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05000373/FIN-2010005-072010Q4LaSalleLicensee-Identified ViolationLicense Condition C.25, Fire Protection Program, requires that the licensee shall implement and maintain all provisions of the approved Fire Protection Program as described in the UFSAR for LaSalle County Station as approved in NUREG-0519 Safety Evaluation Report related to the operation of LaSalle County Station, Unit 1 and 2. Contrary to the above, on October 12, 2010, foreign material exclusion (FME) was found in the fire suppression header in the Division I shared cable spreading area. The finding was determined to be of very low safety significance because it was assigned a low degradation rating. Specifically, less than 10 percent of the nozzle heads in the system were impacted and there were functional nozzle heads within 10 feet of the non-functional ones. The licensee entered this issue into their CAP as IR 1120517, flushed and returned the system to service satisfactorily and revised the procedure to provide better testing of the fire suppression system in the future.
05000373/FIN-2010005-062010Q4LaSalleImplementation of the Racklife computer model to monitor Unit 2 spent fuel pool storage racks degradationThe inspectors identified an unresolved item (URI) associated with the potential failure to conduct an adequate 10 CFR 50.59 evaluation for the implementation of the Racklife computer code as a method to calculate Boraflex degradation of the Unit 2 SFP. This item remains unresolved pending further review by the NRC staff. Description: On June 26, 1996, the NRC published Generic Letter (GL) 96-04: Boraflex Degradation in Spent Fuel Pool Storage Racks. The licensee was required to respond to this letter since the SPF for Unit 2 used Boraflex as a neutron absorber. The response required an assessment of the capability of Boraflex to maintain 5 percent sub-criticality margin and a description of the proposed actions if this margin could not be maintained by Boraflex. The licensee responded to GL 96-04 on November 6, 1996, by providing an assessment of the Boraflex condition in the Unit 2 SFP. The assessment was based on coupon testing, rack exposure management and the margin to criticality existing at the time. In this response, Racklife is mentioned as an Electrical Power Research Institute (EPRI)-sponsored calculational model that is under development and the licensee stated that the Racklife models predictions would be used in the future to support the unit 2 SFP rack management strategy and to identify the need for additional activities to offset any degradation. In 2005, through a 50.59 Screening, the licensee revised the UFSAR Section 9.1.2.2 Unit 2 Spent Fuel Pool to describe a comprehensive Boraflex monitoring program that included Boraflex coupon surveillance (onsite and off-site). In addition, the change to the UFSAR added periodic neutron blackness testing (Badger testing) and the use of EPRIs Racklife computer code to model Boraflex degradation. Subsequently, in 2006, an additional 50.59 Screening was performed to again revise Section 9 of the UFSAR to specify that the licensee will conduct Badger testing every 3 years for as long as Boraflex is credited to help control the Unit 2 SFP reactivity. In accordance with licensee TS, a Keff of less than 0.95 must be maintained to ensure operability of the SFP. Using a criticality analysis for the most reactive fuel, the licensee determined that even with 57 percent cell degradation, the acceptance criterion of Keff of less than 0.95 will still be met (factors for that determination include fuel enrichment, pool temperature, etc). After applying a factor of safety of 5 percent, the licensee established 52 percent degradation as the cell operability criteria. As a result, any cell that exhibits a higher percentage of degradation is declared inoperable and is unusable. The Racklife computer model is not part of the criticality analysis that is used to meet the TS operability criteria. However, the Racklife computer model, which is run every 6 months, provides an updated percent of degradation value for each cell. This input from Racklife allows the licensee to manage the storage capacity of the Unit 2 SFP and is what the licensee uses to determine if spent fuel can be stored in any particular cell. These results are used to declare cells inoperable. Using industry guidance provided in Nuclear Energy Institute (NEI) 96-07, Revision 1, Guidelines for 10 CFR 50.59 Implementation, the resident inspectors determined that implementing Racklife is a departure from a method of evaluation described in the UFSAR. By implementing Racklife to help manage the Unit 2 SFP storage capacity, the licensee changed to a different method of evaluation from the one described in the UFSAR. This new method has not been approved by the NRC. The licensees 50.59 screening document dismisses this screening question (Does the proposed activity involve an adverse change to an element of a UFSAR described evaluation methodology, or use of an alternative evaluation methodology, that is used in establishing the design bases or used in the safety analyses?) by stating the use of Racklife does not influence the criticality analysis. The inspectors plan to engage personnel in the Nuclear Reactor Regulation office to ensure that the licensee is implementing the 50.59 guidelines and processes appropriately and to ensure that the use of the Racklife computer model by all licensees is treated consistently.
05000373/FIN-2010005-032010Q4LaSalleFailure to Perform Adequate Evlauation for Reactor Building Crane UpgradeDuring an inspection of pre-operational testing activities of an independent spent fuel storage installation (ISFSI) at the LaSalle County Station, the inspectors identified a finding of very low safety significance with an associated NCV of Part 10 of the Code of Federal Regulations (CFR) Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to perform adequate evaluations to upgrade the single failure proof crane. Specifically, the inspectors identified five examples where the licensee failed to perform adequate evaluations in accordance with American Society of Mechanical Engineers (ASME) NOG-1-2004, Rules for Construction of Overhead and Gantry Cranes (Top Running and Bridge, Multiple Girder), requirements. The reactor building crane was designed to meet Seismic Category I requirements, and the licensee used compliance with ASME NOG-1-2004 as the design basis for their crane upgrade to a single failure proof crane. The inspectors determined that the failure to perform adequate evaluations was contrary to ASME NOG-1-2004 requirements and was a performance deficiency. The licensee documented the conditions in Issue Report (IR) 957014, IR 1093028, and IR 1098435 and initiated actions for calculation revisions and field modifications. The finding was of more than minor significance because it was associated with the Initiating Events Cornerstone attribute of Equipment Performance and affected the cornerstone objective of limiting the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the failure to perform adequate evaluations affected the licensees ability to provide reasonable assurance that loads would not be dropped during critical lifts. The inspectors evaluated the finding using IMC 0609.04, Phase 1 - Initial Screening and Characterization of Findings, and based on a No answer to all of the questions in the Initiating Events column of Table 4a, determined the finding to be of very low safety significance (Green). This finding has a cross-cutting aspect in the area of Human Performance, Work Practices because the licensee did not ensure supervisory and management oversight of work activities, including contractors, such that nuclear safety is supported (IMC 0310, H.4(c)).
05000373/FIN-2010005-022010Q4LaSalleFailure to Foolow Performance Centered Monitoring Process ProcedureA finding of very low safety significance (Green) and an associated NCV of Technical Specification (TS) 5.4.1, Procedures, was self-revealed, for the failure to follow procedural guidance specified in procedure MA-AA-716-210, Performance Centered Monitoring Process. Specifically, a control relay for the Unit 2 Division 3 switchgear room ventilation was inappropriately classified for its preventive maintenance schedule and had a recommended replacement frequency of as required instead of the 10 year frequency required, by procedure, for this type of equipment. As a result, when this relay failed, it caused the switchgear room ventilation system (VD) to trip and the unexpected unavailability and inoperability of the Unit 2 high pressure core spray (HPCS) system. The inspectors determined that the finding was of more than minor significance because it affected the Mitigating Systems Cornerstone attribute of Human Performance (human error pre-event), and it affected the cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, since HPCS is a single train, this constituted a loss of safety function. The finding was determined to be of very low safety significance using an SDP Phase 3 analysis. As part of the corrective actions for this issue, the licensee re-classified the control relay to Critical, high duty cycle, to help ensure that replacement of the component occurs at the appropriate time-based frequency. The inspectors did not identify a cross-cutting aspect associated with this finding.
05000373/FIN-2010005-042010Q4LaSalleFailure to Design the ISFSI Pad to Adequately Support the Static and Dynamic Loads of Stored CasksThe inspectors identified an NCV of 10 CFR 72.212 (b)(2)(i)(B), Conditions of a General License Issued Under 72.210, for the licensees failure to perform adequate evaluations of the ISFSI pad. Specifically, the inspectors identified five examples where the licensee failed to design the ISFSI pad to adequately support the static and dynamic loads of the stored casks, considering potential amplification of earthquakes through soil-structure interaction. The licensee documented the conditions in IRs 900610, 966506 and 1102633. As an interim corrective action, the licensee provided a technical paper containing justification for partial loading of the pad with 10 casks. Because this violation was related to an ISFSI license, it was dispositioned using the traditional enforcement process in accordance with Section 2.2 of the Enforcement Policy. The inspectors determined that the deficiency was of more than minor significance because, if left uncorrected, a failure of the ISFSI pad could lead to a more significant safety concern. The inspectors determined that the violation could be screened using Section 6.5.d.1 of the NRC Enforcement Policy as a Severity Level IV Violation.
05000373/FIN-2010005-052010Q4LaSalleFailure to Perform Adequate Evaluations to Ensure Compliance with 10 CFR 72.212(b)(3) and 10 CFR 72.122(b)(i)The inspectors identified an NCV of 10 CFR 72.146, Design Control, for the licensees failure to perform adequate evaluations to ensure compliance with 10 CFR 72.212(b)(3) and 10 CFR 72.122 (b)(2)(i). Specifically, the inspectors identified that the licensee failed to evaluate that the reactor site parameters including analyses of tornado effects were enveloped by the cask design basis, and perform additional analysis to ensure compliance with 10 CFR 72.122(b)(2)(i). The licensee documented the condition in IR 1137279 and initiated a new calculation to demonstrate compliance. Because this violation was related to an ISFSI license, it was dispositioned using the traditional enforcement process in accordance with Section 2.2 of the Enforcement Policy. The violation was determined to be of more than minor significance because the licensee failed to have an evaluation to assure transfer cask (HI-TRAC) integrity during a tornado event and an additional calculation was required. The licensees new calculation determined that overturning and sliding of the HI-TRAC on the refuel floor would not occur during a tornado. Therefore, the violation screened as having very low safety significance (Severity Level IV).
05000456/FIN-2010003-032010Q2BraidwoodLicensee-Identified ViolationTitle 10 CFR Part 50, Appendix B, Criterion V, Procedures, requires, in part, that activities affecting quality shall be prescribed by documented instructions or procedures of a type appropriate to the circumstances, shall be accomplished in accordance with those instructions or procedures, and acceptance criteria shall be included in instructions or procedures to determine that important activities have been satisfactorily accomplished. Contrary to the above, Braidwood Operating Procedure (BwOP) RH-4, Draining the RH System, Revisions 20 and 22, did not adequately control vent and drain valves during the on line draining of the RH system. This finding was determined to be of very low safety significance and was entered into the CAP.
05000456/FIN-2010003-022010Q2BraidwoodLicensee-Identified ViolationTechnical Specification 3.7.8, Condition C, requires that the plant be in Mode 3 within 6 hours and Mode 5 within 36 hours if the required Actions and associated completion time of Condition A or Condition B is not met. Technical Specification 3.7.8, Condition A, requires a unit specific SX train to be restored to Operable status within 72 hours in Modes 1,2,3, and 4. Contrary to the above, 31 Enclosure on January 2, 2010 the 2A SX train had been inoperable greater than the allowed LCO outage time after the licensee discovered the 2A SX pump seal cooling hose was leaking on January 29, 2010. This issue was determined to be of very low safety significance and was entered in the licensees CAP.
05000456/FIN-2010003-012010Q2BraidwoodDegraded Condition of Reactor Head Vent ValvesA finding of very low safety significance was self-revealed on July 30, 2009, after the Unit 2 reactor tripped due to a trip of the 2C reactor coolant pump on overcurrent. The 2C reactor coolant pump tripped on overcurrent following an automatic bus transfer due to the loss of station auxiliary transformer 242-1 on a sudden pressure relay actuation. Subsequent investigation identified the cause of the 2C reactor coolant pump trip to be incorrect setpoints on the reactor coolant pump overcurrent relays. The inspector determined that this cause was not a violation of NRC requirements since the overcurrent trip function of the reactor coolant pump is not a safety-related function. The licensee entered this condition into their corrective action program. Corrective actions included: increasing the Unit 2 reactor coolant pump overcurrent relay dropout values from 75 to 90 percent, adjustment of the 2C reactor coolant pump overcurrent time delay setting, extent of condition review for Unit 1 during their next scheduled refuelling outage (Fall 2010), and a revision of station procedures to include periodic calibration of the reactor coolant pump overcurrent relays. This performance deficiency was considered more than minor because it impacted the Configuration Control attribute of the Initiating Events Cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. The inspectors performed a Phase 1 Significance Determination Process review for this finding using the guidance provided in IMC 0609, Attachment 4, Initial Screening and Characterization of Findings. Based on Tables 2, Cornerstones and Functions Degraded as a Result of the Deficiency, and 3b, Significance Determination Process Phase 1 Screening Worksheet for Initiating Events, Mitigation Systems, and Barriers Cornerstones, in IMC 0609, Attachment 4, the inspectors determined the finding was a transient initiator contributor in the Initiating Events Cornerstone. The inspectors answered No to the Transient Initiators question in the Initiating Events Cornerstone Column of IMC 0609, Attachment 4, Table 4a, Characterization Worksheet for Initiating Event, Mitigating System, and Barrier Integrity Cornerstones, and determined that the issue was of very low safety significance. No 2 Enclosure cross-cutting aspects were assigned to this issue since the performance deficiency was not reflective of current performance.
05000263/FIN-2010002-042010Q1MonticelloLicensee-Identified ViolationThe licensee identified that during the Monticello 2008 ISFSI loading campaign a contractor performing non-destructive examinations (NDE) on two dry shielded canisters (DSCs) failed to follow a step of TriVis Procedure QP-9.202,Revision 3, Color Contrast Liquid Penetrant (PT) Examination Using the Solvent-Removable Method, which required the base metal temperature of the surface for the NDE to be below 250 degrees F. Specifically, the base metal temperature for DSC 002 was 270 degrees F and 253 degrees F for DSC 005 when the NDE was performed. The licensee immediately evaluated the situation and held a stand down to emphasize the importance of procedural adherence. Since the loaded and welded canisters were already stored in the Horizontal Storage Modules on the ISFSI pad at the time of discovery of the discrepancies, the licensee performed qualification PT examinations using two comparator blocks at a procedural non-standard temperature of 325 degrees F. The NDE products adequately identified flaws on the comparator blocks even beyond the qualified procedure range for the base metal temperature. Title 10 CFR 72.150, Instructions, Procedures, and Drawings, requires, in part, that the licensee prescribe activities affecting quality by documented instructions, procedures, or drawings of a type appropriate to the circumstances and requires that these instructions, procedures, and drawings be followed. The violation was addressed by traditional enforcement since 10 CFR Part 72 is not risk based and is not covered under the Reactor Oversight Process. The inspectors reviewed the examples in the Enforcement Policy, Supplement I and determined that the failure to follow the procedure was a violation that had more than minor safety or environmental significance but did not rise to a Severity Level I, II, or III violation due to the above mentioned results of the comparator blocks and the fact that the test port plug (weld no. 5) did not serve a structural or pressure retaining function. The inspectors determined that the violation had more than minor safety significance because failure to follow procedures and keep the base metal temperature below the temperatures at which the PT examination materials function properly could have lead to errors in identifying potential flaws in more critical welds that serve as pressure boundaries. The licensee entered these issues into its corrective action program as AR 01156986 and AR 01155771
05000263/FIN-2010002-012010Q1MonticelloReactor Building Crane Design and Licensing Basis IssuesThe inspectors reviewed the following licensing documents for the reactor building crane: NRC letter to Northern States Power (NSP), Safety Evaluation by the Office of Nuclear Reactor Regulation (NRR) Supporting Approval of Crane Modification and Use of 70 Ton Spent Fuel Shipping Cask IF-300, dated May 19, 1977; NSP letter to NRC, Response to Request for Additional Information, dated February 28, 1977; and USAR, Section 10.2, page 4 of 24, and Section 12.2 page 28 of 49, and page 29 of 49, Revision 23 and Revision 25.The NRC letter to NSP, Safety Evaluation by the Office of Nuclear Reactor Regulation Supporting Approval of Crane Modification and Use of 70 Ton Spent Fuel Shipping Cask IF-300, dated May 19, 1977, established the reactor building overhead crane capacity as a maximum of 85 tons and the crane seismic analysis did not analyze for a maximum 85 ton lifted load concurrent with a seismic event based on extremely low probability of both events occurring simultaneously. The licensee subsequently changed the reactor building crane capacity from 85 tons in USAR, Section 10.2, page 4 of 24,and Section 12.2, page 28 of 49, and page 29 of 49, Revision 23 to a crane capacity of105 tons in USAR Section 10.2, page 4 of 24 and Section 12.2, page 28 of 49 and page 29 of 49, Revision 25.The inspectors noted that the licensee did not perform a written 10 CFR 50.59evaluation to assess the following: 1) whether the change of increasing design loads on the crane and the crane support structure required a license amendment and, 2) probabilistic analysis with consideration for a new maximum crane lifted load of105 tons that evaluates whether or not a lifted load must be considered during a seismic event for the design of the reactor building crane and crane support structure. The inspectors reviewed Calculation Nos. CA 76 138, Structural Requalification for New 85 Ton Crane, Revision 0; CA-05-103, Reactor Building Superstructure Seismic Response Analysis with 105 Ton Crane, Revision 0A; and CA-05-107,Structural Seismic Qualification Reactor Building Crane Upgrade for ISFSI, Revision 0B. The inspectors were concerned that the reactor building crane and reactor building crane support structure had been evaluated using friction in a linear elastic analysis to reduce seismic load effects applied to the reactor building crane and crane support structure. The licensee used much smaller seismic loads limited by the friction force and this resulted in a significant load reduction for qualification of the reactor building crane and reactor building crane support structure. In addition, the non-linear effects of friction have not been addressed in the aforementioned calculations. The licensee was unable to provide evidence that the NRR staff had approved friction in a linear elastic analysis as a method of evaluation for this application. The use of friction to reduce seismic load effects on the reactor building crane and reactor building crane support structure was not discussed in the USAR. The inspectors reviewed Calculation No. CA-05-101, Evaluation of Reactor Steel Superstructure for 105 Ton Reactor Building Crane, Revision 3A. The inspectors were concerned with the following: 1) The minimum yield strength for the American Society of Testing and Materials (ASTM) A1 trolley and the bridge rail has not been established in accordance with the American Institute of Steel Construction (AISC) code and,2) The restraint mechanism in the longitudinal direction of the trolley rail and bridge rail connection was based on the use of friction resistance between the bottom of the rail and the supporting beam to resist the sliding of the rail during a design and licensing basis event. In response to the concern, the licensee initiated corrective action program documents CAP 01214808, RB Crane Seismic Calc may not be Consistent W/License Basis, dated January 22, 2010 and CAP 01222530, Crane Heavy Lift Inspection URI:10 CFR 50.59 for Crane Upgrade, dated March 13, 2010. Near the end of the inspection period, the licensee provided the inspectors additional information relevant to the design basis and licensing basis of the reactor building crane and reactor building crane support structure which will require additional review. Therefore, this issue is considered an unresolved item (URI 05000263/2010002-01, Reactor Building Crane Design and Licensing Basis Issues) pending additional inspector review to determine design and licensing basis requirements
05000263/FIN-2010002-022010Q1MonticelloSRV Low Low Set Surveillance Procedure ImplementationThe inspectors identified a finding of very low safety significance and NCV of Technical Specification 5.4.1 for the licensee failing to appropriately implement an applicable procedure recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Specifically, when unexpected local alarms were received during the performance of the safety relief valve (SRV) low low set system quarterly test, Instrument and Control (I&C) personnel elected to attempt to clear the alarms prior to notifying operations and without fully understanding which alarms were present. The surveillance procedure provided no guidance on how to clear the unexpected module trip alarms and relay energized lights. The licensee entered this issue into their corrective action program. The inspectors determined that the performance deficiency affected the cross-cutting area of Human Performance, having decision-making components, and involving aspects associated with using conservative assumptions indecision making. H.1(a)The inspectors determined that the performance deficiency was more than minor and a finding because it was associated with the Barrier Integrity Cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. The inspectors evaluated the finding using IMC 0609, Appendix A, Attachment 1, Significance Determination of Reactor Inspection Findings for At-Power Situations, using the Phase 1 Worksheet for the Barrier Integrity Cornerstone. Since the inspectors answered no to all four questions in the Containment Barrier column of the Characterization Worksheet for Initiating Events, Mitigating Systems, and Barrier Integrity Cornerstones, the inspectors concluded that the finding was of very low safety significance
05000263/FIN-2010002-032010Q1MonticelloInadequate Corrective Actions for Unexpected SRV Low Low Set Trips Encountered During Surveillance TestingThe inspectors identified a finding of very low safety significance and NCV of10 CFR 50, Appendix B, Criterion XVI, for the licensees failure to adequately evaluate and take corrective actions for a condition adverse to quality. Specifically, the licensee failed to appropriately evaluate the implications of the unexpected trips of high/low pressure switches, PSHL-4065A and PSHL-4066A, during the January 28, 2009, performance of the SRV low low set system quarterly tests and implement appropriate corrective actions. The failure to adequately evaluate the unexpected trips and correct the condition adverse to quality directly contributed to a repeat occurrence and subsequent unplanned Technical Specification Action entry during the January 27, 2010, performance of the same surveillance test. The licensee entered the issue into their corrective action program. The inspectors determined that the performance deficiency affected the cross-cutting aspect in the area of Problem Identification and Resolution, having corrective action program components, and involving aspects associated with the licensee thoroughly evaluating problems such that the resolutions address causes and extent of conditions, as necessary. P.1(c) The inspectors determined that the performance deficiency was more than minor and a finding because it was associated with the Barrier Integrity Cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. The inspectors evaluated the finding using IMC 0609, Appendix A, Attachment 1, Significance Determination of Reactor Inspection Findings for At-Power Situations, using the Phase 1 Worksheet for the Barrier Integrity Cornerstone. Since the inspectors answered no to all four questions in the Containment Barrier column of the Characterization Worksheet for Initiating Events, Mitigating Systems, and Barrier Integrity Cornerstones, the inspectors concluded that the finding was of very low safety significance
05000255/FIN-2009005-032009Q4PalisadesAdequacy of building lightning protectionDuring the previous inspection period, the inspectors reviewed lightning protection adequacy of risk significant structures. The inspectors recognized that the auxiliary building does not have lightning rods installed and requested the licensees basis for determining that the auxiliary building had adequate protection. In report No. 05000255/2009-004, the inspectors reviewed site strategies to counter the effects of lightning strikes. The need to protect structures, systems, and components important to safety from the effects of natural phenomena (to include lightning) is discussed in the UFSAR and in the plants response to Fire Protection Branch Technical Position APCSB 9.5-1. As part of the inspection, the inspectors performed a walkdown of various rooftop areas. Based on this review, the inspectors questioned if air terminals, or lightning rods, were required on the auxiliary building. The licensee responded that the nearby (and taller) containment structure, which has four air terminals, adequately protected the auxiliary building. Subsequent to the issuance of report No. 05000255/2009-004, ongoing discussions with the licensee revealed that National Fire Protection Association (NFPA) codes did not support the licensee position that containment structure would provide protection to the auxiliary building. Therefore, the inspectors concluded that the basis for the acceptability of the lightning protection of the auxiliary building is not available and additional information is needed to determine the adequacy of the current configuration. The licensee has entered the issue into their corrective action program as CR-PLP-2009-5419, which contains a corrective action to perform an assessment of lightning protection systems on site. Pending the licensees evaluation of the condition and a review of the evaluation by the inspectors, this issue will be considered a URI. The assessment is currently scheduled to start during the next inspection period, therefore, the issue will be entered as URI 05000255/2009005-003, Adequacy of Auxiliary Building Lightning Protection.
05000255/FIN-2009005-012009Q4PalisadesNOED for repair to service water pump P-7CDuring the request for a NOED, the licensee committed to performing an independent verification of hardness on each pump coupling. Subsequently, the licensee informed the inspectors that an independent verification of hardness had not been completed on each coupling. On September 29, while at 100 percent power, the upper shaft coupling for the P-7C service water pump failed, rendering the pump inoperable. The licensee determined that the pump would not be operable prior to expiration of the 72 completion time. On October 1, the licensee verbally requested enforcement discretion to avoid a shutdown. During the request, the licensee informed the NRC that the failed coupling likely failed due to improper heat treatment of the coupling that resulted in high out of specification hardness. Since the testing requirements in place should have identified the out of specification hardness, the licensee committed to independently testing each coupling for hardness prior to installation. The licensee reiterated that each coupling would be independently hardness tested prior to installation in the written NOED request. Subsequently, the licensee informed the NRC that the independent hardness test had not been performed. The licensee wrote a CR to document this item and evaluated that the P-7C was operable. The independent hardness test could not be performed with the pump re-assembled. The inspectors evaluated the licensees assessment of operability of the P-7C pump using the guidelines of 71111.15. The inspectors concluded there was reasonable assurance the couplings were acceptable. Pending determination on whether a violation occurred, URI 05000255/2009005-01 will remain open.
05000255/FIN-2009005-022009Q4PalisadesAdequacy of evaluation of interface with state and local governmentsThe inspector reviewed the quality assurance audits conducted pursuant to10 CFR 50.54(t) for the adequacy of the independent evaluation of the interface of the licensee with State and local governments. For the Palisades Nuclear Power Plant EPZ, Michigan Department of State Police Emergency Management Division is the leading state agency for emergency response planning and operations. The local governments in the EPZ include Allegan, Berrien, and Van Buren counties. In the 2008 Quality Assurance audit report, the auditor evaluated the interface of the licensee with State and local Governments as satisfactory. The auditor made contact with officials from the Michigan State Police, Allegan, and Van Buren County. During the 2009 audit, the auditor made contact with Berrien County and also evaluated the interface as adequate. Palisades follows the Entergy Nuclear Emergency Plan Master Audit Plan which lists the evaluation of the adequacy of the interfaces with State and local governments as a mandatory core scope element. The licensee reported the mandatory scope elements are to be evaluated during the surveillance conducted every 12 months. The Entergy Nuclear Management Manual states the audits of the emergency preparedness program must review all elements of the program at least once every 24 months. If an audit is to be performed beyond 12 months from the previous audit, an assessment shall be performed to include performance indicators. Pending review of additional information requested from the licensee concerning the licensees methods and performance indicators for evaluating the adequacy of the interface with the State and local governments in order to determine if the audit plan and schedule met the requirements of 10 CFR 50.54(t), this issue is considered an Unresolved Item(URI), 05000255/2009005-02.
05000456/FIN-2009005-012009Q4BraidwoodWater Found in Underground Cable VaultsThe inspectors have identified an Unresolved Item (URI) related to underground cable vaults. Specifically, the inspectors reviewed an Issue Report(IR) generated by the licensee that documented the deteriorating condition of numerous underground cable vaults. The IR stated that water was found in all of the vaults that were opened and many cables were partially or fully submerged in water. During a review of the condition of cable vaults at Braidwood, the inspectors reviewed IR 968522, which documented the condition of cable vaults that were accessed as part of the installation of unrelated plant modifications. The inspectors also reviewed photographs of each cable vault that was accessed during the modification installation. None of the cables contained in the vaults were safety-related but many were associated with Maintenance Rule systems, such as Circulating Water, Non-Essential Service Water, and Auxiliary Power systems. The cable vaults that were accessed were 1E, 1Z, 2D, 2E, 2F, 2G, 2H, 2J, and X. The licensee reported that water was found in each cable vault and at least some cables were submerged in water in each cable vault. In addition to submerged cables, personnel also observed cracking of the concrete vault walls, rusting cable trays and supports, taped cable splices that were submerged in water, and sludge build-up on many cables and structures. All cable vaults on-site have not been inspected; however, the licensee believes the conditions observed in the vaults that were accessed exist inthe remaining vaults as well. The licensee has developed a modification to add the capability to remove water from the vaults but it has not yet been implemented. At the conclusion of the inspection period, the inspectors have notified NRC personnel from the Office of Nuclear Reactor Regulation, per IP 71111.06, and are awaiting further instruction. Pending additional information, this issue will remain open.(URI 05000456/2009005-01; 05000457/2009005-01
05000341/FIN-2009005-012009Q4FermiFailure to Adhere to Self-imposed Maintenance Rule Procedural RequirementsA finding of very low safety significance (Green) was identified by the inspectors for the licensees failure to adhere to self-imposed maintenance rule procedural requirements. Contrary to maintenance rule monitoring requirements, while performing a maintenance rule functional failure evaluation of a diesel fire pump functional failure, licensee personnel inappropriately determined the failure was not maintenance preventable and assigned an incorrect causal code to the event prior to completing and documenting a cause analysis. These actions led to a delay in licensee recognition that the fire protection system had exceeded its performance criteria; therefore, presentation of the systems condition to the maintenance rule expert panel for a(1) consideration was delayed by several months. No violation of NRC requirements occurred. The licensee entered this item into their corrective action program (CAP) as condition assessment and resolution document (CARD) 09-28649. The licensees immediate actions included correction of the causal code for the maintenance rule functional failure and initiation of the a(1) evaluation process for the affected system. The system was placed in a(1) status on January 12, 2010. The finding was determined to be more than minor in accordance with IMC 0612, Appendix E, Example 4.a, in the not minor section, because procedural noncompliance in the maintenance rule area continues to be an issue at Fermi. In addition, if left uncorrected, the failure to adhere to procedures could have the potential to lead to a more significant safety concern. Specifically, not following procedural requirements specified in the Fermi Maintenance Rule Conduct Manual has lead to a failure to monitor degraded equipment in an a(1) status as required. The finding affected the Mitigating Systems cornerstone and was determined to be of very low significance (Green), because the finding was a procedural compliance issue that was confirmed not to result in loss of operability or functionality; it did not result in a loss of system safety function, and did not screen as potentially risk significant due to external initiating events. This finding has a cross-cutting aspect in Human PerformanceWork Practices human error prevention techniques due to a failure to use error prevention techniques during the assessment of the failure (H.4(a))
05000456/FIN-2009005-042009Q4BraidwoodPossible Failure To Follow Stroke Time Test ProcedureThe inspectors identified a Green finding and an associated NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, related to Post Maintenance Testing (PMT). Specifically, the licensee failed to follow maintenance procedures and work instructions thus work that could have affected the operability of safety-related SX Return Isolation Valve from the Auxiliary Feed Water Diesel Heat Exchanger was completed and the system returned to operable status without completing the necessary PMT. On November 12, 2009, following the completion of the Unit 2 RFO, the licensee performed a scheduled stroke time test for Valve 2SX178 (SX Return Isolation Valve from the Auxiliary Feed Water Diesel Heat Exchanger). The stroke time exceeded the alert limit and was nearly double the expected time. Since the valve had been satisfactorily stroke time tested on October 27, 2009, the inspectors questioned why the stroke time had increased in such a short period of time. The October 27, while the unit was shut down, stroke time of the valve was scheduled to be completed in accordance with Work Order 1133366-01. The work order included two tasks. Task 1 was to perform a flowscan of the valve and Task 2 was to complete a PMT stroke time test following the flowscan. Since the process of performing a flowscan can affect the time it takes for a valve to stroke, it is necessary to verify stroke times after completion of the flowscan. Specifically, Procedure MA-AA-716-012, Post Maintenance Testing, Revision 11, requires that a PMT shall be performed following any corrective and some preventive maintenance activities on plant equipment that may have impacted the equipments ability to perform its intended function. During the review of this matter, the inspectors noted the following three issues: 1. Task 1 of Work Order 1133366-01, the flowscan, was completed on October 28 and Task 2 of the Work Order, the stroke time test, was completed on October 27. Therefore, the PMT was not performed following completion of an work activity as required by Procedure MA-AA-716-012. 2. The stroke time test procedure had previously been modified due to a temporary modification that changed the valve opening logic. Maintenance performed during the RFO, prior to completion of WO 1133366-01, eliminated the need for the temporary modification. The temporary modification was removed on October 14, 2009, but the procedure for stroke time testing the 2SX178 valve was not revised. Therefore, the test procedure used on October 27 and initially on November 12 was not appropriate for the plant configuration after the temporary modification was removed. Furthermore, this was the reason for the test results of a stroke time in excess of the alert limit, as was found on November 12. 3. The test procedure in place on October 27 was not appropriate for the plant configuration after the temporary modification was removed. If followed properly, it should have resulted in a stroke time in excess of the alert limit, as was found on November 12. Therefore, the licensee apparently did not follow the stroke time test procedure during the RFO. Once discovered, the licensee revised the stroke time test procedure and re-performed the test satisfactorily. At the completion of the inspection period, the licensee was performing an Apparent Cause Evaluation to determine why the procedure was not revised and how operators used the procedure to time the valve stroke on October 27. Pending on the review of the licensees evaluation, the issue related to not following the stroke time test procedure is considered an URI. (URI 05000457/2009005-04
05000305/FIN-2009004-022009Q3KewauneeContainment Isolation Valve Inoperable with No Technical Specification Action Requirement EntryA finding of very low safety significance and associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified by the inspectors for the licensees failure to have adequate procedures that ensured technical specifications were entered and followed for containment isolation valves. The licensee entered the issue into their corrective action program as CR344856 and CR350526A, and provided additional guidance to operations personnel. At the end of the inspection period, the licensee continued to perform a causal analysis. The inspectors determined that the issue was more than minor because the finding, if left uncorrected, would become a more significant safety concern. Specifically, not entering the appropriate technical specification action requirements, when necessary, would lead to more significant safety concerns. The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of findings, Table 4a for the Barrier Integrity Cornerstone. The inspectors answered no to the Barrier Integrity questions and screened the finding as having very low safety significance (Green). The finding has a cross-cutting aspect in the area of human performance, resources, because the licensee did not have complete, accurate and up-to-date design documentation, procedures and work packages (H.2(c))
05000305/FIN-2009004-032009Q3KewauneeFailure to Adequately Analyze the Automatic Fast Transfer Feature That Allowed Operation with Both 4 Kv SAFETY-RELATED Buses 1-5 and 1-6 Connected to the RatA finding of very low safety-significance and associated NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, was identified by the inspectors for the failure to perform a power system analysis calculation that would have identified that the fast transfer design feature/scheme was deficient, in that, it allowed an unanalyzed electrical power system alignment where both redundant 4.16-kiloVolt safety-related buses were being supplied by an offsite source via the same transformer. Use of this electrical configuration could have resulted in an out-of-phase transfer, loss of available offsite power to the buses and potential damaging effects on redundant safety-related equipment, during a design basis event such as initiation of safety injection signal. When identified, the licensee entered this issue into their corrective action program and implemented interim actions to prohibit use of the fast transfer feature or manually aligning two safety-related buses to be fed from the same transformer during plant operation. This performance deficiency was more than minor because the failure to perform the required calculation resulted in a condition where the plant was being operated in an unanalyzed configuration where there was reasonable doubt as to the operability of redundant safeguard loads; this concern resulted in issuance of a Licensee Event Report (LER) 2007-007-00 on May 21, 2007. Consequently, the potential for damage or loss of power to safety-related loads during an event could have led to unacceptable consequences. The finding screened as being of very low safety-significance (Green) for the Initiating Events Cornerstone because the finding did not contribute to both the likelihood of a reactor trip and the likelihood that mitigating equipment or functions will not be available. The inspectors did not identify a cross-cutting aspect associated with this finding because the cause of the performance deficiency was related to a historical design issue and not indicative of current licensee performance
05000456/FIN-2009004-042009Q3BraidwoodReactor Trip Due to Trip of 2C Reactor Coolant PumpAn Unresolved Item (URI) was self-revealed when, on July 30, 2009, the Unit 2 reactor experienced an automatic reactor trip from full power due to a trip of the 2C RCP. The 2C RCP tripped on overcurrent following an automatic bus transfer due to the loss of SAT 242-1 on a SPR actuation. At 8:59 p.m. on July 30, 2009, Unit 2 received a SPR actuation on SAT 242-1. As a result, the feed breakers for SAT 242-1 and SAT 242-2 opened as designed, which de-energized the 6.9 kV Busses 258 and 259. Both busses automatically transferred to UATs 241-1 and 241-2. Following the transfer of Bus 258 to UAT 241-2, the 2C RCP, which was powered by Bus 258, tripped unexpectedly on overcurrent. This resulted in a Unit 2 reactor trip due to less than four RCPs running at greater than 30 percent reactor power. The reactor trip resulted in a turbine-generator trip that caused UATs 241-1 and 241-2 to become de-energized, which in turn caused the remaining three RCPs to trip off due to loss of power to their buses. The loss of both SATs and both UATs resulted in a loss of offsite power to all Unit 2 emergency and nonemergency electrical buses. The licensee declared an Unusual Event due to a loss of offsite power greater than 15 minutes. The condition was reported to the NRC in Event Notification 45238 in accordance with 10 CFR 50.72(a)(1)(i) for declaration of the Unusual Event, 10 CFR 50.72(b)(2)(iv)(B) due to actuation of the reactor protection system while the reactor was critical, and 10 CFR 50.72(b)(3)(iv)(A) for valid actuation of the AF system. Following the reactor trip, the 2A and 2B EDGs started and loaded 4 kV safety-related Busses 241 and 242 and the 2A and 2B AF pumps started. Since nonsafety-related equipment was not powered immediately following the reactor trip, operators were unable to use steam dump valves and the condenser for normal heat removal. Therefore, the operators used a feed & bleed method of cooling and depressurizing by pumping water into the steam generators with the AF pumps and removing the steam through steam generator power operated relief valves to the atmosphere. This process continued until the afternoon of July 31, 2009, when reactor coolant system pressure was low enough to place the RH system in the shutdown cooling mode. The Unusual Event was terminated at 12:36 a.m. on August 2, 2009, when offsite power was restored to the safety-related 4 kV busses through SAT 242-2. Initial investigations by the licensee were unable to determine the cause of the SAT 242-1 SPR actuation. Though the plant normally operates with SATs 242-1 and 242-2 tied together, each is capable of powering Unit 2 alone. Therefore, the licensee manually disconnected SAT 242-1 from SAT 242-2 and started up Unit 2 using only SAT 242-2 on August 4, 2009. Unit 2 reached full power on August 6, 2009. Further investigation by the licensee included a Root Cause Evaluation focused on why the 2C RCP unexpectedly tripped and a separate apparent cause evaluation focused on why the SPR actuated on SAT 242-1. The licensee completed both investigations but new information has raised questions about the results of the root cause evaluation. At the conclusion of the inspection period, the licensee was reviewing the new information that may impact the completed Root Cause Evaluation. Pending the results of that review, this issue will remain open as an URI. (URI 05000457/2009004-04
05000305/FIN-2009004-042009Q3KewauneePotential Unreported Safety System Functional FailuresDuring a review of recent LERs for SSFFs, the inspectors identified two LERs that may also be reportable as SSFFs. These items remain open pending resolution of the inspectors questions regarding reportability. While reviewing LER 2008-001, which was reported as an unanalyzed condition, the inspectors questioned why the LER wasnt also reported as a SSFF. The LER describes a condition where during a design basis fire in the relay room, the control cabling for pressurizer PORV PR-2B was found to be vulnerable to spurious operation due to hot shorts as defined in NRC guidance and NRC endorsed NEI guidance for circuit analysis. The inspectors believed that the loss of pressure and inventory control, caused by the spurious opening of PORV PR-2B during a design basis fire, could have prevented the fulfillment of the safety function of structures or systems that are needed to shutdown the reactor and maintain it in a safe shutdown condition. The inspectors explained their observations to the licensee; however, the licensee believes that the condition did not result in a SSFF. The inspectors also reviewed LER 2009-003, which was reported as a condition prohibited by plant TSs, and questioned why the LER wasnt also reported as a SSFF. This LER describes a condition where the 1A containment spray pump could have potentially tripped during a degraded voltage condition. The licensee believes that a degraded voltage condition is an environmental condition that can be historically reviewed and determined to have not occurred. The inspectors believed the degraded voltage condition is associated with the initiating event. These items remain open pending additional information to determine if there is a performance deficiency
05000305/FIN-2009004-012009Q3KewauneeTechnical Specification Action Requirements During a Leak in a Containment Fan Coil Unit Service Water LineThe inspectors identified that the licensee responded differently for two similar CFCU leaks and were concerned that the licensee was in a condition prohibited by TSs during an August 15, 2008, CFCU service water leak. The inspectors identified that the licensee entered TS action requirement 3.0.c, standard shutdown sequence, for a leak inside containment on a CFCU service water line on September 13, 2009. The inspectors reviewed a similar leak that occurred on August 15, 2008, and found that the licensee did not enter the same TS action requirement for that leak. The inspectors asked the licensee to explain the different responses to the two events and the licensee was still evaluating the issue at the conclusion of the inspection period. This issue is unresolved pending additional information required to determine if there is a performance deficiency
05000454/FIN-2009004-032009Q3ByronInadequate Evaluation of Seismic Restraint on the FHB Crane TrolleyA finding of very low safety-significance and associated Non-Cited Violation (NCV) of 10 CFR Part 50, Appendix B, Criterion III, Design Control, was identified by the inspectors for failure to perform an adequate evaluation of seismic restraint on the Fuel Handling Building (FHB) crane trolley. Specifically, for evaluation of the seismic restraint in their single failure proof trolley analysis, the licensee failed to use adequate seismic acceleration values and failed to evaluate the connections for resulting reaction forces. Subsequent review found that the restraint was inadequate. The licensee documented the condition in Issue Report (IR) 934467 and initiated actions for calculation revision and installation of a field modification. The inspectors determined that the failure to perform an adequate analysis for the seismic restraint and its connections for seismic loads was contrary to American Society of Mechanical Engineers (ASME) NOG-1-2004, requirements and was a performance deficiency. The FHB crane is designed to Seismic Category I requirements and the licensee used compliance with ASME NOG-1-2004, as the design basis for their upgrade to a single failure proof crane. The finding was more than minor because it was associated with the Initiating Events cornerstone attribute of Equipment Performance, Refueling/Fuel Handling equipment, and affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. The inspectors evaluated the finding using IMC 0609.04, Phase 1 - Initial Screening and Characterization of Findings, and based on a No answer to all the questions in the Initiating Events column of Table 4a, determined the finding to be of very low safety-significance (Green). This finding has a cross-cutting aspect in the area of Human Performance, Work Practices (H.4(c)) because the licensee did not provide adequate oversight of work activities, including contractors, such that nuclear safety is supported
05000305/FIN-2009004-072009Q3KewauneeLicensee-Identified ViolationTechnical Specification 6.4 states: A training and retraining program for the Plant Staff shall be maintained and shall meet or exceed the requirements and recommendations of Section 5.5 of ANSI-18.1-1971 and 10 CFR Part 55. General Nuclear Procedure GNP-13.03.01 Revision 23 Conduct of Training implements these requirements. This procedure identifies that trainees are responsible for ensuring personal qualifications are current to independently perform assigned work. Contrary to the above, on July 16, 2008, a lead chemistry technician independently performed an activity without having met the requisite qualification. Specifically, the individual completed a radiological liquid waste release discharge permit after his qualification for performing the activity was revoked during the periodic re-qualification program on July 16, 2008. Based on an Office of Investigations investigation; Case No. 3-2008-027, the NRC staff concluded that a lead chemistry technician deliberately violated the training requirements by completing a radiological liquid waste release discharge permit knowing that his qualifications were not current. The violation was categorized as a Severity Level IV violation because: 1) the violation had limited actual radiological significance and low potential significance; 2) the violation involved the acts of a low-level individual; 3) the violation resulted from an isolated action without management involvement; 4) there was no economic or other advantage gained as a result of the violation; and 5) adequate remedial action was taken by the licensee. Because the violation is of very low safety significance, it meets the additional criteria in Section VI.A.1 of the NRC Enforcement Policy, and because it has been entered into the corrective action system (CR103866) it is being treated, after consultation with the Director, Office of Enforcement, as an NCV
05000373/FIN-2009004-012009Q3LaSalleFailure to Decalre SBLC System Inoperable During Surveillance TestingThe inspectors identified a finding of very low safety significance and an associated NCV of Technical Specification (TS) 5.4.1, Procedures, for the failure to provide adequate procedural guidance to operations personnel when performing the quarterly SBLC operability test on unit 2. Specifically, operations personnel performingLOS-SC-Q1, SBLC pump operability test, did not posses appropriate procedural guidance while performing this test and, as a result, did not declare both trains for the Standby Liquid Control (SBLC) system inoperable and did not enter the associated limiting condition for operation (LCO) action statements as required per TSs. The inspectors determined that the finding was more than minor because it was associated with the procedure quality attribute of the Mitigating Systems Cornerstone, and it affected the cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, operations personnel would not have been able to return SBLC to a standby configuration if needed in case of an anticipated transient without a scram (ATWS) in 120 seconds as required by the design basis. The finding was determined to be of very low safety significance using the SDP Phase 2. This finding was also related to the cross-cutting area of Human Performance (resources) because the procedure used for this evolution was inaccurate in that it provided improper guidance to maintain SBLC operability provided that a dedicated operator was briefed and stationed locally. The licensee entered this issue into the corrective action program. Corrective actions taken by the licensee included the future revision of procedure LOS-SC-Q1 to remove the statement that indicates that the system can be maintained operable during the surveillance and to include an emergency restoration attachment with steps to quickly return the system to its standby configuration if required in case of an ATWS.
05000454/FIN-2009004-022009Q3ByronDiesel Oil Storage Vents Not Seismically Qualified or Tornado ResistantA finding of very low safety significance and associated NCV of 10 CFR 50, Appendix A, Criterion 2, Design Basis for Protection Against Natural Phenomena, and Criterion 4, Environmental and Natural Effects Design Bases, was identified by the inspectors for the failure to seismically support and protect the Emergency Diesel Generator (EDG) fuel oil storage tank vent lines from tornado generated missiles. Specifically, the licensee installed the vent lines as non-safety related and as such they were not seismically supported nor protected from tornado generated missiles. In response to the issue, the licensee performed an operability determination and concluded that the EDGs remained operable. This performance deficiency was more than minor because it was associated with the Mitigating Systems Cornerstone attribute of equipment performance and adversely affected the cornerstone objective of ensuring availability of the EDG to respond to initiating events to prevent undesirable consequences. This finding was of very low safety significance (Green) because the inspectors determined that the finding was a design deficiency confirmed not to result in loss of operability or functionality and the finding screened as Green using the Significance Determination Process Phase 1 screening worksheet. The inspectors did not identify a cross-cutting aspect associated with this finding because the performance deficiency occurred over 30 years ago and was not current.
05000305/FIN-2009004-062009Q3KewauneeFailure to Follow ISFSI Loading Procedure StepThe inspectors identified a Severity Level IV NCV of 10 CFR 72.150, Instructions, Procedures, and Drawings, during the Independent Spent Fuel Storage Installation loading campaign. The licensee failed to follow procedure OP-KW-NOP-ISF-001, Dry Shielded Canister Loading. The inspectors determined that the licensees failure to follow step 5.2.6 of Procedure OP-KW-NOP-ISF-001 to perform a crane brake check was contrary to 10 CFR 72.150. The licensee immediately evaluated the situation and discussed the need to check the crane brakes when lifting loads approaching the rated loads with the refueling crew to prevent missing this step in the future. The inspectors determined that the violation had more than minor safety significance because the failure to check the crane brakes, results in not knowing if the brakes are functioning properly, which may lead to a failure of the brakes while lifting a loaded spent fuel canister. The issue was addressed by traditional enforcement since 10 CFR Part 72 is not risk based and is not covered under the reactor oversight process. Because this violation was of very low safety significance, was non-repetitive and non-willful, and was entered into the corrective action program, this violation is being treated as a NCV of 10 CFR 72.150 consistent with Section VI.A.1 of the Enforcement Policy. The inspectors determined that there was no cross-cutting aspect associated with this finding
05000373/FIN-2009004-022009Q3LaSalleFailure to Make Required Non-Emergency 50.72 Notification to NRC Following Loss of Shutdown CoolingThe inspectors identified a Green (Severity Level IV) NCV of10 CFR 50.72 (b)(3)(v) for the licensees failure to make a required non-emergency eight-hour notification to the NRC for a loss of safety function of a system which was required to remove residual heat from the reactor. The licensee entered this issue into their CAP as IR 971982.The inspectors determined that the finding should be evaluated using the traditional enforcement process, since the failure to make a required report to the NRC had the potential to impact the agencys ability to perform its regulatory function. The finding was considered to be Severity Level IV, as the NRC Enforcement Policy states, in part, that the severity level of a violation involving the failure to make a required report to the NRC will be based upon the significance of and the circumstances surrounding the matter that should have been reported. As such, the ability of the operators to restore a train of the residual heat removal (RHR) system by non-extraordinary means and in a timely manner (without experiencing an unplanned mode change) to a shutdown cooling lineup was considered by the inspectors to have mitigated the effects of the loss of functionality of the decay heat removal system to a very low safety impact on the plant.
05000454/FIN-2009004-052009Q3ByronUnresolved Technical Concerns on Design of Seismic Restraint on FHB Crane TrolleyA URI was identified by the inspectors for their incomplete review of the design documents related to the FHB crane upgrade to single failure proof. Specifically, not all of the licensees design and modification documents required to complete the inspection were complete at the conclusion of the inspection. The licensee performed the following calculations to demonstrate that the crane trolley seismic design is in accordance with ASME NOG-1-2004. 36272-02; Exelon/Byron and Braidwood Hoist Reeving Equipment Calculation; 36272-12; Exelon/Byron and Braidwood Single Failure Proof Trolley Seismic Analysis; 36272-13; Exelon/Byron and Braidwood Single Failure Proof Trolley Critical Weld Calculations; and 36272-17; Exelon/Byron and Braidwood Single Failure Proof Trolley Misc. Item Seismic Analysis. At conclusion of the inspections, the licensee had not completed all the necessary design activities and there were open technical concerns regarding adequacy of the seismic restraint evaluated in Calculation 36272-12 as described in Section 4OA5.1.b(1), Inadequate Seismic Restraint on Fuel Handling Building Crane Trolley. In addition, resolution of the open technical concern regarding use of friction to limit seismic loads, as described in Section 4OA5.1.b (2), Use of Friction in Seismic Analysis..., may impact some of the above calculations. All revised calculations from those listed above and any new design documents including calculations and modifications issued to resolve these technical concerns will need to be reviewed. This issue will be a URI pending the inspectors reviews of the licensees design documents demonstrating resolution of the technical concerns identified during the inspection (URI 05000454/2009004-05; 05000455/2009004-05)
05000305/FIN-2009004-052009Q3KewauneeInadequate Design Analysis for 105-ton Transfer Cask-Lifting BeamA finding of very low safety significance and associated NCV of Title 10 Code of Federal Regulations (CFR) Part 50, Appendix B, Criterion III, Design Control, was identified by the inspectors for the licensees failure to provide an adequate single failure proof design basis analysis for the 105-ton transfer cask-lifting beam. The licensee entered this issue into their corrective action program as condition report CR339267. The licensee revised the design calculation for the 105-ton transfer cask-lifting beam and demonstrated compliance with single failure proof acceptance criteria. The finding was determined to be more than minor because the finding was associated with the Initiating Events Cornerstone attribute of equipment performance and adversely affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. The finding was determined to be of very low safety significance by the NRCs significance determination process because the transfer cask-lifting beam had not been previously used at the Kewaunee Power Station. This finding has a crosscutting aspect in the area of human performance, work practices, because the licensee did not ensure supervisory and management oversight of work activities, including contractors, such that nuclear safety is supported, in that, the licensee failed to perform an effective owners review to assure that appropriate design methods are used in calculations that demonstrate nuclear safety (H.4(c))
05000373/FIN-2009004-032009Q3LaSalleReactor Scram During Turbine TestingThe inspectors identified a finding of very low safety significance for the licensee failing to recognize that an existing alarm condition in the unit 2 digital electro-hydraulic control system (DEHC) trip logic would result in a turbine trip and subsequent reactors cram when weekly turbine trip testing was performed. The licensee entered this issue into its corrective action program (CAP) as issue report (IR) 953784.The finding was greater than minor because it affected the initiating events objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during power operations and was associated with the cornerstone attribute of Configuration Control. The inspectors determined that the finding was Green, or of very low safety significance, by answering no to the IMC 0609 Phase 1 Screening Worksheet question Does the finding contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions will not be available? The finding had across-cutting aspect in the area of Human Performance (resources) in that the sites design documentation was not complete and accurate with regards to the necessary ramifications of a control module communications failure (H.2(c)).
05000373/FIN-2009004-042009Q3LaSalleLicensee-Identified ViolationTechnical Specification 5.2.2.d requires that procedures be established, implemented, and maintained covering the control of plant staff overtime, to limit the work hours worked by staff performing safety-related functions in accordance with the NRC Policy Statement on working hours (NRC GL 82-12). The NRCs GL 82-12, Nuclear Power Plant Staff Working Hours specifies in part that guidelines should be followed that limit individuals to working no more than 72 hours in any 7-day period. Recognizing that very unusual circumstance may arise, requiring deviation from this guideline, such deviation shall be authorized by the plant manager or his deputy, or higher levels of management. Contrary to this requirement, from September 16through September 18, 2009, an IMD technician worked 8 hours over the 72-hourlimit in any 7-day period without prior plant management authorization. This was identified in the licensees CAP as IR 969479. This finding is of very low safety significance because no human performance issues or significant events were directly linked to personnel fatigued as a result of the hours worked.
05000454/FIN-2009004-062009Q3ByronLicensee-Identified ViolationTechnical Specification 5.7.1.b states that any individual permitted to enter high radiation areas shall be provided with or accompanied by a radiation monitoring device that continuously integrates the radiation dose rate in the area and alarms when a preset integrated dose is received. Contrary to this, a worker entered Area Five, a posted high radiation area (HRA) area to perform boric acid cleaning on a valve, left his electronic dosimeter (ED) on the bench during a dress-out process. The worker worked in the HRA area for approximately 15 minutes without the ED radiation monitoring device. The worker was identified and escorted out of the radiological controlled are (RCA). This event was entered into the licensees Corrective Action Program as IR 966917. The RP department immediately took control by escorting the worker from the RCA and removed worker RCA access pending investigation. The licensee conducted a human performance investigation on this event. The issue is of very low safety significance because it did not involve ALARA planning or work controls, an overexposure, substantial potential for overexposure, or limit the ability to assess radiation dose.
05000454/FIN-2009004-042009Q3ByronUse of Friction in Design of FHB Crane to Single Failure ProofAn URI was identified by the inspectors for the licensees use of friction in their seismic analysis methodology that may not be consistent with the design requirements of ASME NOG-1-2004. Specifically, in the seismic analysis of the FHB trolley and components, the licensee used friction force developed at the trolley wheel/rail interface to reduce the horizontal seismic loads applied to the trolley components. Since Table 4154.3-1 of ASME NOG-1-2004 specifies analytical boundary conditions that would prevent sliding between the trolley and the rails, the licensees use of friction is contrary to the requirements of the ASME NOG-1-2004 Rules for Construction of Overhead and Gantry Cranes. The NRC staff is currently reviewing the appropriateness of the licensees application of friction with respect to the design requirements specified in ASME NOG-1-2004. Seismic evaluations of the new single failure proof crane trolley and its components are included in Calculations 36272-02, 36272-12, 36272-13, and 36272-17. The inspectors identified that for evaluation of trolley components in Calculation 36272-17, instead of using seismic loads based on accelerations obtained from the crane dynamic analysis performed in accordance with ASME NOG-1-2004, the licensee used much smaller loads limited by the frictional force at the rail surface. This resulted in a significant load reduction for qualification of the trolley components, and is contrary to the ASME NOG-1-2004, requirements for the boundary conditions to be used in dynamic analysis model. The use of friction was first identified during review of calculations at Exelons LaSalle County Station and is currently being reviewed by the inspectors and NRR staff. The issue is captured in IR 957014 for LaSalle. The licensee subsequently issued IR 966184 for addressing the impact at Byron. Per IR 966184, the license identified that Calculations 36272-12 and 36272-17 utilized friction and the licensee is in the process of revising these and any other affected calculations to remove the use of friction methodology. All revised calculations issued to resolve this concern need to be reviewed. Note that since the licensee has decided to revise the affected calculation, the NRC review may be performed as part of the URI described in Section 4AO5.1.b(3), Review of FHB Crane Trolley Upgrade Design Document Not Completed. This issue will be a URI pending the inspectors reviews of the licensees resolution of the use of friction in their design of structures and components in the upgrade of the FHB crane to single failure proof (URI 005000454/2009004-04; 05000455/2009004-04)
05000454/FIN-2009004-012009Q3ByronAssigning appropriate 10 CFR 61 waste stream to radioactive waste shipmentsAssigning appropriate 10 CFR 61 waste stream to radioactive waste shipment The inspector identified an Unresolved Item (URI) associated with the licensees characterization of the quantities and types of radionuclides in selected shipments. The inspectors reviewed several shipments that occurred at the end of 2007 and beginning of 2008. Based on the initial assessment by the inspectors, there appeared to be discrepancies with radionuclide activities reported on the shipping manifests and the associated 10 CFR Part 61 analysis for the most appropriate waste stream for the contents of the shipments. The discrepancy could not be immediately resolved by the licensee. Therefore, the inspectors could not evaluate whether the packages were correctly characterized for shipment and ultimate burial. Consequently, this issue remains under review by the NRC to determine if it represents a performance deficiency and is categorized as an URI (URI 05000454/2009004-01; 05000455/2009004-01)
05000305/FIN-2009003-012009Q2KewauneeEmergency Diesel Generator Fuel Oil Storage and Day Tank Vent Line Tornado QualificationThe inspectors identified an unresolved item (URI) relating to the tornado missile qualification of the EDG fuel oil storage and day tank vent lines. During a high wind/tornado seasonal readiness preparations inspection, the inspectors found that the EDG fuel oil storage and day tanks were not missile protected as required by the licensees USAR. The inspectors reviewed the licensees operability evaluation for the vent lines and found that the licensee was using the TORMIS methodology to justify operability until it completed a modification to correct the deficiency. The TORMIS methodology was a probabilistic approach and the inspectors questioned why it was allowable to use this method without an amendment because Regulatory Issue Summary (RIS) 2005-20, Revision to NRC Inspection Manual Part9900 Technical Guidance, Operability Determinations & Functionality Assessments for Resolution of Degraded or Nonconforming Conditions Adverse to Quality or Safety, specifically stated that probability could not be used to justify operability. The licensee believed that TORMIS could be used as an alternative analytical methodology because the NRC documented the acceptability of the method in the NRC Safety Evaluation of October 26, 1983. The inspectors reviewed the 1983 safety evaluation, and RIS 2008-14, Use of TORMIS Computer Code for Assessment of Tornado Missile Protection. Regulatory Issue Summary 2008-14 stated that the initial use of TORMIS methodology required a license amendment, but did not discuss the use of TORMIS inoperability. This issue is considered unresolved pending an agency decision on whether the use of the TORMIS methodology is appropriate in operability evaluations without having a specific amendment for the use of TORMIS (URI 05000305/2009003-01)
05000454/FIN-2009003-022009Q2ByronDiesel Oil Storage Tank Vent Regulatory Compliance Backfit May be RequiredThe inspectors noted that the diesel oil storage tank (DOST) vent piping was non-safety related and was located in a non-safety related structure. Subsequent inspector questions focused on the DOSTs ability to vent if the vent lines were crimped during a seismic or tornado generated missile event. During the course of the inspection, the inspectors ascertained that in the associated amendments and Supplemental Safety Evaluation Reports of the early 1980s, the NRC reviewers position was that the vents needed to be seismic and missile protected. Subsequent to that time, communications between the licensee and the NRC resulted in the NRC reviewers accepting the licensees design where the vent lines were routed through the Category II turbine building. However, the reviewers basis was that the licensee had committed to make the vent lines seismically supported, that the licensee had stated that the vent lines would break before crimping, that there were alternate vent paths and that the lines were designed in accordance with ANSI B31.1 piping standards. The NRC inspectors determined that the lines were not modified to be seismically supported and that there were no calculations supporting the break before crimp position. Piping experts consulted by the licensee also indicated that the lines would crimp before breaking. Although alternate vent paths do exist, there was no instrumentation that would alert the plant operators to a need for the alternate vent paths prior to diesel generator operability impact. There were also no procedures, training, or tools needed by the operators to establish the alternate vent paths. A more detailed review of the docket by the inspectors and the licensee determined that there was no actual submittal by the licensee stating they would upgrade the vent paths to seismic grade and the source of the NRC reviewers comment could not be located. The licensee initiated IR 877430 and performed a prompt operability determination. The licensee concluded that the diesel oil storage tanks and the diesel generators remained operable, but degraded in the installed configuration specifically that the NRC reviewers basis for accepting this changes from the design requirements was not valid. The inspectors reviewed the operability determination with no issues identified regarding operability. However, this issue will remain unresolved pending further review of the installed configuration and assessment of 10 CFR 50.109(a)(4) to determine if a modification is necessary to bring the facility into compliance with the rules or orders of the Commission
05000263/FIN-2009003-032009Q2MonticelloLicensee-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 SSCs to which this appendix applies are correctly translated into specific drawings, procedures, and instructions. Contrary to this requirement, the licensee failed to control the design of the facility to prevent two separate operational vulnerabilities to the Division II essential service water system from HELB related events. The finding was determined to be of very low safety significance primarily because the issue was determined to not result in the loss of the safety function for essential service water
05000263/FIN-2009003-022009Q2MonticelloLicensee-Identified ViolationTechnical Specification 5.7.1.a requires that each entryway to a HRA be barricaded and conspicuously posted, except as necessary to permit entry or exit. On February 21, 2009, a RP technician erected a HRA rope barricade with postings located in the condensate demineralizer area at elevation 951 of the turbine building. The technician failed to follow detailed rope barrier installation and inadequately established the area. On the following morning, the rope barricade and the attached postings were found on the floor and; therefore, did not constitute an adequate barricade or posting for the area. This was identified in the licensees CAP as AR 01170392. The finding was determined to be of very low safety significance because it was not an ALARA planning issue; there was no overexposure; and the licensees ability to access dose was not compromised.
05000263/FIN-2009003-012009Q2MonticelloFailure to Comply with Technical Specification and RWP Requirements during Work in a Locked High Radiation AreaA self-revealed finding of very low safety significance and an associated non-cited violation (NCV) of Technical Specification 5.7.1.b was identified for the failure to comply with the requirements of the radiation work permit during ultrasonic testing preparations in the condenser hot side, an area posted as a locked high radiation area, on January 2, 2009. Specifically, a mechanical maintenance worker was directed by the outage control center staff to leave his assigned work area and to investigate a leak near the D moisture separator. The worker was briefed on the high radiation area conditions at the ultrasonic testing preparation area; however, the individual was not briefed on the radiological conditions along his path to the D moisture separator. As a result, the worker encountered radiation levels greater than those anticipated and received a dose rate alarm on his electronic dosimeter. The licensees corrective actions included counseling of the involved workers and conducting a stand-down with the operations department to reinforce radiological requirements and communication expectations. A radiation protection liaison was also assigned to the outage control center for the remainder of the down-power to ensure that work assignments were coordinated with the appropriate supervisor, rather than interfacing directly with the worker. The licensee had completed an apparent cause evaluation to formulate additional actions to prevent recurrence. The finding was more than minor because it impacted the program and process attribute of the Occupational Radiation Safety Cornerstone and affected the cornerstone objective of ensuring adequate protection of worker health and safety from exposure to radiation; in that, access into high radiation areas whose radiological conditions were unknown placed the worker at risk for unnecessary radiation exposure. The finding was determined to be of very low safety significance because it was not an as-low-as-is-reasonably-achievable (ALARA) planning issue; there was no overexposure or substantial potential for an overexposure; and the licensees ability to assess worker dose was not compromised. The finding involved a cross-cutting aspect in the area of human performance related to work practices; in that, radiation work permit compliance for access into D moisture separator areas was not effectively communicated to the worker, and the worker failed to follow the radiation work permit.
05000454/FIN-2009007-032009Q1ByronConcerns with Licensee\\\'s Margin to Overfill (MTO) Analysis Related to Steam Generator Tube Rupture (SGTR) Event.The inspectors identified an unresolved item (URI) related to the licensees evaluation of potential failures of the steam generator power operated relief valves (SG PORVs) during a postulated steam generator tube rupture (SGTR) event. Specifically, the licensees margin to overfill (MTO) analysis was based on the failure of a single SG PORV to open and did not consider the potential failure of two valves to open due to a common electrical system failure (most limiting single failure). The inspectors reviewed the function on the SG PORVs during a postulated SGTR event. After a SGTR the operators open the SG PORVs associated with the intact steam generators to cooldown and depressurize the reactor coolant system. This operation would be time critical to prevent overfilling the ruptured steam generator and allowing liquid to enter the steam piping. The licensees SGTR accident analysis was based on the single failure of one SG PORV to open when required; this was consistent with UFSAR Section 15.6.3 and Table 15.0-15. Failure of one SG PORV would enable operators to cooldown the reactor coolant system using the remaining two SG PORVs. However, these electric/hydraulic valves require 480V power to operate. The four SG PORVs (MS018A-D) are powered from two redundant 480V electrical busses. Each bus provides power to two SG PORVs. Therefore, the failure of a single electrical power supply could result in the failure of two SG PORVs to operate. The inspectors questioned if the single failure assumptions used in the SGTR MTO analysis were in accordance with the Byron licensing basis. In response to this concern, the licensee stated that this question had been previously addressed in detail and provided several corrective action documents that addressed the function of the SG PORVs during a SGTR event. The inspectors reviewed the following related corrective action documents: Issued Report (IR) 00680419 (initiated October 5, 2007), addressed local operator actions to open the SG PORVs after a SGTR. This IR questioned if the operators would be able to manually open the PORVs in the times assumed by the accident analysis. This IR identified that the single failure of one 480V bus would be more limiting than the loss of the entire 4kV electrical bus because all the ECCS pumps would continue to operate if only one 480V bus was lost. The loss of one 480V bus could result in the failure of two SG PORVs to open. The AR referred to a similar issue at Catawba Station, identified in 1997, which resulted in a LER. IR 00687783 (initiated October 22, 2007), addressed similar concerns to IR 00680419. A detailed licensing basis evaluation was performed to address these concerns in IR 00687783. This IR included an evaluation of the Byron current licensing basis (CLB) regarding postulated single failures. The IR evaluation stated, in part, The conclusion drawn from the review is that for the design basis SGTR event, when the phrase single failure is used, its meaning is restricted to only single active failures and is not intended to convey all types of potential failures (i.e., passive and active). IR 00706293 (initiated December 2, 2007), addressed various SGTR issues, including the MTO single failure concerns that were previously addressed by IR 00680419 and IR 00687783. Action AR 00706293-05 was initiated to perform a third party review of the SGTR single failure criteria. The independent review was completed on December 17, 2007. This review addressed the issue of passive verses active single failure, including an extensive review of regulatory requirements. The report stated, in part, With regard to the semantics of single failure vs. active single failure, there was nothing in the licensing history reviewed that specifically said passive failures do not need to be considered. Action AR 00713904 (initiated December 19, 2007), addressed the specific recommendations of the independent review report. The conclusions of this internal review did not agree with those of the independent reviewer (AR 00706293-05). The AR 00713904 re-review concluded that a passive single failure of electrical components did not need to be considered for the SGTR MTO accident analysis. This review addresses the apparent contradiction between the GDC and Chapter 15 of the SRP. Action AR 00713904-04 stated, in part, The SRP on accident analyses and the GDC were prepared for different purposes. The GDC set forth a conservative set of rules for design that are intended to achieve defense in depth. The performance objectives of the GDC are high-level goals relating to the health and safety of the public. The SRP on accident analysis provides specific direction regarding the methodology, assumptions, and acceptance criteria for detailed analysis of accidents and Anticipated Operational Occurrences (AOOs). For some accidents, the SRP may establish additional intermediate-level acceptance criteria at a lower level than the high level performance objectives of the GDC. It may be possible for a plant design to meet the high level performance objectives of the GDC for a broad spectrum of initiating events and failures (including multiple failures); but the ability to meet specific acceptance criteria in accident analysis may be contingent on the specific assumptions made (the SRP acceptance criteria was established with a specific set of assumptions in mind.) The review then addressed the question of why it was acceptable not to analyze for passive failures. The response to that question stated, The underlying technical basis for the SRPs approach to accident analysis is based on risk assessment methodology. Condition IV and other accident events have a very low frequency of occurrence. When combined with an additional random single active failure, the probability of the event combination is even lower (e.g., Condition IV events with two random active failures) would not add significant value in improving safety, and therefore is not required. A similar argument can be made for the combination of accidents with random passive failures. Finally, the review included a risk-based argument, which addressed how the above discussion related to the licensing of the SGTR accident analysis. This portion on the review includes a discussion of compliance with GDC 17, which states that the electrical system design meets the GDC 17 criteria but also includes the statement, GDC 17 does not address the intermediate-level acceptance criteria for the SGTR accident analysis of preventing overfill of the ruptured SG. For the SGTR the high-level performance objective of the GDC is met, with or without SG overfill; and, therefore, one need not distinguish between active and passive failures. The inspectors noted that the Byron licensing basis for SGTR events was based on the generic Westinghouse analysis. The Westinghouse SGTR analysis (WCAP-10698) was based on a three-loop reference plant and the failure of a single SG PORV to open but did not specifically address electrical bus failures. In the single failure evaluation section, the WCAP stated, common mode failures of all steam generator PORVs were not evaluated since electrical power and air supplies to the PORVs are largely plant specific... The associated NRC evaluation (dated March 30, 1987), concluded that the WCAP analysis methodology was conservative, but pointed out that there may be major design differences between plants and required plant specific information. Section D.5 of the NRC evaluation required the following plant specific information, A survey of plant primary and balance-of-plant systems design to determine the compatibility with the bounding plant analysis in WCAP-10698. Major design differences should be noted. The worst single failure should be identified if different from the WCAP-10698 analysis and the effect of the difference on the margin of overfill should be provided. In response to the NRC, the licensee provided the required plant specific information (Commonwealth Edison letter, dated April 25, 1990). This letter included revision 1 of the SGTR analysis for the Byron and Braidwood plants. The analysis stated, in part, The compatibility of the Byron/Braidwood systems with the WCAP-10698-P-A bounding plant analysis has been evaluated and no major design differences affecting the MTO exist. The same limiting single failures as identified in WCAP-10698-P-A and Supplement 1 of WCAP-10698-P-A were utilized in the analysis... The NRCs evaluation of the Byron/Braidwood plant specific SGTR analysis (NRC letter dated April 23, 1992) included a statement that the licensee had responded satisfactorily to this confirmatory issue. Based on review of these corrective action documents, review of available Byron licensing documentation, and extensive discussions with Byron personnel, the inspectors were concerned that the licensee did not correctly evaluate the potential failure of the steam generator power operated relief valves (SG PORVs) during a postulated steam generator tube rupture (SGTR) event. The application of the single failure criteria is addressed in 10 CFR 50, Appendix A, the definition of single failure states: A single failure means an occurrence which results in the loss of capability of a component to perform its intended safety functions. Multiple failures resulting from a single occurrence are considered to be a single failure. Fluid and electric systems are considered to be designed against an assumed single failure if neither: (1) a single failure of any active component (assuming passive components function properly); nor (2) a single failure of a passive component (assuming active components function properly), results in a loss of the capability of the system to perform its safety functions.2 2 Single failures of passive components in electric systems should be assumed in designing against a single failure. The conditions under which a single failure of a passive component in a fluid system should be considered in designing the system against a single failure are under development. This definition of single failure clearly states that single failures of passive components in electric systems should be assumed in designing against a single component failure. Based on this, it did not appear valid to make a distinction between active and passive failures of electrical components in accident analyses. In addition, 10 CFR 50, Appendix A, GDC 17, states, in part: An onsite electric power system and an offsite electric power system shall be provided to permit functioning of structures, systems, and components important to safety. The safety function for each system (assuming the other system is not functioning) shall be to provide sufficient capacity and capability to assure that: (1) specified acceptable fuel design limits and design conditions of the reactor coolant pressure boundary are not exceeded as a result of anticipated operational occurrences; and (2) the core is cooled and containment integrity and other vital functions are maintained in the event of postulated accidents. The onsite electric power supplies, including the batteries, and the onsite electric distribution system, shall have sufficient independence, redundancy, and testability to perform their safety functions assuming a single failure... The inspectors were concerned that the licensees position that GDC 17 does not address the intermediate-level acceptance criteria for the SGTR accident analysis of reventing overfill of the ruptured SG was not correct. The GDC 17 stated that onsite electric power supplies shall have sufficient independence, redundancy, and testability to perform their safety functions assuming a single failure. In accordance with the Byron licensing basis, preventing overfill of the ruptured steam generator was a safety function of the onsite electric power supply. Because the operator response time would not be adequate to locally open the SG PORVs after a SGTR event, the onsite electric power supply must be capable of performing that safety function, assuming a single failure (either active or passive). The licensee initiated IR 00897354 on March 25, 2009, to document the NRCs position on this issue; this IR stated that some mitigating actions would be initiated and stated that a new IR would be written upon formal receipt of NRCs position. The IR 00897354 did not include corrective actions to address the licensees single failure assumptions. The licensee also referred the inspectors to guidance included in NRC NUREG/CR 4893, dated May 1991. The inspectors reviewed the NUREG and noted that it discussed the assumption of worst single active failures in the analysis of SGTR events. However, the NUREG did not specifically address electrical failures and it was not clear if the reference to single active failures was applicable to electrical failures or just to fluid system failures. In addition, the inspectors reviewed the applicability of unresolved item (URI) 05000454/2005002-06; 05000455/2005002-06 to this issue. As documented in NRC Inspection Report 05000454/2008008; 05000455/2008008 (dated May 5, 2008), the NRC determined that Byron was required to consider the passive failure of electrical components in the power supplies to essential service water cooling tower fans. This determination was based, in part, on the requirements of 10 CFR 50, Appendix A. The NRC determined that the provisions of 10 CFR 50.109(a)(4) were applicable, in that, a modification was necessary to bring the facility into compliance with the rules and orders of the Commission. The inspectors were concerned that this licensing basis issue was very similar to the SGTR MTO analysis issue, and that Byron failed to adequately evaluate the impact of this determination on the SGTR MTO analysis. The inspectors have discussed this design and licensing basis issue with NRC staff in the Office of Nuclear Reactor Regulation. Due to complexity of establishing the appropriate design and licensing bases for this issue, this item is considered unresolved pending further NRC review (URI 05000454/455/2009007-03(DRS)).
05000263/FIN-2008003-012008Q2MonticelloLicensee Inadvertently Actuated and Reset the Standby Gas Treatment System while Conducting Routine Control Room Panel Lamp ChecksA finding of very low safety significance and NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was self-revealed when the licensee failed to operate safety significant equipment in accordance with approved operating procedures. Specifically, during the conduct of routine control room panel lamp checks, the operator inadvertently actuated the standby gas treatment system, and then improperly reset the actuation signal. The inspectors determined that the performance deficiency affected the crosscutting area of Human Performance, having decision making components, and involving aspects associated with licensed operators making safety significant decisions using a systematic process to ensure safety is maintained. (H.1(a)) The inspectors determined that the finding was more than minor because it could reasonably be viewed as a precursor to a more significant event. The finding was determined to be of very low safety significance (Green) because it only represented a degradation of the radiological barrier function provided for the reactor building and standby gas treatment system. (Section 1R13
05000263/FIN-2008003-022008Q2MonticelloLicensee-Identified ViolationTitle 10 CFR 50, Appendix B, Criterion III, Design Control, requires, in part, that measures shall be established to assure that applicable regulatory requirements and the design basis for those SSCs to which this appendix applies are correctly translated into specifications, drawings, procedures, and instructions. Contrary to this requirement, the licensees calculation of record for HELB did not model the actuation of the fire water sprinklers in the condenser room when the condenser room exceeded 165 degrees Fahrenheit during a postulated HELB. This extra liquid volume in the condenser room was enough to have exceeded the maximum allowable postulated water level at the lower 4kV switchgear room. This issue was documented in the licensees corrective action program as CAP 01125675. The finding is of very low safety significance because the HELB frequency for the Monticello plant is significantly below the level required to result in a core damage frequency (CDF) increase of 1.00 E06/year for the scenario of interest.
05000263/FIN-2008003-032008Q2MonticelloLicensee-Identified ViolationTechnical Specification 3.3.6.2, Condition B, requires, in part, restoration of secondary containment isolation capability within one hour when the Refueling Floor Radiation - High function is not maintained in Modes 1, 2, and 3; during operations with a potential for draining the reactor vessel; and, during movement of recently irradiated fuel assemblies in secondary containment. Contrary to this requirement, the licensee did not perform the required action of TS 3.3.6.2, Condition B.1, within the associated completion time on two occasions when both spent fuel pool radiation monitors were inoperable. The issue was documented in the licensees CAP. The finding is of very low safety significance because it only represented a degradation of the radiological barrier function of the reactor building/SBGT system
05000263/FIN-2008003-042008Q2MonticelloLicensee-Identified ViolationTechnical Specification 3.7.4, Condition E, requires, in part, immediate entry into limiting condition for operation (LCO) 3.0.3 when two CREF subsystems are inoperable in Modes 1, 2 and 3, for reasons other than an inoperable control room boundary. Contrary to this requirement, the licensee performed the required action of TS 3.7.4, Condition E.1, immediately on several occasions during CREF surveillance testing when both subsystems were placed in recirculation mode and automatic realignment and initiation of high radiation mode was not possible. The issue was documented in the licensees CAP. The finding is of very low safety significance because it only represented a degradation of the radiological barrier function of the control room
05000263/FIN-2008003-052008Q2MonticelloLicensee-Identified ViolationTitle 10 CFR 50.47 (b) (5) requires that means have been established for alerting the public within the plume exposure pathway and FEMA-REP-10, Guide for the Evaluation of Alert and Notification Systems for Nuclear Power Plants specifies the design requirements. Contrary to the FEMA approved Alert and Notification System (ANS) design report, an individual siren, designated as S-30, was discovered on April 4, 2007, during a stand under observation of the siren performance testing to not meet design requirements. The siren head failed to rotate while sounding. The licensee noted a similar rotation failure for the siren on July 5, 2006, but did not enter the occurrence in the CAP. In May of 2007 on further investigation, the licensee discovered the rotation had existed since installation in July of 2005 and was a result of factory incorrect wiring. The siren rotation failure was identified in the licensees CAP as AR-01090935. The finding was determined to be of very low safety significance using IMC 0609, Appendix B, Emergency Preparedness Significance Determination Process assessing the licensees current performance in problem identification and resolution
05000255/FIN-2008003-052008Q2PalisadesDiscrepancy During Movement of Transfer TrailerThe inspectors identified an issue during movement operations to the ISFSI pad from the protected area. This issue requires additional NRC evaluation and will remain unresolved pending further review. On Wednesday March 5, during the licensees ISFSI dry run, the inspectors observed an issue during the evolution of moving the transfer trailer from within the protected area to the ISFSI pad. Pending resolution by the NRC, this issue will be treated as URI-0500255/2008003-05, Discrepancy During Movement of Transfer Trailer
05000255/FIN-2008003-062008Q2Palisades1-1 EDG Fuel Header LeakThe inspectors identified a Green NCV of 10 CFR 50 Appendix B, Criteria V, Instructions, Procedures and Drawing for failure of the licensee to have documented instructions for maintenance of the 1-1 emergency diesel generator (EDG). Specifically, the licensees procedure for tightening the connection between the fuel oil header and the fuel pump did not require the fasteners to be torqued. Previous corrective action documents and operating experience demonstrated a torque was required. The fuel oil fasteners disconnected from the connection during a run of the EDG requiring engine shutdown. The licensee entered the item into the corrective action process as CR-PLP-2007-04078 and torqued all susceptible fasteners on both EDGs. The finding is more than minor because it impacts the equipment performance attribute of the Mitigating Systems cornerstone and adversely affects the objective to ensure availability, reliability and capability of the systems which respond to initiating events. Because this deficiency could have an impact on the EDG ability to adequately deliver fuel to the cylinders required in an accident, and because this condition may have existed (in some state where the bolts could loosen) for some time, the issue required a detailed assessment to evaluate the condition. The inspectors reviewed the licensees past operability assessment. The assessment concluded the EDG could reasonably perform its safety function for its required mission with some operator intervention around 24 hrs into the event. The inspectors concluded the evaluation was reasonable. Therefore, the inspectors determined the finding is of very low safety significance (Green), because the finding did not cause a loss of safety function and the item screened out in phase I of IMC 0609. The finding includes a cross-cutting aspect in the area of problem identification and resolution in that the licensee failed to communicate operating experience (OE) to the internal stakeholders in a timely manner for relevant issues (P.2(a)). (Section 4OA5
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