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05000315/FIN-2018003-022018Q3CookSite Specific Shielding and Barriers for HI-TRAC Transfer Cask Require NRC Approval Prior to UseCertificate of Compliance (CoC) 1014, Amendment 9, Design Feature, Section 3.9, Environmental Temperature Requirements, requires building ambient temperatures be less than 110 degrees Fahrenheit during canister processing based upon the thermal analysis in the Holtec HI-STORM Final Safety Analysis Report, Revision 13. The thermal model documented in the Final Safety Analysis Report, Revision 13, Section 4.5.1, HI-TRAC Thermal Model, states that heat is passively rejected to the ambient from the outer surface of the HI-TRAC transfer cask by natural convection and thermal radiation. However, at D.C. Cook, the licensee uses additional shielding materials for as low as reasonably achievable purposes that are in contact with and in the general area of the HI-TRAC. The licensee requested Holtec to perform a site-specific thermal analysis, HI2177676, Thermal Evaluation of Shielding Package around the HI-TRAC at DC Cook, to include the shielding material in the thermal model. The analysis contained inputs that were different than the design basis calculation inputs, which were previously incorporated into Design Feature Section 3.9 and Approved Contents Section 2.4. The licensee performed a 10 CFR 72.48 Screening and Evaluation 2018013902, which concluded that shielding could be used without prior NRC approval and subsequently issued 212CR0017, which revised the 72.212 Report. The licensee implemented administrative controls on building temperature and fuel assembly heat load limits based upon the site specific thermal analysis. This unresolved item is being opened to determine if: A) the licensee is in compliance with Design Feature, Section 3.9, Environmental Temperature Requirements; B) the Design Feature Section 3.9 and Approved Contents Section 2.4 are non-conservative at D.C. Cook; and C) the licensee is in compliance with 10 CFR 72.48. Planned Closure Actions: Region III will coordinate with the Division of Spent Fuel Management in the NRC Office of Nuclear Materials Safety and Safeguards. Corrective Action References: AR 20184056; AR 20186342; AR 20186642
05000316/FIN-2018003-012018Q3CookMisaligned Heater Level Column Valves Leads to Manual Reactor TripA self-revealed, Green finding was identified when the operators manually tripped the Unit 2 reactor in response to a hi-hi level in the Left Moisture Separator Drain Tank. On May 6, 2018, the Unit 2 reactor was at approximately 12 percent power following a startup at the conclusion of the spring 2018 refueling outage. While the station continued to make preparations to start the main turbine and synchronize with the grid, the moisture separator drain tank hi level alarm was received and remained standing for the better part of the shift. The drain tank collects condensed steam and water from the moisture separator reheater and associated high pressure turbine exhaust lines and routes it either to the condenser or #4 feedwater heaters. The day shift operators were hesitant to continue on with starting the main turbine until the cause of the alarm could be determined. Due to a series of miscommunications between day shift, night shift, the outage control center, and personnel performing troubleshooting, the night shift crew believed it was acceptable to continue with the turbine startup with the alarm still standing. The turbine was synchronized to the grid and power was stabilized at approximately 29 percent power with the alarm in for most of the turbine startup and synchronization. The alarm cleared for a period of time at 29 percent power, but then returned along with the hi-hi drain tank level alarm. Per the alarm response procedures, the operators tripped the reactor and main turbine to protect the turbine from excessive water in the system. Later investigation by the site revealed that the level columns for the #4 feedwater heaters had been left isolated following work and testing associated with the replacement of the #5 feedwater heaters. While the Operations Department had completed a valve lineup on the system per their startup procedures, which put the level columns in service, the Projects Department had not finished all of the work on the heaters at the time the lineup was performed. As a result, workers subsequently isolated the columns to complete testing after the Operations lineup was complete. A step in the Projects test procedure EC51366TP001 directed workers to specifically inform the operators that the level columns were isolated following testing and that the system was ready to be lined up per operations procedures. However, the workers did not provide that detail, and simply stated that the test was complete. As a result, operations did not know the valves had been taken out of alignment. Contributing to the issue, the outage schedule did not provide any logic ties to ensure all work was complete on the heaters before allowing operations to do their valve lineups. With the level columns isolated during startup, the #4 heaters indicated an erroneous level. This resulted in the operators believing that the heaters were at a normal operating level when in fact, they were full. Therefore, when the operators (per procedure) opened a high pressure turbine exhaust valve to the 4A heater, this created a pathway for water to flow from the #4 heaters, through the high pressure turbine exhaust lines, and into the moisture separator drain tank. The excessive flow of water caused the hi and hi-hi alarms in the drain tank which then led to the reactor/turbine trip.
05000282/FIN-2017004-012017Q4Prairie IslandLicensee-Identified ViolationTechnical Specification 5.7.1 states, High Radiation Areas accessible to personnel in which radiation levels could result in an individual receiving a deep dose equivalent less than 1.0 rem in one hour at 30 centimeters from the radiation source or from any surface that the radiation penetrates. Technical Specification 5.7.1, further requires in part, that each entryway to such an areashall be barricaded and conspicuously posted as a high radiation area.Contrary to the above, on October 19, 2017, a licensee system engineer identified during the performance of a maintenance and engineering inspection that a chain that functioned as the barricade for the 22 reactor coolant pump vault, a posted high radiation area, was not installed. The licensee documented this issue in CAP 501000004026. The inspectors determined that this issue was of very-low safety significance (Green) after reviewing IMC 0609, Appendix C, Occupational Radiation Safety Significance Determination Process. The inspectors determined that this finding was not an ALARA Planning or Work Control issue; was not an overexposure; was not a substantial potential for overexposure; and the ability to assess dose was not compromised.
05000282/FIN-2017004-022017Q4Prairie IslandLicensee-Identified ViolationTitle 10 CFR 50.54(q)(2) requires, in part, that a holder of a nuclear power reactor operating license shall follow and maintain the effectiveness of an emergency plan that meets the requirements in Title 10 CFR Part 50, Appendix E and the planning standards of Title 10 CFR 50.47(b). Title 10 CFR 50.47(b)(4) requires, in part, that the onsite emergency response plans for nuclear power reactors must meet the following standard: a standard emergency classification and action level scheme, the bases of which include facility system and effluent parameters, is in use by the nuclear facility licensee, and State and local response plans call for reliance on information provided by facility licensees for determinations of minimum initial offsite response measures.Contrary to the above, between November 22, 2000 and September 22, 2017, the licensee failed to maintain the effectiveness of an emergency plan that met the requirements of the planning standards of 10 CFR 50.47(b). Specifically, on September 22, 2017, the licensee identified that prior assessments of NRC Information Notice 9745, Supplement 1, Environmental Qualification Deficiency for Cables and Containment Penetration Pigtails, and a subsequent industry-initiated study to determine signal errors for Prairie Islands Unit 1 & 2 containment high range radiation monitors 1R48, 1R49, 2R48 & 2R49 (used in the licensees emergency classification and action level scheme) that impacted operability of the monitors, failed to restore capability to classify EALs during certain design basis accidents.The violation was more than minor because it was associated with the Facilities and Equipment attribute of the Emergency Preparedness Cornerstone and adversely affected the cornerstone objective of ensuring capability of implementing adequate measures to protect the health and safety of the public in 33 the event of a radiological emergency. The inspectors referenced IMC 0609, Attachment 4, Initial Characterization of Findings, and IMC 0609, Appendix B, Emergency Preparedness Significance Determination Process, Table 5.41 and Figure 5.41. The finding was determined to be of very low safety significance (Green) because timely and accurate EAL classification capability for an event at the General Emergency level was unaffected due to redundant and diverse indications.In response, the licensee entered the issue into the CAP as CAP 501000001861, declared the containment high range radiation monitors inoperable per TS 3.3.3, Event Monitoring Instrumentation, implemented Emergency Plan interim measures to make the emergency response organization aware of the issue, performed an extent-of-condition review, and submitted a letter to the U.S. NRC within 14 days as required by TS. Final corrective actions included the addition of a note to the Prairie Island EAL matrix to acknowledge the potential for TIC errors for the containment high range radiation monitors during the first 5 minutes for post-loss of coolant accident (LOCA) or main steam line break events inside containment.
05000282/FIN-2017004-032017Q4Prairie IslandLicensee-Identified ViolationPrairie Island TS LCO 3.0.3 requires, in part, that when an LCO is not met and an associated ACTION is not provided, action shall be initiated within 1 hour to place the unit in MODE 3 within 7 hours.Contrary to the above, at 1556 hours on May 4, 2016, the licensee failed to place Unit 2 in MODE 3 within 7 hours due to no associated ACTION provided within TS 3.6.5, Containment Spray and Cooling Systems for two containment cooling trains not OPERABLE. Specifically, between May 4 and May 5, 2016, operators failed to recognize that with the ongoing unplanned inoperability of the 122 control room chiller, and the subsequent unplanned inoperability of the A train #23 CFCU, the 122 control room chiller was a required support system for the B train #22 and #24 CFCUs. Therefore, with both of the Unit 2 CFCU trains inoperable, LCO 3.0.3 was required to be entered to place Unit 2 in Mode 3 within 7 hours. Because the supported system TS applicability was not recognized, LCO 3.0.3 was not entered as required and both trains of Unit 2 CFCUs were inoperable for approximately 35 hours.Because the inspectors answered No to questions B.1 and B.2 under Exhibit 3, Barrier Integrity Screening Questions of IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings at Power, the finding screened as very low safety significance (Green). The issue was entered into the licensees CAP as CAP 501000002726. Corrective actions included re-assessing shared system LCOs between Units 1 and 2, revising the LCO tracking database, implementing new standards for LCO 3.0.6 applications, and revisions to the Safety Function Determination Program.
05000282/FIN-2017004-042017Q4Prairie IslandLicensee-Identified ViolationTitle 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality shall be prescribed by documented procedures of a type appropriate to the circumstances and shall be accomplished in accordance with these procedures. Contrary to the above, on October 17, 2017, with Unit 2 in Mode 5, Cold Shutdown, the licensee failed to accomplish procedure 2C12.2, Purification and Chemical Addition Unit 2; Revision 34. Specifically, control room operators signed off steps as completed without validating that the procedure actions were performed in the field. These procedure steps that intended to close letdown valves and open purification valves, resulted in unintended transfer of primary coolant from the RCS to the chemical and volume control system hold-up tank instead of back to the RCS. In turn, this resulted in a reduction in RCS inventorywith reactor vessel level at approximately 1 foot below the flange (reduced inventory operations). Due to operators quickly recognizing a lack of letdown flow as discussed during a pre-job brief, the purification evolution was halted and actions were taken to restore reactor vessel level.Because the inspectors answered No to questions B.2 and B.3 under Exhibit 2, Initiating Events Screening Questions of IMC 0609, Appendix G, Attachment 1, Shutdown Operations Significance Determination Process Phase 1 Initial Screening and Characterization of Findings, the finding screened as very low safety significance (Green). Specifically, the loss of inventory event was self-limiting such that the leakage would have stopped before impacting the operating method of decay heat removal (shutdown cooling via RHR in this case). The issue was entered into the licensees CAP as CAP 501000003923. Corrective actions included an operations department human performance clock reset to share the lessons learned from the event.
05000315/FIN-2017007-012017Q3CookFailure to Correct Operable, but Non - Conforming ConditionsThe inspectors identified a finding of very low safety significance and an associated non -cited violation of 10 Code of Federal Regulations ( CFR ) Part 50, Criterion V for three examples where the licensee failed to follow procedures associated with the licensees quality assurance program. This issue resulted in the licensee not properly classifying some structures, systems and components (SSCs) as operable, but non- conforming, consistent with station procedures . The inspectors determined that the failure to properly classify the above SSCs as operable, but non -conforming, was within the licensees ability to foresee and correct and was, therefore, a performance deficiency. This performance deficiency was considered more than minor, because it adversely affected the Design Control attribute 3 of Reactor Safety Barrier Integrity, ensuring that SSCs would remain functional during a design basis event. Specifically, station procedures required that prompt action be taken to address operable, but non -conforming conditions. The inspectors evaluated the finding using the Significance Determination Process in accordance with IMC 0609, Appendix A, The Significance Determination Process for Findings At -Power, Exhibit 3, dated June 19, 2012. The finding was of very low safety significance (Green), because there was no actual loss of safety function for the affected SSCs. The inspectors determined this finding affected the cross -cutting area of problem identification and resolution in the aspect of resolution, specifically to ensure that the organization takes effective corrective actions to address issues in a timely manner commensurate with their safety significance. (P.3)
05000331/FIN-2017002-012017Q2Duane ArnoldFailure to Comply with Technical Specification Program RequirementsThe inspectors identified a finding of very low safety significance and an associated NCV of Technical Specification (TS) 5.5.13, Control Building Envelope (CBE) Habitability Program, for the licensees failure to implement all TS required elements in the CBE habitability assessment. Specifically, the assessments were not performed at the required frequency and did not verify that the unfiltered air leakage limits for hazardous chemicals would ensure that the CBE occupants exposure to these hazards were within the assumptions in the licensing basis. The violation was entered into the licensees Corrective Action Program as Condition Report 02211000, NRC Violation-CRE Habitability Program. Corrective actions included re-performing the CBE habitability assessment to determine that the unfiltered air leakage limits for hazardous chemicals ensured that the CBE occupants exposure to these hazards were within the assumptions in the licensing basis as required by TS 5.5.13.e and performing a review and revision of the CBE Habitability Program implementing procedure, Administrative Control Procedure (ACP) 1208.12, to ensure full compliance with TS 5.5.13. The inspectors determined the failure to perform a complete and comprehensive assessment that addressed all CBE Habitability Program requirements was a performance deficiency and was within the licensees ability to foresee and correct. Specifically, the licensee did not address the impact on CBE occupants from data gathered during the performance of offsite chemical surveys. The finding was determined to be more than minor because the finding was associated with the Barrier Integrity cornerstone attribute of procedure quality and affected the cornerstone objective of providing reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. The finding was of very low safety significance because no degradation of the barrier function of the CBE against smoke or a toxic atmosphere existed. The inspectors determined this finding affected the cross-cutting area of human performance, in the aspect of documentation, such that the organization creates and maintains complete, accurate and up-to-date documentation. Specifically, the licensee failed to maintain adequate documentation to ensure that TS program requirements were being met. (H.7)
05000390/FIN-2016004-022016Q4Watts BarInadequate Immediate Determination of Operability for Containment Penetration X-65Green: The NRC identified a non-cited violation (NCV) of 10 Code of Federal Regulations (CFR) Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensees failure to address all the design criteria for check valve, 1-CHV-31-3407, in the basis of the immediate determination of operability (IDO) for containment penetration X-65 to conclude that a reasonable expectation of operability existed. On September 19, Technical Specification (TS) compliance was restored when Penetration X-65 returned to operable when it was isolated and drained. The violation was entered into the licensees corrective action program as condition report (CR) 1216892. The performance deficiency was more than minor because it adversely affected the design control attribute of the barrier integrity system cornerstone. Specifically, reasonable assurance of operability did not exist for containment penetration X-65 from September 18, 2016, until September 19, 2016. The inspectors performed an initial screening of the finding and determined that this finding was of very low safety significance (Green) because the finding did not represent an actual open pathway in the physical integrity of reactor containment (valves, airlocks, etc.), containment isolation system (logic and instrumentation), and heat removal components; and hydrogen igniters are not applicable. The cause of this finding had a cross-cutting aspect of Evaluation in the area of Problem Identification and Resolution, because the licensee did not consider all functions of check valve 1-CKV-31-3407 when performing the IDO after the valve failed to pass the surveillance instruction. (P.2).
05000390/FIN-2016004-032016Q4Watts BarNotice of Enforcement Discretion 16-2-01 for Emergency Diesel Generator 1A-A Inoperable for Longer Than Allowed by Technical Specifications(Opened) Emergency Diesel Generator 1A-A Inoperable for Longer Than Allowed by Technical Specifications and Notice of Enforcement Discretion 16-2-01 Introduction: The inspectors opened an unresolved item associated with a potential noncompliance with TS 3.8.1 that occurred on October 15, 2016. Notice of Enforcement Discretion 16-2-01 was granted by the NRC staff agreeing not to enforce compliance with the TS completion time for an additional 130 hours. Description: At 6:32 a.m. on October 12, 2016, Watts Bar operations staff declared the 1A-A EDG inoperable when the output breaker to the 1A shutdown board opened unexpectedly due to phase overcurrent during performance of the load test required by procedure 0-SI-82-13, 24 Hour Load Run - DG 1A-A. The 1A-A emergency diesel generator was operating normally prior to the opening of the breaker. The licensees initial assessment determined the likely cause of the breaker trip was operation of the tap changer associated with the offsite power supply transformer. A subsequent 24 hour EDG load test was started at 12:35 a.m. on October 13, 2016. At 6:45 p.m. on October 13, 2016, operations staff noted mega volt amps (reactive) swings. During subsequent troubleshooting activities, it was determined that the mega volt amps (reactive) variance could be consistently reproduced by slight movement of a potentiometer on the 1A-A EDG voltage regulator. The licensee determined that an issue in the voltage regulator circuit was the most likely cause of the output breaker trip, and made preparations to replace and calibrate the voltage regulator on which the potentiometer was located. The licensee determined that it would require more than 72 hours to complete the removal and replacement of the voltage regulator and post-maintenance testing. The licensee requested a notice of enforcement discretion and an additional 144 hours to restore EDG 1A-A. A notice of enforcement discretion for an additional 130 hours was granted by the NRC staff at 9:30 p.m. on October 14, 2016. Consistent with NRC policy, the NRC agreed not to enforce compliance with the specific TSs in this instance, but will further review the cause(s) that created the apparent need for enforcement discretion to determine if there is a performance deficiency, if the issue is more than minor, or if there is a violation of requirements. This issue will be tracked as an unresolved item. (URI 05000390, 391/2016004-03, Notice of Enforcement Discretion 16-2-01 for Emergency Diesel Generator 1A-A Inoperable for Longer Than Allowed by Technical Specifications) This activity constitutes completion of one event follow-up sample, as defined in IP 71153
05000390/FIN-2016004-012016Q4Watts BarInadequate Immediate Determination of Operability for Essential Raw Cooling Water PumpsGreen: The NRC identified a non-cited violation (NCV) of 10 Code of Federal Regulations (CFR) 50 Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensees failure to base an immediate determination of operability (IDO) for essential raw cooling water (ERCW) pumps on information sufficient to conclude that a reasonable expectation of operability existed. The licensee restored compliance on November 30, 2016, when they documented an IDO that met the requirements of OPDP-8. The violation was entered into the licensees CAP as CR 1237178. The performance deficiency was more than minor because it adversely affected the equipment performance attribute of the Mitigating Systems Cornerstone. Specifically, reasonable assurance of operability did not exist for the ERCW pumps from November 29, 2016 until November 30, 2016. The inspectors determined the finding was of very low safety significance (Green) because it did not represent an actual loss of function for at least a single train for longer than its technical specification allowed outage time. The cause of this finding had a cross cutting aspect of Teamwork in the Human Performance area, because individuals and work groups failed to communicate and coordinate their activities within and across organizational boundaries such that nuclear safety is the overriding priority. (H.4).
05000263/FIN-2016007-012016Q4MonticelloInadequate Procedure for Identification of Significant Conditions Adverse to QualityThe inspectors identified a finding of very low safety significance and non-cited violation of Title 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, for the licensees failure to prescribe a procedure appropriate to the circumstances with respect to the identification of a significant condition adverse to quality (SCAQ). Specifically, FPPAARP01, CAP Action Request Process, provided an overly restrictive definition of what constituted a SCAQ. Consequently, the failure to provide an adequate definition of a SCAQ could result in a failure to identify a SCAQ and therefore, failure to implement corrective actions that preclude repetitive failures of safety-related equipment. The licensee entered this issue into the CAP as action request (AR) 1536735. The inspectors determined that the licensees failure to prescribe a procedure appropriate to the circumstances under FPPAARP01 was a performance deficiency. The performance deficiency was determined to be more than minor in accordance with IMC 0612, "Power Reactor Inspection Reports," Appendix B, "Issue Screening," because, if left uncorrected the performance deficiency would have the potential to lead to a more significant safety concern. Although, this issue could potentially affect each of the Reactor Safety Cornerstones, the inspectors elected to evaluate this issue under the Mitigating Systems Cornerstone because inspectors concluded it impacted the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage) more than the attributes of the other Cornerstones. The inspectors utilized IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, and IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, and determined that the finding screened as very low safety significance (Green) since the inspectors answered No to each of the questions in Exhibit 2, Section A, Mitigating Systems Screening Questions. The inspectors determined that the performance characteristic of the finding that was the most significant causal factor of the performance deficiency was associated with the cross-cutting aspect of Problem Identification and Resolution, Self-Assessment, and involving the organization routinely conducting self-critical and objective assessments of its programs and practices. Specifically, the failure to identify the overly restrictive definition of SCAQ during previous audits of the CAP was caused by an insufficiently self-critical audit focus.
05000282/FIN-2016007-012016Q2Prairie IslandFailure to Ensure Breaker Main Contacts are Fully AlignedA finding of very low safety significance and associated non-cited violation of Technical Specification Section 5.4.1, Procedures, was identified by the inspectors for the licensees failure to ensure the 21 safeguards diesel exhaust fan main contact connectors were fully engaged and aligned as required per electrical maintenance procedures to ensure proper operation of the breaker. As part of their corrective actions, the licensee aligned and re-engaged the main contact connectors as necessary. In addition, the licensee ensured maintenance personnel were aware of the operating experience to prevent the same issue from occurring in the future. The violation was entered into the licensees corrective action program as Action Request 1525844. The finding was determined to be more than minor because the finding was associated with the Mitigating Systems Cornerstone and the breaker failure led to the inoperability of the 21 safeguards diesel exhaust fan and impacted the availability of the 22 cooling water system diesel driven pump. This finding represented a loss of the 22 safeguards diesel cooling water pump function for longer than the Technical Specification allowed outage time of 7 days and therefore required a detailed risk evaluation. The regional senior reactor analyst performed a detailed risk evaluation of this finding using the Prairie Island Standardized Plant Analysis Risk Model revision 8.19 and determined the finding was of very low safety significance (Green). The inspectors did not identify a cross-cutting aspect associated with this finding because it was not indicative of current performance.
05000282/FIN-2016007-022016Q2Prairie IslandInadequate Operability DeterminationsA finding of very low safety significance with two examples and an associated non-cited violation of Title 10, Code of Federal Regulations (CFR), Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified by the inspectors for the licensees failure to accomplish the requirements of procedure FPOPOL01, Operability/Functionality Determination, Revisions 14 and 15. Specifically, on two occasions, the licensee failed to properly evaluate potential operability concerns associated with the Unit 2 emergency diesel generator (EDG) day tanks and the Unit 2 train A cooling water (CL) system piping. The licensee entered the issues into the Corrective Action Program as Action Requests 1525842 and 1526070. The inspectors determined that the licensees failure to accomplish the requirements of procedure FPOPOL01, Operability/Functionality Determination, Revisions 14 and 15, to properly evaluate the operability issues associated with the Unit 2 EDG day tank fuel oil level and the Unit 2 CL system piping (both safety-related, mitigating systems) was a performance deficiency. The performance deficiency, with two examples, was determined to be more than minor in accordance with Inspection Manual Chapter (IMC) 0612, "Power Reactor Inspection Reports," Appendix B, "Issue Screening," it was associated with the Mitigating Systems Cornerstone attributes of Equipment Performance (for the Unit 2 EDGs) and Protection against External Factors (for the Unit 2 CL piping) and adversely affected the Cornerstone objective of ensuring the availability, reliability, and capability of mitigating systems to respond to initiating events. The inspectors utilized IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, and IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, and determined that the finding screened as very low safety significance (Green) since the inspectors answered Yes to Question 1 of Section A of Exhibit 2, Mitigating Systems Screening Questions. The inspectors concluded that this issue was cross-cutting in the area of Problem Identification and Resolution in the aspect of Evaluation. As defined in IMC 0310, Aspects Within the Cross-Cutting Areas, this aspect states, The organization thoroughly evaluates issues to ensure that resolutions address causes and extent of conditions commensurate with their safety significance. Specifically, the licensee had not thoroughly evaluated the operability issues associated with the Unit 2 EDG day tank levels and the Unit 2 CL piping structural integrity.
05000390/FIN-2016001-092016Q1Watts BarAppropriateness of Corrective Actions Associated with Safety Related Pump Mechanical Seal Issues and the Effect on Plant ResponseThe inspectors identified an URI associated with the timely and effective corrective action associated with an adverse trend in safety related pump performance, including mechanical seal degradation and failure. This item is unresolved pending review and evaluation of the licensees response to the CRs generated to determine if a performance deficiency exists. During Unit 1, 2015 fall outage, the 1A Safety Injection (SI) pump mechanical seal was replaced. The mechanical seal had degraded to a point at which the leakage was greater than the Technical Specification limit for ECCS leakage outside of containment. The inspectors identified several issues during a review of the Prompt Determination of Operability for CR 1125623 and WO 116050574 to replace the seal. Specifically, inspectors found that non-QA1 parts were being used for seal replacement, the seal was the original equipment manufacturer part from startup, the failure mechanism was not clearly understood, and an extent of condition review was not performed. The inspectors reviewed other safety related pump mechanical seal performance and corrective action program entries. The inspectors are awaiting the completion of the licensees evaluation to determine the licensees compliance with applicable procedures and TS relative to pump operability and ECCS leakage limits outside containment. Additional inspection activities are needed to determine the extent of condition and compliance with the procedures and TS. Pending the results of this additional inspection, an URI will be opened and designated as URI 05000390/2016001-09, Appropriateness of Corrective Actions Associated with Safety Related Pump Mechanical Seal Issues and the Effect on Plant Response.
05000263/FIN-2015003-042015Q3MonticelloDrywell to Torus Vacuum Breaker Past OperabilityDuring the cycle preceding the 2015 refueling outage, two evaluations associated with torus to drywell vacuum breaker operation were developed due to issues identified in the first quarter 2014. These included: CAP 1417977, Failure of drywell-torus vacuum breaker to close, which identified an occasion of dual indication during Procedure 0143 procedure. A second occurrence was observed several days later and was documented in CAP 1418471, AO-2382A Torus-to-DW vacuum breaker closed indication anomaly. CAP 1420318, DW-Torus vacuum breaker work performed with inadequate PMT, identified the PMT following shaft sealing component (O-ring) replacement during the 2013 outage was not performed as planned. The licensee evaluations for these CAP conditions concluded the Drywell to Torus vacuum breakers were operable. However, neither evaluation specifically considered the effect of an interference between the vacuum breaker test lever and vacuum breaker test actuator stem. Since this specific mechanism was not addressed in these two evaluations, past operability of the torus to drywell vacuum breakers was questioned. As a result, the licensee established a past operability evaluation be conducted via CAPs 1479198 and 1478212. The licensee completed its past operability evaluation on June 26, 2015. After review, the inspectors conveyed a number of questions to the licensees engineering staff in regard to the past operability evaluation. Although the licensee provided responses for the majority of these questions during the remainder inspection quarter, the licensee had requested external input in regard to one of the inspectors questions. Specifically, inspectors questioned whether it was possible for the bottom of the lever arm to be at an elevation above the top of the actuator stem at valve disc full open and if so, could the valve test lever arm have come to rest on top of the actuator stem, potentially impacting the ability of the vacuum breaker valve to close. Upon the close of this inspection period, that input had not yet been finalized and made available to the inspectors. As a result, this issue was considered to be an unresolved item pending a review of the licensees response and past operability for CAPs 1479198 and 1478212, including and the licensee response to open inspector questions.
05000263/FIN-2015003-032015Q3MonticelloFailure to Identify Safe Shutdown Equipment Impacts in Fire Strategy ProceduresThe inspectors identified a finding of very low safety significance and an NCV of TS 5.4.1.d when the licensee failed to maintain procedures associated with Fire Protection Program Implementation, consistent with the Updated Safety Analysis Report (USAR), to ensure that fire strategy procedures accurately indicated safe shutdown (SSD) equipment. Specifically, on June 25, 2015, the licensee failed to maintain A.3-12-C, Condenser Room Fire Strategy, to ensure SSD equipment was appropriately identified. In this case, fire strategy A.3-12-C failed to identify any SSD equipment in the room, despite the fact that SSD cabling ran through the room and was included in the USAR Fire Hazards Analysis. Corrective actions included performance of an extent of condition review which identified 40 other fire strategies where safe shutdown cabling was not identified, and initiation of procedure changes to include the appropriate SSD equipment. This issue was entered into the licensees CAP (CAP 1484142). The inspectors determined that the failure to maintain fire strategy procedures to ensure that SSD equipment was identified was a performance deficiency requiring evaluation. The inspectors determined the issue was more than minor in accordance with IMC 0612, Appendix B, because it was associated with the Mitigating Systems Cornerstone attribute of Protection Against External Factorsincluding fire, and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). The inspectors assessed the significance of this finding using IMC 0609, Attachment 4, Initial Characterization of Findings," and IMC 0609, Appendix F, Fire Protection SDP, and determined that it had very low safety significance. The inspectors determined that the contributing cause that provided the most insight into the performance deficiency was associated with the cross-cutting area of Problem Identification and Resolution, Self-Assessment aspect because of the licensees failure to conduct self-critical and objective assessments of its programs and practices.
05000263/FIN-2015003-052015Q3MonticelloFailure to Provide Complete and Accurate Information in LER 05000263/2015-002-00The inspectors identified a Severity Level IV NCV of Title 10 of the Code of Federal Regulations (10 CFR) 50.9 due to the licensees failure to provide information to the NRC that was complete and accurate in all material respects in accordance with the NRCs reporting requirements in 10 CFR 50.73(a)(1), Licensee Event Report (LER) System. Specifically, on June 29, 2015, the licensee failed to include an accurate assessment of the safety consequences and implications of a loss of shutdown cooling event when they issued LER 05000263/2015-002-00. This LER included an inaccurate assessment of safety implications, stating that engineering calculations show a potential worst case maximum temperature of 115 degrees Fahrenheit (F). The inspectors identified that engineering models actually showed potential worst case temperatures of 25-26 degrees F higher, which could have challenged or exceeded fuel pool cooling design specifications. Corrective actions included issuance of a revision to LER 2015-002-00 which contained the correct engineering modeling results and associated discussion of safety implications. The licensee entered this issue into its CAP (CAP 1484633). This issue was of more than minor significance under the Traditional Enforcement Process because the NRC relies on licensees to identify and correctly report conditions or events meeting the criteria specified in the regulations in order to perform its regulatory function. Because this issue affected the NRC's ability to perform its regulatory function, the inspectors evaluated it using the traditional enforcement process. The underlying technical issue (i.e., loss of shutdown cooling) was evaluated separately and determined to be a finding of very low safety significance as documented in the 2015 2nd Quarter Integrated Inspection Report (05000263/2015002-01). In accordance with Section 2.2.2.d, and consistent with the examples included in Section 6.9.d of the NRC Enforcement Policy, this violation was categorized as Severity Level IV because it was of more than minor concern with relatively inappreciable potential safety significance and is related to a finding that was determined to be a more than minor issue. Consistent with Example 6.9.d.1, this represented an example where the licensee submitted inaccurate information in a required report, which resulted in expansion of the scope of the next regularly scheduled inspection and required LER revision. Because there was no finding evaluated with this violation, the inspectors did not assign a cross-cutting aspect to this issue.
05000263/FIN-2015003-012015Q3MonticelloInadequate Evaluation of Refueling Floor Structural Steel BeamsThe inspectors identified a finding of very low safety significance, and an associated NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to provide for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculational methods, or by the performance of a suitable testing program. Specifically, on September 3, 2008, licensee personnel failed to verify the adequacy of design when they failed to use correct section properties in their calculation of stresses on structural steel beams supporting the refueling floor for the increased spent fuel cask loading. Reevaluation of the beams using correct methodology resulted in the conclusion that the beams would not meet the design basis stress limits. Immediate corrective actions for this issue included initiation of a CAP, performance of a functionality assessment which concluded that the refueling floor remained functional but non-conforming, and creating compensatory measures which limited the refueling floor live load in the cask loading area (CAP 1492837). The inspectors determined that the licensees calculational methodology was contrary to the standard engineering principles applicable for determination of stresses in structural members, which resulted in a failure to meet Criterion III, Design Control, and was a performance deficiency. The finding was determined to be more than minor in accordance with IMC 0612 because it was associated with the Design Control attribute of the Barrier Integrity Cornerstone and adversely affected the cornerstone objective of providing reasonable assurance that physical barriers (reactor building) protect the public from radionuclide releases caused by accidents or events. Additionally, More than Minor Example 3.j of IMC 0612, Appendix E, Examples of Minor Issues, was used to inform the more than minor screening. The inspectors used IMC 0609, SDP, Attachment 4, Initial Characterization of Findings, and Appendix A of IMC 0609 to screen this finding. The inspectors answered No to questions C.1 and C.2 in Exhibit 3, Barrier Integrity Screening Questions. As a result, the inspectors concluded that the finding was of very low safety significance (Green). The inspectors did not identify a cross-cutting aspect associated with this finding because the finding was not representative of current performance.
05000263/FIN-2015003-022015Q3MonticelloFailure to Perform High Radiation Area Portable Fire Extinguisher SurveillancesThe inspectors identified a finding of very low safety significance and an NCV of Technical Specification (TS) 5.4.1.d when the licensee failed to implement procedures associated with Fire Protection Program Implementation, to ensure that required refueling outage surveillances were performed for fire extinguishers located in high radiation areas (HRAs). Specifically, between March 2007 and May 2015, the licensee failed to implement steps 9 and 10 of 1123, Portable Fire Extinguishers, which required weighing and verifying adequate hydrostatic testing of the fire extinguishers in HRAs on a refueling outage frequency. Corrective actions included surveillance process changes and evaluation of the current status of the high radiation area fire extinguishers which resulted in the determination that outside of the surveillance process, a separate work activity had exchanged all the affected extinguishers with ones that were current on their surveillances in May 2015. This issue was entered into the licensees Corrective Action Program (CAP) 1484257 The inspectors determined that the failure to implement HRA fire extinguisher surveillances was a performance deficiency requiring evaluation. The inspectors determined the issue was more than minor in accordance with IMC 0612, Appendix B, because it was associated with the Mitigating Systems Cornerstone attribute of Protection Against External Factorsincluding fire, and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). The inspectors assessed the significance of this finding using IMC 0609, Attachment 4, Initial Characterization of Findings," and IMC 0609, Appendix F, Fire Protection SDP, and determined that it had very low safety significance. The inspectors determined that the contributing cause that provided the most insight into the performance deficiency was associated with the cross-cutting area of Human Performance, Work Management aspect because of the failure to implement a process of planning, controlling, and executing work activities such that nuclear safety is the overriding priority and the failure to identify the need for coordination with different groups or job activities
05000237/FIN-2013005-012013Q4DresdenInadvertent Lo-Lo Reactor Water Level Indication Received During Maintenance Resulting in Unavailability of the 2/3 EDG to Unit 3A finding of very low safety significance and associated non-cited violation of Technical Specification (TS) 5.4.1, Procedures , was self-revealed on November 17, 2013, when the 2/3 Emergency Diesel Generator (EDG) was inoperable to Unit 3 with an Emergency Core Cooling Systems (ECCS) signal present on Unit 2 due to sensing a low reactor water level condition. Specifically, while the licensee performed procedure DIS 0263-07, Revision 20, Unit 2 ATWS RPT/ARI and ECCS Level Transmitters Channel Calibration Test and EQ Maintenance Inspection , in conjunction with Anticipated Transient Without a Scram (ATWS) level transmitter replacements, a failure to remove trip relays in addition to performing all transmitter replacements at the same time resulted in an unexpected Lo-Lo reactor water level trip signal, subsequently resulting in the auto initiation of the Unit 2 EDG and the 2/3 EDG, causing the 2/3 EDG to be inoperable to Unit 3. The licensee immediately restored the ATWS trip relay circuitry, clearing the Lo-Lo reactor water level signal. This enabled the EDGs to be returned to a standby condition and, thereby, restored 2/3 EDG availability to Unit 3. The licensees failure to properly implement the steps in the procedure was a performance deficiency that was determined to be more than minor, and thus a finding, because it was associated with the Mitigating Systems Cornerstone attribute of Configuration Control and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding was determined to be of very low safety significance. The finding was of very low safety significance because each of the questions provided in IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, were answered no. The finding has a cross-cutting aspect in the area of human performance, work control, for failing to appropriately coordinate work activities by incorporating actions to address the impact of changes to the work activity on the plant. Specifically, the licensee committed a human performance error by failing to adequately address the impact of work activity changes on the plant and implement the required prerequisites.
05000454/FIN-2013007-012013Q3ByronInadequate Identification of Fire Curtain Sprinkler Degradation for an Auxiliary Building StairwellThe inspectors identified a finding of very low safety significance and an associated NCV of Byron Operating License (OL) Condition 2.C.6 for Unit 1 and 2.E for Unit 2 when licensee personnel failed to identify that a fire sprinkler curtain on Elevation 346 had degraded. Specifically, a ball valve had a twisted stem, which had the effect of indicating that an isolation valve was fully open, when in fact it was significantly closed. As part of their immediate corrective actions, the licensee declared the auxiliary building Elevation 346 fire curtain inoperable and initiated compensatory measures that included fire watches until the isolation valve stem was replaced. The licensee entered this issue into their CAP as IR 1560667, Adverse Trend in Main Drain Results for 346 AB (Auxiliary Building) Sprinkler System. The performance deficiency was determined to be more than minor because it was associated with the External Factors attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. The inspectors determined that the finding could be evaluated using the SDP in accordance with IMC 0609, Appendix F, Fire Protection Significance Determination Process, because it was associated with fire protection defense-in-depth strategies involving fire confinement. The inspectors determined that while flow to the sprinkler heads was significantly degraded, because less than 10 percent of the heads were obstructed or fouled, and no adjacent heads were fouled, the water curtain had a low degradation rating in accordance with IMC 0609, Appendix F, Attachment 2. Therefore, in accordance with IMC 0609, Appendix F, Attachment 1, Step 1.3.1.B, the finding was determined to be of very low safety significance (Green). This finding had a cross-cutting aspect in the CAP component of the PI&R cross-cutting area (P.1.(a)), because licensee personnel twice failed to identify the degraded sprinkler curtain and when NRC personnel identified the issue and informed licensee personnel, the issue was not entered into the licensees CAP in a timely manner.
05000454/FIN-2013007-032013Q3ByronAcceptance Criteria for Battery Voltage in TS Surveillance Procedure Failed to Account for Test Equipment UncertaintyThe inspectors identified a finding of very low safety significance and an associated NCV of 10 CFR Part 50, Appendix B, Criterion XI, Test Control, when licensee personnel failed to account for test instrument uncertainty in the acceptance criteria for TS Surveillance procedure 2BOSR 8.6.1-2, 125VDC (Volt Direct Current) ESF (Engineered Safety Feature) Battery Bank and Charger 212 Operability Weekly Surveillance. As part of the licensees immediate corrective actions, the voltage of the affected battery charger was adjusted. The licensee also planned to perform a fleet-wide evaluation of the issue. The licensee entered this issue into their CAP as IR 0156440, 125 VDC Battery TS Surveillance Values. The performance deficiency was determined to be more than minor because it was associated with the Equipment Performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the acceptance criteria for the battery voltage did not assure the availability of the safety-related direct current (DC) batteries that would meet the minimum voltage as required by the TSs. This finding screened as having very low safety significance, in accordance with Exhibit 2 of IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings for At- Power, because it was a design deficiency confirmed not to result in a loss of operability. The inspectors did not identify a cross-cutting aspect associated with this finding because the finding was not representative of current performance. Specifically, the decision to not include the instrument uncertainty was made in 2003, as part of an evaluation for a previously identified issue.
05000454/FIN-2013007-022013Q3ByronFailure to Properly Assess Operability of the 2A EDG Following Post-Modification TestingThe inspectors identified a finding of very low safety significance and an associated NCV of Technical Specification (TS) 3.8.1 when licensee personnel failed to properly assess the operability of the 2A emergency diesel generator (EDG) following a post-maintenance test that rendered the 2A EDG ventilation fan, a credited support system, incapable of performing its auto-start support system function for a period of two days. As part of the licensees immediate corrective actions, a trip signal that prevented the 2A EDG fan from starting was reset. The licensee entered this issue into their CAP as IR 1252529, 2A DG (EDG) Vent Fan Trip Signal Not Reset. The performance deficiency was determined to be more than minor because it was associated with the Configuration Control and Human Performance attributes of the Mitigating Systems cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, following an August 15, 2011, post-maintenance test of the 2A EDG room ventilation system high differential pressure (D/P) trip time delay, the licensee failed to implement the necessary procedural steps that ensured the high D/P trip signal was reset. This resulted in the 2A EDG room ventilation fan from auto-starting, resulting in the inoperability of the 2A EDG from August 15-17, 2011. The inspectors determined that this finding screened as having very low safety significance (Green) in accordance with IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings at Power, Exhibit 2, Mitigating Systems Screening Questions, as it did not represent an actual loss of function of at least a single train of safety-related equipment for greater than its Technical Specification (TS) allowed outage time and did not represent an actual loss of function of one or more non-TS trains of equipment designated as high safety-significant in accordance with the licensees maintenance rule program for greater than 24 hours. This issue had a cross-cutting aspect in the Work Practices component of the Human Performance cross-cutting area (H.4(a)), because licensee personnel failed to use appropriate human performance techniques to ensure that work tasks were performed safely and individuals do not proceed in the face of uncertainty.
05000282/FIN-2012007-032012Q3Prairie IslandLack of Design Basis Information for Steam Exclusion Damper LeakageAn unresolved item was identified by the inspectors due to a lack of steam exclusion (SE) damper leakage design basis information, questions regarding the adequacy of SE damper testing, the functionality of the SE system, and the operability of safety related equipment protected by the dampers following a high energy line break (HELB) event. In 1998 the licensee identified concerns regarding the ability of the SE system dampers to meet the leakage rate described in the USAR and the deterioration of non-metallic gears due to environmental conditions. These issues were documented as Nonconformance Reports 19981361 and 19981104. The licensee initially planned to disposition the conditions as use as is conditions until a revised HELB analysis was completed and the SE dampers were replaced. On October 7, 2009, the licensee initiated AR 1201589 to document that the activities needed to disposition the conditions described above as use as is conditions had not been completed. The licensee reviewed operability recommendations, engineering change records, and 10 CFR 50.59 screenings and evaluations and were unable to find any documents which evaluated the condition of the SE dampers as acceptable. The licensee screened AR 1201589 as a B level corrective action document. No apparent or root cause evaluation was assigned. The screening team concluded that the equipment conditions described in the 1998 Nonconformance Reports should be classified as operable but nonconforming conditions since they had not been corrected. As part of this inspection, the inspectors reviewed the licensees resolution of AR 1201589. The inspectors identified the following: The licensee had not used the operability/functionality process described in Procedure FP-OP-OL-01, Operability/Functionality Program, when classifying the SE damper conditions as operable but nonconforming in 2009; The failure to use the process described in Procedure FP-OP-OL-01 resulted in someone other than the shift manager approving the operable but nonconforming decision; A formal operability recommendation did not exist; and the status of the SE system dampers should have been classified as functional but nonconforming rather than operable but nonconforming. Corrective action document 1201589 also clarified that the SE damper leakage rate described in the USAR was a manufacturing specification rather than design basis information. The inspectors reviewed the most recent SE system health report and found that it also contained information which indicated that design basis information regarding the amount of SE damper leakage that could exist following a HELB did not exist. A large contributor to the lack of this design basis information was due to the fact that the 1998 HELB analysis remained incomplete as of August 10, 2012. Based upon this information, the inspectors were concerned that the licensees monthly SE damper testing may not be adequately verifying the functionality of the SE system. The inspectors were also concerned that assumptions used in currently open operability recommendations regarding the heat up of the battery rooms, the auxiliary feedwater pump rooms, the D1 and D2 emergency diesel generator rooms and several other areas may not be adequate to ensure that the equipment in these rooms would remain capable of performing their specified safety functions following a HELB event. The licensee documented the inspectors concerns in ARs 1345879, 1347752, and 1349909. At the conclusion of the inspection, the shift manager had designated the SE dampers as functional but nonconforming due to the lack of design basis leakage criteria and recent SE damper test results which demonstrated that the dampers had appropriately closed when needed. However, the licensee was continuing to review the adequacy of the SE damper test and the assumptions in the currently open operability recommendations. As a result, this issue will be considered unresolved pending an inspection of the licensees review results
05000282/FIN-2012011-032012Q3Prairie IslandFailure to Update the Calculations for Steam Generator DrainingAn inspector-identified finding of very low safety significance and an NCV of 10 CFR 50, Appendix B, Criterion III, was identified due to the licensees failure to update engineering calculations for the amount of nitrogen to be used during steam generator tube draining. Specifically, the failure to correctly include the number of plugged steam generator tubes into the engineering calculations was considered a performance deficiency. This deficiency was more than minor, as it contributed to the vessel overpressure that resulted in over-draining of the RCS on March 6 2012, and a NOUE. The licensee initiated ARs 01328420, 01329464, and 01328366 to evaluate this issue. This finding was determined to be cross-cutting in the area of Resources, specifically having complete and up-to-date design documentation (H.2.(c)). Because the licensee inappropriately placed the engineering calculations in non-active status, they were not updated to reflect the actual number of plugged steam generator tubes. This resulted in the station procedure incorrectly stating the amount of nitrogen needed and the amount of water removed during steam generator tube draining.
05000282/FIN-2012011-022012Q3Prairie IslandInadequate Procedure for Draining of Reactor Coolant SystemAn inspector-identified finding of very low safety significance and a non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion V, was identified due to the licensees use of an inadequate procedure during draining of the RCS. The inspectors determined that the procedure used during the March 6, 2012, draining of the reactor coolant to the vessel flange level, did not contain adequate guidance for identifying and compensating for inadequate reactor vessel level indication due to over pressurization of the reactor vessel. This was a performance deficiency that required an evaluation using the SDP. This deficiency was more than minor as inaccurate RCS level indication resulted in plant operators declaring an NOUE and over-draining the RCS to the point where the function of the safety-related residual heat removal system was potentially affected. The licensee initiated Action Request (AR) 1329465 to evaluate this issue. This finding was determined to be crosscutting in the Resources area, because the licensee has not maintained compete, up-to-date procedures for performing RCS draining (H.2(c)). The licensee had prior instances where RCS level indication was lost due to vessel overpressure; however, the licensee decided not to revise the procedures based on an incorrect assumption that the procedures contained adequate guidance.
05000282/FIN-2012011-012012Q3Prairie IslandFailure to Take Corrective Action for Reactor Coolant System Level Indication IssuesAn inspector-identified finding of very low safety significance was identified due to the failure to take corrective action for a Condition Adverse to Quality. The inspectors determined that the failure to correct for the loss of reactor coolant system (RCS) level indication during the 2010 refueling outage was a performance deficiency that required an evaluation using the SDP. This deficiency was more than minor as the loss of RCS level indication during draining, may result in level decreasing to the point where the function of the safety-related residual heat removal system may be affected. These level indication issues recurred during the RCS draining on March 6, 2012, resulting in a Notice of Unusual Event (NOUE) being declared. The licensee initiated Action Request (AR) 1329470 to evaluate this issue. This finding was determined to be crosscutting in the Problem Identification and Resolution, area because the licensee had not taken appropriate corrective actions to address the RCS level indication issues (P.1 (d)). This finding was not considered a violation, as the affected RCS level indicators were not considered safety-related.
05000282/FIN-2012007-022012Q3Prairie IslandFailure to Perform Maintenance Rule Evaluations After Discovering Degraded Radiation MonitorsThe inspectors identified an unresolved item regarding the failure to perform maintenance rule evaluations after discovering degraded conditions on four separate radiation monitors. Due to the missing evaluations, the inspectors were unable to determine whether the radiation monitor system had been appropriately evaluated under the maintenance rule as required by 10 CFR 50.65. On July 15, 2010, the licensee initiated AR 1241216 to document that radiation monitor 1RM-48 was reading downscale. During the screening of this AR, the licensee assigned an individual to complete an apparent cause evaluation to determine the cause of the downscale condition. The licensee also assigned a maintenance rule evaluation to determine whether the condition of the radiation monitor constituted a maintenance rule functional failure as defined by 10 CFR 50.65. Two days later, the licensee initiated AR 1241453 to document that several radiation monitors (including 1RM-48) were adversely impacted during the installation of a new R-11 radiation monitor. During the screening of this corrective action document, the licensee determined that an apparent cause evaluation was not needed since the poor design of the radiation monitor cabinetry, combined with the installation of new wires amongst older wires, had caused the adverse impacts. In addition, the screening team approved the cancellation of the apparent cause and maintenance rule evaluations assigned as part of AR 1241216 based upon the information contained in AR 1241453. The inspectors reviewed the assignment cancellation information and agreed that the apparent cause evaluation was not needed. However, the maintenance rule evaluation was needed to determine whether additional maintenance rule related actions were required. The inspectors questioned licensee personnel to determine whether a maintenance rule evaluation was completed for the equipment issue discussed in AR 1241216. The licensee informed the inspectors that the maintenance rule evaluation had not been completed. In addition, maintenance rule evaluations for the three other radiation monitors (2RM-48, 2R-71, and R-41) discussed in AR 1241453 were not performed. The licensee documented the failure to perform the maintenance rule evaluations as AR 1347349. The maintenance rule evaluations were ongoing at the conclusion of the inspection. As a result, this issue will be considered unresolved pending the inspectors review of the maintenance rule evaluations and a determination of whether the failures should have resulted in the radiation monitoring system being classified as an a(1) maintenance rule system
05000282/FIN-2012007-012012Q3Prairie IslandNumber of Air Receivers Required to Be Greater than 480 PSIG to Support EDG OperabilityThe inspectors identified an unresolved item due to differences between procedural guidance and the Updated Safety Analysis Report (USAR) regarding the number of emergency diesel generator (EDG) air receivers that needed to be pressurized to greater than 480 pounds per square inch gauge (psig) to support EDG operability. On October 15, 2010, the licensee initiated AR 1254304 to document that the D6 EDG 2A starting air compressor relief valve (2EG-39-7) was leaking. This condition caused the pressure in the 2A starting air receiver to drop below 480 psig. Upon identifying this condition, the operators checked the operating status of the remaining three air receivers and determined that the 1A receiver was also less than 480 psig due to maintenance on the 1A starting air compressor. The operations crew immediately declared the D6 EDG inoperable since Alarm Response Procedures C50001, D5 Engine 1 Remote Alarm Responses and C60001, D6 Engine 1 Remote Alarm Responses, contained a note which stated that the pressure in three out of four air receivers must be greater than 480 psig to maintain EDG operability. As part of this inspection, the inspectors reviewed the licensees evaluation and resolution of AR 1254304. The inspectors found that the 1A and 2A starting air compressors were repaired by the maintenance staff. Repairing the compressors allowed the pressure in the associated air receivers to be restored to normal operating levels. The inspectors also found that the licensee had assigned engineering personnel to evaluate whether the inability to maintain pressure in the 1A and 2A air receivers above 480 psig needed to be considered a maintenance rule functional failure. The inspectors reviewed the licensees completed maintenance rule evaluation and found that the condition of the 1A and 2A air receivers was not considered a functional failure due to information contained in the USAR which specified that only two of the four air receivers were needed for EDG operability. The inspectors were concerned by this conclusion since it was supported by information that conflicted with the alarm response procedures in effect in July 2010 and Procedure 2C20.7, D5/D6 Diesel Generators On August 3, 2012, the inspectors discussed the conflicting information with the licensee. The inspectors specifically discussed that the conflicting information could have resulted in one of the following conditions: Operations personnel declaring the D6 EDG inoperable due to overly conservative procedural guidance regarding air receiver pressure; or An incorrect maintenance rule evaluation may have been completed due to incorrect USAR information. The licensee initiated AR 1347636 to document the inspectors concern. The licensee was evaluating the actual number of air receivers required to be pressurized to greater than 480 psig to support EDG operability at the conclusion of the inspection. As a result, this issue will be considered unresolved pending the inspectors review of the licensees evaluation and a determination regarding whether the licensee had appropriately evaluated the conditions described in AR 1254304
05000305/FIN-2012003-012012Q2KewauneeFailure to Utilize Work Order for Temporary Weld Repair on ASME Code, Class 2 PipingA finding of very low safety significance and associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was self-revealed for the failure to accomplish Temporary Modification (TMOD) 2012-11 in accordance with Work Order (WO) KW100894696 and the associated weld data sheet and map. Specifically, licensee personnel failed to utilize the WO instructions, weld data sheet and weld map when welding a temporary NRC-approved clamp on American Society of Mechanical Engineers (ASME) Code Class 2 residual heat removal (RHR) piping. The failure to use the required documentation to perform the work resulted in the worker creating a second through wall leak on the ASME Code, Class 2 RHR piping upstream of valve RHR-600. The licensee entered the issue into its corrective action program (CAP) as condition report (CR) 472915 and permanently corrected both through wall leaks on the RHR system piping following the approval of a second proposed alternative, without incident on May 5, 2012. At the end of the inspection period, the licensee continued to perform an apparent cause evaluation (ACE) to determine the causes for the organizational failures that occurred. The finding was determined to be more than minor in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, dated December 24, 2009, because the finding was associated with the Mitigating Systems Cornerstone attribute of human error (pre-event) and adversely affected the cornerstone objective to ensure the reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). The inspectors determined that the finding could be evaluated in accordance with IMC 0609, Appendix G, Shut-down Operations SDP, dated February 28, 2005. The inspectors used Checklist 1, PWR Hot Shutdown Operation: Time to Core Boiling <2 Hours, contained in Attachment 1 and determined that the finding affected core heat removal guidelines I.B(1), Procedures, and I.C(2), Equipment. The inspectors screened the finding as very low safety significance (Green) because it did not degrade the licensees ability to establish an alternate core cooling path if decay heat removal could not be re-established and, therefore, did not require a phase 2 or phase 3 analysis. This finding has a cross-cutting aspect in the area of human performance, resources, because the licensee did not ensure supervisory and management oversight of work activities, including contractors, such that nuclear safety was supported. Specifically, the inspectors identified that the pre-job brief conducted by supervision and management for this work did not include a review of the WO, weld sheet, or weld map and did not convey accurate information regarding the significance of the activity, the type of weld to be performed and the system conditions where the weld was performed.
05000305/FIN-2012003-022012Q2KewauneeLoose Cable Clamp Caused Loaded Spent Fuel Upender to Unintentionally LowerA finding of very low safety significance (Green) and associated NCV of Technical Specification (TS) 5.4.1, Procedures, was self-revealed because procedure MCM-FH-001, Repair of the Fuel Transfer System, was inadequate. Specifically, the procedure did not contain torque specifications for tightening the upender frame cable clamps and, on April 23, the cable for the spent fuel pool (SFP) upender slipped through the cable clamps and allowed the upender containing a fuel assembly to descend approximately 12 inches. The licensee confirmed that no damage occurred to the fuel assembly and placed procedure MCM-FH-001 on administrative hold to prevent its use until it could be updated with the appropriate torque specifications. At the end of this inspection period, the licensee was performing an ACE to determine the causes of the event, and develop corrective actions. The finding was determined to be more than minor because, if left uncorrected, the finding had the potential to lead to a more significant safety concern. Specifically, the upender containing the fuel assembly could have fallen from the near-full vertical position to the horizontal position. The inspectors evaluated the finding by applying the SFP questions in the Fuel Barrier column of Table 4a, located in IMC 0609, Attachment 4, dated January 10, 2008. The inspectors answered No to all three questions and determined that the finding was of very low safety significance (Green). The finding has a cross-cutting aspect in the areas of problem identification and resolution, operating experience (OE), because the licensee failed to communicate to affected internal stakeholders in a timely manner relevant external OE. Specifically, the licensee failed to discuss available and relevant OE related to the failure to appropriately torque cable clamps on an SFP upender.
05000305/FIN-2012003-032012Q2KewauneeFailure to Provide Adequate Suppression in Cable Spreading AreaThe inspectors identified a finding of very low safety significance (Green) and associated NCV of 10 CFR Part 50, Appendix R, Section III.G.3, for the licensees failure to provide adequate fire suppression coverage for fire zone AX-32. Specifically, the licensee failed to provide required fire suppression coverage for safe shutdown functions of source range monitoring, isolation of a steam generator (SG) blowdown line, and pressurizer level instrumentation in the cable spreading area. The licensee entered the issue into the CAP, designated manual backup from hose stations, and implemented an hourly fire watch for the radiation protection office (RP) in fire zone AX-32. The inspectors determined that the finding was more than minor because the failure to provide suppression for redundant trains of safe shutdown equipment increased the likelihood that alternative shutdown methods would have to be used in the event of a fire. The finding was of very low safety significance based on a Phase 3 significance determination analysis. The finding has a cross-cutting aspect in the area of problem identification, corrective action program, because the licensee did not take appropriate corrective actions to address the inadequate suppression system in fire zone AX-32
05000305/FIN-2012003-042012Q2KewauneeIncorrect Leakage Requirement Submitted for a Proposed Temporary Pipe ClampA Severity Level (SL) IV NCV of 10 CFR Part 50.9(a), Completeness and Accuracy of Information, was identified by the inspectors for the failure of the licensee to provide complete and accurate information in all material respects to the Commission in licensee Request RR-2-3, dated April 29, 2012 (ADAMS Accession No. ML12122A138). As part of a license amendment for a proposed temporary deviation from the requirements of 10 CFR 50.55a and ASME Code, Section XI, the licensee incorrectly stated the allowable leakage from the temporary clamp in transition from Mode 5 to 4 was governed by TS 5.5.2, Primary Coolant Sources Outside Containment, and proposed an allowable leakage value of 5.5 gallons per hour (gph). After licensee Request No. RR-2-3 was verbally approved by the NRC on April 30, 2012, the inspectors and NRC staff determined that the governing leakage requirement was no leakage in Mode 4 for the clamp as required by TS 3.4.13, Reactor Coolant System Operational Leakage. The performance deficiency was determined to be more than minor in accordance with the NRC Enforcement Policy and Enforcement Manual because the NRC identified the performance deficiency, the NRC relied on the information provided in a licensing decision, and the misinformation was identified after the NRC relied on the information in its licensing decision. Because violations of 10 CFR 50.9 are considered to be violations that potentially impact the regulatory process, they are dispositioned using the traditional enforcement process instead of the ROP SDP. Because the performance deficiency, specifically a failure to submit complete and accurate information, was not an ROP finding per IMC 0612, Appendix B, Issue Screening, a cross-cutting aspect was not assigned to this violation. The severity of the violation was mitigated because of the facts surrounding the licensees implementation of Request No. RR-2-3.
05000263/FIN-2012003-032012Q2MonticelloLicensee-Identified ViolationThe licensee identified a finding of very low safety significance (Green) and associated NCV of planning standard 10 CFR 50.47(b)(4). This regulation states that, A standard emergency classification and action level scheme, the bases of which include facility system and effluent parameters, is in use by the nuclear facility licensee, and State and local response plans call for reliance on information provided by facility licensees for determinations of minimum initial offsite response measures. Contrary to this, the emergency action level (EAL) classification scheme contained an initiating condition that had been rendered ineffective, such that an Alert would not have been declared. Specifically, the licensee\'s EAL RA1.2 specified an instrument set-point beyond the limit of the process radiation monitors capability. This event was documented in the licensees CAP as apparent cause evaluation (ACE) 1242696. Revision 43 of Procedure A.2-101, Classification of Emergencies, was revised to include an Alert value that was on scale of the instrumentation and fleet procedure (FP)-R-EP-05, Revision and Control of the Emergency Plan and Emergency Actions, was revised to provide direction on future EAL set-point changes. The performance deficiency was determined to be more than minor because it could reasonably be viewed as a precursor to a significant event, due to the potential for a delayed Alert declaration. Using IMC 0609, Appendix B, for EP SDP, Figure 5.4-1, Significance Determination for Ineffective EALs, the event would be declared in a degraded manner (not timely). The inspectors determined the finding to be of very low significance.
05000263/FIN-2012003-022012Q2MonticelloFAILURE TO MONITOR SSF PLANT LEVEL PERFORMANCE CRITERION EQUIPMENT UNDER 10 CFR 50.56(a)(1) DUE TO INADEQUATE SSF DATA TRACKINGThe inspectors identified a finding of very low safety significance and non-cited violation (NCV) of 10 CFR 50.65(a)(1)/(a)(2), Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, for the licensees failure to evaluate a(1) goals for equipment tracked under the Safety System Failure (SSF) Plant Level Performance criterion when the plant level a(2) preventative maintenance demonstration became invalid. Specifically, in October 2011, the SSF plant level indicator exceeded its performance criterion when the plant experienced a fourth SSF in a two year period. The licensee failed to appropriately account for these failures in their Maintenance Rule program and, as a result, the site failed to evaluate the affected equipment under 10 CFR 50.65(a)(1) as required. Corrective actions taken by the licensee to address this issue included performing an apparent cause evaluation of the equipment that caused the plant to exceed its plant level performance criterion. This issue was entered into the licensees corrective action program as CAP 01339425 and CAP 01339429. The inspectors determined that the licensees failure to evaluate goal setting for the equipment that caused the plant to exceed its SSF performance criteria in accordance with the requirements of 10 CFR 50.65(a)(1), due to inadequately accounting for SSF data under 10 CFR 50.65(a)(2), was a performance deficiency because it was the result of the failure to meet a requirement or a standard; the cause was reasonably within the licensees ability to foresee and correct; and should have been prevented. The inspectors screened the performance deficiency per IMC 0612, Power Reactor Inspection Reports, Appendix B, and determined that the issue was more than minor because it impacted the equipment performance attribute of the Mitigating Systems Cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). The inspectors applied IMC 0609, Attachment 4, to this finding. The inspectors evaluated the issue under the Mitigating Systems Cornerstone, and utilized Column 2 of the Table 4a worksheet to screen the finding. The inspectors answered No to all five questions, and determined the finding to be of very low safety significance. The inspectors determined that the contributing cause that provided the most insight into the performance deficiency was associated with the cross-cutting area of Human Performance, having work practices components, and involving aspects associated with the licensee communicating human error prevention techniques, such as self and peer checking and proper documentation of activities
05000263/FIN-2012003-012012Q2MonticelloFAILURE TO MONITOR RESIDUAL HEAT REMOVAL SYSTEM UNDER 10 CFR 50.56(a)(1) DUE TO INAPPROPRIATE A(2) TRANSITIONThe inspectors identified a finding of very low safety significance and non-cited violation (NCV) of 10 CFR 50.65(a)(1)/(a)(2), Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, for the licensees failure to establish a(1) goals for the residual heat removal (RHR) system when the a(2) preventative maintenance demonstration became invalid. Specifically, in June 2011, the No. 13 RHR pump exceeded its performance criteria when it experienced a second maintenance preventable functional failure (MPFF). In February 2012, the inspectors identified both of these and a third MPFF, and while the licensee determined that the system required a(1) classification, the site failed to create goals for effective monitoring of the equipment when they inappropriately applied a(1) status exit criteria to the system. As a result, the site failed to monitor the equipment under 10 CFR 50.65(a)(1) as required. Corrective actions taken by the licensee to address this issue included revision of the a(1) action plan for the RHR system and retraining of Maintenance Rule Expert Panel members. This issue was entered into the licensees corrective action program as CAP 01341703. The inspectors determined that the licensees failure to monitor the RHR system in accordance with the requirements of 10 CFR 50.65(a)(1), due to inappropriately transitioning the system from a(1) to a(2) status, was a performance deficiency because it was the result of the failure to meet a requirement or a standard; the cause was reasonably within the licensees ability to foresee and correct; and should have been prevented. The inspectors screened the performance deficiency per IMC 0612, Power Reactor Inspection Reports, Appendix B, and determined that the issue was more than minor because it impacted the equipment performance attribute of the Mitigating Systems Cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). The inspectors applied IMC 0609, Attachment 4, to this finding. The inspectors evaluated the issue under the Mitigating Systems Cornerstone, and utilized Column 2 of the Table 4a worksheet to screen the finding. The inspectors answered No to all five questions, and determined the finding to be of very low safety significance. The inspectors determined that the contributing cause that provided the most insight into the performance deficiency was associated with the cross-cutting area of Human Performance, having resources components, and involving aspects associated with the licensee having personnel, procedures, and other resources adequate to maintain long term plant safety by maintenance of design margins and minimizing of long-standing equipment issues.
05000282/FIN-2012002-092012Q1Prairie IslandReview of Root Cause Evaluation for March 6, 2012, Notice of Unusual EventOn March 6, 2012, operations personnel declared a Notice of Unusual Event due to receiving an indication that Unit 2 RCS leakage was greater than 10 gallons per minute. The inspectors were in the control room when the event was declared. The inspectors observed the operators respond to the event to ensure that the licensees procedural requirements were followed. The inspectors also monitored available control room indications to determine whether any equipment complications occurred while the operators were responding to the event. None were identified. The inspectors initial review of this event determined that a leak in the RCS had not occurred. However, it appeared that the procedures used to drain a portion of the RCS and the Unit 2 reactor head vent piping may be deficient. Both the inspectors and the licensees review of this event were ongoing at the conclusion of the inspection period. As a result, this item will be carried as a URI pending the inspectors review of the licensees root cause evaluation report and the proposed corrective actions
05000373/FIN-2011008-012011Q3LaSalleTechnical Specification Violation Due to Failures to Follow Operability Determinations ProcedureA finding of very low safety significance (Green) and associated non-cited violation of Technical Specifications (TS) was identified by the inspectors for the licensees failure to follow station procedure OP-AA-108-115, Operability Determinations, Revisions 8 and 10. Specifically, the licensee failed to follow their operability determination procedure during loss of shutdown cooling (SDC) events occurring on July 20, 2009, and February 2, 2011. These events were caused by the closure of the residual heat removal (RHR) common suction valve. These events also resulted in the violation of TS 3.4.9, 3.4.10, and 3.0.2. The licensee entered this issue into its CAP as Issue Report (IR) 1248293. The finding was considered more than minor because it was associated with the Mitigating Systems Cornerstone attribute of Equipment Performance and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, failing to follow the Operability Determinations procedure caused the licensee to incorrectly assess the RHR SDC systems capability to perform its safety function, and also led the licensee to make a specific TS required isolation feature unavailable. This finding has a cross-cutting aspect in the area of human performance, decision making, because the licensee used non-conservative assumptions when confronted with unexpected system failures.
05000263/FIN-2011004-032011Q3MonticelloShipping and Transportation of a Radioactively Contaminated Condensate Demineralizer VesselOn July 14, 2011, it was reported to the licensee by the driver of the vehicle that there was a puncture in the side of a container package on radioactive material shipment number 11-127. The package was a Sealand box inside an enclosed conveyance. The Sealand box contained a radioactively contaminated condensate demineralizer vessel and the puncture was a nominal 4 by 6 inch hole. There was no spread of contamination as a result of the compromised package. The inspectors initial review determined that a performance deficiency exists, in that, the shipping container contents was inappropriately braced and blocked for transport. Regulations require that licensees ensure that loads not shift under conditions normally incident to transportation. The inspectors will review the additional information provided by the licensee and determine the significance of the performance deficiency.
05000263/FIN-2011004-022011Q3MonticelloFailure to Follow Emergency Diesel Generator Quarterly Surveillance ProcedureThe inspectors identified a finding of very low safety significance and an associated non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, when the licensee failed to follow the quarterly emergency diesel generator (EDG) surveillance procedure during testing of the EDG air start system. Specifically, the licensee failed to follow a procedural step that involved in-service testing of a check valve in the EDG air start system that, if degraded, could allow air to bleed out of the starting air tanks which are required for diesel generator operability. The licensee entered this issue into their corrective action program (CAP), and corrective actions for this issue included suspension of the test, performance of a Human Performance Investigation Team review, and disqualification of the individual performing the test. The inspectors determined that the contributing cause that provided the most insight into the performance deficiency was associated with the cross-cutting area of Human Performance, having work practices components, and involving aspects associated with using human error prevention techniques during performance of work activities. (H.4(a)) The inspectors determined that the licensees failure to follow their EDG surveillance procedure was a performance deficiency, because it was the result of the failure to meet a requirement; the cause was reasonably within the licensees ability to foresee and correct; and should have been prevented. The inspectors screened the performance deficiency per Inspection Manual Chapter (IMC) 0612, Power Reactor Inspection Reports, Appendix B, and determined that the issue was more than minor because the performance deficiency was associated with the Human Performance attribute of the Mitigating Systems Cornerstone and affected the cornerstones objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). As a result, this finding was evaluated under the Mitigating Systems Cornerstone. The inspectors applied IMC 0609, Attachment 4, Phase 1 Initial Screening and Characterization of Findings, to this finding. The inspectors utilized Column 2 of the Table 4a worksheet to screen the finding. The finding was determined to have very low safety significance because the inspectors answered No to all five questions.
05000263/FIN-2011004-012011Q3MonticelloNOED for Emergency Diesel Generator Load Rejection Surveillance Requirement 3.8.1.7On September 27, 2011, during an engineering self-assessment, the licensee identified a potential issue associated with the testing methodology used to demonstrate each EDGs capability to withstand the rejection of an electrical load that is equivalent to the single largest post-accident electrical load. On September 29, 2011, the licensee verified that their existing surveillance test OSP-ECC-0566, Low Pressure ECCS (emergency core cooling system ) Automatic Initiation and Loss of Auxiliary power Test, Revision 8, did not ensure that the load rejection test was performed with sufficient load to satisfy the requirements of SR 3.8.1.7 (Verify each EDG rejects a load greater than or equal to its associated single largest post-accident load and, following load rejection, the frequency is less than or equal to 67.5 Hz.). On September 29, 2011, at approximately 1700, the licensee declared both 11 and 12 EDGs inoperable and entered the Action for TS 3.8.1.E, Two EDGs Inoperable. At approximately 2200, the licensee requested enforcement discretion to extend the Action Completion Time for TS 3.8.1.F, from twelve hours to five days, to allow time to perform the required EDG load rejection testing. At approximately 23:58, the Agency granted NOED 11-3-001. The inspectors evaluation of the issue included a review of the technical documents associated with the issue and several meetings with the licensee management and technical staff. The initial information gained by the inspectors and their assessment of the issue was communicated to senior agency managers well in advance of the licensees NOED request, significantly contributing to the Agencys understanding and appropriate disposition of the issue. Additional information associated with the inadequate surveillance procedure and EDG operability is documented in Section 1R15 of this report.
05000373/FIN-2011008-022011Q3LaSalleFailure to Implement A Corrective Action To Prevent Recurrence to Address a Significant Condition Adverse to QualityA finding of very low safety significance and associated NCV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, was identified by the inspectors for the licensees failure to develop and implement adequate corrective action to prevent recurrence (CAPR) in response to a significant condition adverse to quality (SCAQ) associated with work activities on the 1D RHR service water (WS) pump. The licensee entered this issue into their CAP as IR 1241118. The finding was considered more than minor because it impacted the Reactor Safety Mitigating Systems Cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences and affected the cornerstone attribute of Equipment Performance. Specifically, the inadequate corrective action allowed for recurrence of this issue during similar work on other safety-related components. A cross-cutting aspect associated with Problem Identification and Resolution was also assigned to this finding.
05000373/FIN-2011004-012011Q3LaSalleNon-Conservative Voltage Input for Motor Starting CalculationsThe inspectors identified a finding of very low safety significance (Green) and associated NCV of Title 10 Code of Federal Regulations (CFR) Part 50, Appendix B, Criterion III, Design Control, involving the licenseei12s failure to perform adequate analysis to demonstrate that safety-related motors would start during a design basis event. The licensee entered this issue into the corrective action program (CAP) as Action Report (AR) 01139601 and conducted preliminary analysis to verify operability. The licenseei12s failure to perform adequate analysis to demonstrate that motors would start during block loading was determined to be more than minor because there was reasonable doubt as to whether motors which are required to start at the onset of an accident would have adequate voltage to start, pending reanalysis. The inspectors determined that this was a design deficiency that did not result in loss of operability or functionality; and therefore, the finding was of very low safety significance (Green). This finding was determined not to have a cross-cutting aspect
05000263/FIN-2011002-052011Q1MonticelloContainment Overpressure Not Ensured in the Appendix R AnalysisThe licensee issued Licensee Event Reports (LER 05000263-2009-001-00 and LER 05000263-2009-001-01) regarding the licensees failure to consider the spurious opening and venting of the primary containment, via purge and vent valves, in the event of a fire in the main control room or cable spreading room. Both LER revisions were closed in Inspection Report 05000263/2009004 and documented as a violation of NRC requirements. Because the licensee was transitioning to NFPA 805 and the violation met the criteria established by the NRC Interim Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection Issues (10 CFR Part 50.48(c)) for licensee in NFPA 805 transition, the NRC exercised enforcement discretion to not cite the violation in accordance with the NRCs Enforcement Policy. On December 22, 2010, the licensee provided an update to LER 05000263-2009-001-02 to reflect their withdrawal of the letter of intent to voluntarily implement 10 CFR 50.48(c) at the MNGP. On May 14, 2009, the NRC issued EGM 09-002, Enforcement Discretion for Fire Induced Circuit Faults, dated May 14, 2009, which authorized enforcement discretion for non-compliance issues associated with fire induced multiple circuit cable faults, providing that the licensee identified the non-compliances, entered them into their CAPs, and instituted appropriated compensatory measures until the issues were corrected, within the six month period following a planned revision to RG 1.189, Fire Protection for Nuclear Power Plants. Regulatory Guide 1.189, Revision 2, issued in October 2009, provided a method acceptable to the NRC to evaluate and resolve multiple fire induced circuit faults. After the six month period designated for the identification of non-compliances, the EGM further authorized enforcement discretion for an additional 30 month period, for licensees to resolve the identified multiple fire-induced circuit fault issues. The inspectors screened this violation and determined that because the violation was associated with multiple fire induced circuit faults and was identified during the discretion period as described in EGM 09-002, the NRC is exercising enforcement discretion for this violation in accordance with EGM 09-002.
05000373/FIN-2010006-052011Q1LaSalleFast Bus Transfer AnalysisThe team identified an unresolved issue (URI) related to the licensee s failure to use worst case voltage for motor starting calculations. Specifically, the licensee assumed voltage near to the administratively controlled minimum offsite voltage rather than the voltage afforded by the setpoint of the DV relay defined in the TS. The original NRC Safety Evaluation Report, NUREG-0519, dated March 1981 - Section 8.2.2.2, Low And/Or Degraded Grid Voltage Condition required the implementation of a second level undervoltage scheme to protect safety-related loads and stated, in part, the voltage and time setpoints will be determined from analysis of voltage requirements of the safety-related loads. Updated Final Safety Analysis Report 8.2.3.2.2, Criteria for Acceptable Voltage states in part, The minimum acceptable level (i.e., starting voltage) for safety-related motors is based on the minimum equipment terminal voltages postulated at the lower analytical limit or design basis of the second-level undervoltage protection setpoint. LaSalle TS Table 3.3.8.1 specified the Allowable Value for the degraded-voltage relay voltage setpoint as Y3814V and U3900V. Calculation AN71 also defined the Analytical Limit for the degraded voltage relay as 3814V (approximately 91.7 percent of 4160V). The team determined that Calculation L-003364 only analyzed steady state motor running and individual motor starting with 3814V on the safety bus. The calculation did not consider or analyze block loading at the worst case voltage allowed by the Technical Specification setpoint without disconnecting from offsite power. The team calculated the lowest value the relay will reset is at 3833V. This value reflects the vendor\\\'s specified dropout to reset ratio for the relay of 99.5 percent and the Technical Specification setpoint of 3814V (3814/0.995=3833). Therefore, based on a Technical Specification analytical limit of 3814V, a reset ratio of 99.5 percent, and block loading conditions, the lowest voltage that can occur on the bus immediately following block loading, without separating from the grid will be 3833V. The team noted that Calculation L-003364 analyzed motor starting voltage during block loading using a switchyard voltage input of 352kV, which was intended to bound the minimum expected switchyard voltage of 354kV, defined in UFSAR 8.2.3.2, Adequacy of Offsite Power. This resulted in safety bus voltage of approximately 3960V vs. the analytical limit of 3814V. The team determined that the corresponding switchyard voltage for a fully loaded safety bus at 3833V is 341.5kV, which is considerably below the value used by the licensee in their calculation of 352kV. Since licensee s approach was not consistent with UFSAR 8.2.3.2.2 which states that motor starting voltage was based on lower analytical limit or design basis of the second level undervoltage protection setpoint, the team concluded that the block motor starting results in Calculation L-003364 were non conservative by approximately 3 percent. In response to the teams concerns, the licensee stated that the LaSalle licensing basis did not require postulating a concurrent LOCA and degraded voltage condition. After consultation with NRR and review of the LaSalle licensing record, including FSAR Question 40.102 and NUREG-0519, they concluded that the licensee s position was incorrect. During the inspection, the licensee performed preliminary calculations using the electrical transient analysis program (ETAP) and voltages based on the degraded voltage relay settings. These calculations showed that the safety related motors would start and accelerate satisfactorily. Based on these preliminary calculations the team concluded that this finding did not represent an operability concern. On November 12, 2010, the licensee issued IR 01139601 to determine whether the block start, at a bus voltage of 3833V (minimum degraded voltage relay reset afforded by the degraded voltage protection scheme), is part of the LaSalle design basis. On December 15, 2010, engineering initiated action item IR 01139601-03 to perform a formal analysis at a switchyard voltage that results in a recovery voltage at the minimum degraded voltage relay reset of approximately 3833V, at the 4 kV buses and revise Calculation L-003364 accordingly. Concerning this finding, the licensee stated that the NRC previously reviewed License Amendment number 135/120 and the associated Safety Evaluation Report (SER) and concluded that the setpoint change for the undervoltage relay was acceptable. However, the team could not identify in the SER that the NRC specifically reviewed the licensee s motor block start analysis at the worst case bus voltage of 3833 Vac (minimum degraded voltage relay reset value). This issue is considered unresolved pending resolution of differences in interpretation between the NRC and the licensee of the original licensing basis concerning motor-block- starting analysis. (URI 05000373/2010006-05; 05000374/2010006-05, Non-Conservative Voltage Input for Motor Starting Calculations.)
05000373/FIN-2011002-022011Q1LaSalleFailure to Follow Plant Barrier Control Process Caused Secondary Containment to Become InoperableA 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 follow steps 3.6 and 3.7 of procedure CC-AA-201, Revision 8, Plant Barrier Control Program. Specifically, two airlock doors were opened simultaneously for a period of time sufficient to allow reactor building air pressure to surpass the TS allowed value for operability of secondary containment. The licensee entered this issue into its CAP as action requests (ARs) 1182255 and 1195987, and, at the time of this report, was in the process of conducting an apparent cause evaluation to determine the causes of the occurrence and to develop corrective actions. The finding was determined to be more than minor because it was associated with the Barrier Integrity Cornerstone attribute of configuration control and affected the cornerstone objective of providing reasonable assurance that physical design barriers (secondary containment) protect the public from radionuclide releases caused by accidents or events. The inspectors performed a Phase 1 SDP review of this finding using the guidance provided in IMC 0609, and a Region III SRA continued the risk assessment using IMC 0609, Appendix H, Containment Integrity Significance Determination Process. For Unit 1, since an open pathway existed to the environment from the secondary containment, the SRA performed a Phase 2 SDP analysis using the Appendix H guidance. For Unit 2, the SRA performed a Phase 1 SDP analysis using Figure 6.2, Road Map for LERF (Large Early Release Frequency)-based Risk Significance Evaluation for Type B Findings at Shutdown. The SRA concluded that the total risk associated with this finding is very low and best characterized as Green. This finding has a cross-cutting aspect in the area of Human Performance, Work Control, because the licensee did not appropriately coordinate work activities by incorporating actions to address the impact of the work on different job activities, and the need for work groups to communicate, coordinate, and cooperate with each other during activities in which interdepartmental coordination is necessary to assure plant and human performance (H.3(b)).
05000263/FIN-2011002-012011Q1MonticelloInadequate System Isolation during Check Valve MaintenanceA finding of very low safety significance and associated NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was self-revealed when the licensee failed to adequately implement the requirements of their fleet tagging procedure, a procedure affecting quality, during maintenance on the safety-related CST-88 B low pressure coolant injection (LPCI) fill line check valve. This failure resulted in an unintentional breach of the condensate service water (CSW) system and subjected workers to a potentially contaminated, pressurized water source. Additionally, at the time of the breach, the CSW system was one of the water sources being credited in support of the shutdown safety function of inventory control. The licensee entered this issue into the corrective action program (CAPs 1275935 and 1275963) and took immediate corrective actions to restore the check valve to its installed configuration to terminate the water leakage. At the time of this report, the licensee had assembled a team to perform a root cause evaluation. The inspectors determined that the licensees failure to adequately implement their tagging process to protect workers and equipment from the effects of breaching the pressurized CSW header during maintenance on a safety-related check valve was a performance deficiency because it was the result of the failure to meet a requirement, the cause was reasonably within the licensees ability to foresee and correct, and should have been prevented. The inspectors screened the performance deficiency per IMC 0612, Power Reactor Inspection Reports, Appendix B, and determined that the issue was more than minor because the performance deficiency could have reasonably been viewed as a precursor to a more significant event. In this instance, the performance deficiency resulted in an unintentional breach of the operating CSW system and subjected workers to a potentially contaminated, pressurized water source. Additionally, at the time of the breach, the CSW system was one of the water sources being credited in support of the shutdown safety function of inventory control. As a result, this finding was evaluated under the Initiating Events Cornerstone. The inspectors applied NRC IMC 0609, Significance Determination Process, Appendix G, Shutdown Operations Significance Determination, Attachment 1, to this finding. The finding was determined to have very low safety significance because it did not adversely affect core heat removal, inventory control, power availability, containment control, or reactivity guidelines. This finding has a cross-cutting aspect in the area of Human Performance, work control, because the licensee failed to appropriately plan work activities by incorporating job site conditions impacting plant systems and components (H.3(a)).
05000263/FIN-2011002-032011Q1MonticelloFailure to Control a Level 1 FME Area during New Fuel Receipt ActivitiesA finding of very low safety significance and associated NCV of Technical Specification 5.4, Procedures, was identified by the inspectors when the licensee failed to implement the requirements of their foreign material exclusion (FME) and control procedure during new fuel receipt activities. Specifically, the inspectors observed two operators exiting and re-entering a Level 1 FME area, without the knowledge of the FME monitor, at a point that was not being controlled by the FME monitor. When informed of the issue, the licensee took corrective actions to address the issue. The inspectors determined that the licensees failure to adequately implement the requirements of their FME control procedure during new fuel receipt activities to prevent the unmonitored access of two operators into a Level 1 FME area was a performance deficiency because it was the result of the failure to meet a requirement or a standard, the cause was reasonably within the licensees ability to foresee and correct, and should have been prevented. The inspectors screened the performance deficiency per IMC 0612, Power Reactor Inspection Reports, Appendix B, and determined that the issue was more than minor because it impacted the human performance attribute of the Barrier Integrity Cornerstones objective to provide reasonable assurance that physical design barriers (fuel cladding, reactor coolant system, and containment) protect the public from radionuclide releases caused by accidents or events. The inspectors applied IMC 0609, Attachment 4, Phase 1 Initial Screening and Characterization of Findings, to this finding. The inspectors utilized Column 3 of the Table 4a worksheet to screen the finding. Since the finding only had the potential to impact the fuel barrier, it screened to be of very low safety significance. This finding has a cross-cutting aspect in the area of Human Performance, Work Practices because the licensee did not define and effectively communicate expectations regarding procedural compliance and personnel following procedures (H.4(b)).
05000263/FIN-2011002-042011Q1MonticelloLicensee-Identified ViolationTechnical Specification LCO 3.0.4 states, in part, that when an LCO is not met, entry into a MODE in the applicability shall only be made when the associated ACTIONS to be entered permit continued operation in the MODE or other specified condition in the applicability for an unlimited period of time. Technical Specification LCO 3.6.1.3, Primary Containment Isolation Valves (PCIVs), states, in part, that each PCIV, except reactor building-to-suppression chamber vacuum breakers, shall be OPERABLE in MODES 1, 2, and 3, when associated instrumentation is required to be OPERABLE per LCO 3.3.6.1, Primary Containment Isolation Instrumentation. Technical Specification LCO 3.3.6.1 states, in part, that the primary containment isolation instrumentation for Function 1, Main Steam Line Isolation, shall be OPERABLE for the Reactor Vessel Water Level Low Low, Main Steam Line Flow High, and Main Steam Line Tunnel Temperature High functions in MODES 1, 2, and 3. Contrary to the requirement of TS LCO 3.0.4, on November 22, 2010, the inboard and outboard main steam line PCIVs were not operable (unable to automatically close on a primary containment isolation signal due to an electrical isolation) prior to entering Mode 2, and the associated actions to be entered did not permit continued operation in Mode 2 for an unlimited period of time. Once identified, the licensee restored electrical power to the PCIVs and entered the issue into the corrective action program as CAP 01259879. The inspectors applied IMC 0609, Attachment 4, Phase 1 Initial Screening and Characterization of Findings, to this finding. Using the Table 4a worksheet, the inspectors answered Yes to Question 3 and applied IMC 0609, Appendix H, Containment Integrity Significance Determination Process. Per IMC 0609, Appendix H, the finding was considered a Type B finding; that is, a finding that has potentially important implications for integrity of containment without affecting the likelihood of core damage. Table 6.2, Phase 2 Risk Significance Type B Findings at Full Power, provided the risk significance for this finding. For BWR Mark I reactor types, the significance of Type B findings for less than three days duration is Green.
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