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05000266/FIN-2013003-052013Q2Point BeachFailure to Implement Risk Management Actions During Bus D-40 OutageA self-revealed finding of very low safety significance and an associated non-cited violation of 10 CFR 50.65(a)(4) occurred on April 29, 2013, as a result of the licensees failure to properly manage and assess risk during a scheduled maintenance outage for emergency diesel generator G-04. Specifically, not all ongoing maintenance activities had been taken into account in the risk assessment for the in-progress maintenance activities and an unplanned entry into yellow risk occurred when they isolated bus D-40. The licensee entered this issue into the CAP as action request AR01870208. Corrective actions for this issue included restoring bus D-40 to service and initiating an evaluation of the issue through the condition reporting process. The inspectors determined the finding to be more than minor because it was similar to Example 7.e of IMC 0612, Appendix E, Example of Minor Issues, dated August 11, 2009, and because it was associated with the Design Control attribute of the Mitigating Systems Cornerstone. The finding also affected the Cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors evaluated the finding using IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, Tables 2 and 3, and Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process. The inspectors determined that the finding was a mitigating systems contributor; evaluated the risk deficit for each instance; and found that the issue screened as having very low safety significance. The inspectors determined that the finding has a cross-cutting aspect in the area of human performance, work control, because the licensee failed to appropriately plan and coordinate work activities. Specifically, when the licensee attempted to remove bus D-40 isolation work from the work schedule, the work package was not updated to reflect the change; and there was a failure to communicate and/or coordinate the changes in the work scope to the appropriate groups (H.3(b)).
05000266/FIN-2013003-062013Q2Point BeachFailure to Account for Plant-Specific Maintenance History in the Development of Preventive Maintenance FrequencyThe inspectors identified a finding of very low safety significance and an associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion V for the licensees failure to follow procedure FP-PE- 90-01, Preventive Maintenance Program. Specifically, in 2009, when setting the preventive maintenance frequency for containment isolation valve 1MS-02083, t he licensee determined that a 15-year frequency was appropriate instead of the recommended 10 years. The licensees justification was based on internal maintenance history showing good performance. However, the inspectors review revealed that the maintenance history for this category of valves did not support this determination. The valve subsequently failed during surveillance on March 21, 2013, after 13 years of service. The licensee entered this issue into the CAP as AR01858451; corrective actions included replacing the valve and an action to review the preventive maintenance frequencies of critical solenoid-operated valves. The inspectors determined that the finding was more than minor in accordance with IMC 0612, Appendix B, because it was associated with the Barrier Performance attribute of the Barrier Integrity Cornerstone, and adversely affected the Cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. The inspectors evaluated this finding using IMC 0609, Appendix G, Shutdown Operations Significance Determination Process, Checklist 3, and determined that the finding was of very low safety significance because the inspectors determined that a quantitative assessment was not required. The inspectors did not identify a cross-cutting aspect associated with this finding because the finding did not reflect current performance due to the age of the performance deficiency.
05000266/FIN-2013003-072013Q2Point BeachLicensee-Identified ViolationTitle 10 CFR 50.54(q)(2) requires that a holder of a nuclear power reactor operating license follow and maintain the effectiveness of an emergency plan that meets the requirements in Appendix E to this part and the planning standards of 10 CFR 50.47(b). The Point Beach Nuclear Plant Emergency Plan Implementing Procedure EPIP 1.2, Emergency Classification, Section 5.1 states in part, Review the basis for the selected Emergency Action Level (EAL) to determine/confirm that the EAL applies, and, if an event meets the threshold of the EAL, then classify the emergency. Contrary to the above, on April 25, 2012, the licensee failed to follow its Emergency Plan during an actual emergency and that resulted in a failure to properly implement EALs. Specifically, inaccurate communications resulted in the over classification of an alert emergency classification level based on (EAL) HA3.1. Using Manual Chapter 0609, Appendix B, Emergency Preparedness Significance Determination Process, dated February 24, 2012, Section 4.0 Actual Event Implementation Issue (Failure to Implement), and the inspectors determined that the violation was not greater than very low safety significance (Green) because no public official protective actions were implemented as a result of this event over classification. The issue is documented in the licensees Corrective Action Program as AR 01759720.
05000266/FIN-2013003-082013Q2Point BeachLicensee-Identified ViolationThe licensee identified a finding of very low safety significance (Green) and an associated NCV of Limiting Condition for Operability (LCO) 3.0.4. Licensee LCO 3.0.4 states in part, When an LCO is not met, entry into a MODE or other specified condition 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. Contrary to this, on April 14, 2013, the Unit 1 entered Mode 4 with the Spray Additive System inoperable and LCO 3.6.7 did not permit continued operation in Mode 4 with the system inoperable. Specifically, the outage senior reactor operator elected to walkdown all existing tags prior to Uni1 transitioning from Mode 4 to Mode 3. The senior reactor operator identified a tag was hung on 1SI-831A, Spray Additive Tank Outlet Valve, and was unsure about the purpose of the tag because the system was required to be operable in Mode 4. Investigations showed that the tag should have been removed prior to entry into Mode 4, but was left hung due to a sequencing error between the Mode change checklist and the tagging process. The licensee immediately entered the LCO 3.6.7, Spray Additive System, restored the system alignment and exited the LCO; this evolution lasted approximately 16 minutes. This issue was entered into the licensees CAP as AR01865777 and immediate corrective actions to restore the system to operable were taken, and a root cause evaluation was assigned. The inspectors determined the performance deficiency to be more than minor in accordance with IMC 0612, Appendix B, because it was associated with the configuration control attribute of the Mitigating Systems Cornerstone. The finding also affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, with the Spray Additive Tank outlet valve closed it rendered the Spray Additive System inoperable in Mode 4. The inspectors and the R-III Senior Reactor Analyst reviewed IMC 0609, Significance Determination Process, Appendix G, Shutdown Operations Significance Determination Process, and determined that a Quantitative Assessment was not required; close spaces the issue was of very low safety significance.
05000266/FIN-2014004-012014Q3Point BeachFailure to Identify Degraded Water Sprinkler SystemThe inspectors identified a finding of very low safety significance and associated NCV of license condition 4.F for the licensees failure to identify a degraded water sprinkler system in the service water pump room and implement hourly fire watch inspections. Specifically, the licensee installed scaffolding in the service water pump room that interfered with the operation of the water sprinkler system and failed to implement hourly fire watch inspections as a compensatory measure. The licensee began fire watch inspections and credited installed fire hoses in the area for backup suppression until the planking could be removed from the scaffolding. The finding was determined to be more than minor because the failure to identify the degraded sprinkler system and implement compensatory fire watch inspections was associated with the Mitigating Systems cornerstone attribute of Protection Against External Events (Fire) and affected the cornerstone objective of preventing undesirable consequences (i.e., core damage). In accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, Table 2, the inspectors determined the finding affected the Mitigating Systems cornerstone. The finding degraded fire protection defense-in-depth strategies, and the inspectors determined, using Table 3, that it could be evaluated using Appendix F, Fire Protection Significance Determination Process. The inspectors screened the issue to Green under the Phase 1 Screening Question 1.3.1A, because the inspectors determined that the impact of a fire would be limited to one train/division of service water pumps and a credited safe shutdown path would be unaffected. This finding has a cross-cutting aspect of Procedure Adherence (H.8), in the area of human performance, because the licensee did not follow processes, procedures, and work instructions.
05000266/FIN-2014004-022014Q3Point BeachFailure to Perform Required Fire Watch InspectionsThe inspectors identified a finding of very low safety significance and associated NCV of license condition 4.F for the failure to conduct required fire watch inspections. Specifically, the licensee failed to inspect multiple fire zones at the correct frequency and to identify work activities that could introduce potential ignition sources, combustible materials, and other abnormal activities that could introduce an increased likelihood of a fire starting in the fire zone. The licensee implemented short term corrective actions, which included issuing guidance to personnel that prescribed a specific route and general timeframe for performing fire watch inspections, as well as, requiring the fire watches to initial for each individual fire zone for each inspection. The finding was determined to be more than minor because the failure to conduct the required fire watch inspections was associated with the Initiating Events cornerstone attribute of Protection Against External Events (Fire) and affected the cornerstone objective of preventing undesirable consequences (i.e., core damage). The inspectors evaluated the finding in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Screening and Characterization of Findings, Table 3, SDP Appendix Router. In Question 2 of Section E, Fire Protection, the inspectors answered "Yes" to the screening question Does the finding involve: 1) A failure to adequately implement fire prevention and administrative controls for transient combustible materials, transient ignition sources, or hot work activities? Therefore, a detailed risk evaluation was performed by the Senior Reactor Analysts (SRAs) using IMC 0609, Appendix F, Fire Protection Significance Determination Process, and the licensees preliminary NFPA805 analyses as described in Section 1R05.1. Based on the detailed risk evaluation, the SRAs determined that the finding was of very low safety-significance. This finding has a cross-cutting aspect of Avoid Complacency (H.12), in the area of human performance, for failing implement appropriate error reduction tools.
05000266/FIN-2014004-032014Q3Point BeachDeficiencies in Calculation Performed to Support Containment Dome Truss OperabilityThe inspectors identified a finding of very low safety significance for deficiencies in licensees calculation performed to support operability of the unit 1 containment building dome truss and the safety related components supported from the truss. The licensee reassessed the dome truss members and connections that were found to be highly stressed and concluded that the components remained within the acceptable limits. The licensee initiated action request (AR) 01986069 to capture the concern identified by the inspectors and revised the POD. The finding was determined to be more than minor because the finding is associated with the reactor coolant system (RCS) Equipment and Barrier Performance Attribute of the Barrier Integrity cornerstone and adversely affected the cornerstone objective of providing reasonable assurance that physical design barriers (fuel cladding, reactor coolant system, and containment) protect the public from radionuclide releases caused by accidents or events. Specifically, failure of the dome truss could impact the reliability/availability of the containment spray system to maintain operability of the containment. Additionally, More than Minor Example 3.j of IMC 0612, Appendix E, Examples of Minor Issues, was used to inform the answer to this more than minor screening question. Specifically, the licensees failure to address torsional effects and use of non-conservative allowable stress values for evaluation of containment dome truss components, at the time of discovery, resulted in reasonable doubt of the operability of the subject walls. In accordance with IMC 0609, Significance Determination Process, Attachment 4, Initial Characterization of Findings, Table 2, the inspectors determined the finding affected the Barrier Integrity cornerstone. As a result, the inspectors determined the finding could be evaluated using IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 3. Because the finding did not represent an actual failure of a component required to maintain containment integrity, the inspectors answered No to Screening Questions 1 and 2 for the Reactor Containment section, and determined the finding was of very low safety significance. This finding has a cross-cutting aspect of Conservative Bias (H.14) in the area of human performance for the licensees failure to use conservative decision making practices in the operability evaluation of the containment dome truss.
05000266/FIN-2014004-042014Q3Point BeachIncomplete Prompt Operability Determination of Non-Seismic Block WallThe inspectors identified a finding of very low safety significance due to the licensees failure to follow procedure ENAA2031001, Operability Determinations/Functionality Assessments. Specifically, when the licensee identified that the north non-vital switchgear (NVSGR) block wall was found to be non-seismic and potentially susceptible to collapsing and blocking the flood relief dampers, they failed to evaluate all potential water sources that could spray or flood the NVSGR and cascade into the vital switchgear room below. Following questions by the inspectors, the licensee evaluated the additional water sources; isolated two additional fire protection hose reels on the south side of the NVSGR; and updated the prompt operability determination (POD). The finding was determined to be more than minor because the failure to evaluate and disposition each potential flood source in the POD was associated with the Mitigating Systems cornerstone attribute of Protection Against External Events (Seismic) and affected the cornerstone objective of preventing undesirable consequences (i.e., core damage). The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, dated June 19, 2012, and Appendix A, The Significance Determination Process for Findings At-Power, Exhibit 4, External Events Screening Questions, dated June 19, 2012. The inspectors answered Yes to question 1 of External Events screening questions since the finding could potentially degrade one train of the emergency power system. The inspectors consulted the regional SRA, who completed a detailed risk evaluation, and determined that the finding was of very low safety-significance. This finding has a cross-cutting aspect of Identification (P.1), in the area of problem identification and resolution, for failing to identify issues completely, accurately, and in a timely manner in accordance with the program.
05000266/FIN-2014005-022014Q4Point BeachLicensee-Identified ViolationThe licensee identified a NCV of TS 5.4.1, Procedures for the failure to follow the defined heavy load shipping path inside containment as specified in procedure, SLP1, Safe Load Path and Rigging Manual, which resulted in the movement of the polar crane main block over exposed reactor fuel. The licensees TS 5.4.1 required, in part, that written procedures shall be implemented covering refueling activities. The licensees refueling procedure governing the movement of the unit 1 containment crane was SLP1, which described the predefined safe load travel paths and laydown areas in containment during refueling operations that have been pre-analyzed per the FSAR and NUREG0612. Procedure SLP1 stated that the main load block of the polar crane was considered a heavy load because it is not single failure proof and weighed approximately 8,550 pounds; and therefore, shall not be moved over the reactor vessel when the head is removed and fuel is in the vessel, with the exception to lift the vessel internals. Contrary to the above, on October 11, 2014, while unit 1 was in mode 6 with the reactor vessel head removed, the cavity flooded in excess of 23 feet, and irradiated fuel in the reactor vessel during defueling; the licensee moved the main load block of the polar crane over the reactor vessel during the performance of daily crane checks. The licensee entered this issue into the CAP as AR 01998150 and AR 02020076. The inspectors determined that this issue was of very low safety significance (Green) after reviewing IMC 0609, Appendix G, Shutdown Operations Significance Determination Process, Attachment 1, dated May 9, 2014. The inspectors answered "No" to all questions in Exhibit 2 for Initiating Events. Therefore the finding screened as Green (very low safety significance).
05000266/FIN-2014005-032014Q4Point BeachLicensee-Identified ViolationThe licensee identified a NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure to incorporate vendor torque specifications into applicable maintenance procedures for all four of the plants EDGs. On October 25, 2014, during a fast start test of the G01 EDG, a six-inch expansion joint coupling on the engines jacket water system began leaking upon start, and stopped leaking shortly after the EDG reached rated speed. The licensee found upon initial investigation that the coupling band, which secured the joint assembly together, was less than snug tight. The licensee identified this condition in AR 02002147 and noted that the facilitys maintenance procedures, RMP 9043 series procedures, did not contain a torque value for this and other similar couplings located on EDG components. On November 7, 2014, during a monthly run of the G04 EDG, the six-inch engine jacket water coupling began leaking in a similar fashion to that as the above described leak for the G01 EDG. The licensee identified this condition in AR 02005324 and AR 02005443. These ARs included an attachment, vendor technical information, which specified torque values for the couplings of concern. On November 17, 2014, the licensee initiated AR 02007284 which stated that the licensees system engineering had the vendor information with the torque values since December 2012, but had not initiated changes to the EDG maintenance procedures until the November 7, 2014 condition was discovered. Title 10 CFR Part 50, Appendix B, Criterion V, requires, in part, that activities affecting quality be prescribed and accomplished by procedures appropriate to the circumstance, and in accordance with those instructions and procedures. Additionally, instructions and procedures shall include appropriate quantitative or qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished. Contrary to the above, from December 2012 to November 7, 2014, the licensees RMP 9043 series procedures did not contain final torque values for the flexible fittings used in the EDGs jacket water cooling and oil systems. The licensee entered this issue into the CAP as AR 02007284 and AR 02020080, and initiated procedure changes to incorporate the torque specifications for these fittings. Additionally, the licensee updated future WOs to perform torque checks on these fittings prior to the next EDG maintenance runs. The inspectors determined that this issue was of very low safety significance (Green) after reviewing IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, dated July 1, 2012 and IMC 0609, Appendix A, The Significance Determination Process For Findings At-Power, dated July 1, 2012. The inspectors answered "NO" to all questions in Exhibit 2, Section A, Mitigating structures systems components (SSCs) and Functionality. Therefore, the finding screened as very low safety significance (Green).
05000266/FIN-2014005-042014Q4Point BeachLicensee-Identified ViolationThe licensee identified a finding of very low safety significance (Green) and associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, which requires, in part, that activities affecting quality shall be accomplished in accordance with instructions, procedures, and drawings. During the performance of WO 40118062, on breaker B52DB50078, the licensee failed to correctly perform the steps in section 5.4.5 of procedure RMP 9303, DB50 Breaker Routine Maintenance. Procedure RMP 9303 inspected and bent as necessary, the control relay contacts for the breaker to obtain the proper contact alignment. The breaker was subsequently installed and used in the P32C SW pump breaker cubicle, 1B5220C, and failed to close on May 29, 2014, during surveillance testing. The licensee concluded that oxide buildup on the control relay contacts had prevented them from making up, which prevented the breaker from closing. The oxide buildup was the result of improper contact alignment, which inhibited the proper wiping action needed to clean the contacts each time they were cycled. The licensee concluded, based on the contact arms being rigid, that the misalignment was present since the new control relay was installed and RMP 9303 performed in July 2012. Title 10 CFR Part 50, Appendix B, Criterion V, requires, in part, that activities affecting quality shall be accomplished in accordance with instructions, procedures, and drawings. RMP 9303 is the licensees procedure containing instructions for the inspection and adjustment of safety-related control relay contacts, an activity affecting quality. Contrary to the above, between July 11, 2012 and July 24, 2012, the licensee failed to properly complete RMP 9303 Section 5.4.5, which required the licensee to inspect and adjust contacts to ensure that the contacts had the appropriate gap, contacted in the appropriate sequence, and contacted in the approximate center. The inspectors determined that this issue was more than minor as it impacted the equipment performance attribute of the Mitigation Systems Cornerstone. The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, dated June 19, 2012, and Appendix A, The Significance Determination Process for Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, dated June 19, 2012. Since the breaker operated successfully on May 7 and failed to operate on May 29, the inspectors answered "Yes" to the mitigating systems screening question number 3, and consulted regional senior risk analysts to perform a detailed risk evaluation. The senior risk analysts performed a detailed risk evaluation for the finding as described below. Since the time of actual failure of the breaker for the P32C SW pump cannot be determined, a T/2 evaluation provides an exposure time of 11 days (i.e., 22 days from May 7, 2014 to May 29, 2014 divided by 2 or 11 days). The T/2 exposure time is appropriate based on Risk Assessment Standardization Project manual guidance. The Point Beach Standardized Plant Analysis Risk model version 8.22, Systems Analysis Programs for Hands-on Integrated Reliability Evaluations (SAPHIRE) version 8.1.2 software, and the Support System Initiating Event (SSIE) methodology that is incorporated into the Standardized Plant Analysis Risk model was used to obtain a CDF of 1.29E7/yr for internal events for the failure-to-start of the P32C SW pump due to the breaker failure. The dominant core damage sequences involve a loss-of-offsite-power (LOOP) with the failure of AFW and the failure of high pressure recirculation. Since the total estimated change in core damage frequency was greater than 1.0E7/yr, an evaluation was performed for external event delta risk contributions. The total CDF was found to be the sum of the CDF contributions from internal events, fire, and seismic or 4.46E7/yr (i.e., 1.29E7/yr + 3.21E7/yr + 8.4E11/yr = 4.50E7/yr). Large Early Release Frequency - Since the total estimated change in core damage frequency was greater than 1.0E7/yr, IMC 0609 Appendix H, Containment Integrity Significance Determination Process was used to determine the potential risk contribution due to large early release frequency. Each Point Beach Unit is a 2-loop Westinghouse Pressurized Water Reactor with a large dry containment. Sequences important to large early release frequency include steam generator tube rupture events and inter-system loss-of-coolant-accident events. These were not the dominant core damage sequences for this finding. Based on the Detailed Risk Evaluation, the inspectors determined that the finding was of very low safety-significance (Green). This issue was entered into the CAP as AR 01968602 and AR 02020073.
05000266/FIN-2014007-012014Q1Point BeachFailure to Take Corrective Actions to Address External Flooding Procedure DeficienciesThe inspectors identified a finding of very low safety significance and associated non-citied violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Actions, in that from March 13, 2013 until February 14, 2014, the licensee failed to assure that for a significant condition adverse to quality (SQAC), the cause of the condition was determined and corrective actions were taken to preclude repetition. Specifically, the licensees corrective actions failed to preclude repetition of an SQAC where Procedure PC 80 Part 7, Lake Water Level Determination, as implemented, would not protect safety-related equipment in the turbine building or Circulating Water Pump House (CWPH). After the licensee had taken corrective actions to improve the wave barrier procedure in response to an NRC-identified NOV, PC 80 Part 7 and other flood protection implementing procedures specified inadequate timelines to ensure wave run-up flood barriers would be installed prior to the lake level at which wave run-up could impact the site. Corrective actions for this issue included changing the affected procedures to install the wave barriers at a lower lake level, changing the lake level determination surveillance from monthly to weekly, and reducing the allowed installation time for the barriers from 3 weeks to 1 week. The performance deficiency was screened against the Reactor Oversight Process per the guidance of lMC 0612, Appendix B, and determined to be more than minor because the finding was associated with the Mitigating Systems Cornerstone attributes of Protection Against External Factors (Flood Hazard) and Procedure Quality, and adversely 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). Specifically, the licensees failure to correct procedural deficiencies associated with flood barrier construction timelines, could challenge the timely installation of the barriers, which could impact the ability of mitigating systems to respond during an external flooding event. The inspectors evaluated the finding using IMC 0609, Attachment 0609.04, Tables 2 and 3, and Appendix A. Based on a review of Appendix A, Exhibit 2, Item 4.B, the inspectors determined that this issue screened as having very low safety significance (Green). This finding has a cross-cutting aspect in the area of problem identification and resolution, because the licensee failed to thoroughly evaluate issues to ensure that resolutions address causes and extent of conditions commensurate with their safety significance.
05000266/FIN-2014007-022014Q1Point BeachFailure to Maintain External Flooding Procedure to Address All Possible CLB FloodsThe inspectors identified a finding of very low safety significance and associated non-citied violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, in that from January 19, 1996 until November 25, 2013, the licensee failed to ensure that activities affecting quality were prescribed by documented procedures of a type appropriate to the circumstances to address external flooding as described in the Final Safety Analysis Report (FSAR). Specifically, PC 80 Part 7, Lake Water Level Determination directed advanced installation of concrete barriers to protect against deep wave action from the lake, which introduced significant unrecognized blockages in the natural drainage path credited in the FSAR to protect against the probable maximum precipitation and Turbine Building internal flooding events. Corrective actions for this issue included changing the procedure and FSAR to include actions to provide an additional flood relief path through the CWPH building and reliance on internal flood relief dampers for the affected flooding events. The performance deficiency was screened against the Reactor Oversight Process per the guidance of lMC 0612, Appendix B, and determined to be more than minor because the finding was associated with the Mitigating Systems Cornerstone attributes of Protection Against External Factors (Flood Hazard) and Procedure Quality, and adversely 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). Specifically, the licensees failure to procedurally control external flooding design features to ensure they would not adversely affect the strategy for other flooding events, could negatively impact mitigating systems ability to respond during external and internal flooding events. The inspectors evaluated the finding using IMC 0609, Attachment 0609.04, Tables 2 and 3, and Appendix A, and determined a detailed risk evaluation was required. Following a detailed risk evaluation, Region III SRAs determined that the finding had very low safety significance (Green). This finding has a cross-cutting aspect in the area of problem identification and resolution, because the licensee failed to take effective corrective actions to address issues in a timely manner commensurate with their safety significance.
05000266/FIN-2014007-032014Q1Point BeachFailure to Perform a Required 10 CFR Part 50.59 EvaluationThe inspectors identified a finding of very low safety significance and associated Severity Level IV, non-citied violation of 10 CFR 50.59(d)(1), Changes, tests and experiments, when, on November 25, 2013, the licensee failed to perform an evaluation against the criteria in 10 CFR 50.59(c)(2) for a change to procedure PC 80 Part 7 to include actions to maintain functionality of drainage paths during probable maximum precipitation and turbine building flooding events. Specifically, PC 80 Part 7, Lake Water Level Determination was changed to include actions to open the CWPH rollup doors to provide an additional drainage path while wave barriers were in place, without fully evaluating the viability of reliance on additional flood features not credited for external flooding in the Current License Basis (CLB). Corrective actions for this issue included to updating the FSAR to describe the new flood paths, performing a 10 CFR 50.59 screening and 10 CFR 50.59 evaluation for the new drainage path which had put the site outside of the CLB, revising a related functionality assessment, controlling external flooding areas to ensure they are clear of debris, and creating a procedure to install curtains on the CWPH rollup doors during periods when they were required to be open. The inspectors determined that the licensees failure to fully evaluate the viability of newly created flooding drainage paths as required by 10 CFR 50.59(d)(1) was a performance deficiency. The inspectors evaluated the performance deficiency using traditional enforcement in conjunction with the SDP because the performance deficiency had the potential to impact the regulatory process. The performance deficiency was screened per the guidance of lMC 0612, Appendix B, and determined to be more than minor because the finding was associated with the Mitigating Systems Cornerstone attributes of Protection Against External Factors (Flood Hazard) and Design 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 (i.e. core damage). Specifically, the licensee did not fully demonstrate that the availability, reliability, and capability of mitigating systems would be maintained during flooding events due to the sites failure to evaluate the viability of alternate flood drainage paths through the CWPH. The inspectors evaluated the finding using IMC 0609, Attachment 0609.04, Tables 2 and 3, and Appendix A. Based on a review of Appendix A, Exhibit 2, Item 4.B, the inspectors determined that this issue screened as having very low safety significance (Green). Additionally, in accordance with Section 6.1.d.2 of the NRC Enforcement Policy, this violation is categorized as a Severity Level IV because the resulting conditions were evaluated as having very low safety significance (Green) by the SDP. This finding has a cross-cutting aspect in the area of problem identification and resolution, because the licensee failed to thoroughly evaluate issues to ensure that resolutions address causes and extent of conditions commensurate with their safety significance.
05000266/FIN-2014007-042014Q1Point BeachFailure to Perform a Required 10 CFR Part 50.59 EvaluationThe inspectors identified a finding of very low safety significance and associated Severity Level IV, non-citied violation of 10 CFR 50.59(d)(1), Changes, tests and experiments, when, on November 25, 2013, the licensee failed to perform an evaluation against the criteria in 10 CFR 50.59(c)(2) for a change to procedure PC 80 Part 7 to include actions to maintain functionality of drainage paths during probable maximum precipitation and turbine building flooding events. Specifically, PC 80 Part 7, Lake Water Level Determination was changed to include actions to open the CWPH rollup doors to provide an additional drainage path while wave barriers were in place, without fully evaluating the viability of reliance on additional flood features not credited for external flooding in the Current License Basis (CLB). Corrective actions for this issue included to updating the FSAR to describe the new flood paths, performing a 10 CFR 50.59 screening and 10 CFR 50.59 evaluation for the new drainage path which had put the site outside of the CLB, revising a related functionality assessment, controlling external flooding areas to ensure they are clear of debris, and creating a procedure to install curtains on the CWPH rollup doors during periods when they were required to be open. The inspectors determined that the licensees failure to fully evaluate the viability of newly created flooding drainage paths as required by 10 CFR 50.59(d)(1) was a performance deficiency. The inspectors evaluated the performance deficiency using traditional enforcement in conjunction with the SDP because the performance deficiency had the potential to impact the regulatory process. The performance deficiency was screened per the guidance of lMC 0612, Appendix B, and determined to be more than minor because the finding was associated with the Mitigating Systems Cornerstone attributes of Protection Against External Factors (Flood Hazard) and Design 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 (i.e. core damage). Specifically, the licensee did not fully demonstrate that the availability, reliability, and capability of mitigating systems would be maintained during flooding events due to the sites failure to evaluate the viability of alternate flood drainage paths through the CWPH. The inspectors evaluated the finding using IMC 0609, Attachment 0609.04, Tables 2 and 3, and Appendix A. Based on a review of Appendix A, Exhibit 2, Item 4.B, the inspectors determined that this issue screened as having very low safety significance (Green). Additionally, in accordance with Section 6.1.d.2 of the NRC Enforcement Policy, this violation is categorized as a Severity Level IV because the resulting conditions were evaluated as having very low safety significance (Green) by the SDP. This finding has a cross-cutting aspect in the area of problem identification and resolution, because the licensee failed to thoroughly evaluate issues to ensure that resolutions address causes and extent of conditions commensurate with their safety significance.
05000266/FIN-2014007-052014Q1Point BeachFailure to Establish EFR Attributes to Assess the Effectiveness of Corrective ActionsThe inspectors identified a finding of very low safety significance (Green) and associated non-citied violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure to ensure the effectiveness review attributes for a significant condition adverse to quality would ensure the corrective actions would eliminate or reduce the recurrence rate. The inspectors determined that the licensees failure to establish effectiveness review criteria that would have identified whether the corrective action to prevent recurrence (CAPRs) had effectively resolved the conditions was a performance deficiency warranting further review. The inspectors determined that this finding was more than minor in accordance with IMC 0612, Appendix B, because it was affected the Mitigating Systems Cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. If left uncorrected, would the performance deficiency have the potential to lead to a more significant safety concern? The inspectors evaluated the finding using IMC 0609, Appendix A. The inspectors determined the finding was of very low safety significance (Green) because the finding was not a deficiency affecting the design or qualification of a mitigating structure, system or component and did not result in a loss of operability or functionality. In addition, the finding did not represent a loss of system or function, did not represent an actual loss of function of a least a single train for longer than its technical specification allowed outage time, and did not represent an actual loss of function of one or more nontechnical specification trains of equipment designated as high safety-significance. The finding had a cross cutting aspect in the area of problem identification and resolution, specifically resolution, because licensee personnel failed to ensure the corrective actions to prevent recurrence had effective attributes.
05000280/FIN-2010002-022010Q1SurryEmergency Plan Minimum StaffingAn unresolved item (URI) was identified by the inspectors relating to maintenance of the required minimum onsite manning in accordance with the licensees Emergency Plan. On January 4, 2010, the licensee identified issues relating to the Emergency Plan minimum manning requirements for maintenance personnel. They subsequently initiated CR364061 in their CAP and the respective root cause evaluation, RCE000999, for appropriate corrective actions. The inspectors reviewed RCE000999 and require additional information from the licensee to appropriately characterize a performance deficiency which may be greater than minor. This issue is identified as URI05000280, 281/2010002-02, Emergency Plan Minimum Staffing
05000280/FIN-2010004-012010Q3SurryLicensee-Identified Violation10 CFR 50.54(q) states in part that a licensee authorized to possess and operate a nuclear power reactor shall follow and maintain in effect emergency plans which meet the standards in 10 CFR 50.47(b) and the requirements in appendix E of this part. Contrary to this, between early December 2006 and January 2010, the licensee identified that the staffing was reduced for mechanical maintenance and electrical maintenance personnel on shift to below the minimum shift staffing requirements of the Emergency Plan without a 50.54(q) review. The violation was determined to be of very low safety significance because, the licensee demonstrated non-designated coincidental coverage for the shift staffing positions in question, no degradation of the planning standard existed and the criteria for a white finding was not met. The licensee corrected the deficiency when it was discovered and entered it into the corrective action program as condition report CR364194.
05000282/FIN-2009004-032009Q3Prairie IslandPotential Testing Emergency Response Organization Callout and Augmentation Process Performing DeficiencyThe inspectors identified an unresolved item (URI) concerning the licensee\\\'s process for testing its capability to callout the ERO to ensure timely augmentation of response capabilities is available. Specifically, during the review of the April 2007 through April 2009 off-hours, unannounced callout tests, the inspectors could not adequately verify that the test results supported the emergency plan commitment to have the capability for additional personnel within 30 and 60 minutes of notification. The inspectors reviewed a sampling of records for emergency organization augmentation response tests. The purpose of these tests was to determine the number of ERO personnel who would be available and the time required to respond to the plant. The inspectors noted for the successful tests, results indicated a number of 30-minute response personnel would take 30 minutes to arrive. Thirty minutes to arrive plus any delays in the callout process could challenge the 30-minute response time requirement. Prairie Island\\\'s approved emergency plan for ERO augmentation requires response times of 30 and 60 minutes from the time of notification. The guidance in NUREG 0654 states the licensee must be able to augment on-shift capabilities within a short period after declaration of an emergency. The licensee entered this issue into its corrective action program as CAP 01189478. Pending NRC staff\\\'s review if there is a performance deficiency, this issue was considered an Unresolved Item (URI 05000282/2009004-03; 05000306/2009004-03)
05000282/FIN-2011004-042011Q3Prairie IslandFailure to Make Eight Hour Report Pursuant to 10 CFR 50.72The inspectors identified a Severity Level IV NCV of 10 CFR 50.72(b)(3)(v)(D) for the licensees failure to report an event or condition that could have prevented the fulfillment of a safety function to the NRC within 8 hours. Specifically, on June 27, 2011, an unexpected lockout of the 2RY transformer rendered one of two required offsite power paths inoperable. A subsequent review of the remaining transmission system capabilities resulted in declaring the second offsite power path inoperable due to inadequate minimum post-trip voltage. However, the licensee failed to recognize that the inoperability of both offsite power paths constituted a loss of safety function that was reportable to the NRC within 8 hours. The licensee initiated a corrective action document, CAP 1292940, for this issue. Corrective actions for this issue included reporting this issue to the NRC on July 1, 2011, revising procedures to ensure that inoperable offsite power paths that remain available were reported to the NRC, and repairing the 2RY transformer. The inspectors determined that the failure to report required plant events or conditions to the NRC had the potential to impede or impact the regulatory process. As a result, the NRC dispositions violations of 10 CFR 50.72 using the traditional enforcement process instead of the SDP. However, if possible, the underlying technical issue was evaluated using the SDP. In this case, the inspectors determined that the 2RY transformer locked out due to moisture entering a degraded bus duct, which was exposed to the environment. The licensee failed to identify the degraded bus duct earlier due to the inappropriate deferral of preventive maintenance activities. The inspectors determined that this issue was more than minor because it was associated with the protection against external factors attribute of the Initiating Events Cornerstone, and affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during power operations. Since the finding contributed to both the likelihood of a plant trip and that mitigating systems equipment or functions would not be available, a Region III Senior Reactor Analyst (SRA) was contacted for assistance. The results of the Phase 3 analysis showed a change in core damage frequency of 2.4E-8/year, which represented a finding of very low safety significance (Green). In accordance with Section 6.1.d.2 of the NRC Enforcement Policy, this violation was categorized as Severity Level IV because the underlying technical issue was evaluated by the SDP and determined to be of very low safety significance. The inspectors concluded that this finding was cross-cutting in the Human Performance, Work Practices area because licensee personnel failed to follow procedures regarding the preventive maintenance deferral process.
05000282/FIN-2011004-072011Q3Prairie IslandFailure to Provide Complete and Accurate Information in a Licensee Event ReportThe inspectors identified a Severity Level IV NCV of 10 CFR 50.9 due to the licensees failure to provide information to the NRC that was complete and accurate in all material respects. Specifically, Licensee Event Report (LER) 05000282/2011-001-00; 05000306/2011-001-00, stated that the unplanned actuation of the 121 motor driven cooling water pump (MDCLP) was caused by the over tightening of a gasketed connection on the 11 containment and auxiliary building chiller. The results of a subsequent apparent cause evaluation showed that the unplanned actuation of the 121 MDCLP was due to operating the chiller in a manner outside of its design. The licensee initiated corrective action document, CAP 1299410, to document this issue. Corrective actions for this issue included submitting a revised LER to the NRC and evaluating actions that could be taken to ensure that future chiller operation would not result in actuations of the cooling water pump. The inspectors determined that this violation was more than minor because the inaccurate information could impede or impact the regulatory process. Specifically, in order for the NRC to determine the acceptability of the licensees corrective actions as part of the LER review, the licensee was required to provide complete and accurate information regarding the cause of the event. As a result, the NRC dispositions these violations using the traditional enforcement process instead of the SDP. However, if possible, the NRC evaluates the underlying technical issue using the SDP. In this case, the inspectors determined that the failure to operate the 11 containment and auxiliary building chiller in accordance with design could be assessed using IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 Initial Screening and Characterization of Findings, Tables 3b and 4a. The inspectors concluded that the finding was of very low safety significance because each of the questions in Table 4a could be answered No. In accordance with Section 6.1.d.2 of the NRC Enforcement Policy, this violation was categorized as Severity Level IV because the underlying technical issue was evaluated by the SDP and determined to be of very low safety significance. No cross-cutting aspect was assigned to this finding as the reason for operating the chiller outside of its design was not associated with any of the components/aspects provided in NRC IMC 0310, Components within the Cross-Cutting Areas.
05000282/FIN-2011502-012011Q2Prairie IslandIncomplete and Inaccurate Emergency Action Level Change SubmittalThe NRC identified a Severity Level IV Non-Cited Violation of 10 CFR 50.9 for failing to provide complete and accurate information for prior approval of a new Emergency Action Level (EAL) scheme. The licensees submittal to the NRC, entitled, Revision to Emergency Action Levels, dated October 22, 2004, was not complete and accurate in all material respects. The submitted EAL scheme specified instrument threshold values for Alert classifications, EALs RA1.1 and RA1.2, which were beyond the indicated ranges of the effluent radiation monitors R-18, R-25, and R-31. The NRC accepted and approved the proposed EALs not realizing the information was incomplete and inaccurate. The inspectors determined that the licensees failure to provide complete and accurate information to the NRC, a violation of 10 CFR 50.9, was a performance deficiency and within the licensees ability to foresee and prevent. The deficiency was determined to be more than minor because it was associated with the Emergency Preparedness Cornerstone attribute of Procedure Quality. As a violation that potentially impedes or impacts the regulator process, it was dispositioned using the traditional enforcement process as described in NRC Inspection Manual Chapter 0612, Revision 04/30/10. Using Section 6.9 of the Enforcement Policy and after consultation with the Director of the Office of Enforcement, this issue was determined to be a Severity Level IV violation. Specifically, though the NRC would have questioned the issue with additional and correct information, the EAL ultimately would have been acceptable with an adjustment in the indicator range or EAL entry criteria value. In either case, it would not have resulted in substantial further inquiry. Additionally, the associated technical violation was determined to be of very low safety significance. As this was a traditional enforcement action, no cross cutting aspect was screened.
05000282/FIN-2012002-012012Q1Prairie IslandBreaker 212E-44 Failure due to Lack of Preventive MaintenanceA self-revealed finding of very low safety significance and an NCV of Technical Specification (TS) 5.4.1 occurred on January 19, 2012, due to the safety-related breaker for the 21 reactor vessel gap cooling fan failing while in service. Specifically, preventive maintenance activities used to ensure the breaker remained operable were not performed in a timely manner. Corrective actions for this issue included repairing/replacing the breaker for the 21 reactor vessel gap cooling fan and performing an extent of condition review to determine whether timely preventive maintenance was completed on similar breakers. The inspectors determined that this issue was more than minor because it was associated with the equipment performance attribute of the Initiating Events Cornerstone and impacted the cornerstone objective of limiting the likelihood of those events that upset plant stability (such as having to perform a reactor shutdown). The inspectors determined that the finding was of very low safety significance since it did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions would not be available. The cause of this finding was determined to be cross-cutting in the Human Performance, Work Control area because the licensee failed to appropriately coordinate work activities to support the continued operability and reliability of breaker 212E-44
05000282/FIN-2012002-022012Q1Prairie IslandReview Of Steam Exclusion Damper Maintenance EffectivenessOn March 21, 2012, the licensee performed surveillance testing on the SE system as directed by Surveillance Procedure (SP) 1112, Steam Exclusion Damper Monthly Test. The purpose of the test was to ensure that SE dampers used to protect certain areas of the plant from a high energy line break (HELB) event closed as required. During the test, the licensee identified that control dampers CD-34187 and CD-34188 failed to fully close. Specifically, both dampers contained several gaps between the damper blades. Operations personnel immediately declared the dampers non-functional and entered Technical Requirements Manual Limiting Condition for Operation (TLCO) 3.7.1. Operations personnel closed both of the SE dampers to comply with the TLCO. Both dampers remained OOS at the conclusion of the inspection period. Over the last several months, the inspectors have reviewed multiple CAP documents regarding the failure of one or both of the control dampers. As a result, the inspectors were concerned that maintenance personnel may not be implementing appropriate work practices during the damper repairs and/or the licensee may not be properly identifying and addressing the potential for common cause damper failures. The inspectors reviewed the surveillance test history for control dampers CD-34187 and CD-34188 since September 2011. The inspectors determined that damper CD-34187 had failed its surveillance test two out of the last six times while CD-34188 had failed four of the last six tests. The licensee initiated CAPs 1326072 and 1330276 to document the issues with the SE dampers. The licensee was evaluating the potential maintenance issues at the conclusion of the inspection period. As a result, determinations regarding maintenance effectiveness and the potential for common cause failure will be considered unresolved pending a review of the licensees causal evaluation
05000282/FIN-2012002-032012Q1Prairie IslandFailure to Properly Assess Operability of D2 EDG following Surveillance TestingA finding of very low safety significance and an NCV of TS 3.8.1 was identified by the inspectors on February 23, 2012, due to the licensees failure to properly assess the continued operability of the D2 emergency diesel generator (EDG) following monthly surveillance testing. As a result, the D2 EDG was incorrectly declared operable with a known equipment deficiency. Corrective actions for this issue included declaring the D2 EDG inoperable, repairing the equipment deficiency, and requiring operability decisions to be reviewed by the shift manager. The inspectors determined that this finding was more than minor because it was associated with the human performance and equipment performance attributes of the Mitigating Systems Cornerstone. In addition, the performance deficiency impacted the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors determined that this finding was of very low safety significance because each of the questions listed under the Mitigating Systems Cornerstone column of IMC 0609.04, Table 4A could be answered no. The inspectors determined that this finding was cross-cutting in the Human Performance, Decision Making area because the licensee did not make a safety-significant and/or risk-significant decision using a systematic process when faced with uncertain or unexpected plant conditions to ensure that safety was maintained
05000282/FIN-2012002-042012Q1Prairie IslandFailure to Assess Operability of Circuit Breakers due to Inadequate LubricationThe inspectors identified a finding of very low safety significance and an NCV of 10 CFR Part 50, Appendix B, Criterion V, on January 19, 2012, due to the licensees failure to properly assess information contained in the Corrective Action Program (CAP) document 1322404 as required by Procedure FP-OP-OL-01, Operability/Functionality Determination. Specifically, the CAP contained information that a safety-related breaker failed to operate due to a lack of lubrication. However, an extent of condition assessment was not included in CAP 1322404 nor was an operability recommendation assigned to evaluate the potential impact on similar equipment. Corrective actions included performing an extent of condition review and ensuring that other safety-related equipment remained operable. The inspectors determined that this issue was more than minor because, if left uncorrected, the failure to properly assess equipment operability could result in inappropriately leaving plant equipment in service (a more significant safety concern). The inspectors determined that this finding was of very low safety significance because each of the questions listed under the Mitigating Systems Cornerstone column of IMC 0609.04, Table 4A could be answered no. This finding was determined to be cross-cutting in the Human Performance, Decision Making area because the licensee failed to use conservative assumptions when making decisions regarding the continued operability of the breakers discussed above
05000282/FIN-2012002-052012Q1Prairie IslandFailure to Implement Procedure Use and Adherence Requirements While Draining Sodium Hypochlorite Draw Down TankA finding of very low safety significance was self revealed on January 7, 2012, due to chemistry personnel failing to comply with requirements contained in Procedure FP-G-DOC-03, Procedure Use and Adherence, prior to draining the sodium hypochlorite draw down tank. Specifically, personnel failed to identify that the procedure used during the draining activity was inadequate. The use of an inadequate procedure led to a pipe break, the release of sodium hypochlorite into a bermed area, and an Alert classification under the licensees emergency plan. No violations of NRC requirements were identified for this issue since the sodium hypochlorite system was non-safety related. Corrective actions for this issue included reviewing chemistry procedure adequacy and increasing supervisory oversight of chemistry activities. The inspectors determined that this issue was more than minor because it was a precursor to a significant event. Specifically, the licensee declared an ALERT emergency action level due to the sodium hypochlorite spill. The inspectors concluded that the finding was of very low safety significance since all of the questions located in the Mitigating Systems Cornerstone column of IMC 0609.04, Table 4a were answered no. The inspectors determined that this finding was cross-cutting in the Human Performance, Work Practices area because the licensee failed to ensure supervisory and management oversight of work activities such that nuclear safety was supported
05000282/FIN-2012002-072012Q1Prairie IslandFailure to Timely Activate ERDSA self-revealed finding of very low safety significance and an NCV of 10 CFR 50.72(a)(4) was identified on January 7, 2012, due to the licensees failure to activate the Emergency Response Data System (ERDS) within one hour of an Alert declaration. Specifically, the ERDS was not made operable until 80 minutes after the Alert declaration due to task priority and equipment issues related to a system upgrade. Corrective actions for this issue included emphasizing the timely activation of ERDS with emergency responders and repairing the system upgrade equipment issues. The inspectors determined this performance deficiency was more than minor because it was associated with the emergency response organization performance attribute of the Emergency Preparedness Cornerstone and affected the cornerstone objective of ensuring that the licensee was capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. This finding was evaluated in accordance with IMC 0609, Appendix B, Emergency Preparedness SDP, that considers a failure to activate ERDS as a failure to implement. Using the Actual Event Implementation Problem Sheet 2, the inspectors determined the finding to be of very low safety significance because it was not a failure to implement a risk significant planning standard. This finding was determined to be cross-cutting in the CAP component of the Problem Identification and Resolution cross-cutting area because the licensee failed to take appropriate corrective actions to address a previously identified ERDS activation issue in a timely manner
05000282/FIN-2012002-082012Q1Prairie IslandUnit 2 Manual Reactor Trip During Shutdown for Outage 2R27On February 21, 2012, the licensee conducted a normal shutdown in preparation for refueling outage 2R27. When Unit 2 reactor power reached approximately 11.42 percent, operations personnel manually tripped the reactor due to the receipt of high-high level indications and alarms on multiple feedwater heaters. The inspectors were in the control room when the reactor trip occurred. The inspectors observed the operators respond to the event to ensure that the licensees procedures were followed. The inspectors also observed equipment parameters available in the control room to ensure that the reactor and the associated equipment responded as expected following the reactor trip. The licensee documented the need to manually trip the reactor as CAP 1325986. The licensee was continuing to determine the cause of the high-high feedwater heater level at the conclusion of the inspection period. As a result, the inspectors determined that this issue should be considered a URI pending the review of the licensees causal investigation report and the proposed corrective actions.
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
05000282/FIN-2012002-102012Q1Prairie IslandInadequate Three Hour Fire Barrier Between Bus 26 And Bus 27 RoomsA finding of very low safety significance and an NCV of Condition 2.C.4 of the Unit 2 operating license was identified by the inspectors on November 8, 2011, due to the failure to implement and maintain in effect all provisions of the approved fire protection program. Specifically, a wall between the Bus 26 and Bus 27 rooms contained gaps such that it was not able to be credited as a 3-hour fire barrier. Corrective actions for this issue included establishing a fire watch and repairing the gaps so that the fire barrier/wall provided the required protection. The inspectors determined that this finding was more than minor because it affected the protection against external factors attribute of the Mitigating Systems Cornerstone. This finding also affected the cornerstone objective of ensuring 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 because no credible fire scenarios affecting the safe shutdown of Unit 2 existed, the distance between the gap and the safe shutdown equipment was large, and negligible combustible loading existed in the adjacent areas. No cross-cutting issue was identified since the cause of this finding occurred more than three years ago and was not reflective of current plant performance.
05000282/FIN-2012002-112012Q1Prairie IslandInadequate Operational Log EntriesA finding of very low safety significance and an NCV of TS 5.4.1 was identified by the inspectors between February 23 and March 27, 2012, due to the licensees failure to maintain the control room narrative logs as required by Procedure FP-OP-COO-19, Logkeeping. Specifically, control room log entries were not properly documented as late entries, failed to provide the basis for operational decisions, and failed to adequately discuss the status of plant equipment. Corrective actions for this issue included daily management review of control room log entries and the correction of each identified logging deficiency. The inspectors determined that this issue was more than minor because it was associated with the Mitigating System Cornerstone attribute of Configuration Control, and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. This finding was determined to be of very low safety significance because each of the questions contained in IMC 0609.04, Table 4A could be answered no. The inspectors concluded that this finding was cross-cutting in the Human Performance, Work Practices area since the licensee did not support the effective use of human error prevention techniques through proper documentation of activities.
05000282/FIN-2012002-122012Q1Prairie IslandLicensee-Identified ViolationThe following violation that affects 10 CFR 50.48 was identified by the licensee and is a violation of NRC requirements. This violation has been screened and determined to warrant enforcement discretion per the Interim Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection Issues. A violation of 10 CFR Part 50, Appendix R, Section III.G.2 was identified by the licensee for the failure to ensure that one train of systems necessary to achieve and maintain hot shutdown conditions from either the control room or emergency control station is free of fire damage. Specifically, due to inadequate cable separation, there was a potential for a fire in the Administration Building Electrical and Piping Area to damage control cables of diesel-driven cooling water pumps 12 and 22 and associated equipment. On June 4, 2007, the licensee identified that they were relying on unapproved manual actions to mitigate potential damage to safe shutdown equipment. The Region III Senior Risk Analysts completed a risk-assessment evaluation and determined that the issue was not of high safety significance (i.e., the violation was less than Red) using SAPHIRE Version 8.0.7.17 and the Prairie Island Standardized Plant Analysis Risk (SPAR) model (Version 8.17)
05000282/FIN-2012002-132012Q1Prairie IslandLicensee-Identified ViolationTitle 10 CFR Part 50, Appendix B, Criterion V, requires that activities affecting quality be performed in accordance with instructions, procedures and drawings appropriate to the circumstance. Contrary to the above, on March 25, 2012, post-maintenance testing was performed on motor operated valve 32030 (the 22 turbine driven auxiliary feedwater pump suction cooling water supply valve) without using instructions, procedures, or drawings appropriate to the circumstance. As a result, cooling water was introduced into both Unit 2 steam generators. The inspectors determined that this issue was of very low safety significance (Green) because Unit 2 was shut down when this issue occurred, the Unit 2 steam generators were not operable, and the licensee flushed the cooling water from the steam generators to ensure it would not have any lasting impacts on steam generator tube integrity.
05000282/FIN-2012003-052012Q2Prairie IslandImpact of Outside Air Temperatures on D1 and D2 EDG OperabilityThe inspectors identified an unresolved item (URI) regarding the licensees preparations to ensure that the Unit 1 EDGs were ready for operation during extreme outside air temperatures. On June 8, 2011, the licensee provided a 10 CFR 50.72 report to the NRC when both of the Unit 1 EDGs (D1 and D2) were declared inoperable due to extreme outside air temperatures. Specifically, the outside air temperature on June 8, 2011, was 101.4oF while the licensees maximum temperature to support EDG operability was 100.5oF. Several weeks later, the licensee retracted the 10 CFR 50.72 report based upon additional analysis which showed that D1 and D2 remained operable up to a maximum outside air temperature of 102.5oF. On February 29, 2012, the licensee initiated CAP 1327157 to document that the analysis used to support the 10 CFR 50.72 retraction discussed above was non-conservative. On April 15, 2012, the licensee completed an operability recommendation (OPR 1327157-01, Revision 0), to address the non-conservatisms. The results of the operability recommendation showed that the D1 and D2 EDGs were rendered inoperable when the outside air temperature exceeded 97oF. During the week of June 26, 2012, the inspectors performed a maintenance effectiveness inspection on the D1 EDG (see Section 1R12 of this inspection report). As part of this inspection, the inspectors discovered Engineering Change (EC) 20055 which was approved by the engineering department on approximately June 10, 2012. The purpose of this EC was to evaluate the operability of the D1 and D2 EDGs over the past three years based upon a maximum outside air temperature. The inspectors reviewed the contents of the EC and were concerned that the licensee had assessed the past operability of the EDGs using a maximum outside air temperature of 105oF even though the temperature limit stated in the operability recommendation remained at 97oF. As a result, the licensee may not have properly reported periods of past EDG inoperability to the NRC. The inspectors also found that the licensee had approved increasing the maximum EDG room temperature without adequately assessing the impact of critical EDG components such as the diesel engine, the generator, and three lube oil pressure switches. Specifically, the licensee had deemed the continued operation of these components acceptable based upon engineering judgment without providing an appropriate basis for the conclusion. The inspectors discussed their concerns, and the impending weather forecast which predicted temperatures in excess of 97oF, with engineering, operations, and licensee management personnel. Following these discussions, licensee management rescinded the results of EC 20055; performed an additional review of the critical components to determine whether other actions could be completed to gain additional operability margin; and reaffirmed that the D1 and D2 EDG outside air temperature operability limit was 97oF. At the conclusion of the inspection period, the licensee determined that additional margin could be gained by derating the EDG when outside air temperatures exceeded a specified temperature and by replacing the lube oil pressure switches with switches qualified for a higher operating temperature. The licensee replaced the D2 EDG lube oil pressure switches on June 30, 2012. The D1 EDG pressure switches were scheduled for replacement as soon as the weather conditions allowed. The licensee also planned to perform testing on the replaced temperature switches to determine their maximum operating temperature. These test results will be used to determine whether the D1 and D2 EDGs had been inoperable at any time during the past three years. Since the test results were not available for inspection and review at the conclusion of the inspection period, this issue will be documented as an unresolved item
05000282/FIN-2012005-012012Q4Prairie IslandFailure to Disposition a Relevant Snubber Indication in Accordance with the ASME CodeThe inspectors identified a finding of very low safety significance and a NCV of 10 CFR50.55a(g)(4) on November 13, 2012, due to the licensees failure to disposition a relevant indication on a common steam generator snubber reservoir in accordance with the American Society of Mechanical Engineers (ASME) OM4 Code. Specifically, the licensee did not properly evaluate and disposition a condition where the hydraulic fluid level for a common reservoir serving snubbers H1 through H4 on the 12 steam generator was below the minimum required. The licensee issued a work order to fill the reservoir and documented the failure to properly disposition the indication in the corrective action program. The inspectors determined that this finding was more than minor because if left uncorrected, the failure to properly disposition relevant indications could become a more significant safety concern. Absent NRC identification of this issue, the licensee would not have re-established the required fluid level in the reservoir for an indefinite period. This finding was determined to be of very low safety significance because a subsequent evaluation demonstrated that the low fluid level did not result in the piping system becoming inoperable. This issue was determined to be cross cutting in the Problem Identification and Resolution, Corrective Action Program area because the licensee failed to thoroughly evaluate problems such that the resolutions addressed the cause and extent of condition, as necessary
05000282/FIN-2012005-022012Q4Prairie IslandInadequate Evaluation of Operating Crew During Annual Requalification ExaminationThe inspectors identified a finding of very low safety significance on October 6, 2012, due to the failure to properly evaluate an operating crews annual requalification examination performance in accordance with Procedure FP-T-SAT-73, Licensed Operator Requalification Program Examinations. Specifically, the evaluators did not adequately assess the communications competency area when evaluating the crews overall performance. As a result, the crews performance was rated as satisfactory with remediation rather than as unsatisfactory. Corrective actions for this issue included providing remedial training to the crew and having the crew complete an additional evaluated scenario as part of their annual examination. This issue was more than minor because if left uncorrected the failure to properly assess licensed operator performance had the potential to lead to a more significant safety concern. The inspectors determined that this issue could be evaluated using IMC 0609, Appendix I, Licensed Operator Requalification Significance Determination Process. The inspectors determined that this finding was of very low safety significance because it was related to the licensees administration of an annual requalification operating test as discussed in Section 03.05 of NRC Inspection Procedure 71111.11, Licensed Operator Requalification Program. This issue was determined to be cross-cutting in the Human Performance, Decision Making area because the licensee did not make conservative assumptions during decisions regarding how this crew of licensed operators was evaluated
05000282/FIN-2012005-032012Q4Prairie IslandFailure to Replace Rubber Hoses on D5 and D6 EDG in Accordance with Vendor RecommendationsThe inspectors identified a finding of very low safety significance and an NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, due to the licensees failure to implement vendor recommendations to replace rubber hoses on the emergency diesel generators (EDGs) at a 10-year frequency. Specifically, some of the installed rubber hoses were found to be in service beyond the vendor recommended service life and if they were to degrade, could impact the safety-related functions of the EDGs. Corrective actions for this issue evaluating the condition and replacing the hoses on specific diesel engines. The inspectors determined that this issue was more than minor because if left uncorrected, it could become a more significant safety concern because the rubber hoses could continue to degrade until operation of the diesel engines were impacted. The finding was of very low safety significance because each of the questions listed in IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, could be answered no. Due to the age of this issue, the cause of the finding was not reflective of current performance and therefore, a cross cutting aspect was not assigned.
05000282/FIN-2012005-042012Q4Prairie IslandFailure of Seasonal Readiness Procedure to Identify Operability IssuesThe inspectors identified a finding of very low safety significance and an NCV of 10 CFR Part 50, Appendix B, Criterion V, on June 26, 2012, due to the licensees failure to have procedures appropriate to the circumstance for coordinating and preparing for the onset of hot weather conditions. Specifically, Procedure FP-WM-SR-01, Seasonal Readiness Program, Attachment 2, failed to include criteria to ensure that issues associated with the ability of the Unit 1 EDGs to operate when outside air temperatures exceeded 97 degrees Fahrenheit were identified and addressed prior to the onset of hot weather. This resulted in both Unit 1 EDGs being rendered inoperable, and the D1 EDG being rendered unavailable, on July 2, 2012. The inspectors determined that this issue was more than minor as it impacted the protection against external events objective of the Mitigating Systems Cornerstone. In addition, this finding impacted the cornerstone objective of ensuring the availability of systems that respond to initiating events to prevent undesirable consequences. The inspectors determined that this issue was of very low safety significance because each of the questions listed in IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, could be answered no. This finding was cross cutting in the Human Performance, Work Control area because Procedure FP-WM-SR-01 was not written to ensure that activities needed to support long term equipment reliability and availability were planned such that they were performed in a preventative manner rather than in a reactive manner
05000282/FIN-2012005-052012Q4Prairie IslandFailure to Demonstrate Performance or Condition of Radiation Monitors Were Effectively Controlled Through the Performance of MaintenanceA finding of very low safety significance and an NCV of 10 CFR 50.65 was identified by the inspectors on August 22, 2012, due to the licensees failure to demonstrate that the performance or condition of the radiation monitoring system was being effectively controlled through the performance of appropriate preventive maintenance such that the structure, system or component (SSC) remained capable of performing its intended function. Specifically, the licensee failed to perform maintenance rule evaluations following the failure of multiple radiation monitors in July 2010. Since the evaluations were not completed, the licensee was unable to demonstrate that the performance of the radiation monitors was being effectively controlled through the performance of maintenance. Corrective actions for this issue included performing the evaluations and comparing the results to pre-established performance monitoring criteria. The inspectors determined that this finding was more than minor because it impacted the equipment performance attribute of the Mitigating Systems Cornerstone and impacted the cornerstones objective of ensuring the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences. This finding also impacted the SSC and barrier performance attributes of the Barrier Integrity Cornerstone by affecting the reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents and events. The inspectors determined that this issue was of very low safety significance because each of the questions listed in IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, could be answered no. The inspectors determined that this finding was cross cutting in the Problem Identification and Resolution, Corrective Action Program area because the licensee failed to thoroughly evaluate this problem such that the resolution addressed the cause and extent of condition as necessary
05000282/FIN-2012005-062012Q4Prairie IslandConcerns with Analytical Methods Used for Predicting Void Transport BehaviorThe inspectors identified a URI regarding the analytical methods used by the licensee for evaluating and predicting void transport behavior. Specifically, some methods used by the licensee relied on the use of computer software and test results which were previously questioned by the NRC staff. As a result, the inspectors questioned the acceptability of the analytical methods. Description: On January 11, 2008, the NRC requested each addressee of GL 2008-01 to evaluate its Emergency Core Cooling System (ECCS), Decay Heat Removal, and Containment Spray (CS) systems licensing basis, design, testing, and corrective actions to ensure that gas accumulation (voids) was maintained less than the amount that would challenge the operability of these systems. Licensees were instructed to take appropriate actions when conditions adverse to quality were identified. As part of this effort, Prairie Island developed analytical methods for evaluating identified voids in the subject systems. During a subsequent onsite inspection, the inspectors noted concerns with respect to the licensees void assessment methodologies. Specifically, the inspectors noted the licensee relied on the use of computer codes to evaluate the acceptability of some voids. Specifically, the licensee used a combination of PIPER Q2.05, SYSFLO Q3.08, and AIRDST codes in their evaluations. The code, PIPER Q2.05, was used to generate a mathematical model of the piping in the form of control volumes and connectors. The control volumes represented the mass and energy of the fluid while the connectors represented the inertia of the fluid and the hydraulic resistance of the flow path. The SYSFLO Q3.08 code used this model to solve the mass, energy, and momentum conservation equations to obtain the pressure, temperature, and flow rate information. The AIRDST program used these results to simulate transport of air in the flow. The inspectors noted instances where the basis of this void assessment analysis tool was not well supported. Specifically, the licensee used WCAP-17271-P, Air Water Transport in Large Diameter Piping Systems, Analysis and Evaluation of Large Diameter Testing Performed at Purdue, to show that the AIRDST code could acceptably predict quantitative void transport behavior. The inspectors noted the test configuration and conditions used in the WCAP-17271-P report differed from actual plant configuration and conditions, and questioned whether the application of some of the test results was acceptable. For example: FnThe difference between test and plant pressures was not considered in assessing void decrease in the vertical test section. The pressure range used during the test was significantly lower than the typical range in nuclear power plants. Therefore, 41 Enclosure the inspectors questioned if the void fraction change observed during testing would be analogous in a nuclear power plant. FnTwo phase fluid flow test data typically exhibited significant scatter. This was addressed by running many duplicate tests and carefully examining the test results. However, as documented in, Forthcoming Meeting with the Nuclear Energy Institute to Discuss NRC Generic Letter 2008-01, (ML090150637), the NRC stated this effort was not fully successful and some of the conclusions were not adequately supported by the test data due to data scatter. Specifically, this effort did not address allowances for uncertainty and the effect of actual plant pressures in contrast to test pressures. FnThe inspectors questioned whether the test report adequately considered a water fall effect (also known as hydraulic jump) when the upper part of the vertical pipe was voided. Specifically, the inspectors questioned whether the pipe length used for the test was representative of the limiting conditions of a plant. The inspectors were concerned if such an effect could propel air further down in the pipe than would be predicted using a single dimensional Froude number and would be of concern if the vertical pipe length was significantly less than the pipe used for the test. The inspectors also noted the evaluation which validated the use of AIRDST, Calculation 1067-1106-0038-00, Comparison of Purdue Experimental Results to SYSFLO and AIRDST Program Predictions, stated the repeatability of some of the test results was questionable. Specifically, the evaluation stated multiple readings did not always match with each other with the differences being significant. The evaluation also noted the AIRDST Program over-predicted and under-predicted void fractions depending on the conditions in the piping. The inspectors discussed these observations with individuals from NRR. It was determined these observations required further evaluation by NRR to better understand the acceptability of the application of the test results contained in the WCAP-17271-P report to void assessment analysis. The inspectors also noted that the licensee was unable to remove several voids which currently existed in the suction piping for the residual heat removal (RHR) and CS systems. The licensee justified the void acceptability using the above mentioned computer codes. Because of the inspectors questions associated with these computer codes, the licensee re-evaluated these voids using the conventional methods contained in Guidance to NRC/NRR/DSS/SRXB Reviewers for Writing TI Suggestions for the Region Inspections (ML103400347), and confirmed the voids met the acceptance criteria with the exception of the voids located between the containment sump B isolation valves. These voids were procedurally created in order to alleviate pressurelocking concerns on these valves. Based on the information currently available, the licensee determined that these voids did not impact operability. The licensee was also evaluating potential modifications to address the voids. Similarly, the inspectors noted the licensee had relied on these computer codes to justify the acceptability of previously identified voids (that no longer exist). The licensee also confirmed that these voids did not challenge system operability using NRRs conventional method with two exceptions. Specifically, voids found at locations 2CS-06 and 1RH-03 were determined to exceed NRRs acceptance criteria when using the conventional method. The licensee used the simplified method contained in the WCAP-17276-P, Investigation of Simplified Equation for Gas Transport, report and concluded the voids were acceptable. However, the inspectors noted the void at location 1RH-03 was acceptable per the simplified equation method; however, the void at location 2CS-06 did not meet the limitations of the simplified equation method. The inspectors consulted with NRR on the acceptability of this methodology and determined this methodology was also based on the same tests used to validate the computer codes. Because a void did not currently exist at locations 2CS-06 or 1RH-03, the inspectors determined the past operability of the CS and RHR systems would be addressed when NRR concluded their reviews on the use of computer software and the simplified equation methodology. This issues discussed above were determined to be unresolved pending further evaluation of the licensees analytical methods. The NRR staff will evaluate the matter and provide a determination on the acceptability of: (1) applying the test results contained in the WCAP-17271-P report to void assessment analysis; (2) the use of computer software for void transport analysis of the sump voids; and (3) using the simplified method contained in the WCAP-17276-P report for locations 1RH-03 and 2CS-06
05000282/FIN-2012005-072012Q4Prairie IslandLicensee-Identified ViolationTitle 10 CFR 50.65(a)(iv) requires, in part, that licensees must properly assess and manage risk. When the Unit 1 reactor was in a shut-down condition, the licensee implemented 5 AWI 15.6.1, Shutdown Safety Assessment, to assess and manage the risk as required by 10 CFR 50.65(a)(iv). Table 2 of 5 AWI 15.6.1 stated that no credit was to be given for the function/availability of the containment release barriers during the movement of heavy loads over irradiated fuel. Contrary to the above, on November 6, 2012, the licensee failed to properly assess the risk associated with moving the Unit 1 reactor vessel head. Specifically, operations personnel allowed credit to be given for the functionality/availability of multiple containment release barriers during the movement of the Unit 1 reactor vessel head (a heavy load) over irradiated fuel. The inspectors assessed the significance of this finding using Checklist 3 of IMC 0609, Appendix G, Attachment 1, Shut-down Operations Significance Determination Process Phase 1 Operational Checklists for Both PWRs and BWRs. The inspectors determined that this finding was of very low safety significance (Green) because the licensee met the containment control guidelines described in Section IV of Checklist 3 while moving the heavy load. The licensee documented this condition as CAP 1358291. Corrective actions for this issue included revising the shutdown safety assessment document, providing training to operations personnel that perform the shutdown safety assessment activities, and revising 5 AWI 15.6.1 to provide additional clarification regarding containment closure credit during the movement of heavy loads over irradiated fuel.
05000282/FIN-2012005-082012Q4Prairie IslandLicensee-Identified ViolationTitle 10 CFR Part 50, Appendix B, Criterion VIII, Identification and Control of Materials, Parts and Components, states that measures shall be established for the identification and control of materials, parts and components, including partially fabricated assemblies. These measures shall assure that identification of the item is maintained by heat number, part number, serial number, or other appropriate means, either on the item or on records traceable to the item, as required throughout fabrication, erection, installation, and use of the item. These identification and control measures shall be designed to prevent the use of incorrect or defective material, parts and components. Contrary to the above, on May 22, September 14, November 1, and November 4, 2012, the design of the identification and control measures were not adequate to prevent the use of incorrect materials. Specifically, on the dates listed above, safety-related and/or augmented quality plant doors were repaired with parts whose identification were not maintained or were not traceable by an appropriate means. The inspectors assessed the significance of this issue using IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power. The inspectors determined that this issue was of very low safety significance (Green) because Question A.1 was answered yes, and Question B was answered no. For those doors considered fire doors, the inspectors assessed the risk of this issue using IMC 0609, Appendix F, Significance Determination Process for Fire Protection Issues. The inspectors assigned a fire confinement category to this issue since it was associated with fire doors. The inspectors assigned a low degradation rating to this finding as the performance and reliability of the doors was minimally impacted by the non-conforming parts. Per Task 1.3.1 of IMC 0609, Appendix F, this finding was also determined to be of very low safety significance (Green) due to the low degradation rating. The licensee documented this condition as CAP 1357789. Corrective actions for this issue included the implementation of a stop work order, declaring the doors functional but non-conforming, and ensuring that the non-conforming doors were repaired with the appropriate parts.
05000282/FIN-2012005-092012Q4Prairie 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 instructions, procedures and drawings of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures or drawings. Instructions, procedures or drawings shall include appropriate quantitative or qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished. Contrary to the above, on October 24, 2012, the licensee failed to perform surveillance testing on the 22 Turbine Driven Auxiliary Feedwater (TDAFW) Pump (an activity affecting quality) with a procedure appropriate to the circumstance. Specifically, quantitative acceptance criteria contained in Surveillance Procedure SP 2102, 22 TDAFW Pump Monthly Test, was not updated to reflect a change in the baseline stroke time data for valve CV-31999, 22 TDAFW Pump Main Steam Supply Control Valve. As a result, CV-31999 failed to meet the procedurally indicated stroke time criteria. This required operations personnel to declare the 22 TDAFW pump inoperable. The inspectors assessed the significance of this finding using IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power. The inspectors determined that this issue was of very low safety significance (Green) because each of the questions contained in IMC 0609, Appendix A, Exhibit 2 could be answered no. Specifically, a loss of function did not occur because the actual valve stroke time met the revised baseline acceptance criteria. The licensee documented this issue as CAP 1356385. Corrective actions for this issue included issuing the revised surveillance procedure, performing an extent of condition review, and ensuring that procedures which required revisions to their acceptance criteria were quarantined until the procedure revision was approved.
05000282/FIN-2012005-102012Q4Prairie IslandLicensee-Identified ViolationTitle 10 CFR 50.54(q)(2) requires that a holder of a nuclear power reactor operating license follow and maintain the effectiveness of an emergency plan that meets the requirements in Appendix E to this part and the planning standards of 10 CFR 50.47(b). The Prairie Island Nuclear Generating Plant (PINGP) Emergency Plan, Section 4.0 states in part, PINGP has and maintains the capability to assess, classify, and declare an emergency condition within 15 minutes after the availability of indications to plant operators that an EAL has been exceeded. Upon identification of the appropriate emergency classification level the emergency condition will be promptly declared. Contrary to the above, on October 31, 2012, the licensee failed to follow its Emergency Plan during an actual emergency which resulted in a failure to implement. Specifically, inaccurate communications resulted in the over classification of a NOUE based on EAL HU4.1. Using IMC 0609, Appendix B, Emergency Preparedness Significance Determination Process, dated February 24, 2012, Section 4.0, Actual Event Implementation Issue (Failure to Implement), the inspectors determined that the violation was not greater than very low safety significance (Green) because no public official protective actions were implemented as a result of this event over classification. The issue was documented in the licensees corrective action program as CAP 1357663. Corrective actions included making revision to emergency procedures regarding this type of security event and providing additional training to security personnel. components. Based on the above, the SRA concluded that the total risk increase to the plant due this finding based on CDF was very low (Green). The licensee documented this issue in the CAP as CAP 1345525. Corrective actions included re-installing the flood barrier, labeling the flood barrier, and ensuring that information was readily available to alert plant personnel to the fact that the concrete trench cover was used as an internal flooding barrier.
05000282/FIN-2012005-112012Q4Prairie IslandLicensee-Identified ViolationTechnical Specification 3.8.1 requires that two diesel generators capable of supplying the onsite 4 kV safeguards distribution system be operable when the reactor is operating in Modes 1, 2, 3 or 4. With one diesel generator inoperable, Limiting Condition for Operation (LCO) 3.8.1.b requires that the diesel generator be returned to service within 14 days. With both diesel generators inoperable, LCO 3.8.1.e requires that one diesel generator be restored to an operable status within 2 hours. Contrary to the above, on June 25 and July 9, 2012, the D5 and D6 diesel generators were not restored to an operable status within two hours of removing a concrete trench which served as a barrier to protect the diesel generators from the impact of an internal flood. Per Procedure 5AWI 8.9.0, Internal Flooding Drainage Control, the concrete trench cover must be in place to support diesel generator operability whenever there is a possibility of a HELB in the Unit 2 turbine building. The inspectors performed a significance screening of this finding using the guidance provided in IMC 0609, Significance Determination Process, Appendix A, The Significance Determination Process for Findings At-Power. In accordance with Exhibit 2, Mitigating Systems Screening Questions, the inspectors answered Yes to the screening question Does the finding represent a loss of system and/or function? since there was the potential for the D5 and D6 emergency power sources to be rendered unavailable. The exposure time for the performance deficiency was the period of time that the flood barrier was missing, which was the 25-day period from June 25 to July 20, 2012. In order to affect an increase in plant risk, the D5 and D6 diesel generators would have to be rendered unavailable by some type of flooding event concurrent with a loss of offsite power (LOOP) event. This scenario was assumed to occur during a seismic event which causes a LOOP along with certain pipe breaks. Such pipe breaks can result from direct seismic failures of the piping itself or indirectly from seismic-induced HELB events that in turn break other piping in the turbine building. The NRC performed a detailed SDP analysis for a separate turbine building flooding issue that bounds this issue. On May 27, 2010, the NRC issued Inspection Report 05000282/2010010; 05000306/2010010 (EA-10-070; ML101470607). This inspection report contained the NRC\'s preliminary risk analysis to assess the impact on both units due to the failure to ensure that engineered safety features, including the diesel generators, were not adversely affected by events that cause turbine building flooding. A subset of that analysis is relevant for this current performance deficiency; namely, the seismic-induced failure of piping for Unit 2. 47 Enclosure The NRC later completed its final risk analysis based, in part, on the licensee\'s analysis from a report titled Turbine Building HELB/Internal Flooding Significance Determination Process, which included a Main Report and seven Addendums (dated June 25, 2010). In Addendum 7, Seismic Analysis and Quantification, the licensee performed a detailed SDP analysis of seismic initiating events. The senior reactor analyst (SRA) used that part of the licensees seismic analysis to assess the risk for this current performance deficiency. The resultant seismic-induced flood risk increase for Unit 2 was 1.98E-6 for an entire year, which equated to a risk increase of 1.4E-7/yr for the 25-day exposure period. This value is conservative since it included non-LOOP as well as LOOP events. Since only 18 percent of the Unit 2 sequences involved LOOP flooding scenarios, the SRA determined that the change in core damage frequency (ACDF) for this finding would be approximately 2.5E-8/yr. The dominant sequence involved a station blackout with pipe breaks associated with these pieces of equipment: generator hydrogen cooler, generator exciter cooler, hydrogen seal oil unit cooler, condensate pump motor unit coolers, miscellaneous small piping, and multiple fire protection
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-2012007-032012Q3Prairie 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-2012504-012012Q4Prairie IslandDegraded Emergency Action Level SchemeA finding having a significance of preliminarily White with one AV of 10 CFR 50.54(q)(2) associated with risk-significant planning standard 10 CFR 50.47(b)(4) was identified by the NRC for the licensee\\\'s failure to follow and maintain the effectiveness of its emergency plan. Specifically, from July 24, 2011, until May 18, 2012, Prairie Island Nuclear Generating Plants Unit 1 response to the loss of 1R-50 Shield Building Hi Range Vent Gas Radiation Detector failed to restore the capability to classify Emergency Action Levels (EALs), RG1.1, General Emergency, and RS1.1, Site Area Emergency. On May 17, 2012, Corrective Action Program entry 01338120 was written and identified the incorrect repair priority on 1R-50. The instrument was repaired and returned to service on May 18, 2012. This finding was determined to be more than minor because it was associated with the Emergency Response Organization performance attribute of the Reactor Safety Emergency Preparedness Cornerstone. This finding adversely affected the cornerstone objective of ensuring that the licensee is capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. This finding was evaluated in accordance with IMC 0609, Appendix B, Emergency Preparedness Significance Determination Process. As Appendix B was revised in February 2012, the finding was evaluated using both the version in effect at the time of the violation and the current version. Under both versions, other than changing the names of the involved Section and Sheet/Attachment, there was no effect on the final outcome. The issue was determined to be a Failure to Comply. The risk was evaluated using Section 4.0 of IMC 0609 and Sheet 1, Failure to Comply, in the previous revision, and Section 5.0 and Attachment 2, Failure to Comply Significance Logic, in the current revision, along with their associated narratives. With EALs, RG1.1 and RS1.1, ineffective, the inspectors considered mitigating factors, such as alternative EALs, within the same initiating condition and determined the alternative EALs were such that an accurate declaration of the initiating condition would have been made. Therefore, the inspectors determined that no loss of Risk-Significant Planning Standard (RSPS) function existed. However, the alternative EAL classifications would have been delayed, and, therefore, the event would have been declared in a degraded manner. The finding was preliminarily determined to be of low to moderate safety significance (White) in that ineffective EALs, RG1.1, and RS1.1 existed, degraded an RSPS function, and affected the ability of the licensee to properly classify events involving a radiological release. A cross-cutting aspect (H.1(a)) was identified within the decision making component. The licensees risk-significant decision concerning the timely corrective actions to restore the failed 1R-50 Shield Building Hi Range Vent Gas Radiation Detector did not use a systematic process to ensure safety was maintained. A lack of formally defined authority and roles for decisions and communications precluded the appropriate interdisciplinary input, evaluation, and repair of this equipment.
05000282/FIN-2013004-012013Q3Prairie IslandImproper Work Instructions Rendered 2R-49 InoperableA self-revealing finding of very low safety significance (Green) and an non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings was identified on July 2, 2013, for the failure to have documented instructions, procedures, or drawings, of a type appropriate to the circumstances while performing maintenance. Specifically, maintenance personnel rendered Unit 2 Containment High Range Area Monitor 2R-49 inoperable after lifting a wire as part of a Unit 1 Containment High Range Area Monitor 1R-49 power supply replacement. Corrective actions for this issue included returning 1R-49 and 2R-49 to service and providing additional supervisory involvement to ensure all maintenance personnel were aware of expectations for ensuring that energized leads were appropriately identified, that adequate barriers were established to prevent inadvertent contact with energized leads, and ensuring that access to leads to be lifted were adequate for safe manipulation. The inspectors determined that this issue was more than minor because it was associated with the configuration control and procedure quality 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). This issue 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. This issue was cross cutting in the Human Performance, Work Control area because the licensee failed to appropriately plan work activities by incorporating job site conditions which may impact human performance or plant structures, systems, and components (H.3(a)).
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