill.The NRC also identified an apparent violation of 10 CFR 50.9, Completeness and Accuracy of Information, associated with incomplete and inaccurate information the licensee provided to the NRC in a falsified critique record associated with the August 2002 EP drill. The licensee provided the falsified critique record to NRC inspectors on November 20, 2002. Specifically, the falsified critique record for the August 2002 EP drill indicated that the licensee had self-identified the untimely declaration of an Alert emergency classification. However, the OI investigation determined that the EP Manager and the EP Coordinator deliberately altered the critique record to indicate that the untimely Alert classification declaration was self-identified by the licensee as a part of its formal critique process. The information is material to the NRC because, the NRC relies, in part, on the licensees conduct and self-critiquing of EP drills and exercises to ensure the licensee maintains an effective emergency preparedness and response capability. In a letter to the NRC, dated May 16, 2003, the licensee documented the corrective actions it had taken based upon its own internal investigation of the EP Manager and the EP Coordinators November 2002 deliberate falsification of the August 2002 EP drill and providing of the falsified record to the NRC. Based upon information developed during the NRC inspections and investigation and provided in your letter dated May 16, 2003, we believe that we have sufficient information to make a final significance determination for the preliminary White Finding and to determine the appropriate significance and enforcement actions for the apparent violations. However, before we make a final decision on these matters, we are providing you an opportunity to present to the NRC your perspectives on the facts used by the NRC to arrive at the finding and its significance, and the apparent violations and their significance at a combined regulatory and predecisional enforcement conference (conference) or through the submittal to the NRC of your position on the finding and the apparent violations in writing. If you choose to request a conference, it should be held within 30 days of the receipt of this letter and we encourage you to submit supporting documentation at least one week prior to the conference in an effort to make the conference more efficient and effective. If a conference is held, that portion of the conference associated with the White Finding and the associated apparent violation will be open for public observation. The portion of the conference associated with the 10 CFR 50.9 apparent violation will be closed for public observation because it involves an OI investigation. If you decide to submit only a written response, such submittal should be sent to the NRC within 30 days of the receipt of this letter.
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