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05000302/FIN-2012005-012012Q4GreenLicensee-identifiedLicensee-Identified ViolationThe inspectors reviewed the reportability evaluations associated with the unsatisfactory penetrations. The inspectors questioned the adequacy of these evaluations in that they estimated that a significant level of water (approximately three to four feet) would accumulate in the turbine building during PMH conditions, but concluded that none of this flood water would pass through the set of fire doors from the turbine building to the auxiliary building. The subject fire doors are rated for 2 feet of water pressure. The reportability evaluations heavily relied upon actions taken in the licensees adverse weather procedure EM-220, Violent Weather, to sandbag the fire doors prior to hurricane conditions. The inspectors did not have confidence in the adequacy of sandbagging instructions in EM-220 or that the door could withstand three to four feet of turbine building flooding to preclude flooding in auxiliary building. As a result of the inspectors concerns, the licensee initiated CR 563931 to re-evaluate the expected flood levels in the turbine building during PMH conditions. The inspectors reviewed the completed evaluation and noted that more reasonable external flooding conditions were used and the evaluation took credit for other actions in the adverse weather procedure such as use of dewatering pumps. The inspectors also noted that the evaluation included the estimated flooding contribution from two additional unsatisfactory penetrations which were identified in August 2012 during the licensees Fukushima flooding walkdowns and documented in CRs 556385 and 557156. The inspectors concluded that, due to the location and condition of the two penetrations, their overall flooding contribution was negligible when compared to the overall flood level due to the 29 penetrations previously identified by the licensee. The new evaluation concluded that the resulting flood level through the 29 penetrations during PMH conditions would be 1.27 feet of water in the turbine building, which is within the rating of the fire doors. The inspectors concurred with the licensees conclusion that this flood level would not adversely impact the allowable flood limit in the auxiliary building. The inspectors verified that the licensee had performed an adequate extent of condition review to identify the unsatisfactory below grade penetrations and that appropriate actions were being taken to correct the issue. The inspectors verified that, as of the end of this inspection period, 19 of the 28 unsatisfactory penetrations had been repaired. The remaining were scheduled for repair.
05000302/FIN-2011005-012011Q4GreenLicensee-identifiedLicensee-Identified ViolationThe following violation of very low safety significance (Green) was identified by the licensee and was a violation of NRC requirements which met the criteria of the NRC Enforcement Policy for being dispositioned as a Non-Cited Violation: • Improved Technical Specification 5.6.1.1a requires that written procedures recommended in Regulatory Guide (RG) 1.33, Revision 2, Appendix A, be established, implemented, and maintained. RG 1.33, Appendix A, includes general operating procedures for Refueling & Core Alterations in the list of recommended procedures. Plant Operating Manual FP-601A, Operation of the Main Fuel Handling Bridge FHCR-1, Section 3.2.22, requires, in part, that a refueling SRO be stationed during a core alteration. Contrary to this requirement, the licensee secured the refueling SRO during activities determined to be a core alteration for approximately seven-hours on May 24, 2011. The licensee entered this issue into their CAP as CR 467392. The significance of the finding was determined using Manual Chapter 0609, Significance Determination Process, Appendix G, Checklist 4 (PWR Refueling Operation, RCS level > 23 ft) and determined to be of very low safety significance (Green), because it did not cause the loss of mitigating capability of core heat removal, inventory control, power availability, containment control, or reactivity control. Additional information regarding this NCV is discussed in Section 4OA2 of this inspection report.
05000302/FIN-2011402-012011Q4GreenNRC identifiedSecurity
05000302/FIN-2011501-012011Q3WhiteH.13Licensee-identifiedFailure to Maintain a Standard EAL SchemeAn AV was identified for failure to follow and maintain in effect emergency plans which use a standard emergency classification and action level scheme. Specifically, the licensee's emergency plan emergency action level (EAL) 1.4, General Emergency - Gaseous Effluent, specified instrument values that were beyond the limits of the effluent radiation monitors capabilities to accurately measure. This finding was considered more than minor because the licensee is required to be capable of implementing adequate measures to protect public health and safety in the event of a radiological emergency. Regulations require a standard emergency classification and action level scheme, the bases which include facility system and effluent parameters, in use by the licensee and State and local response plans call for reliance on information provided by the licensee for determination of minimum initial offsite response measures. As a result of having General Emergency EAL threshold values that were beyond the range of the associated effluent radiation monitors, Crystal River Unit 3 personnel may not have been able to perform timely and accurate classification of an emergency based upon an effluent radioactive material release. Emergency response actions directed by the State and local emergency response plans, which rely on information provided by the licensee, could have potentially been delayed. The cause of the finding is related to the human performance cross-cutting element of Decision-making (H.1(a)) for ensuring that risk-significant decisions are made using a systematic process and obtaining interdisciplinary input and reviews. - THIS FINDING WAS LICENSEE IDENTIFIED
05000302/FIN-2011003-012011Q2GreenLicensee-identifiedLicensee-Identified Violation10 CFR 50 Appendix B, Criterion III, Design Control, requires, in part, that measures shall be established to assure that applicable regulatory requirements and design basis for those structures, systems, and components are correctly translated into specifications, drawings, procedures and instructions. Licensee corporate engineering procedures EGR-NGGC-0005, Engineering Change; and Administrative Corporate procedure ADM-NGGC-0116, Nuclear Planning, implement those requirements. Contrary to the above, the licensee failed to translate the design basis requirements of modifications MAR 86-09-15, Raw Water Joint Encapsulation Sleeve, and MAR 90-08-16, Circulating Water Joint Encapsulation Sleeve, into work orders or procedures to ensure continued maintenance of design basis requirements. As a result, the raw water and circulating water encapsulation sleeves were found to have a larger gap than allowed by design, and consequently would have caused a greater internal flood rate into the auxiliary building had the expansion joints failed. The performance deficiency of failing to maintain the gaps within the required tolerances on the raw water and circulating water encapsulation sleeves is more than minor because, if left uncorrected, would have the potential to lead to a more significant safety concern during a rupture of a raw water or circulating water expansion joint. The licensees corrective actions include revising maintenance procedures to add acceptance criteria for the encapsulation sleeve gaps. The finding was determined to be of very low safety significance (Green) because after performing additional engineering evaluations and calculations, it was concluded that the auxiliary building internal design basis flood requirements were not exceeded. This issue was documented in the licensees corrective action program as NCRs 456729, 457510, and 457181.
05000302/FIN-2011008-012011Q2GreenNRC identifiedFailure to Maintain Fire Loading Within Allowable LimitsThe inspectors identified two examples of a non-cited violation of Crystal River Unit 3 Operating License Condition 2.C (9), for the failure to adequately evaluate changes to the approved Fire Protection Program. Specifically, in 1999, and 2003, the licensee revised their fire protection program to increase the combustible loading beyond the maximum permissible limits for FA CC-124-116, 480V ES Switchgear Bus Room 3B and FA CC-124-117, 480V ES Switchgear Bus Room 3A, respectively without performing an evaluation to ensure compliance with the approved Fire Protection Program. The licensee initiated nuclear condition reports 461209, and 476342 to address this issue. The finding was more than minor because it affected the reactor safety mitigating system cornerstone attribute of protection against external events (i.e. fire). For both examples the selection of a low degradation rating was supported by screening criteria provided in Inspection Manual Chapter (IMC) 0609, Appendix F, Fire Protection Significance Determination Process as well as IMC 0609, Appendix F, Attachment 2 Degradation Rating Guide Specific to Various Fire Protection Elements. Based on the above criteria, this finding is screened as having very low safety significance (Green) in Phase 1 of the Significance Determination Process. The performance deficiency was not assigned a cross cutting aspect as this deficiency occurred over three years ago and is therefore not reflective of current plant performance.
05000302/FIN-2011008-022011Q2GreenH.5NRC identifiedInadequate Procedure OP-880B for Turbine Building Post-Fire Safe ShutdownThe inspectors identified a non-cited violation of Crystal River Unit 3 (CR3) Technical Specification 5.6.1.1.a., for inadequate guidance in procedure OP-880B, Appendix R Turbine Building Post-Fire Safe Shutdown Information. Specifically, the procedure could not have been performed as written because it did not identify the appropriate equipment that was to be manipulated to ensure that the reactor coolant pumps remained de-energized after being secured in the event of a fire in turbine building Fire Zones TB-95-400A, TB-119-400E, or TB- 145-400F. Additionally, procedure OP-880B did not provide adequate guidance regarding how CR3 operators would communicate with Crystal River Unit1/Unit 2 (CR1/CR2) operators, and did not specify if a reliable means of communications was available. The licensee initiated nuclear condition reports 460602, and 461736 to address this issue. The inspectors determined that inadequate safe shutdown procedure guidance was a performance deficiency. This finding was more than minor because it was associated with the procedure quality attribute of the mitigating systems cornerstone and it affected the cornerstone objective of protection against external events (i.e., fire). The inspectors assessed this finding using NRC Inspection Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process. The inspectors determined that this finding was of very low safety significance (Green) because during the time that procedure OP-880B was issued and in effect (April 16, 2010, to April 22, 2011), CR3 was in cold shutdown and procedure OP-880B was not applicable. The inspectors determined that the cause of this finding had a cross-cutting aspect in the Human Performance Area, Work Control Component, in that, the licensee did not address the need for CR3 work groups to maintain interfaces with offsite organizations (i.e., CR1/CR2), to communicate and coordinate with each other during activities in which interdepartmental coordination was necessary to ensure plant and human performance.
05000302/FIN-2011008-032011Q2Severity level Enforcement DiscretionNRC identifiedMotor Operated Valves Not Protected From Hot Shorts That Could Bypass Torque SwitchesThe failure to ensure that one train of systems necessary to achieve and maintain hot shutdown conditions was free of fire damage as required by 10 CFR Part 50, Appendix R, Section III.G is a performance deficiency. The noncompliance is considered to be more than minor because it is associated with the protection against external factors attribute (i.e. fire) and it degraded the reactor safety Mitigating Systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent consequences. The risk significance of the finding was determined utilizing the guidance of IMC 0609, Appendix F, Fire Protection Significance Determination Process. Pursuant to IMC 0609, Appendix F, the finding category was Post-fire Safe Shutdown . The finding was assigned a high degradation rating because the Post-fire SSD analysis was incomplete with regard to analyzing the effects of fires in MCCs and the potential impacts on MOVs. Because the finding was assigned a high degradation rating it did not screen in Phase 1 requiring a Phase 2 analysis. The MCCs affected by this finding were located in the auxiliary building in fire zones AB-95-3B, AB-95-3C, AB-95-3G and AB-119-6E, AB-119-6J, AB-119-6Q on elevations 95 and 119, respectively. All but one of the fire zones have fixed suppression, all have detection. The fire zone that does not have fixed automatic suppression is FZ AB-119-6Q. However, the valve fed from the MCC located in the zone is only required for cold shutdown which would screen to Green in Phase 1 of the SDP. For fires external to the MCCs there is a high likelihood that the fires will be detected and suppressed prior to damaging the components inside the MCC cabinet. For fires that start internal to the MCC cabinets it is more likely that damage will occur before the fire can be suppressed so no credit is given for manual or automatic suppression. However, independent of other factors, including fire suppression credit, the frequency of fires in electrical cabinets coupled with the probability of spurious operation is of sufficiently low likelihood that it is concluded that this finding is not associated with a finding of high safety significance (i.e. red). The inspectors determined the performance deficiency does not have a cross-cutting aspect because it does not represent current licensee performance since the analysis was completed prior to 2000.
05000302/FIN-2011002-012011Q1GreenH.9Self-revealingOperating Crew Failures on the 2011 Annual Requalification Operating TestA self-revealing Green finding, associated with operating crew performance on the simulator during facility-administered requalification examination was identified. Two of the eight crews evaluated failed to pass their simulator examinations. As immediate corrective action, the failed operating crews were remediated (i.e., the operating crews were re-trained and successfully retested) prior to returning to shift. The licensee has entered this issue into the corrective action program as Nuclear Condition Report (NRC) 450196. The inspectors determined that the crew failures constituted a performance deficiency based on the fact that licensed operators are expected to operate the plant with acceptable standards of knowledge and abilities demonstrated through periodic testing as required by 10 CFR 55.59(a)(2). Two out of eight crews of licensed operators failed to demonstrate a satisfactory understanding of the required actions and mitigating strategies required to safely operate the facility under normal, abnormal, and emergency conditions. The finding is greater than minor because the performance deficiency potentially affects the Human Performance attribute of the Mitigating Systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the finding reflected the crews potential inability to take timely actions in response to actual abnormal and emergency conditions. The cause of this finding was directly related to the cross-cutting aspect of personnel training and qualifications in the Resources component of the Human Performance area, in that the licensee failed to ensure the adequacy of the training provided to operators to assure nuclear safety.
05000302/FIN-2011002-022011Q1GreenLicensee-identifiedLicensee-Identified ViolationImproved Technical Specification (ITS) 3.4.9 states that two pressurizer code safety valves (PCSVs) shall be operable in Modes 1, 2 and 3. To be operable, the lift setpoints must be within +/- 2 percent of 2500 psig. Contrary to the above, on September 1, 2010 and on October 5, 2010, Progress Energy was notified that the as-found lift setpoints of PCSVs RCV-9 and RCV-8 were outside ITS setpoint limits, respectively. The as-found lift setpoint of RCV-9 was 5.32 percent above the lift setpoint and RCV-8 was 2.08 percent above the lift setpoint. The licensee identified a selected cause associated with the licensees failure to manage vendor quality. The performance deficiency, failure to provide proper relief valve specifications to the vendor, was determined to be greater than minor because if left uncorrected, the performance deficiency would have the potential to lead to a more significant safety concern regarding the integrity of the reactor coolant system (RCS) barrier during plant transients. Corrective actions planned or completed include: changing the as-left setpoint to +0/-1 percent of the nominal setpoint; installing PCSVs with +0/-1 percent of nominal setpoint prior to unit startup; creation of a test procedure for steam testing the PCSV to meet the licensees standards; and revision of specifications associated with PCSV repairs. As documented in Section 4OA3, the finding was determined to be of very low safety significance (Green) because there was no loss of safety function due to the lift setpoints being outside of the ITS limit. This issue was documented in the licensees corrective action program as NCR 426852.
05000302/FIN-2010201-012010Q4GreenNRC identifiedSecurity
05000302/FIN-2010005-012010Q4GreenLicensee-identifiedLicensee-Identified Violation10 CFR 50 Appendix B, Criterion III, Design Control, requires, in part, that measures shall be established to assure that applicable regulatory requirements and design basis for those structures, systems, and components are correctly translated into specifications, drawings, procedures and instructions. Engineering corporate procedures EGR-NGGC-0011, Engineering Rigor; and EGR-NGGC-0155, Specifying Electrical / I&C Modification Related Tests, implement those requirements. Contrary to the above, the licensee failed to translate the design basis into drawings and procedures when performing design modification EC 71897. This resulted in an electrical circuit error in the A EDG breaker logic circuitry. The inadequate EC removed a switchgear internal control wire that supplied DC control power to the following: 1) OPT differential lockout relay to trip breaker 3211, 2) MCB control switch open contacts to trip breaker 3211, and 3) emergency safety A-bus under-voltage trip circuit to trip breaker 3211. As a result of breaker 3211 not being able to trip under any of these three signals, the A EDG would not have been able to meet the logic required to load onto the safety bus when required. The licensee determined that engineering personnel did not have an adequate understanding of assessing the correct engineering depth and detail involved in designing and implementing the EC. The process deficiency of failing to provide adequate depth and detail on the EC is more than minor because, if left uncorrected, would have the potential to lead to a more significant safety concern. The finding was determined to be of very low safety significance (Green) because there were no diesel operability requirements during the time the inadequate EC had been installed. Additionally, the inadequate EC was identified and corrected by the licensee prior to the emergency generator being required by plant technical specifications to be available to support a change in mode. This issue was documented in the licensees corrective action program as NCR 431407. Additional information regarding this issue can be found in Section 4OA2.3.
05000302/FIN-2010007-032010Q3GreenNRC identifiedFailure to Monitor the Service Water and Decay Cooling Expansion Tank Check ValvesThe team identified a non-cited violation of 10 CFR 50.65(a)(1) for the licensees failure to monitor service water and decay heat cooling expansion tank level indicator check valves. In response to this concern, the licensee closed the isolation valves as an interim action, performed an in situ check valve test with satisfactory results, and entered the deficiency into their corrective action program for resolution. The licensees failure to perform appropriate maintenance on the check valves was a performance deficiency. This finding is more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences. The finding is of very low safety significance (Green) using the SDP because it did not represent a loss of system or safety function. A cross-cutting aspect was not identified because the finding does not represent current performance.
05000302/FIN-2010004-012010Q3GreenNRC identifiedFlood Calculations did not Reflect Plant ConfigurationThe inspectors identified a non-cited violation (NCV) of 10 CFR 50 Appendix B, Criterion III, Design Control, regarding the licensees failure to ensure that the design bases of two components were correctly translated into specifications, drawings, procedures, and instructions. Specifically, licensee personnel failed to ensure that two floor penetration flood barriers (metal sleeves) were of the proper height to prevent water from entering the A train decay heat removal (DHR)/building spray (BS) vault during a design basis internal flooding event. The design basis did not assume any leakage to the vault. The licensee initiated nuclear condition report (NCR) 409263 in the corrective action program to address the issue. This finding is more than minor because it affects the design control attribute of the mitigating system cornerstone, and affected the cornerstone objective of ensuring availability, reliability, and capability of systems that respond to initiating events. Using Manual Chapter 0609, Phase 1 screening worksheet, the inspectors determined that the finding has very low safety significance because it did not result in a loss of any system safety function. The inspectors found that the cause of the finding is not reflective of current performance and therefore, a cross-cutting aspect will not be assigned.
05000302/FIN-2010004-022010Q3GreenP.2NRC identifiedInoperable Fire Barrier Penetration SealsThe inspectors identified an NCV, with five examples, of Crystal River Unit 3 Operating License Condition 2.C (9), fire protection program. The NCV was associated with one inoperable fire penetration seal in the ceiling of the B train decay heat and building spray pump vault and four inoperable fire penetration seals associated with the main steam piping in the wall between the intermediate building and the turbine building. Once identified, the licensee initiated an hourly watch and entered the issue in the corrective action program as nuclear condition reports 369096, 406215, and 418755. The finding is more than minor because if left uncorrected, the fire seals could experience further degradation and potentially lead to a more significant safety concern. Using NRC IMC 0609, Appendix F, Fire Protection Significance Determination Process, the inspectors assessed the defense-in-depth (DID) element of each fire barrier degradation in the fire confinement category. One penetration was determined to have a low degradation rating and was determined to be of very low safety significance. The other four degraded penetrations were determined to have moderate degradation and were screened to be very low safety significance due to having non-degraded automatic full area water-based fire suppression system available in the exposing fire area. A contributing cause of the finding is related to the cross-cutting area of Problem Identification and Resolution with an evaluation aspect (P.1.(c)). Specifically, the licensee had the opportunity to evaluate the need to change the frequency of main steam line fire penetration inspections after finding degradation of main steam piping penetrations in 2007.
05000302/FIN-2010004-032010Q3GreenH.14NRC identifiedFailure to Submit Production Splices of Swaged Mechanical Splices for the TestingThe inspectors identified a finding of very low safety significance and an associated NCV of 10 CFR Part 50, Appendix B, Criterion IX, Control of Special Processes, for the licensees failure to establish measures to assure that testing of rebar splices would adhere to the requirements of American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code. Specifically, licensee procedures for containment building repairs did not accommodate rebar production splice testing, which was required by Code. As part of their immediate corrective actions, the licensee revised their procedures to include production splice testing and also entered the issue into their corrective action program. The inspectors determined that the finding was more than minor because it was associated with the human performance attribute of the barrier systems cornerstone and affected the cornerstone objective of ensuring the reliability of containment wall barrier system. Failure to adhere to ASME Code testing requirements can adversely affect assurance that the rebar splices would meet strength requirements as part of the containment barrier. The inspectors completed a Phase 1 screening of the finding using Inspection Manual Chapter 0609, Significance Determination Process, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings and determined that the performance deficiency represented a finding of very low safety significance (Green). Specifically, the finding did not result in the actual loss of function of the Unit 3 Containment Wall. This finding has a cross-cutting aspect in the area of Human Performance under the Effectiveness Reviews aspect of the Decision-Making component because the licensee failed to validate assumptions used as a basis for their decision to pursue an alternative testing plan. (H.1(b))
05000302/FIN-2010402-012010Q3GreenH.8NRC identifiedSecurity
05000302/FIN-2010007-022010Q3GreenNRC identifiedFailure to Incorporate Requirements of Recovering from a Station Blackout into CalculationsThe team identified a non-cited violation of 10 CFR 50.63, Loss of all alternating current power, for failure to ensure Regulatory Guide 1.155, Station Blackout commitments were implemented in calculations for restoring off-site power. The licensee entered this deficiency into their corrective action program for resolution. The licensees failure to maintain calculations to assure adequate voltage for the remote closing of switchyard breakers during a station blackout event is a performance deficiency. The team determined that the finding is more than minor because it adversely affected the design control attribute of the mitigating reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding is of very low safety significance (Green) using the SDP because it did not represent a loss of system or safety function. A cross-cutting aspect was not identified because the finding does not represent current performance.
05000302/FIN-2010007-012010Q3GreenH.7NRC identifiedPreconditioning of Safety-Related Air Operated ValvesThe team identified a non-cited violation of 10 CFR Part 50, Appendix B, Criterion XI, Test Control for preconditioning of a safety-related air operated valve prior to surveillance testing. The licensee entered this deficiency into their corrective action program for resolution. The licensees preconditioning of air operated valves prior to performing as-found testing is a performance deficiency. This finding is more than minor because if left uncorrected the performance deficiency has the potential to lead to a more significant safety concern in that safety-related valve performance deficiencies could be masked. The finding is of very low safety significance (Green) using the SDP because it did not represent a loss of system or safety function. The finding involved the cross-cutting aspect of complete and accurate procedures under the Resources component of the Human Performance area (H.2(c)).
05000302/FIN-2010003-012010Q2NRC identifiedDegraded Fire/Flood BarriersAs required by Inspection Procedure 71152, Identification and Resolution of Problems, the inspectors performed a review of the licensees CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors review was focused on repetitive equipment issues, but also considered the results of daily inspector CAP item screening discussed in section 4OA2.1 above, plant status reviews, plant tours, and licensee trending efforts. The inspectors review nominally considered the six month period of January 2010 through June 2010. The review also included issues documented in the licensees Plant Health Committee Site Focus List June 2010, various departmental CAP Rollup & Trend Analysis reports, various nuclear assessment section reports and maintenance rule (MR) reports. Corrective actions associated with a sample of the issues identified in the licensees corrective action program were reviewed for adequacy. No findings were identified. The inspectors evaluated the licensees trend methodology and observed that the licensee had performed a detailed review. The inspectors review of licensee performance over the last six months noted one negative trend associated with degraded fire penetrations. In April, the inspectors found a degraded flood/fire penetration in the floor between the auxiliary building 95 elevation and the auxiliary building 75 elevation B train DHR/BS vault. In June, the inspectors found two degraded fire penetrations in the wall between the intermediate building and the turbine building. These penetrations are associated with the A train main steam piping. In both cases, the licensee declared the penetrations inoperable, initiated fire watches and entered the issues into the CAP (NCRs 396095 and 406215). As a result of these NRC inspector observations, the licensee indicated that they will perform an extent of condition inspection of all fire/flood penetrations to determine whether the fire barrier inspection frequency needs to be adjusted. The issue associated with these degraded fire barriers is unresolved pending completion of NRC review and analysis of licensee corrective actions and is identified as Unresolved Item (URI) 05000302/2010003-01, Degraded Fire/Flood Barriers.
05000302/FIN-2010002-012010Q1GreenNRC identifiedFailure to Take Compensatory Actions When a MCR to CSR Floor/Ceiling Interface Access Hatch Was Open.The inspectors identified a non-cited violation of Crystal River Unit 3 Operating License Condition 2.C.(9), for failure to take compensatory actions when a main control room (MCR) and cable spreading room (CSR) floor/ceiling interface access hatch was open rendering the CSR Halon fire extinguishing system inoperable. Once identified, the licensee initiated nuclear condition report (NCR) 266356 in the corrective action program to address this issue. The finding is more than minor because it is associated with the protection against external factors attribute, i.e., fire, and degraded the Mitigating Systems cornerstone objective to ensure the availability of systems that respond to initiating events. Specifically, the finding adversely affected the suppression fire extinguishing system capability defense-in-depth element. The inspectors evaluated this finding under NRC Inspection Manual Chapter (IMC) 0609, Appendix F, Fire Protection Significance Determination Process (SDP). The inspectors determined that a Phase 2 SDP was required for this finding because the CSR Halon concentration was highly degraded; a fire could occur due to non-qualified cables or transient combustibles while the hatch between the MCR and CSR was open; a duration factor (exposure time) was between 3 and 30 days; and control room operators evacuated the MCR in response to the fire. However, Phase 2 SDP of IMC 0609 Appendix F does not currently include explicit treatment of fires leading to MCR abandonment, either due to fire in the MCR or due to fires in other fire areas. Therefore, a Phase 3 SDP evaluation for this type of finding was needed. A Regional Senior Reactor Analyst performed a Phase 3 SDP for this finding and concluded that the finding was of very low safety significance (Green). The major assumptions and the dominant accident sequence were discussed in the 4OA5 analysis section of this report. The inspectors did not identify a cross-cutting aspect associated with this finding because it does not reflect current licensee performance.
05000302/FIN-2010002-022010Q1GreenLicensee-identifiedLicensee-Identified ViolationThe following issue of very low safety significance (Green) was identified by the licensee and was a violation of NRC requirements. This issue met the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as a non-cited violation. Improved Technical Specification (ITS) 3.7.1 states that MSSVs shall be operable as specified in ITS Table 3.7.1-1 in Modes 1, 2 and 3. Contrary to the above, on September 22, 2009, while performing SP-650, ASME Code Safety Valves Test, on the A OTSG in Mode 1, the as-found set points of three MSSVs were found outside the ITS 3.7.1 acceptance criteria of +/- 3 percent of the nominal set point. The valves were returned to operable status by adjusting their set point to within +/- 1 percent. The licensee concluded that the three MSSVs were inoperable for a period longer than allowed by plant ITS. The licensee determined that this ITS violation was a result of a failure, in past years when MSSVs were found out of tolerance, to provide adequate instructions to the vendor refurbishing the valves to determine the root causes of the out of tolerance condition. This lack of adequate vendor instructions was the result of the licensees failure to follow Corrective Action Program procedures which require that physical evidence and important information that is essential to identifying cause(s) be preserved. The finding was evaluated using Phase 1 of the At-Power SDP, and was determined to be of very low safety significance (Green) because the inspectors responded no to all questions in the mitigating systems cornerstone column of Table 4a, Manual Chapter 0609, Attachment 0609.04. This issue was documented in the licensees corrective action program as NCR 356521
05000302/FIN-2009005-022009Q4GreenH.8Self-revealingManual Reactor Trip Due to Group 7 Control Rods Insertion Caused by Inadequately Protected Test JumperA self-revealing NCV of Improved Technical Specification (ITS) 5.6.1.1.a was identified for the failure to follow the provisions of preventative maintenance procedure PM-126, Electrical Checks of CRD (Control Rod Drive) Power Train. Failure to follow PM-126 caused the failure of the Group 7 control rod programmer during maintenance and resulted in the unexpected insertion of the Group 7 control rods fully into the core. This unexpected insertion of these control rods into the core caused control room operations personnel to manually trip the reactor from 100 percent power. The licensee entered this issue into the corrective action program as NCR 351705. This finding was determined to be more than minor because it was associated with the initiating events cornerstone attribute of Human Performance, and adversely affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during at-power operations. The finding was evaluated using Phase 1 of the At-Power SDP, and was determined to be of very low safety significance (Green) because it did not contribute to both the likelihood of a reactor trip and the likelihood that mitigating equipment or functions were not available. The cause of this finding was directly related to the cross-cutting area of Human Performance with a work practices aspect (H.4 (b)). Specifically, the workers failed to follow the preventative maintenance procedure
05000302/FIN-2009005-032009Q4GreenLicensee-identifiedLicensee-Identified ViolationThe following issue of very low safety significance (Green) was identified by the licensee and was a violation of NRC requirements. This issue met the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as a Non-Cited Violation. 10 CFR 26.205(d) requires, in part, that individuals subject to work hour controls do not exceed 26 work hours in any 48-hour period and 72 work hours in any 7-day period; requires a 34-hour break in any 9-day period; and a 10-hour break between successive work periods. During the period of October 12 to October 19, 2009, one worker exceeded 26 hours in a 48-hour period; nine workers exceeded 72 hours in a 7-day period; five workers did not have a 34-hour break in a 9-day period; and two workers did not have the required 10-hour break between successive work periods. The violation was limited to one work group, Florida Transmission Personnel, who were on-site to support outage work. The licensee determined that the Transmission personnel did not have a firm understanding of the revised 10 CFR Part 26 requirements. The finding was more than minor because, if left uncorrected, it would become a more significant safety concern. Specifically, the excessive work hours would increase the likelihood of human performance errors during plant maintenance activities that could affect equipment performance. The finding is of very low safety significance because no significant events or human performance issues were directly linked to personnel fatigue as a result of the hours worked. This issue was documented in the licensees corrective action program as NCR 361777
05000302/FIN-2009005-012009Q4GreenH.2Self-revealingFailure to Follow a Plant Procedure Resulted in an Inoperable HPI SystemA self-revealing Non-Cited Violation (NCV) of Improved Technical Specification (ITS) 5.6.1.1.a was identified for the failure to follow a plant procedure which resulted in a loss of a 480 volt engineered safeguards motor control center (ES MCC)-3B1. Concurrent with pre-existing conditions, the high pressure injection (HPI) system was declared inoperable and ITS 3.0.3 was entered for a period of one hour and 24 minutes. The licensee entered this issue into the corrective action program as nuclear condition report (NCR) 333515. The finding was more than minor since it affected the equipment availability attribute of the mitigating system cornerstone and resulted in ITS 3.0.3 entry for the HPI system being inoperable. The finding was evaluated against NRC Phase 1 Significance Determination Process (SDP) and Phase 2 SDP was required due to a loss safety function of the HPI system. A Regional Senior Reactor Analyst performed a Phase 3 SDP evaluation and concluded this finding was of very low safety significance (Green). The major assumptions of the evaluation were that the HPI function was out of service for exposure period (1 .5 hours) and there would be no recovery of the de-energized motor control center. The dominant accident sequence involved a support system failure of the Emergency Feedwater (EF) Indication and Control System rendering Main Feedwater and automatic control of EF unavailable, operators were unable to manually control EF flow causing its failure and with the HPI function lost due to the performance deficiency, core damage ensued. The inspectors determined the cause of the finding is related to the cross-cutting area of Human performance with a work practices aspect H.4 (c)). Specifically, work scope changes involving safety-related equipment did not receive the appropriate level management oversight resulted in a plant procedural violation
05000302/FIN-2009004-012009Q3GreenNRC identifiedInadequate Risk Assessments When Performing Surveillance TestingThe inspectors identified a non-cited violation (NCV) of 10 CFR 50.65(a)(4) for the failure to perform adequate risk assessments associated with a number of surveillance tests. Specifically, it was determined that risk assessments were not being properly performed for equipment that became unavailable as a result of surveillance testing. This condition has existed since implementation of the Equipment out of Service (EOOS) risk assessment software more than 10 years ago. Short term corrective actions include performance of additional peer reviews of upcoming performance and surveillance tests (PTs and SPs) to ensure they are included in the plant risk assessment and a similar independent review by the corporate probabilistic risk assessment staff. Long term corrective actions include: screen all SPs and PTs to evaluate for risk impact; develop a methodology to include risk significant SPs and PTs in the plant risk assessment, either automatically from the work schedule or a manual process; incorporate risk assessment process changes in licensee procedures; and provide additional EOOS training to the plant staff. Utilizing IMC 0612, Appendix B, Issue Screening, the finding was determined to be more than minor since licensee risk assessments failed to consider risk significant systems and support systems that were unavailable during maintenance. In order to determine the risk significance of this finding, the inspectors selected two recently performed surveillance procedures for two high risk systems that were not included in the licensees risk assessment. The SPs selected were decay heat system (DHR) SP-340B, DHP-1A, BSP-1A and Valve Surveillance and emergency feedwater (EFW) system SP-146A, EFIC Monthly Functional Test (During Modes 1, 2, 3). The risk deficit for SP-340B was determined to be less than 1E-6 incremental core damage probability deficit (ICDPD). The risk associated with SP-146A was not quantified since it was determined that the system did not lose its functionality during the SP. Utilizing IMC 0609, Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process (SDP), Flow Chart 1, the finding was determined to be of very low safety significance. This finding was not assigned a cross cutting aspect since the issue existed for greater than 10 years and is not indicative of current licensee performance
05000302/FIN-2009002-012009Q1GreenSelf-revealingFailure to Have Adequate Controls in Place to Ensure the Temperature of the Emergency Diesel Room was Maintained to Support EGDG OperabilityA self-revealing finding was identified for failing to have adequate controls in place to ensure the temperature of the emergency diesel room was maintained to support emergency diesel generator (EGDG) operability. As a result, during cold weather conditions, licensee personnel did not close an access door which caused a low EGDG-1B lube oil temperature condition and inoperability of the EGDG. Corrective actions include: posting signs on all external doors of both safety and non-safety EGDGs rooms indicating that the doors should not be left open, discussing the event with site personnel; and initiation of changes to the sites cold weather checklist to check closed EGDG room doors during cold weather conditions. The finding was more than minor since it affected the equipment availability attribute of the Mitigating System Cornerstone and resulted in an unavailable emergency diesel generator train for approximately 13 hours. The inspectors assessed the finding using the SDP and determined that the finding was of very low safety significance (Green) since it was not a design or qualification deficiency, did not result in a loss of a system safety function, did not result in an actual loss of safety function of a single train for greater than allowed by improved technical specifications (ITS), did not represent an actual loss of safety function of risk-significant, non-technical specification equipment, and did not screen as risk significant due to external events. The inspectors found that the cause of this finding was not reflective of current performance since the EGDG door lacked the proper signage since initial plant operation. Therefore, a cross-cutting aspect was not assigned
05000302/FIN-2009002-022009Q1GreenP.5
P.2(b)		NRC identifiedFailure to Take Timely and Effective Corrective Actions Resulted in a Repeat Failure of a Main Feedwater Isolation Valve due to Magnesium Rotor Oxidation/CorrosionThe inspectors identified a NCV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Actions, for failure to take timely and effective corrective actions to prevent a second failure of a main feedwater isolation valve (MFIV) due to corrosion of the valve actuators magnesium rotor. Specifically, corrective actions associated with a similar failure of a MFIV in 2005 were not enhanced when additional information became available through NRC Information Notice (IN) 2006-026, Failure of Magnesium Rotors in Motor-Operator Valve Actuators. As a result, in December 2008, a MFIV failed to operate due to magnesium rotor degradation. Corrective actions for the failure of FWV- 30 include: installation of a new motor; development and implementation of engineering changes to replace the stations motor-operated valve (MOV) magnesium rotor motors with aluminum rotor motors (when available); ensuring the engineering staff is trained on effective correction action plans; and revision of MOV maintenance procedures to include information obtained from IN 2006-026 prior to the next MOV inspections. The finding was more than minor because it affected the equipment availability attribute of the Mitigating System cornerstone and resulted in a MFIV being inoperable for a period of time greater than allowed by ITS. Since the valve would not have performed its safety function for greater than the ITS allowed outage time, a SDP Phase 2 analysis was required. Based upon the Phase 2 results, a regional senior reactor analyst performed a Phase 3 evaluation. The Phase 3 evaluation concluded that the finding was of very low safety significance (Green). A contributing cause of the finding is related to the cross-cutting area of Problem Identification and Resolution with an operating experience component (P.2(b)). Specifically, the licensee did not implement and institutionalize, in a timely manner, IN 2006-26 in station procedures and training programs associated with magnesium rotor inspections
05000302/FIN-2009002-032009Q1GreenH.11
H.12		Self-revealingInadequate Peer and Peer Checking Resulted in Connecting Improper Test Equipment and a Manual Plant TripA self-revealing finding was identified for the failure to follow procedure HUMNGGC- 0001, Human Performance Program, which required workers to perform self and peer checks to ensure the correct action is performed on the correct component. Specifically, during meter calibration activities, workers performing voltage checks failed to perform adequate self and peer checks when connecting test equipment. As a result, incorrect test equipment was connected resulting in blown fuses, the loss of several secondary plant pumps, and ultimately a manual plant trip. Corrective actions include: move relay work identified in the extent of condition review from on-line to outage to prevent recurrence, revise maintenance procedures associated with calibration of meters and relays to incorporate human factoring from lessons learned from this event, and perform an analysis of and incorporate best practices in procedures regarding how plant risk is assessed for activities that could cause transients. The finding was more than minor since it affected the human performance attribute of the Initiating Event Cornerstone and resulted in an event that upset plant stability. Specifically, the failure to properly utilize human performance tools such as self and peer checking as specified in HUM-GGC-0001, Revision 2, resulted in the connection of incorrect test equipment, the loss of several secondary plant pumps and ultimately led to a manual reactor trip. The inspectors assessed the finding using the SDP and determined that the finding was of very low safety significance (Green) since it did not contribute to the likelihood of a loss of coolant accident, did not contribute to a loss of mitigation equipment, and did not increase the likelihood of a fire or internal/external flood. The cause of the finding is related to the cross-cutting area of Human Performance with a work practices aspect (H.4(a)). Specifically, workers did not utilize proper self and peer checking
05000302/FIN-2008004-012008Q3GreenLicensee-identifiedLicensee-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 NCV. License Condition 2.C.(9) states, in part, that Florida Power Corporation shall implement and maintain in effect all provisions of the approved fire protection program as described in the FSAR. The FSAR, section 9.8.4, states, in part, that administrative controls covering CR3\'s Fire Protection Program are provided by the Fire Protection Plan. The Fire Protection Plan, section 1.6.2, Implementing Documents, references SP-367, Fire Service Valve Alignment and Operability Check, to verify semiannually the operability of Post Indicator Valves (PIV). SP-367, Revision 33, section 4.2.1.1 contains instructions to cycle PIVs listed in Enclosure 3 and to leave the valves in the required position. Enclosure 3 specifies a required position for fire service valve FSV-604 as Sealed Open. Contrary to the above, on January 19, 2008, during performance of the semiannual PIV operability check FSV- 604 was left in the closed position. This issue was more than minor because the fire protection for several fire areas were considered to be degraded and not in compliance with the fire protection plan. Since several fire areas were affected, a Phase 3 evaluation was required. A regional Senior Reactor Analyst performed a Phase 3 evaluation of this performance deficiency under the Significance Determination Process. Based upon the results of this evaluation, the performance deficiency was characterized as of very low safety significance (Green). The dominant accident sequence(s) involved a hypothetical fire of one circuit breaker in either the 3A or B 4160 VAC Engineered Safeguards Compartment that could have been suppressed prior to cable damage by manual suppression, had the isolation valve been in the correct position. This was followed by an independent failure of the safe shutdown train that was unaffected by the fire. Thus, core damage ensued. Major assumptions included that the fire service isolation valve could not be recovered, no credible ignition source was present on the 164 elevation of the control complex that would require evacuation of the Main Control Room and a train of mitigation equipments failure probability was on the order of 1 in 100. The exposure time used for the evaluation was 30 days. The licensee entered this issue in the CAP as NCR 266866
05000302/FIN-2008006-052008Q1Severity level Enforcement DiscretionNRC identifiedDesign Oversight Results in 10 CFR 50, Appendix R, Cable Separation Criteria Not MetThe problem described in the LER is a performance deficiency because the licensee failed to protect cables important to safe shutdown as required. The problem is more than minor because it was associated with the external factors attribute, i.e. fire, 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. When the probability of fire starting in the penetration area or inside containment is multiplied by the probability of the multiple cable damage states described above the result indicates the postulated event is lower than high safety significance (Red) and indicative of having very low safety significance.
05000302/FIN-2008002-052008Q1GreenLicensee-identifiedLicensee-Identified Violation10 CFR 50, Appendix B, Criterion V, Instructions Procedures and Drawings, requires that activities affecting quality shall be prescribed by documented instructions, procedures or drawings of a type appropriate to the circumstances and these instructions, procedures and drawings shall include appropriate quantitative or qualitative acceptance criteria for determining that the important activities have been satisfactorily accomplished. Contrary to these requirements, there were no written instructions to inform personnel implementing dissimilar metal weld inspections on what to do if the coverage of greater than 90 percent required by MRP-139 is not obtained. This resulted in the plant returning to power from RFO 15 without the ultrasonic examinations being conducted in accordance with the requirements of MRP-139. This finding is determined to be of very low safety significance because the deficiency was identified and examinations that met the requirements of MRP- 139 were performed during a forced outage prior to the due date in MRP-139. The licensee entered the finding into their corrective action program as NCR 270077
05000302/FIN-2008002-042008Q1GreenLicensee-identifiedLicensee-Identified Violation10 CFR 55.33 (b) states that if an applicants general medical condition does not meet the minimum standards under 55.33(a)(1), the Commission may approve the application and include conditions to accommodate the medical defect. Contrary to the above, one licensed operator stood watch in a TS position as Operator at the Controls on 19 different occasions between July 9 and August 30, 2007, without complying with a newly issued license condition to take prescribed medication while performing licensed duties. Because of the extenuating circumstances that resulted in the operator not being properly informed of the new restriction, compliance with his license was reasonably beyond his control. This finding is of very low safety significance because other licensed operators were available to man the controls and the restricted operator was under supervision at all times. This event is documented in the licensees corrective action program as NCR 244615
05000302/FIN-2008002-032008Q1GreenLicensee-identifiedLicensee-Identified ViolationImproved Technical Specification (ITS) 3.3.17, Post Accident monitoring (PAM) Instrumentation, requires, in part, that both channels of the function, Degrees of Subcooling, shall be operable in MODES 1, 2, and 3. ITS 3.3.17, Condition C, states that with one or more functions with two required channels inoperable, restore one channel to operable within 7 days. Contrary to the above, on January 25, 2008, during surveillance testing, the licensee determined that both channels of the function, Degrees of Subcooling, had been inoperable since a software change on August 13, 2007. The inspectors determined that the failure to comply with ITS was of very low safety significance since the Degrees of Subcooling function would have remained available during the most limiting accident conditions (incore temperatures less than 1250oF ). The software change only affected the Degrees of Subcooling function above incore temperatures of 1250oF. This issue is documented in the licensees corrective action program as NCR 263310
05000302/FIN-2008002-012008Q1GreenNRC identifiedInoperable Fire Penetration SealThe inspectors identified a Green non-cited violation (NCV) of Crystal River Unit 3 Operating License Condition 2.C(9), Fire Protection Program. The NCV was associated with an inoperable fire penetration seal in the 3-hour fire rated ceiling of the makeup system valve alley. The licensee declared the penetration seal inoperable. Corrective actions included establishing an hourly fire watch and repairing the penetration to its designed condition. The finding adversely affected the fire confinement capability defense-in-depth element. The finding is greater than minor because it is associated with the protection against external factors attribute, i.e., fire, and degraded the mitigating systems cornerstone objective to ensure the availability of systems that respond to initiating events. Using NRC Inspection Manual Chapter (IMC) 0609, Appendix F, Fire Protection Significance Determination Process, the finding was determined to have a very low safety significance since the gap in the fire penetration seal was small (less than 1/8 inch in width)
05000302/FIN-2008006-022008Q1GreenNRC identifiedFailure to Adequately Protect Cables for Valve DHV-42The team identified a non-cited violation of 10 CFR 50, Appendix R, Section III.G.2., for failure to protect cables from fire damage for components required for safe shutdown. Specifically, the Mecatiss MTS-3 fire wrap installed around the cables for valve DHV-42 (suction from the reactor building sump to the Train A decay heat pump) was not installed in accordance with the vendors tested configuration. The licensee initiated a nuclear condition report and implemented an hourly roving fire watch to address this issue. Additionally, the licensee implemented repairs during the March 2008 forced outage to upgrade the Mecatiss MTS-3 fire wrap to comply with the vendor tested configuration. This finding is more than minor because it is associated with the external factors attribute, i.e., fire, and it degraded the reactor safety Mitigating Systems cornerstone objective. The inspectors completed a Phase 1 screening of the finding in accordance with IMC 0609, Appendix F, Attachment 1, Step 1.3, Qualitative Screening Approach, and concluded that the finding, when given credit for the fixed automatic suppression system in the area, was of very low safety significance (Green)
05000302/FIN-2008002-022008Q1GreenH.5Self-revealingFailure to Implement Adequate Equipment Protection Resulted in a Plant TransientA self-revealing finding was identified for failure to prevent inadvertent bumping of the condensate pump control switch during maintenance activities. As a result of bumping the control switch, a condensate pump had to be secured and reactor power was rapidly reduced to 61 percent to prevent a reactor trip. Corrective actions included removing the control switch handle to prevent it from being bumped. The finding was more than minor since it affected the equipment performance attribute of the Initiating Events Cornerstone and affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenged critical safety functions. The inspectors referenced Inspection manual Chapter 0609.04, Significance Determination process (SDP), Phase 1 screening and determined the finding to be of very low safety significance (Green) because the finding did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions will not be available. A contributing cause of this finding is related to the crosscutting area of human performance, with a work control component. Specifically, the licensee did not adequately plan work activities to protect the condensate pump control switch from being bumped
05000302/FIN-2008006-032008Q1NRC identifiedEvaluate Opening Access Hatch to Cable Spread RoomThe team identified an unresolved item (URI) related to the licensees compliance with the CR-3 operating license condition 2.C.(9) and the approved FPP when the access hatch from the MCR floor to the CSR was opened on more than one occasion for maintenance troubleshooting activities. The team reviewed NCR 264494 which the licensee initiated in response to questions from the NRC resident inspectors who observed the access hatch from the MCR floor to the CSR was open and there did not appear to be any compensatory measures in place. The NCR stated that the licensee opened the access hatch between the MCR floor and the CSR to perform battery ground troubleshooting activities. The team questioned if this activity potentially degraded the CSR Halon suppression system. With the hatch open, the team questioned the capability of the Halon suppression system to meet the licensing basis requirement to maintain a 5% Halon concentration for 10 minutes in the event of an Appendix R fire in the CSR. The team also questioned if the licensee performed an evaluation to determine the impact of the hatch being open on the CSR Halon suppression system and to determine if compensatory measures were needed. As a result of questions raised by the team during the inspection, the licensee initiated NCR 266356 to evaluate the impact on the operability of the CSR Halon suppression system with the MCR access door hatch open. The team requested additional information from the licensee regarding the amount of thermoplastic cables in the CSR, how many times and the duration each time the hatch was opened for maintenance troubleshooting in the past year. The licensee provided the requested information to the team and the information is currently being reviewed. The team informed the licensee that this issue will be identified as an URI pending further NRC review of the requested information. This item will be tracked as URI 05000302/2008006-03, Evaluate Opening Access Hatch to Cable Spread Room
05000302/FIN-2008006-042008Q1GreenP.3Self-revealingReactor Coolant Pump 1B Lube Oil Collection System LeakageA self-revealing non-cited violation of 10 CFR 50, Appendix R, Section III.O, was identified for failure of the reactor coolant pump (RCP) oil collection system to collect and drain RCP oil leakage to a vented closed container. Specifically, the licensee found an estimated one to two gallons of oil on the reactor building floor beneath RCP-1B. The licensee initiated a nuclear condition report for this issue. This finding is more than minor because it is associated with the external factors attribute, i.e., fire, and it degraded the reactor safety Initiating Events cornerstone objective. The team completed a Phase 1 screening of the finding in accordance with IMC 0609, Appendix F, Attachment 1, Step 1.3, Qualitative Screening Approach, and concluded that the finding was of very low safety significance (Green) because the amount of oil identified in 2008 was bounded by the licensees 2004 analysis (which assumed a 21 gallon oil leak). This finding has a cross-cutting aspect in the Corrective Action Program component of the Problem Identification and Resolution area because the licensee did not take appropriate corrective actions in a timely manner to address the adverse trend related to oil leakage for RCP-1B (NRC Inspection Manual Chapter 0305, P.1(d))
05000302/FIN-2008006-012008Q1GreenH.8NRC identifiedFailure to Control Transient CombustiblesThe team identified a non-cited violation of Crystal River Unit 3 Operating License Condition 2.C.(9), for the licensees failure to properly implement fire protection program procedures for control of transient combustible materials. Specifically, transient combustible materials were left unattended for four days in the 3B 480V ES Switchgear Room after work had been completed, which was a violation of the licensees administrative procedures for control of transient combustibles. Once identified, the licensee removed the combustible materials and initiated a nuclear condition report to address the issue. The finding is more than minor because the transient combustible materials presented a credible fire scenario involving equipment important to safety, which degraded the reactor safety Initiating Events cornerstone objective to limit the likelihood of those events that may upset plant stability and challenge critical safety functions. The amount of unattended transient combustible materials did not violate the licensees transient combustible control limits for the fire area. Therefore, the finding was assigned a low degradation rating against the combustible controls program. The finding was of very low safety significance (Green) based on the low degradation rating. This finding has a cross-cutting aspect in the Work Practices component of the Human Performance area because the licensee failed to effectively communicate expectations regarding procedural compliance and personnel following procedures (NRC Inspection Manual Chapter 0305, H.4(b))
05000302/FIN-2005009-022005Q3Severity level IVNRC identifiedCompleteness and Accuracy of Information Provided to the NRC Concerning Steam Generator Inspection Results

The inspectors identified a Non-cited violation (NCV) of 10 CFR 50.9, Completeness and Accuracy of Information, for several examples of inaccuracies and incomplete information in required reports and correspondence. The licensee entered this condition into their corrective action program.

This violation was assessed using traditional enforcement because it impacted the regulatory process. The issue is more than minor because the NRC relies on complete and accurate information to reach conclusions concerning the allowable time between steam generator inspections. It was determined to be a Severity Level IV violation because it was not willful, the technical issue associated with the incomplete and inaccurate information was of very low safety significance, and the NRC had not yet made a regulatory decision based on the information.

05000302/FIN-2004009-012005Q1NRC identifiedUnprotected Post-Fire Safe Shutdown Cables and Related Non-feasible Local Manual Operator Recovery ActionThe team identified a violation of 10 CFR 50, Appendix R, Section III.G.2, for failure to physically protect or separate cables from fire damage and instead relying on an unapproved local manual operator action. The unprotected cables were associated with a common electrical protection and metering circuit which was installed such that fire damage to a cable in or just above the 3A 4160V engineered safeguards (ES) switchgear could result in tripping and locking out all feeder breakers to both 4160V ES busses, resulting in a loss of all safetyrelated alternating current power. In addition, the local manual operator action to reset the 3B emergency diesel generator breaker lockout on the 3B 4160V ES switchgear was determined to be non-feasible. During a severe fire in the adjacent 3A 4160V Switchgear Room the fire response activities would cause the location for the operator action (the 3B 4160V Switchgear Room) to be exposed to hot smoke, water mist, and water on the floor. This finding was an immediate safety concern and the licensee made modifications to correct the nonconforming condition before the inspection team left the site. This finding is unresolved pending the completion of a significance determination. The finding is greater than minor because it degraded the defense in depth for fire protection and also because it is associated with the protection against external factors attribute and degraded the reactor safety mitigating systems cornerstone objective. The finding adversely affected the reliability and capability of equipment required to achieve and maintain a safe shutdown condition following a severe fire in the 3A 4160V ES Switchgear Room.
05000302/FIN-2004009-032005Q1NRC identifiedUnapproved Local Manual Operator Actions Instead of Required Physical Protection or Separation of Cables to Preclude Fire DamageThe team identified a violation of 10 CFR 50, Appendix R, Section III.G.2, for failure to physically protect or separate cables from fire damage and instead relying on unapproved local manual operator actions. The operator actions were to be accomplished outside the main control room (MCR) and were relied on to achieve and maintain safe shutdown from the MCR during a severe fire in the 3A 4160V ES Switchgear Room or the 3A 480V ES Switchgear Room. This finding is unresolved pending the completion of a significance determination. The finding is greater than minor because it degraded the defense in depth for fire protection and also because it is associated with the protection against external factors attribute and degraded the reactor safety mitigating systems cornerstone objective. The finding adversely affected the reliability and capability of equipment required to achieve and maintain a safe shutdown condition following a severe fire. This finding is not an immediate safety concern because each of the manual actions could be reasonably accomplished and the postulated time line demonstrated that there was sufficient time to perform each action. However, this issue remains unresolved pending further NRC review of the overall complexity and number of the manual actions. The finding is applicable to post-fire safe shutdown from the control room during a fire in the 3A 4160V ES Switchgear Room.
05000302/FIN-2004009-022005Q1NRC identifiedSingle Failure Vulnerability of Common Electrical Protection and Metering CircuitsThe team identified a violation of 10 CFR 50, Appendix B, Criterion III, Design Control, for installing and modifying electrical protection and monitoring circuits that did not meet the general design criteria for single active failures. A common electrical protection and metering circuit was installed such that a single active failure of a component in the circuit could trip and lock out all feeder breakers to both 4160V ES busses, resulting in a loss of all safety-related alternating current power. This finding was an immediate safety concern and the licensee made modifications to correct the nonconforming condition before the inspection team left the site. This finding is unresolved pending the completion of a significance determination. The finding is greater than minor because it is associated with the design control and equipment performance attributes of the reactor safety mitigating systems cornerstone. The finding adversely affects the objectives of availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.
05000302/FIN-2004009-052005Q1NRC identifiedMotor Operated Valves Not Protected From Hot Shorts that Could Bypass Torque SwitchesThe team noted that the licensees Appendix R Fire Study indicated that a number of motor-operated valves were not protected from certain hot shorts that could spuriously actuate the valve and also bypass the torque and limit switches. The team noted that such an occurrence could potentially defeat the post-fire SSD strategy, and the licensee planned to further evaluate whether such a vulnerability actually existed. This issue is unresolved pending NRC review of the licensees evaluation. The licensees Appendix R Fire Study stated that many MOVs have had their control circuits modified such that hot shorts which can spuriously actuate the valves will not be able to bypass the torque and limit switches as addressed in NRC Information Notice 92-18. The Fire Study further stated that one exception to this is for a fire located at the valves motor control center. The team noted that fires could occur at motor control centers, and if such a fire caused a hot short that spuriously actuated a motor operated valve that was needed for post-fire SSD and also bypassed the torque switch, the valve could be rendered inoperable by becoming jammed into its valve seat. Consequently, operators would not be able to subsequently open the valve. The team also noted that the plant design included MOVs that were relied upon for both A train and B train post-fire SSD. Examples included the makeup pump minimum-flow valves. These two MOVs were installed in series in the combined minimum-flow line for all three makeup pumps. One was powered from the A train and one from the B train of the electrical system. If either one of these valves were to become damaged in the closed position, all minimum-flow for all makeup pumps would be lost. However, the licensees Appendix R Fire Study relied on having makeup pump mininimum-flow available for post-fire SSD. Another example would be the decay heat drop line, which similarly included two MOVs in series. In response to NRC questions about this potential vulnerability that could affect post-fire SSD, the licensee initiated NCR 148225 to further evaluate whether such a vulnerability actually existed. This issue is unresolved pending NRC review of the licensees evaluation: URI 05000302/2004009-005, Motor Operated Valves Not Protected From Hot Shorts That Could Bypass Torque Switches.
05000302/FIN-2004009-042005Q1NRC identifiedNo Cooling to Reactor Coolant Pump Seals for up to Eight HoursThe team noted that the licensees Appendix R Fire Study and post-fire SSD procedures relied on reactor coolant pump (RCP) seals remaining intact, without leaking, without cooling for up to eight hours. Because this practice differed significantly from general industry RCP seal design capabilities, this issue is unresolved pending further NRC review of the technical basis for acceptability. Crystal River 3 had Byron-Jackson (now Flowserve) N-9000 seal cartridges installed in the RCPs. Further, the licensee had a vendor analysis titled RCP N-9000 Seal Appendix R Evaluation supporting the ability of the seals to go without any cooling for up to eight hours without failing or leaking. Because RCP seals are not generally designed for eight hours without cooling and without failing or leaking, the team determined that NRC review of the vendor analysis was necessary. This issue is identified as URI 05000302/2004009-004, No Cooling to Reactor Coolant Pump Seals for up to Eight Hours.
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