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| Start date | Site | Identified by | Title | Description | |
|---|---|---|---|---|---|
| 05000282/FIN-2018411-01 | 30 September 2018 23:59:59 | Prairie Island | Licensee-identified | Licensee-Identified Violation | |
| 05000306/FIN-2018003-04 | 30 September 2018 23:59:59 | Prairie Island | NRC identified | Failure to Promptly Identify and Correct 21 125 VDC Battery Lid Conditions Adverse to Quality | The inspectors identified a finding of very low safety significance (Green) and associated NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, as of February 15, 2018, for the licensees failure to promptly identify and correct conditions adverse to quality associated with the 21 125 VDC battery system. |
| 05000282/FIN-2018003-03 | 30 September 2018 23:59:59 | Prairie Island | NRC identified | Failure to Promptly Identify Degradation of the 122 DDCLP FOST Vent Piping | The inspectors identified a finding of very low safety significance (Green) and associated NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, as of November 28, 2017, for the licensees failure to promptly identify a condition adverse to quality associated with 122 DDCLP FOST vent piping. |
| 05000282/FIN-2018003-02 | 30 September 2018 23:59:59 | Prairie Island | NRC identified | Failure to Maintain a Preventative Maintenance Strategy for 12 and 22 Cooling Water Pump Diesel Engines | The inspectors identified a finding of very low safety significance (Green) and associated NCV of Prairie Island Technical Specification 5.4.1, Procedures, as of August 9, 2018, for the licensees failure to maintain a preventative maintenance strategy for sacrificial zinc anode plugs on the jacket water system for the 12 and 22 cooling water pump diesel engines (DDCLPs). |
| 05000282/FIN-2018003-01 | 30 September 2018 23:59:59 | Prairie Island | NRC identified | Failure to Repair a D2 EDG Jacket Water Leak per the Leak Management Process | The inspectors identified a finding of very low safety significance (Green) as of July 18, 2018, for the licensees failure to repair a D2 EDG jacket water leak per the Leak Management Process. |
| 05000282/FIN-2018411-02 | 30 September 2018 23:59:59 | Prairie Island | Licensee-identified | Licensee-Identified Violation | |
| 05000282/FIN-2018002-01 | 30 June 2018 23:59:59 | Prairie Island | NRC identified | Results of ISFSICask Array Dose Calculation Not Incorporated into FSAR | Prairie Island ISFSI FSAR, as updated, Revision 18, Section A7A.7 evaluates off-site dose rates for an array of ISFSI casks. In this dose rate calculation, explicit modeling credit is given to the earthen berm that surrounds the Prairie Island ISFSI as discussed in Section A7A.7.1. The earthen berm provides radiation shielding for the ISFSI. This calculation allows the licensee to demonstrate, in part, compliance with Title 10 of the Code of Federal Regulations (CFR) 72.104(a) which requires, in part, that, During normal operations and anticipated occurrences, the annual dose equivalent to any real individual who is located beyond the controlled area must not exceed 0.25 mSv (25 mrem) to the whole body, 0.75 mSv (75 mrem) to the thyroid and 0.25 mSv (25 mrem) to any other critical organ. Calculation TN40HT0502, TN40HT Far Field Shielding Calculations, Revision 0, was performed by the licensee in support of a License Amendment Request (LAR) to modify the Prairie Island ISFSI TN40 cask design (designated as TN40HT casks). The TN40HT LAR was submitted to the NRC by the licensee on March 28, 2008. This dose rate calculation does not credit the earthen berm and, in part, also allows the licensee to demonstrate, in part, compliance with 10 CFR 72.104(a). The licensee also provided this calculation directly to the NRC in a February 29, 2012, letter in response to a Request for Supplemental Information (RSI) from the NRC associated with the license renewal application for the Prairie Island ISFSI. Although the results from calculation TN40HT0502 for a single cask was incorporated into the Prairie Island ISFSI FSAR, Revision 18, in Tables A7A.22 and A7A.61, the results from TN40HT0502 for an array of casks which, in part, allows the licensee to demonstrate, in part, compliance with 10 CFR 72.104(a), has not been incorporated into the ISFSI FSAR, Revision 18.Title 10 CFR 72.70, Safety analysis report updating requires, in part, that (a) Each specific licensee for an ISFSI shall update periodically, as provided in paragraphs (b) and (c) of this section, the FSAR to assure that the information included in the report contains the latest information developed (b) Each update shall contain all the changes necessary to reflect information and analyses submitted to the Commission by the licensee or prepared by the licensee pursuant to Commission requirement since the submission of the original FSAR or, as appropriate, the last update to the FSAR under this section. The update shall include the effects of: (2) All safety analyses and evaluations performed by the licensee in support of approved license amendments.This Unresolved Item is being opened to determine whether or not the licensee is required to update the ISFSI FSAR with the results of calculation TN40HT0502 for an array of casks in accordance with 10 CFR 72.70.Planned Closure Action: Region III will coordinate with the Division of Spent Fuel Management in the NRC Office of Nuclear Material Safety and Safeguards to determine whether or not calculation TN40HT0502 is subject to the FSAR updating requirements of 10 CFR 72.70 for the Prairie Island ISFSI. |
| 05000282/FIN-2018011-01 | 30 June 2018 23:59:59 | Prairie Island | NRC identified | Failure to Justify Load Combinations Used in Main Steam Piping Stress Analysis | Inspectors identified a Green finding and associated Non-Cited Violation of Title 10 of the Code of Federal Regulations, Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to correctly translate provisions from specified quality standards for load combinations into piping analysis. Specifically, in the analysis for the Class I main steam piping, the licensee combined the seismic Operating Basis Earthquake and safety relief valve operating loads by Square Root of Sum of Squares. Prairie Island Updated Safety Analysis Report and the Engineering Manual for piping system stress analysis do not permit the Square Root of Sum of Squares method for combining these loads. |
| 05000282/FIN-2018011-02 | 30 June 2018 23:59:59 | Prairie Island | NRC identified | Potential Failure to Protect Class I Structures, Systems,and Components from Tornado Generated Missiles | Inspectors identified a number of structure, systems,and components (SSCs) that lacked protection from tornado generated missiles. The following SSCs were identified: Division 1 and Division 2 Emergency Diesel Generators (D1/D2 EDGs)engine exhaust, fuel oil day tank vents, and main fuel oil storage tanks vents; and Diesel Driven Cooling Water Pumps (DDCWPs) main fuel storage tank vents, day tank vents, engine exhausts, and rooms ventilation intake and exhaust equipment. In various cases susceptible SSCs for redundant equipment (e.g. fuel tank vents) were right next to or within a few feet of each other such that a single missle could affect both trains of the system A review of the sites licensing bases, including the original FSAR, identified the D1/D2 EDGs and the DDCWPs as Class I, safety-related SSCs, which are required to be designed to withstand, without loss of capability, environmental phenomena including tornadoes and tornado generated missiles. Specifically, the current USAR Table 12.2-1, Classification Of Structures, Systems and Components, list both systems as Class I and has two notes of interest. Note 1 applies to the Diesel Generators and their associated (Main) Fuel Oil Storage Tank, which states, in part, The indicated Design Class I is applicable to D1/D2 Diesel Generators and associated(emphasis added) safety related components and systems. The second note is listed at the beginning of the Table, which states,in part,To determine detail design classifications and boundaries separating different design classes within the overall classification scheme listed here, refer to controlled drawings. A review of controlled drawings, including NF-39255-1, Flow Diagram Diesel Generators D1 & D2 Unit 1 & 2,Revision 85, and NF-39232, Flow Diagram Fuel & Diesel System Unit 1 & 2, Revision 86,showed the fuel oil vents for the main storage tanks, fuel oil vents for the day tanks,engine exhaust piping,mufflers, and silencers for the D1/D2 EDGs and DDCWPs were classified as safety-related Class I SSCs. A review of the current UFSAR identified the following sections of interest:The USAR Section 1.5.I, Overall Plant Requirements, Criterion 2 -Performance Standards, Answer, established in part The system and components designated Class I in Section 12, in conjunction with administrative controls and analysis, as applicable, are designed to withstand, without loss of capability to protect the public, the most severe environmental phenomena ever experienced at the site with appropriate margins included in the design for uncertainties in historical dataThe USAR Section 12.2.1.1.a, Classification of Structures and Components, defines Design Class I as Those structures and components including instruments and controls whose failure might cause or increase the severity of a loss-of-coolant accident or result in an uncontrolled release of substantial amounts of radioactivity, and those structures and components vital to safe shutdown and isolation of the reactor.The USAR Section 12.2.5.1.g.1, Protection for Class I Items, establishes, in part, that Class I items are protected against damage from: Missiles from different sources.These sources comprise: Tornado created missiles.The USAR Section 12.2.1.3.2.c., Tornado Loads, defines the design tornado driven missile as assumed equivalent to an airborne 4 x 12 x 120 plank travelling end-on at 300 mph, or a 4000 lbs automobile flying through the air at 50 mph and at not more than 25 feet above ground level.Based on the above, the inspectors were concerned the susceptible SSCs could lose the capability to perform their safety-related function if they were impacted by tornado generated missiles. For example, an impact to the fuel oil vents could crimp the vent path resulting in a vacuum inside the tanks that could collapse the tank and/or cause the associated fuel transfer pump to lose net positive suction head The licensee provided a position paper proposing the susceptible SSCs identified by the inspectors were meeting their current licensing bases and no further actions were required. The inspectors disagreed, but decided to request support from the Office of Nuclear Reactor Regulation (NRR) to obtain clarification on the sites licensing bases related to tornado generated missiles. Planned Closure Action: The inspectors have requested NRR to provide clarification on the sites current licensing bases regarding tornado generated missiles required protection.Licensee Action: Licensee is considering doing a self-review of design and licensing basis of the fuel oil storage tank vent lines to understand and clarify design class of the lines Corrective Action Reference:501000012997 |
| 05000306/FIN-2018001-01 | 31 March 2018 23:59:59 | Prairie Island | NRC identified | Questions Regarding Corrective Action Program, Use of Operating Experience, and Qualification of the 21 125 VDC Battery due to Cell Lid Cracking | The inspectors identified an unresolved item regarding manual override of the auto-closure function of component cooling water system valves. Specifically, the inspectors noted that the system was not protected from tornado generated missiles when valves CV39153 & CV39154 are opened per procedure to support system alignments. The inspectors initially determined that further review was needed to determine if Technical Specifications are met if/when CV39153 & CV39154 are maintained open.Corrective Action Reference: AR 501000001642; 2017 50.59 Potential PD Evaluation 1133; 08/15/2017 Closure Basis: The inspectors reviewed the license basis documentation, procedures, and interviewed licensee personnel, and did not identify any licensee failure to meet a requirement or standard. |
| 05000282/FIN-2018001-02 | 31 March 2018 23:59:59 | Prairie Island | NRC identified | Questions Regarding the Corrective Action and Aging Management Programs Following the Discovery of 122 DDCLP FOST Vent Piping Degradation | On November 28, 2017, the inspectors identified a small hole in the vent piping for the below-ground 122 DDCLP FOST (located outside and adjacent to the plant screenhouse). The station generated AR 501000005894 and the shift manager declared the supported 22 DDCL pump operable-but-degraded with a temporary procedure change to AB4, Flood as a compensatory measure and wrapping of the pipe to preclude foreign material intrusion. The site backed up the immediate operability determination with a POD, evaluated past operability (no issues identified) and, subsequently replaced the affected portion of the pipe to restore full qualification. The inspectors concluded that these short term actions were acceptable to address the issue, but identified several concerns regarding prior actions to address the vent pipe corrosion. On March 1, 2018, the inspectors were provided the final evaluations for AR 501000005894. After review, the inspectors were concerned that the evaluations did not perform a sufficient review of: whether the corrective action program properly dispositioned corrosion of the pipe when first identified in July of 2015;whether the corrective action program and aging management program (AMP) performed as required to correctly classify and correct and/or manage the corrosion aging mechanism; and whether the extent of cause/condition for the adjacent 121 DDCLP FOST vent pipe was properly addressed.The inspectors passed these concerns to individuals in the engineering and regulatory affairs departments, but the licensee then stated that the evaluations provided on March 1, were, in actuality, still in a revision/review phase. The licensee stated that the final evaluations would likely address the inspectors concerns. On March 22, the inspectors were provided the final evaluations, but it appeared that only minor changes were made and the inspectors concerns were not addressed. On March 28, the inspectors again voiced their concerns with the licensee and two new ARs (501000010169 and 501000010178) were created documenting the following:the AR written identifying corrosion of the piping in July of 2015 was not evaluated under the AMP, the condition was determined to be operable and fully qualified, and it was closed to a work request to re-coat the piping but was never performed.the AR written in April of 2016 again noted the corrosion, but was closed to a non-conservative evaluation, the issue was not evaluated under the AMP, operability was again assessed as operable and fully qualified, and a work request was issued to apply a coating (not completed until May of 2017) 12 the AMP engineer was not consulted in 2015 or 2016 to determine if/how the issue fit into the AMP requirements for increased monitoring, development of acceptance criteria, and final corrective actions.Planned Closure Actions: To resolve this item, the inspectors will review planned actions regarding the degraded 121 DDCLP FOST vent pipe, further extent of condition reviews, and review planned licensee condition and causal evaluations regarding programmatic and/or human performance aspects of the issue.Licensee Actions: At the end of the inspection period, the licensee began excavation activities to replace the 121 DDCLP FOST vent pipe and had apparent cause and extent of condition evaluations in progress.Corrective Action Program References: ARs 501000005894, 501000010169 and 501000010178. |
| 05000282/FIN-2017004-02 | 31 December 2017 23:59:59 | Prairie Island | Licensee-identified | Licensee-Identified Violation | Title 10 CFR 50.54(q)(2) requires, in part, that a holder of a nuclear power reactor operating license shall follow and maintain the effectiveness of an emergency plan that meets the requirements in Title 10 CFR Part 50, Appendix E and the planning standards of Title 10 CFR 50.47(b). Title 10 CFR 50.47(b)(4) requires, in part, that the onsite emergency response plans for nuclear power reactors must meet the following standard: a standard emergency classification and action level scheme, the bases of which include facility system and effluent parameters, is in use by the nuclear facility licensee, and State and local response plans call for reliance on information provided by facility licensees for determinations of minimum initial offsite response measures.Contrary to the above, between November 22, 2000 and September 22, 2017, the licensee failed to maintain the effectiveness of an emergency plan that met the requirements of the planning standards of 10 CFR 50.47(b). Specifically, on September 22, 2017, the licensee identified that prior assessments of NRC Information Notice 9745, Supplement 1, Environmental Qualification Deficiency for Cables and Containment Penetration Pigtails, and a subsequent industry-initiated study to determine signal errors for Prairie Islands Unit 1 & 2 containment high range radiation monitors 1R48, 1R49, 2R48 & 2R49 (used in the licensees emergency classification and action level scheme) that impacted operability of the monitors, failed to restore capability to classify EALs during certain design basis accidents.The violation was more than minor because it was associated with the Facilities and Equipment attribute of the Emergency Preparedness Cornerstone and adversely affected the cornerstone objective of ensuring capability of implementing adequate measures to protect the health and safety of the public in 33 the event of a radiological emergency. The inspectors referenced IMC 0609, Attachment 4, Initial Characterization of Findings, and IMC 0609, Appendix B, Emergency Preparedness Significance Determination Process, Table 5.41 and Figure 5.41. The finding was determined to be of very low safety significance (Green) because timely and accurate EAL classification capability for an event at the General Emergency level was unaffected due to redundant and diverse indications.In response, the licensee entered the issue into the CAP as CAP 501000001861, declared the containment high range radiation monitors inoperable per TS 3.3.3, Event Monitoring Instrumentation, implemented Emergency Plan interim measures to make the emergency response organization aware of the issue, performed an extent-of-condition review, and submitted a letter to the U.S. NRC within 14 days as required by TS. Final corrective actions included the addition of a note to the Prairie Island EAL matrix to acknowledge the potential for TIC errors for the containment high range radiation monitors during the first 5 minutes for post-loss of coolant accident (LOCA) or main steam line break events inside containment. |
| 05000282/FIN-2017004-03 | 31 December 2017 23:59:59 | Prairie Island | Licensee-identified | Licensee-Identified Violation | Prairie Island TS LCO 3.0.3 requires, in part, that when an LCO is not met and an associated ACTION is not provided, action shall be initiated within 1 hour to place the unit in MODE 3 within 7 hours.Contrary to the above, at 1556 hours on May 4, 2016, the licensee failed to place Unit 2 in MODE 3 within 7 hours due to no associated ACTION provided within TS 3.6.5, Containment Spray and Cooling Systems for two containment cooling trains not OPERABLE. Specifically, between May 4 and May 5, 2016, operators failed to recognize that with the ongoing unplanned inoperability of the 122 control room chiller, and the subsequent unplanned inoperability of the A train #23 CFCU, the 122 control room chiller was a required support system for the B train #22 and #24 CFCUs. Therefore, with both of the Unit 2 CFCU trains inoperable, LCO 3.0.3 was required to be entered to place Unit 2 in Mode 3 within 7 hours. Because the supported system TS applicability was not recognized, LCO 3.0.3 was not entered as required and both trains of Unit 2 CFCUs were inoperable for approximately 35 hours.Because the inspectors answered No to questions B.1 and B.2 under Exhibit 3, Barrier Integrity Screening Questions of IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings at Power, the finding screened as very low safety significance (Green). The issue was entered into the licensees CAP as CAP 501000002726. Corrective actions included re-assessing shared system LCOs between Units 1 and 2, revising the LCO tracking database, implementing new standards for LCO 3.0.6 applications, and revisions to the Safety Function Determination Program. |
| 05000282/FIN-2017004-04 | 31 December 2017 23:59:59 | Prairie Island | Licensee-identified | Licensee-Identified Violation | Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality shall be prescribed by documented procedures of a type appropriate to the circumstances and shall be accomplished in accordance with these procedures. Contrary to the above, on October 17, 2017, with Unit 2 in Mode 5, Cold Shutdown, the licensee failed to accomplish procedure 2C12.2, Purification and Chemical Addition Unit 2; Revision 34. Specifically, control room operators signed off steps as completed without validating that the procedure actions were performed in the field. These procedure steps that intended to close letdown valves and open purification valves, resulted in unintended transfer of primary coolant from the RCS to the chemical and volume control system hold-up tank instead of back to the RCS. In turn, this resulted in a reduction in RCS inventorywith reactor vessel level at approximately 1 foot below the flange (reduced inventory operations). Due to operators quickly recognizing a lack of letdown flow as discussed during a pre-job brief, the purification evolution was halted and actions were taken to restore reactor vessel level.Because the inspectors answered No to questions B.2 and B.3 under Exhibit 2, Initiating Events Screening Questions of IMC 0609, Appendix G, Attachment 1, Shutdown Operations Significance Determination Process Phase 1 Initial Screening and Characterization of Findings, the finding screened as very low safety significance (Green). Specifically, the loss of inventory event was self-limiting such that the leakage would have stopped before impacting the operating method of decay heat removal (shutdown cooling via RHR in this case). The issue was entered into the licensees CAP as CAP 501000003923. Corrective actions included an operations department human performance clock reset to share the lessons learned from the event. |
| 05000282/FIN-2017004-01 | 31 December 2017 23:59:59 | Prairie Island | Licensee-identified | Licensee-Identified Violation | Technical Specification 5.7.1 states, High Radiation Areas accessible to personnel in which radiation levels could result in an individual receiving a deep dose equivalent less than 1.0 rem in one hour at 30 centimeters from the radiation source or from any surface that the radiation penetrates. Technical Specification 5.7.1, further requires in part, that each entryway to such an areashall be barricaded and conspicuously posted as a high radiation area.Contrary to the above, on October 19, 2017, a licensee system engineer identified during the performance of a maintenance and engineering inspection that a chain that functioned as the barricade for the 22 reactor coolant pump vault, a posted high radiation area, was not installed. The licensee documented this issue in CAP 501000004026. The inspectors determined that this issue was of very-low safety significance (Green) after reviewing IMC 0609, Appendix C, Occupational Radiation Safety Significance Determination Process. The inspectors determined that this finding was not an ALARA Planning or Work Control issue; was not an overexposure; was not a substantial potential for overexposure; and the ability to assess dose was not compromised. |
| 05000282/FIN-2017003-01 | 30 September 2017 23:59:59 | Prairie Island | NRC identified | Failure to Ensure Correct Operation of Meteorological Tower | A finding of very-low safety significance, and an associated NCV of Technical Specification (TS) 5.4.1 was identified by the NRC inspectors for the failure to implement and maintain procedures to ensure adequate operation of a meteorological tower. The licensee entered this issue into their Corrective Action Program (CAP) as CAP 501000001091, dated July 27, 2017. The licensee had initiated efforts to assess and remove unnecessary vegetation growth. The inspectors determined that the performance deficiency was more-than-minor in accordance with IMC 0612, Appendix B, Issue Screening, because the finding impacted the Plant Facilities/Equipment and Instrumentation Attribute of the Public Radiation Safety Cornerstone, and adversely affected the cornerstone objective of ensuring adequate protection of public health and safety from exposure to radioactive materials released into the public domain as a result of routine civilian nuclear reactor operation. Specifically, existing meteorological tower procedures did not include the assessment and subsequent removal of trees that could impair the correct operation of sensors located at the 10 meter elevation of the tower. The finding was determined to be of very-low safety significance in accordance with IMC 0609, Appendix D, Public Radiation Safety Significance Determination Process, dated February 12, 2008. The violation was of very-low safety significance (Green) because: it was not a failure to implement the Effluent Program, nor did public dose exceed Appendix I or Title 10 of the Code of Federal Regulations (CFR), Part 20.1301(e) criteria. The inspectors concluded that the most significant contributing cause of the performance deficiency involved the Resolution cross cutting component in the area of problem identification and resolution because this issue was previously entered into the licensees CAP in 2015 and closed with no action taken. (P.3) |
| 05000282/FIN-2017003-02 | 30 September 2017 23:59:59 | Prairie Island | Licensee-identified | Licensee-Identified Violation | Title 10 CFR 50.48(b)(2) requires, in part, that all nuclear power plants licensed to operate before January 1, 1979, must satisfy the applicable requirements of Appendix R to this part, including specifically the requirements of Sections III.G, III.J, and III.O. Appendix R, Section III.G.3 of 10 CFR Part 50, requires, in part, that alternative or dedicated shutdown capability and its associated circuits, independent of cables, systems or components in the area, room, or zone under consideration should be provided where the protection of systems whose function is required for hot shutdown does not satisfy the requirement of paragraph G.2 of this section. In addition, fire detection and a fixed fire suppression system shall be installed in the area, room, or zone under consideration. Contrary to the above, on December 21, 2015, the licensee failed to provide an alternative or dedicated shutdown capability for 17 MOVs credited in the licensees Appendix R Safe Shutdown Analysis that did not satisfy the requirements of 10 CFR Part 50, Appendix R, Section G.2. Specifically the MOVs could have been rendered unavailable for manual operator action following a postulated fire in the control or relay rooms. These manual actions were required to achieve and maintain safe shut down in the event of a fire that resulted in functional loss and/or evacuation of the control and/or relay rooms. Section 9.1 of the NRC Enforcement Policy allows the NRC to exercise enforcement discretion for certain fire protection related non compliances identified as a result of a licensees transition to the new risk informed, performance based fire protection approach included in 10 CFR 50.48(c), and for 25 certain existing non compliances that reasonably may be resolved by compliance with 10 CFR 50.48(c) as long as certain criteria are met. This risk informed, performance based approach is referred to as National Fire Protection Association (NFPA) 805, Performance Based Standard for Fire Protection for Light Water Reactor Electric Generating Plants. At the time of discovery, the licensee was in transition to NFPA 805 and therefore the licensee-identified violation was evaluated in accordance with the criteria established by Section 9.1(a) of the NRCs Interim Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48) for a licensee in NFPA 805 transition. The inspectors determined that for this violation: (1) the licensee identified the violation during the scheduled transition to 10 CFR 50.48(c); (2) the licensee had established adequate compensatory measures within a reasonable time frame following identification and would correct the violation as a result of completing the NFPA 805 transition; (3) the violation was not likely to have been previously identified by routine licensee efforts; and (4) the violation was not willful. The finding also met additional criteria established in section 12.01.b of IMC 0305, Operating Assessment Program. In addition, in order for the NRC to consider granting enforcement discretion the violation must not be associated with a finding of high safety significance (i.e., Red). The licensee performed risk evaluation V.SPA.16.001, Revision 0, dated March 27, 2017, and determined that this issue was not associated with a finding of high safety significance. A Region III Senior Reactor Analyst (SRA) reviewed the evaluation and concluded that the result was reasonable and that the finding was less than Red and eligible for enforcement discretion. The dominant core damage sequence from the licensees evaluation was a fire in the Control Room or Cable Spreading Room which could cause spurious operation of several MOVs necessary for safe shutdown. The SRA used IMC 0609, Appendix F, Fire Protection Significance Determination Process, to review the results of the licensees evaluation. The SRA validated the licensees calculations through a series of walkdowns, reviews of the calculation and verification of the values used were consistent with NUREG-6850 and IMC 0609, Appendix F. The licensees results were approximately 1E6 deltaCDF and 2E8 deltaLERF for this finding and hence were significantly lower than the 1E4 deltaCDF threshold for a finding of high safety significance. In addition, the licensee entered this issue into their corrective action program as CAP 1506561. As a result, the inspectors concluded that the violation met all four criteria established by Section 9.1(a) and that the NRC was exercising enforcement discretion to not cite this violation in accordance with the Interim Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection Issues. |
| 05000282/FIN-2017003-03 | 30 September 2017 23:59:59 | Prairie Island | Licensee-identified | Licensee-Identified Violation | Title 10 CFR 50, Appendix B, Criterion XI, Test Control, requires, in part, that a test program shall be established to assure that all testing required to demonstrate that SSCs will perform satisfactorily in service is identified and performed in accordance with written test procedures which incorporate the requirements and acceptance limits contained in applicable design documents. Specifically, the licensee established procedure 5 AWI 3.12.4, 26 Post-Maintenance Testing, Revision 24, as the program for selecting and documenting post maintenance tests (PMTs) and return to service tests to ensure that SSCs would perform their intended function when returned to service. Contrary to the above, on September 20, 2017, the licensee failed to assure that testing required the demonstrate that three safety injection system actuation relays would perform satisfactorily in service was identified and performed in accordance with written test procedures, which incorporated the requirements and acceptance limits contained in applicable design documents. The three safety injection system actuation relays had not been tested following replacement during planned maintenance. Specifically, while reviewing PMT activities performed on the D5 EDG on September 19, 2017, the licensee identified three safety injection system actuation relays that had not been tested following replacement during planned maintenance. As a result, the D5 EDG was declared inoperable at the time of discovery on September 20, 2017. In response, the licensee performed an in-depth review of all recent D5 EDG maintenance activities to ensure that all PMT requirements were met and performed SP 2150, D5 Diesel Generator Function Test, on September 21, 2017, to adequately test all three safety injection system actuation relays and an additional D5 EDG slow start test to fully demonstrate operability of D5. Because the inspectors answered No to all questions under Exhibit 2.A of IMC 0609, Appendix A, The Significance Determination Process for Findings at-Power, the finding screened as very low safety significance (Green). The above issue was documented in the licensees CAP as CAP 501000002920. Corrective actions included performing an apparent cause evaluation, department clock reset, and planned changes to 5 AWI 3.12.4 to ensure all required PMT activities are performed satisfactorily prior to returning SSCs to service. |
| 05000282/FIN-2017003-04 | 30 September 2017 23:59:59 | Prairie Island | Licensee-identified | Licensee-Identified Violation | Prairie Island Technical Specification 3.0.6 requires, in part, that an evaluation shall be performed in accordance with Technical Specification 5.5.13, Safety Function Determination Program, when a supported system LCO is not met solely due to a support system LCO not being met. Specifically, if a loss of safety function is determined to exist by the Safety Function Determination Program, the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists are required to be entered.Contrary to this TS requirement, between August 18 and 22, 2017, control room operators did not evaluate Unit 2 A Component Cooling, Auxiliary Feedwater, and Cooling Water supported system LCOs while the 121 Safeguards Chilled Water support system LCO was not met. As a result, the appropriate Conditions and Required Actions were not entered during Unit 2 B Component Cooling and Auxiliary Feedwater supported system maintenance and testing activities for which a loss of safety function existed. Because the inspectors answered No to all questions under Exhibit 2.A of IMC 0609, Appendix A, The Significance Determination Process for Findings at-Power, the finding screened as very low safety significance (Green). Specifically, the finding did not represent (result in) an actual loss of function of two separate safety systems out-of-service for greater than their TS-allowed outage times. The above issues were documented in the licensees CAP as CAP 501000001929. Corrective actions included revisions to applicable station procedures for implementing TS 3.0.6 and the Safety Function Determination Program. |
| 05000282/FIN-2017201-01 | 30 June 2017 23:59:59 | Prairie Island | NRC identified | Security | |
| 05000282/FIN-2017002-02 | 30 June 2017 23:59:59 | Prairie Island | Self-revealing | Failure to Implement the Emergency Plan | A self-revealed finding, and an associated NCV of Title 10 of the Code of Federal Regulations (10 CFR) 50.54 (q)(2), and 10 CFR 50.47 (b)(5) was identified on August 13, 2016, after a Notice of Unusual Event (NOUE) was declared due to reactor coolant system leakage greater than 25 gpm, the Shift Emergency Communicator (SEC) did not notify the States, Locals, and Tribal Community within 15 minutes of the classification.The inspectors reviewed IMC 0612, Appendix B, and determined that the finding was more than minor because it adversely affected the Emergency Response Performance attribute of the EP cornerstone objective to ensure 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. Since the finding involved a failure to implement emergency preparedness requirements, the inspectors reviewed IMC 0609, Appendix B, Attachment 1, and determined that this was a finding of very-low significance (Green) because it involved the failure to notify the offsite response organizations as required in the Emergency Plan after the classification of an NOUE. The cause of this finding involved the cross-cutting area of human performance, with the aspect of procedure use and adherence because the SEC did not appropriately follow the notification procedure. (H.8) |
| 05000282/FIN-2017002-04 | 30 June 2017 23:59:59 | Prairie Island | Licensee-identified | Licensee-Identified Violation | Title 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 10 CFR Part 50, Appendix E and the planning standards of 10 CFR 50.47(b). Title 10 CFR Part 50.47(b)(8) states, Adequate emergency facilities and equipment to support the emergency response are provided and maintained. Section 8.2.2 of the Prairie Island Emergency Plan, Revision 52, states All supplies are inventoried quarterly and dated equipment and material are periodically replaced according to surveillance and testing program. Contrary to the above, from the fourth quarter of 2015 to fourth quarter of 2016, the licensee failed to maintain the effectiveness of the Emergency Plan by failing to complete the quarterly inventory of supplies and equipment in the alternative emergency response facility at their Red Wing Service Center. Specifically, for approximately five quarters, the licensee had not been conducting required quarterly inventory and equipment checks at the Alternative Emergency Response Facility due to several site procedures and supporting forms that verify continued facility readiness that were not updated or created following the 2014 Hostile Action Based Exercise.The inspectors determined that the finding was of very-low significance (Green) in accordance with NRC Inspection Manual Chapter (IMC) 0609, Appendix B, Emergency Preparedness Significance Determination Process, Attachment 2, because this is a failure to comply with the Emergency Plan that does not result in a loss of a planning standard function. The licensee determined that the alternative emergency response facility remained functional during the time period when the inventories were missed. Because this finding is of very low safety significance, and has been entered into the licenseesCorrective Action Program under CAP 1513061, this violation is being treated as a Green NCV consistent with Section 2.3.2 of the NRCs Enforcement Policy. |
| 05000282/FIN-2017201-02 | 30 June 2017 23:59:59 | Prairie Island | NRC identified | Security | |
| 05000282/FIN-2017002-03 | 30 June 2017 23:59:59 | Prairie Island | NRC identified | Failure to Make an 8Hour Report Required by05000306/201700203 10 CFR 50.72(b)(3)(ii)(B) | The inspectors identified a Severity Level (SL) IV NCV of 10 CFR 50.72(b)(3)(ii)(B) due to the licensees failure on March 20, 2017, to report an unanalyzed condition within eight hours of discovery. Specifically, removing the lower latch assembly of a transom above Door 225, a steam exclusion barrier, during maintenance resulted in the inoperability of the Units 1 and 2 safeguards batteries and Auxiliary Feed Water (AFW) systems, and Unit 1 safeguards bus as determined by CAP 1549724.The inspectors determined that the failure to submit a report required by 10 CFR 50.72 for the unanalyzed condition described above was a performance deficiency. The inspectors determined that this issue had the potential to impact the regulatory process based, in part, on the information that 10 CFR 50.72 reporting serves. Since the issue impacted the regulatory process, it was dispositioned through the Traditional Enforcement process. The inspectors determined that this issue was a SL IV violation based on Example 6.9.d.9 in the NRC Enforcement Policy. Example 6.9.d.9 specifically states, A licensee fails to make a report required by 10 CFR 50.72 or 10 CFR 50.73. Because the issue has been evaluated under the Traditional Enforcement process, there was no cross-cutting aspect associated with this violation. |
| 05000282/FIN-2017002-01 | 30 June 2017 23:59:59 | Prairie Island | NRC identified | Failure to Properly Implement the Minor Maintenance Process During Door 225 Transom Maintenance | The inspectors identified a finding of very low safety significance (Green) and an associated NCV of TS 5.4.1.a, Procedures, associated with the licensees failure to properly implement Procedure FPWMMMP01, Minor Maintenance Process, Revision 5, while planning and performing maintenance on a steam exclusion barriertransom latch assembly. Specifically, on February 3, 2017, maintenance workers in coordination with the Fix-It-Now (FIN) Senior Reactor Operator (SRO) removed the lower latch assembly from a transom above Door 225 that rendered the steam exclusion barrier non-functional. Consequently, for an approximately five minute window during maintenance on the latch assembly, the 11 safeguards battery system was rendered inoperable with respect to a postulated turbine building High Energy Line Break (HELB) event. The licensee entered the issues into the Corrective Action Program (CAP) as CAPs 1548470 and 1549724.The inspectors determined that the licensees failure to properly implement procedure FPWMMMP01 as required by Technical Specification (TS) 5.4.1.a. was aperformance deficiency. The performance deficiency was determined to be more than minor and a finding in accordance with IMC 0612, Appendix B, Issue Screening, because it was associated with the Mitigating Systems Cornerstone attribute of Human Performance and affected the associated cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors applied IMC 0609, Attachment 4, Initial Characterization of Findings, to this finding. Since the inspectors answered No to all questions within IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, the finding screened as very low safety significance (Green). The inspectors determined that the performance characteristic of the finding that was the most significant causal factor of the performance deficiency was associated with the cross-cutting aspect of Teamwork in the Human Performance cross-cutting area, and involved individuals and work groups not properly communicating and coordinating their activities within and across organizational boundaries to ensure nuclear safety was maintained. (H.4) |
| 05000282/FIN-2017001-02 | 31 March 2017 23:59:59 | Prairie Island | Licensee-identified | Licensee-Identified Violation | Title 10 CFR Part 50, Appendix R, Section III.G.2 requires, in part, that where cables or equipment of redundant trains of systems necessary to achieve and maintain hot shutdown conditions are located within the same fire area outside of primary containment, one means of ensuring that one of the redundant trains is free of fire damage shall be provided. Contrary to the above, up until April 21, 2016, the licensee failed to ensure that where cables or equipment of redundant trains of systems necessary to achieve and maintain hot shutdown conditions we re located within the same fire area outside of primary containment, one means of ensuring that one of the redundant trains is free of fire damage was provided. Specifically, the requirement was to provide separation of cables and equipment and associated non -safety circuits of redundant trains by a fire barrier having a 3 hour rating. However, fire barriers with unsealed combustible pathway penetrations existed between FA 85 (Holdup Tank Area/Demineralizer Area) and adjacent FAs 59 (Auxiliary Building Mezzanine Level Unit 1) and FA 74 (Auxiliary Building Mezzanine Level Unit 2) for Units 1 and 2 respectively. Section 9.1 of the NRC Enforcement Policy allows the NRC to exercise enforcement discretion for certain fire protection related non compliances identified as a result of a licensees transition to the new risk informed, performance based fire protection approach included in 10 CFR 50.48(c), and for certain existing noncompliances that reasonably may be resolved by compliance with 10 CFR 50.48(c) as long as certain criteria are met. This risk informed, performance based approach is referred to as NFPA 805, Performance Based Standard for Fire Protection for Light Water Reactor Electric Generating Plants. The licensee is in transition to NFPA 805, and therefore, the licensee- identified violation was evaluated in accordance with the criteria established by Section 9.1(a) of the NRCs Interim Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48) for a licensee in NFPA 805 transition. The inspectors determined that for this violation: (1) the licensee identified the violation during the scheduled transition to 10 CFR 50.48(c); (2) the licensee had established adequate compensatory measures within a reasonable time frame following identification and would correct the violation as a result of completing the NFPA 805 transition; (3) the violation was not likely to have been previously identified by routine licensee efforts; and (4) the violation was not willful. The finding also met additional criteria established in section 12.01.b of IMC 0305, Operating Assessment Program. In addition, in order for the NRC to consider granting enforcement discretion the violation must not be associated with a finding of high safety significance (i.e., Red). The licensee provided the Fire PRA Multi -Compartment Analysis Notebook (FPRA PIMCA) for review, and concluded that this issue was not associated with a finding of high safety significance. An NRC Region III Senior Reactor Analyst (SRA) reviewed the evaluation and discussed it with licensee staff. The evaluation documents the results of fire modeling that concludes the fire 29 scenarios screen from further consideration because a damaging hot gas layer that could affect both compartments is not generated. The SRA concluded that the licensees result was reasonable and that the finding was less than Red and eligible for Enforcement Discretion. In addition, the licensee entered this issue into their CAP as 1519659. As a result, the inspectors concluded that the violation met all four criteria established by Section 9.1(a) of the NRCs Interim Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection Issues and that the NRC was exercising enforcement discretion to not cite this violation in accordance with the Interim Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection Issues. |
| 05000282/FIN-2017001-01 | 31 March 2017 23:59:59 | Prairie Island | NRC identified | Failure to Evaluate Changes to NRC Approved Methodology | Severity Level IV/Green. The inspectors identified a Green finding and associated Severity Level IV Violation of Title 10 of the Code of Federal Regulations (10 CFR) 50.59(d)(1), for the licensees failure to perform a written evaluation which provided the bases for t he determination that a change in the NRC approved Westinghouse methodology referenced in the Updated Safety Analysis Report (USAR) for evaluating the acceptability of reactor pressure vessel internals baffle former bolting distributions did not require a license amendment. This finding was entered into the licensees Correction Action Program ( CAP ) as CAP documents 1539487, Documentation Missing in 50.59 Screening 4443, dated October 26, 2016; 1552331, BFB Screen Referenced Eval for SER Limitation 4 No n-Existent, dated March 6, 2017; and 1552314, BFB Screening Lacks Documentation for SER Limitation 3, dated March 6, 2017. The licensee performed an operability determination and determined the baffle bolts were operable. The inspectors reviewed the operability determination and no performance deficiencies were identified in this determination. The inspectors determined that the licensees failure to perform a written evaluation, providing the bases for the determination that a change in the NRC approved Westinghouse methodology for evaluating the acceptability of baffle former bolting distributions did not require a license amendment, was a performance deficiency. This finding was also evaluated using traditional enforcement because it had the potential for impacting the NRCs ability to perform its regulatory function. The performance deficiency was determined to be more -than -minor because it was associated with the Mitigating Systems cornerstone attribute of design control and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, compliance with the NRC approved methodology of WCAP 15029 PA ensured the baffle former assembly maintained its structural integrity, avoiding a failure or excessive deflection of the baffle plates, and hence the primary concern of ensuring the emergency core cooling system could continue to perform its design function of cooling the reactor core. The inspectors determined the finding could be evaluated using the Significance 3 Determination Process (SDP) in accordance with Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process for Findings At -Pow er, dated June 19, 2012, Exhibit 2, Mitigating Systems Screening Questions, for the Mitigating Systems cornerstone. The finding screened as having very- low safety significance (Green) because the emergency core cooling system maintained its operability , specifically with respect to performing its safety function of ensuring adequate core cooling. As such, the finding corresponded to a Severity Level IV Violation in accordance with Example 6.1.d.2 of the NRC Enforcement Policy. The inspectors did not identify a cross cutting aspect because the performance deficiency was from 2013, and hence the issue did not represent current performance |
| 05000282/FIN-2016004-03 | 31 December 2016 23:59:59 | Prairie Island | NRC identified | Failure to Adequately Calibrate an Electrometer | Green. A finding of very low safety significance, and an associated NCV of Title 10 of the Code of Federal Regulations (10 CFR) 20.1501(c) was identified by the inspectors for the failure to adequately calibrate the electrometer utilized in the validation of a JL Shepherd Calibrator. Specifically on November 30, 2015, the licensee performed a validation of a JL Shepherd Calibrator to ensure its correct operation. The electrometer used was incorrectly calibrated. The electronics and the detectors were required to be calibrated as a set, and this was not performed. The licensee entered this issue into their CAP as CAP 1543432. The inspectors determined that the licensees failure to properly calibrate the electrometer was a PD. The PD was more than minor and a finding in accordance with IMC 0612, Appendix B, Issue Screening, because it was associated with the Occupational Radiation Safety Cornerstone attribute of Program and Process and affected the Cornerstone objective to ensure the adequate protection of worker health and safety from exposure to radiation from radioactive material during routine civilian nuclear reactor operation. The inspectors applied IMC 0609, Appendix C, Occupational Radiation Safety Significance Determination Process, to this finding. Since the finding was not associated with as-low-as-reasonably-achievable (ALARA) planning or work controls, nor was there an overexposure or a substantial potential for an over exposure and the ability to assess dose was not compromised, the finding screened as very low safety significance (Green). The inspectors determined that the performance characteristic of the finding that was the most significant causal factor of the PD was associated with the cross-cutting aspect of Challenge the Unknown in the Human Performance cross-cutting area, and involved the licensee not challenging an unauthorized substitution for part of the electrometer that was damaged during shipment. (H.11) |
| 05000282/FIN-2016004-02 | 31 December 2016 23:59:59 | Prairie Island | Self-revealing | Failure to Properly Implement a Post-Maintenance Test Procedure during Safety Injection System Valve Testing | Green. A finding of very low safety significance was self-revealed, and an associated NCV of Technical Specification (TS) 5.4.1.a, Procedures, was identified for the licensees failure to properly implement surveillance procedure (SP) 1088B, Train B Safety Injection Quarterly Test, Revision 24, while performing a post-maintenance valve stroke test. Specifically, on November 14, 2016, while cycling a safety injection (SI) system pump suction valve, operators exposed the SI suction header to reactor coolant system (RCS) pressure, causing a relief valve to lift as designed, a subsequent unexpected RCS pressure drop below 240 pounds per square inch (psig), and requiring operators to trip both reactor coolant pumps (RCPs). The licensee entered the issue into the Corrective Action Program (CAP) as CAP 1541821. The inspectors determined that the licensees failure to properly implement procedure SP 1088B as required by TS 5.4.1.a was a performance deficiency (PD). The PD was determined to be more than minor and a finding in accordance with IMC 0612, Appendix B, Issue Screening, because it was associated with the Initiating Events Cornerstone attribute of Configuration Control and affected the associated Cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. The inspectors applied IMC 0609, Attachment 4, Initial Characterization of Findings, to this finding. Since the finding pertained to an event while the plant was shut down, the inspectors transitioned to IMC 0609, Appendix G, Attachment 1, Shutdown Operations Significance Determination Process Phase 1 Initial Screening and Characterization of Findings. Since the inspectors answered No to all questions within IMC 0609, Appendix G, Attachment 1, Exhibit 2, Initiating Events Screening Questions, the finding screened as very low safety significance (Green). The inspectors determined that the performance characteristic of the finding that was the most significant causal factor of the PD was associated with the cross-cutting aspect of Teamwork in the Human Performance cross-cutting area, and involved individuals and work groups not communicating and coordinating their activities within and across organizational boundaries to ensure nuclear safety was maintained. (H.4) |
| 05000282/FIN-2016004-04 | 31 December 2016 23:59:59 | Prairie Island | Licensee-identified | Licensee-Identified Violation | Prairie Island Technical Specification 5.4.1, Procedures, required, in part, that written procedures shall be implemented covering the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Regulatory Guide 1.33, Revision 2, Appendix A contains, in part under Section 1, Administrative Procedures, Subsection e., Procedure Review and Approval. Contrary to the above, on December 12, 2013, and June 11, 2013, the licensee failed to properly implement FPGDOC04, Procedure Processing, Revision 19, to ensure that validation reviews were performed to ensure usability of C18.1, Engineered Safeguards Equipment Support Systems, following revisions to the procedure. Specifically, validation reviews were not performed during procedure revisions of C18.1 which lead to inadequate instructions to ensure that SCWSsupported system operability was properly addressed when SCWS functions were affected. This led to seven instances of conditions prohibited by TS for safeguards buses 15 and 16 between January of 2013 and May of 2015. The licensee later determined that although conditions prohibited by TS did occur based on the inadequate C18.1 instructions, an equally correct application of TS would have been to enter a 30day action statement for one SCWS inoperable per TS 3.7.11 and apply Surveillance Requirement 3.0.6 by performing a SFDP evaluation. This would not have resulted in conditions prohibited by TS for the supported AC or DC systems. Because the inspectors answered No to all questions under Exhibit 2 of Inspection Manual Chapter (IMC) 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, the finding screened as very low safety significance (Green). The above issue was documented in the licensees CAP as CAP 1488482. Corrective actions included changes to C18.1 to implement the SFDP for future SCWS removals from service, and revisions to the FPGDOC04 job familiarization guide to ensure validation reviews are properly performed. |
| 05000282/FIN-2016004-01 | 31 December 2016 23:59:59 | Prairie Island | NRC identified | Baffle Former Bolting Acceptance Criteria | From October 17November 28, 2016, the inspectors conducted a review of the implementation of the licensees inservice inspection (ISI) program for monitoring degradation of the reactor coolant system (RCS), risk-significant piping and components and containment systems. This inspection constituted one ISI sample (see Sections 1R08.1, 1R08.3 and 1R08.5 below), as defined in IP 71111.0805. .1 Piping Systems Inservice Inspection a. Inspection Scope The inspectors either observed or reviewed records of the following Non-Destructive Examinations (NDEs) mandated by the American Society of Mechanical Engineers (ASME), Section XI Code, to evaluate compliance with the ASME Code Section XI and Section V requirements, and if any indications and defects were detected, to determine if these were dispositioned in accordance with the ASME Code or an NRC-approved alternative requirement. Ultrasonic examination of tubesheet to shell for steam generator (SG) 11; Magnetic particle examination of an integral attachment support rod for SG 11; Visual examination of reactor vessel nuts and washers (1 through 16); and Unit 1 metallic containment liner visual examination in 2012. During non-destructive surface and volumetric examinations performed since the previous refueling outage, the licensee had not identified any recordable indications. Therefore, no NRC review was completed for this inspection procedure attribute. The inspectors either observed or reviewed the following pressure boundary welds completed for risk-significant systems since the beginning of the last refueling outage to determine if the licensee applied the preservice NDEs, and acceptance criteria required by the Construction Code and ASME Code, Section XI. Additionally, the inspectors reviewed the welding procedure specification and supporting weld procedure qualification records to determine if the weld procedures were qualified in accordance with the requirements of Construction Code and ASME Code Section IX. Unit 1 reactor coolant pump (RCP) seal replacements. b. Findings No findings were identified. .2 Reactor Pressure Vessel Upper Head Penetration Inspection Activities a. Inspection Scope The licensee did not perform any welded repairs to vessel head penetrations since the beginning of the preceding outage for Unit 1. Therefore, no NRC review was completed for this inspection procedure attribute. For the Unit 1 vessel head, no examination was required pursuant to Title 10 of the Code of Federal Regulations (10 CFR), Part 50.55a(g)(6)(ii)(D) for the current refueling outage. Therefore, no NRC review was completed for this inspection attribute. b. Findings No findings were identified. .3 Boric Acid Corrosion Control a. Inspection Scope The inspectors performed an independent walkdown of the RCS and related lines in the containment, which had received a recent licensee boric acid walkdown, and verified whether the licensees boric acid corrosion control visual examinations emphasized locations where boric acid leaks can cause degradation of safety significant components. The inspectors reviewed the following licensee evaluations of RCS components with boric acid deposits to determine if degraded components were documented in the CAP. The inspectors also evaluated corrective actions for any degraded RCS components to determine if they met the ASME Section XI Code. 11 RCP seal bowl. The inspectors reviewed the following corrective actions related to evidence of boric acid leakage to determine if the corrective actions completed were consistent with the requirements of the ASME Code Section XI and 10 CFR Part 50, Appendix B, Criterion XVI. CAP 1465567; 12 RCP Seal Leakage. b. Findings No findings were identified. .4 Steam Generator Tube Inspection Activities a. Inspection Scope The licensee did not perform in-situ pressure testing of SG tubes. Therefore, no NRC review was completed for this inspection attribute. For the Unit 1 SGs, no examination was required pursuant to the TSs during the current refueling outage. Therefore, no NRC review was completed for this inspection procedure attribute. b. Findings No findings were identified. .5 Identification and Resolution of Problems a. Inspection Scope The inspectors performed a review of ISI/SG-related problems entered into the licensees CAP, and conducted interviews with licensee staff to determine if: the licensee had established an appropriate threshold for identifying ISI/SG-related problems; the licensee had performed a root cause evaluation (if applicable) and taken appropriate corrective actions; and the licensee had evaluated operating experience and industry generic issues related to ISI and pressure boundary integrity. The inspectors performed these reviews to evaluate compliance with 10 CFR Part 50, Appendix B, Criterion XVI requirements. Documents reviewed are listed in the Attachment to this report. b. Findings (1) Baffle Former Bolting Analysis Acceptance Criteria Introduction: The inspectors identified an Unresolved Item (URI) concerning the analysis that demonstrated the design adequacy of the baffle former bolting under design and licensing basis loading conditions. Description: The inspectors reviewed WCAP 17586P, Determination of Acceptable Baffle-Barrel Bolting for Prairie Island Units 1 and 2, Revision 0; WCAP15030NPA, Westinghouse Methodology for Evaluating the Acceptability of Baffle-Former-Barrel Bolting Distributions under Faulted Load Conditions, dated March 2, 1999; and Safety Evaluation by the Office of Nuclear Reactor Regulation of WCAP15029, Westinghouse Methodology for Evaluating the Acceptability of Baffle-Former-Barrel Bolting Distributions Under Faulted Load Conditions, dated November 10, 1998. The inspectors were concerned that the licensee had evaluated the baffle former bolting using acceptance criteria different than what was reviewed and approved by the Office of Nuclear Reactor Regulation. In WCAP15030NPA, Section 4.3.2 stated that the stress allowable for primary membrane and bending of irradiated bolt material is taken to 0.9 times Sy (yield stress of baffle bolt material) for the faulted load condition. The stress allowable used in WCAP 17586P was based on ASME, Section III, Appendix F, specifically: (minimum of (0.9 times Su) ultimate stress of baffle bolt material), maximum of (0.67 times Su, Sy + 1/3 (Su - Sy)). The inspectors also reviewed 10 CFR 50.59 Screening No. 4443, Determination of Acceptable Baffle-Barrel Bolting, dated January 24, 2013, to determine whether the licensee performed a 50.59 evaluation for the use of ASME, Section III, Appendix F acceptance criteria. However, the inspectors identified that the change for the use of ASME, Section III, Appendix F acceptance criteria in lieu of the acceptance criteria contained in Section 4.3.2 of WCAP15030NPA was not explicitly reviewed in 50.59 Screening No. 4443. In response to the inspectors concern, the licensee initiated CAP 1539487, Documentation Missing in 50.59 Screening 4443, dated October 26, 2016. This issue is an URI pending evaluation of these concerns by the licensee, subsequent inspector review, and discussion with the licensee and Office of Nuclear Reactor Regulation (URI 05000282/201600401; 05000306/201600401; Baffle Former Bolting Analysis Acceptance Criteria). |
| 05000306/FIN-2016004-05 | 31 December 2016 23:59:59 | Prairie Island | Licensee-identified | Licensee-Identified Violation | Northern States Power CompanyMinnesota (NSPM), Prairie Island Nuclear Generating Plant Renewed Facility Operating License, Appendix B, Additional Conditions, Facility Operating License No. DPR42 and DPR60 (Amendment Nos. 206 and 193, respectively), required, in part, that The Alternate Source Term (AST) License Amendments 206/193 will be implemented after installation of the Unit 2 Replacement Steam Generators (RSGs) within 90 days after the completion of the outage in which the Unit 2 RSGs are installed. Further, implementation requirements incorporated within License Amendment 206/193 stated, in part, that prior to implementation of the AST license amendment, NSPM will revise the Prairie Island Nuclear Generating Plant design and licensing bases to indicate that the Steam Generator Water LevelNarrow Range Instruments are required to meet Regulatory Guide 1.97, Revision 2 requirements. Contrary to the above, on March 27, 2014, the licensee failed to revise the Prairie Island Nuclear Generating Plant design and licensing bases to indicate that the SGNR instruments were required to meet Regulatory Guide 1.97, Revision 2 requirements. Because the inspectors answered Yes to Question 1 under Exhibit 2 of IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, the finding screened as very low safety significance (Green). The above issue was documented in the licensees CAP as CAP 1424460. Corrective actions included replacement of the SGNR instrumentation with Regulatory Guide 1.97 compliant equipment. |
| 05000282/FIN-2016003-01 | 30 September 2016 23:59:59 | Prairie Island | Licensee-identified | Licensee-Identified Violation | Title 10 CFR 50.48(b)(2) requires, in part, that all nuclear power plants licensed to operate before January 1, 1979, must satisfy the applicable requirements of Appendix R to this part, including specifically the requirements of Sections III.G, III.J, and III.O. Appendix R, Section III.G.1 of 10 CFR Part 50, requires, in part, that systems necessary to achieve and maintain cold shutdown from either the control room or emergency control station(s) can be repaired within 72 hours. Contrary to the above, on January 7, 2016, the licensee failed to ensure that the Units 1 and 2 B RCS vent valves (necessary to achieve and maintain cold shutdown) could be repaired within 72 hours following a postulated fire. Specifically, the B RCS vent valves were credited within the licensees SSA following a postulated fire in the Units 1 and 2 auxiliary building mezzanine areas and could have been rendered unavailable for operation from the control room or emergency control station(s). Section 9.1 of the NRC Enforcement Policy allows the NRC to exercise enforcement discretion for certain fire protection related non compliances identified as a result of a licensees transition to the new risk informed, performance based fire protection approach included in 10 CFR 50.48(c), and for certain existing non compliances that reasonably may be resolved by compliance with 10 CFR 50.48(c) as long as certain criteria are met. This risk informed, performance based approach is referred to as NFPA 805, Performance Based Standard for Fire Protection for Light Water Reactor Electric Generating Plants. The licensee is in transition to NFPA 805 and therefore the licensee-identified violation was evaluated in accordance with the criteria established by Section 9.1(a) of the NRCs Interim Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48) for a licensee in NFPA 805 transition. The inspectors determined that for this violation: (1) the licensee would have identified the violation during the scheduled transition to 10 CFR 50.48(c); (2) the licensee had established adequate compensatory measures (see Section 4OA3.3) within a reasonable time frame following identification and would correct the violation as a result of completing the NFPA 805 transition; (3) the violation was not likely to have been previously identified by routine licensee efforts; and (4) the violation was not willful. The finding also met additional criteria established in section 12.01.b of IMC 0305, Operating Assessment Program. In addition, in order for the NRC to consider granting enforcement discretion the violation must not be associated with a finding of high safety significance (i.e., Red). The issue was of very low safety significance (Green) because it did not impact the licensees ability to reach hot shutdown. The licensee entered this issue into their corrective action program as CAP 01507901. As a result, the inspectors concluded that the violation met all four criteria established by Section 9.1 of the NRCs Enforcement Policy and the NRC was exercising enforcement discretion to not cite this violation in accordance with the Interim Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection Issues. |
| 05000282/FIN-2016002-01 | 30 June 2016 23:59:59 | Prairie Island | Licensee-identified | Licensee-Identified Violation | Prairie Island TS 3.6.3, Containment Isolation Valves, Required Action A.1 required, in part, isolation of the affected penetration flow path within 4 hours if one or more penetration flow paths with one containment isolation valve inoperable. Contrary to the above, since August 4, 2012 on 21 occasions for Unit 1 and 23 occasions for Unit 2 (three year reporting window), the licensee failed to isolate containment spray header penetration flow paths within 4 hours during the performance of quarterly containment spray pump surveillance procedures SP 1090A & 1090B and SP 2090A & 2090B. Specifically, the SPs inappropriately credited Note 1 of TS 3.6.3 and created open flow paths from the Unit 1 and 2 containments under administrative control while vent and/or drain valves connected to the containment spray header were opened. The opening of these valves was to facilitate draining of the header and to verify no leakage past manual isolation valves during containment spray pump operation in recirculation mode. On August 4, 2015, the licensee generated CAP 01488454 which questioned whether use of TS 3.6.3 Note 1 to open the containment spray header vent and drain valves under administrative control was permissible. The licensee performed an apparent cause evaluation and determined that because the vent and drain valves were not considered part of a containment penetration flow path, Note 1 could not be applied. A past operability review was performed and it was determined that on multiple occasions (at 1-10 hour durations) over the prior three years, the vent/drain opening resulted in a 3/8 opening in the containment pressure boundary. Because the resultant leakage at peak containment pressure during a design basis accident (approximately 4 percent of the containment volume per day) would have exceeded the maximum allowable leakage rate, conditions that could have prevented the fulfillment of the safety function of the Units 1 and 2 containments and, conditions that were prohibited by TS, had occurred. Because the inspectors answered Yes to question B.1 under Exhibit 3, Barrier Integrity Screening Questions of IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings at Power, the inspectors transitioned to IMC 0609, Appendix H, Containment Integrity Significance Determination Process. Because the leak rate through the vent/drain openings would not have exceeded greater than 100 percent of the containment volume per day at calculated peak containment internal pressure, the finding screened as very low safety significance (Green). The issues were entered into the licensees CAP as CAP 01488454. Corrective actions included immediate quarantine of the affected SPs and subsequent revisions to the SPs and TS Bases. |
| 05000282/FIN-2016007-01 | 30 June 2016 23:59:59 | Prairie Island | NRC identified | Failure to Ensure Breaker Main Contacts are Fully Aligned | A finding of very low safety significance and associated non-cited violation of Technical Specification Section 5.4.1, Procedures, was identified by the inspectors for the licensees failure to ensure the 21 safeguards diesel exhaust fan main contact connectors were fully engaged and aligned as required per electrical maintenance procedures to ensure proper operation of the breaker. As part of their corrective actions, the licensee aligned and re-engaged the main contact connectors as necessary. In addition, the licensee ensured maintenance personnel were aware of the operating experience to prevent the same issue from occurring in the future. The violation was entered into the licensees corrective action program as Action Request 1525844. The finding was determined to be more than minor because the finding was associated with the Mitigating Systems Cornerstone and the breaker failure led to the inoperability of the 21 safeguards diesel exhaust fan and impacted the availability of the 22 cooling water system diesel driven pump. This finding represented a loss of the 22 safeguards diesel cooling water pump function for longer than the Technical Specification allowed outage time of 7 days and therefore required a detailed risk evaluation. The regional senior reactor analyst performed a detailed risk evaluation of this finding using the Prairie Island Standardized Plant Analysis Risk Model revision 8.19 and determined the finding was of very low safety significance (Green). The inspectors did not identify a cross-cutting aspect associated with this finding because it was not indicative of current performance. |
| 05000282/FIN-2016007-02 | 30 June 2016 23:59:59 | Prairie Island | NRC identified | Inadequate Operability Determinations | A finding of very low safety significance with two examples and an associated non-cited violation of Title 10, Code of Federal Regulations (CFR), Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified by the inspectors for the licensees failure to accomplish the requirements of procedure FPOPOL01, Operability/Functionality Determination, Revisions 14 and 15. Specifically, on two occasions, the licensee failed to properly evaluate potential operability concerns associated with the Unit 2 emergency diesel generator (EDG) day tanks and the Unit 2 train A cooling water (CL) system piping. The licensee entered the issues into the Corrective Action Program as Action Requests 1525842 and 1526070. The inspectors determined that the licensees failure to accomplish the requirements of procedure FPOPOL01, Operability/Functionality Determination, Revisions 14 and 15, to properly evaluate the operability issues associated with the Unit 2 EDG day tank fuel oil level and the Unit 2 CL system piping (both safety-related, mitigating systems) was a performance deficiency. The performance deficiency, with two examples, was determined to be more than minor in accordance with Inspection Manual Chapter (IMC) 0612, "Power Reactor Inspection Reports," Appendix B, "Issue Screening," it was associated with the Mitigating Systems Cornerstone attributes of Equipment Performance (for the Unit 2 EDGs) and Protection against External Factors (for the Unit 2 CL piping) and adversely affected the Cornerstone objective of ensuring the availability, reliability, and capability of mitigating systems to respond to initiating events. The inspectors utilized IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, and IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, and determined that the finding screened as very low safety significance (Green) since the inspectors answered Yes to Question 1 of Section A of Exhibit 2, Mitigating Systems Screening Questions. The inspectors concluded that this issue was cross-cutting in the area of Problem Identification and Resolution in the aspect of Evaluation. As defined in IMC 0310, Aspects Within the Cross-Cutting Areas, this aspect states, The organization thoroughly evaluates issues to ensure that resolutions address causes and extent of conditions commensurate with their safety significance. Specifically, the licensee had not thoroughly evaluated the operability issues associated with the Unit 2 EDG day tank levels and the Unit 2 CL piping structural integrity. |
| 05000282/FIN-2016403-01 | 30 June 2016 23:59:59 | Prairie Island | Licensee-identified | Licensee-Identified Violation | |
| 05000282/FIN-2016407-01 | 31 March 2016 23:59:59 | Prairie Island | NRC identified | Security | |
| 05000282/FIN-2016008-01 | 31 March 2016 23:59:59 | Prairie Island | NRC identified | Failure to Maintain Cold Shutdown Repair Procedure | The inspectors identified a finding of very-low safety significance (Green), and an associated Non-Cited Violation of Technical Specifications Section 5.4.1.d for the licensees failure to maintain Procedure F5 Appendix B. Specifically, the licensee failed to update the procedure to reflect physical changes made in the plant that resulted in the licensee not being able to perform the procedure as written. The licensee entered the issue into their Corrective Action Program, and planned to update drawings and label components in the field and include the proper tools to accomplish the actions specified in the procedure. The inspectors determined that the performance deficiency was more than minor because the licensees failure to maintain Procedure F5 Appendix B would have resulted in a delay in achieving and maintaining cold shutdown. The finding was of very-low safety significance because it did not impact the licensees ability to reach hot shutdown. The finding did not have a cross-cutting aspect associated with it because it was not reflective of current performance. |
| 05000306/FIN-2015008-01 | 31 December 2015 23:59:59 | Prairie Island | NRC identified | Failure to Correct an NCV Associated with Inadequate Gas Monitoring of Inaccessible RHR Gas Susceptible Locations | The inspectors identified a finding of very low safety significance (Green), and an associated cited violation of Title 10, Code of Federal Regulations (CFR), Part 50, Appendix B, Criterion XVI, Corrective Actions, for the failure to correct a condition adverse to quality (CAQ). Specifically, on August 1, 2011, the NRC issued an NCV for the failure to monitor five safety-related gas susceptible locations considered to be inaccessible, which is a CAQ. As of November 24, 2015, the licensee had not corrected this CAQ for two of those locations and did not have plans to restore compliance. The licensee captured this issue into their Corrective Action Program (CAP) with a proposed corrective action to develop an alternative monitoring method for these locations when the unit is operating. The performance deficiency was determined to be more than minor because it was associated with the Mitigating Systems cornerstone attribute of equipment performance, and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding screened as of very low safety significance (Green) because it did not result in the loss of operability or functionality of mitigating systems. Specifically, the licensee was able to access and inspect these locations during the refueling outage that was ongoing when this issue was identified and confirmed that they were full of water during the previous operating cycle. In addition, a historical review did not find information that challenged operability due to gas accumulation at these locations. The inspectors determined that this finding had a cross-cutting aspect in the area of problem identification and resolution because the licensee did not thoroughly evaluate their discovery that the CAQ was not been corrected on July 29, 2013. Specifically, on 2013, the licensee initiated a condition evaluation (CE) to determine if the action plan at the time addressed the NCV associated with the CAQ. However, the CE was closed by crediting actions that were similar to those that resulted in the NCV and other documented observations associated with the inappropriate resolution of the issue. |
| 05000282/FIN-2015008-03 | 31 December 2015 23:59:59 | Prairie Island | Self-revealing | Failure to Establish Procedures to Verify RHR is Full of Water Following Maintenance Outages | A finding of very low safety significance (Green), and an associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was self-revealed for the licensees failure to establish procedures to verify RHR is operable with respect to gas accumulation following maintenance outages. Specifically, procedures were not established to verify the system is sufficiently full of water when RHR is secured in its standby emergency core cooling system mode of operation during startup activities following maintenance outages. The licensee captured this issue into their CAP. As a long term corrective action, the licensee revised procedures to require gas accumulation inspections of the affected gas susceptible locations as part of the unit startup activities following a maintenance outage. The performance deficiency was determined to be more than minor because it was associated with the Mitigating Systems cornerstone attribute of equipment performance, and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding screened as of very low safety significance (Green) because it did not result in the loss of operability or functionality of mitigating systems. Specifically, the licensee performed a past operability review of the limiting void found at the RHR piping after maintenance outages and reasonably concluded that the system remained operable. The inspectors did not identify a cross-cutting aspect associated with this finding because it was not confirmed to reflect current performance. |
| 05000282/FIN-2015008-02 | 31 December 2015 23:59:59 | Prairie Island | NRC identified | Failure to Manage Gas Accumulation at the RHR Train Credited for Emergency Core Cooling in MODE 4 | The inspectors identified a finding of very low safety significance (Green), and an associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensees failure to manage gas accumulation at the residual heat removal (RHR) train credited for emergency core cooling in MODE 4, Hot Shutdown. Specifically, the RHR train credited for emergency core cooling in MODE 4 was not verified to be full of water before its operability was required in MODE 4 following system draining during refueling outage 1R29. The licensee captured this issue into their CAP with a proposed corrective action to revise procedures to explicitly require these inspections prior to transitioning into MODE 4 during startup activities The performance deficiency was determined to be more than minor because it was associated with the Mitigating Systems cornerstone attribute of equipment performance, and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding screened as of very low safety significance (Green) because it did not result in the loss of operability or functionality of mitigating systems. Specifically, the licensee reviewed records associated with gas accumulation management activities during 1R29 and discovered that a non-conforming void was vented 12 18 hours after the transition to MODE 4. However, an operability review reasonably determined that this non-conforming condition did not result in loss of operability. The inspectors did not identify a cross-cutting aspect associated with this finding because it was not confirmed to reflect current performance. |
| 05000282/FIN-2015004-03 | 31 December 2015 23:59:59 | Prairie Island | Licensee-identified | Licensee-Identified Violation | Title 10 CFR 50.48(b)(2) requires, in part, that all nuclear power plants licensed to operate before January 1, 1979, must satisfy the applicable requirements of Appendix R to this part, including specifically the requirements of Sections III.G, III.J, and III.O. Appendix R, Section III.G.3 of 10 CFR Part 50, requires, in part, that alternative or dedicated shutdown capability and its associated circuits, independent of cables, systems or components in the area, room, or zone under consideration should be provided where the protection of systems whose function is required for hot shutdown does not satisfy the requirement of paragraph G.2 of this section. In addition, fire detection and a fixed fire suppression system shall be installed in the area, room, or zone under consideration. Contrary to the above, on April 19, 2015, the licensee failed to ensure that alternative or dedicated shutdown capability and its associated circuits were independent of cables in the area. Specifically, procedure F5 Appendix B, Control Room Evacuation (Fire), Revision 31, did not contain actions to isolate the RCP breaker circuits to prevent restarting due to a fire induced loss of remote trip and loss of RCP seal cooling water that could lead to an increased rate of seal degradation and a small break loss of coolant accident. These actions were required to achieve and maintain safe shutdown in the event of a fire that resulted in functional loss and/or evacuation of the control/relay and cable spreading rooms. Section 9.1 of the NRC Enforcement Policy allows the NRC to exercise enforcement discretion for certain fire protection related non compliances identified as a result of a licensees transition to the new risk informed, performance based fire protection approach included in 10 CFR 50.48(c), and for certain existing non compliances that reasonably may be resolved by compliance with 10 CFR 50.48(c) as long as certain criteria are met. This risk informed, performance based approach is referred to as NFPA 805, Performance Based Standard for Fire Protection for Light Water Reactor Electric Generating Plants. The licensee is in transition to NFPA 805 and therefore the licensee-identified violation was evaluated in accordance with the criteria established by Section 9.1(a) of the NRCs Interim Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48) for a licensee in NFPA 805 transition. The inspectors determined that for this violation: (1) the licensee would have identified the violation during the scheduled transition to 10 CFR 50.48(c); (2) the licensee had established adequate compensatory measures within a reasonable time frame following identification and would correct the violation as a result of completing the NFPA 805 transition; (3) the violation was not likely to have been previously identified by routine licensee efforts; and (4) the violation was not willful. The finding also met additional criteria established in section 12.01.b of IMC 0305, Operating Assessment Program. In addition, in order for the NRC to consider granting enforcement discretion the violation must not be associated with a finding of high safety significance (i.e., Red). The licensee performed risk evaluation V.SPA.15.012, Revision 3, dated December 18, 2015, and determined that this issue was not associated with a finding of high safety significance. A region III senior reactor analyst (SRA) reviewed the evaluation and concluded that the result was reasonable and that the finding was less than Red and eligible for enforcement discretion. The dominant core damage sequence from the licensees evaluation involved an electrical cabinet fire in the relay room involving the cables that could cause spurious operation of the RCPs and that would lead to alternate shutdown. The licensee identified several conservative assumptions in the analysis. The SRA agreed that some were conservative, notably that any fire affecting the cables in the relay room that could cause a spurious start of an RCP would also result in a loss of all seal cooling due to fire damage. The SRA used IMC 0609, Appendix F, Fire Protection Significance Determination Process, to review the results of the licensees evaluation. The relay room is similar to a cable spreading room with electrical cabinets. The fire frequency for this room in Appendix F is 6E3/yr. The probability of non-suppression was estimated to be 2E2 and the spurious operation probability was assumed to be 0.6. The product of these values (7.2E5/yr) represents a bounding relay room fire scenario delta core damage frequency (CDF) for this finding. Since the bounding result is consistent with the licensees conclusion, the SRA determined that the delta core damage frequency for the finding was less than 1E4/yr, which is less than Red. In addition, the licensee entered this issue into their corrective action program as CAP 01475242. As a result, the inspectors concluded that the violation met all four criteria established by Section 9.1(a) and that the NRC was exercising enforcement discretion to not cite this violation in accordance with the Interim Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection Issues. |
| 05000306/FIN-2015004-01 | 31 December 2015 23:59:59 | Prairie Island | NRC identified | Failure to Meet ANSI N14.6 Section 5.3.1 Requirements | The inspectors identified a finding of very low safety significance (Green), and an associated NCV of Title 10 of the Code of Federal Regulations (CFR) Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to incorporate the American National Standards Institute (ANSI) N14.61978, Section 5.3.1 required testing frequency for the reactor vessel head and reactor vessel internals lifting devices into the controlling preventive maintenance procedure. Compliance with the ANSI standard was documented in the Safety Evaluation Report (SER) for the licensees control of heavy loads. The licensee documented the issue in the corrective action program (CAP) as CAP 01497779 and performed testing on the reactor vessel head and internals lifting devices during the outage. The inspectors determined the licensees failure to comply with ANSI N14.61978, Section 5.3.1, for the continued use testing of special lifting devices was a performance deficiency (PD). The PD was determined to be more-than-minor and a finding because the PD was associated with the Initiating Events Cornerstone attribute of design control, and adversely affected the cornerstone objective to limit the likelihood of those events that upset the plant stability and challenge critical safety functions during shutdown, as well as power operations. Specifically, compliance with ANSI N14.61978, Section 5.3.1 ensured safe load handling of heavy loads over the reactor core, and/or over safety-related systems through established testing for the continued functionality of the special lifting devices. The failure to perform the required frequency of testing on special lifting devices could increase the likelihood of a load drop and could decrease the load handling reliability of the lifting device if the device were returned to service with potentially unacceptable flaws. The inspectors determined the finding could be evaluated using the Significance Determination Process in accordance with Inspection Manual Chapter 0609, Significance Determination Process, Attachment 0609.04, Phase I - Initial Screening and Characterization of Findings, Table 3. Since the finding was associated with shutdown conditions, the inspectors used Inspection Manual Chapter 0609, Appendix G, Shutdown Operations Significance Determination Process. The inspectors determined that none of the conditions constituting a loss of control were met, as described in Appendix G, Attachment 1, Phase I Operational Checklists for Both PWRs (Pressurized Water Reactors) and BWRs (Boiling Water Reactors), for this finding, and neither a Phase II nor a Phase III analysis was required. Therefore, the inspectors determined that this finding was of very low safety significance (Green). The inspectors determined that this finding has a cross-cutting aspect in the area of Human Performance, Resources, for the licensees failure to ensure that personnel, equipment, procedures, and other resources were available and adequate to support nuclear safety. Specifically, the licensee staff evaluated NRC Information Notice (IN) 201412, Crane and Heavy Lift Issues Identified during NRC Inspections, in corrective action program (CAP) document 01457469. However, in CAP 01457469, the licensee concluded that issues identified in IN 201412 related to other licensees not performing testing in accordance with ANSI N14.6 requirements were not applicable to the licensee at the Prairie Island Nuclear Generating Plant. Therefore, the inspectors determined that there was a recent missed opportunity for the licensee to have reasonably identified that the current preventive maintenance procedure for special lifting devices was not in accordance with the ANSI N14.61978 requirements, as referenced in the SER. |
| 05000282/FIN-2015004-02 | 31 December 2015 23:59:59 | Prairie Island | NRC identified | Failure to Adequately Calibrate Liquid Effluent Monitors | The inspectors identified a finding of very low safety significance (Green) and associated NCV of TS 5.5.1.a for the failure to comply with the Offsite Dose Calculation Manual (ODCM) for not using calibration sources that were traceable to the National Institute of Standards and Technology (NIST) or equivalent during the calibration of station effluent monitors. The licensee entered the issues into the CAP as CAPs 01490581 and 01500149. Immediate corrective actions included the re-calibration of impacted monitors and the performance of an extent of condition evaluation for other radiation monitor calibrations. The PD was determined to be of more than minor safety significance in accordance with IMC 0612, Appendix B, Issue Screening, dated September 7, 2012, because it was associated with the plant facilities/equipment and instrumentation attribute of Public Radiation Safety and it adversely impacted the cornerstone objective of ensuring adequate protection of public health and safety due to failure to properly calibrate certain effluent monitors. Subsequent calibrations of the monitors determined that the monitor efficiency was previously overstated. The inspectors also reviewed IMC 0612, Appendix E, Examples of Minor Issues, dated August 11, 2009, but did not identify any similar examples. The finding was assessed using IMC 0609, Appendix D, Public Radiation Safety Significance Determination Process, dated, February 12, 2008, and determined to be of very low safety significance (Green), because it was associated with the effluent release program but was not a failure to implement an effluent program, public dose did not exceed Appendix I criteria, and the limits in Title 10 CFR 20.1301(e) were not exceeded. A cross-cutting aspect was not assigned as this issue occurred numerous years ago. The station has since performed monitor calibrations with radioactive sources with known quality. |
| 05000282/FIN-2015008-04 | 31 December 2015 23:59:59 | Prairie Island | NRC identified | Failure to Manage Potential Gas Accumulation Due to SI Isolation Check Valve Leakage Following Maintenance Outages | The inspectors identified a finding of very low safety significance (Green), and an associated NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to manage potential gas accumulation due to safety injection isolation check valve leakage following maintenance outages. Specifically, the licensee did not evaluate the potential to accumulate nitrogen at multiple RHR and safety injection gas susceptible locations due to safety injection check valve unseating caused by maintenance outages. As a result, the station did not manage this gas intrusion mechanism. The licensee captured this issue into their CAP with a proposed corrective action to revise procedures to verify that the safety injection check valves are seated as part of the unit startup activities following a maintenance outage. The performance deficiency was determined to be more than minor because it was associated with the Mitigating Systems cornerstone attribute of equipment performance, and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding screened as of very low safety significance (Green) because it did not result in the loss of operability or functionality of mitigating systems. Specifically, the licensee performed a past operability review of the limiting void found at one of the affected piping locations and reasonably concluded that the associated system remained operable. The inspectors did not identify a cross-cutting aspect associated with this finding because it was not confirmed to reflect current performance. |
| 05000282/FIN-2015008-05 | 31 December 2015 23:59:59 | Prairie Island | NRC identified | Failure to Identify a Continuous Gas Intrusion into RHR | The inspectors identified a finding of very low safety significance (Green) and associated NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, for the licensees failure to identify a continuous gas intrusion into one train of RHR, which was a CAQ, resulting in a continuous undetected void growth that exceeded the applicable operability limits. The licensee did not consider applicable active gas intrusion mechanisms when evaluating the discovery of a void at the RHR piping. The licensee captured this issue into their CAP and stopped the continuous gas intrusion into the affected piping location. The performance deficiency was determined to be more than minor because it was associated with the Mitigating Systems cornerstone attribute of equipment performance, and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding screened as of very low safety significance (Green) because it did not result in the loss of operability or functionality of mitigating systems. Specifically, the licensee performed a past operability review of the void and reasonably concluded that the system remained operable. The inspectors determined that this finding had a cross cutting aspect in the area of human performance because the licensee did not recognize and plan for the possibility of mistakes when evaluating the gas surveillance results of February 10, 2015. Specifically, the licensee did not plan for the possibility that the unacceptable results were indicative of a different problem than originally determined or a combination of problems. As a result, the licensee failed to identify the continuous gas intrusion incident. |
| 05000282/FIN-2015407-01 | 31 December 2015 23:59:59 | Prairie Island | Licensee-identified | Security | |
| 05000282/FIN-2015008-06 | 31 December 2015 23:59:59 | Prairie Island | Licensee-identified | Licensee-Identified Violation | Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, requires, in part, that the licensee provide for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculational methods, or by the performance of a suitable testing program. Contrary to the above, as of November 24, 2015, the licensee failed to verify the adequacy of the ECCS vent designs. Specifically, the licensee did not verify that the ECCS vent designs were adequate. As a result, some vents were inadequate to remove gas that accumulated in excess of the applicable design limits. The licensee captured their concern in their CAP as AR 01482500 and AR 01465114, and initiated actions to add and/or modify the vents. The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, SDP, Attachment 0609.04, Initial Characterization of Findings. Because the finding impacted the Mitigating Systems cornerstone, the inspectors screened the finding through IMC 0609 Appendix A, The SDP for Findings At-Power, using Exhibit 2, Mitigating Systems Screening Questions. The finding screened as of very low safety significance (Green) because it did not result in the loss of operability or functionality of mitigating systems. Specifically, the licensee evaluated the voids that could not be vented and reasonably determined they did not result in loss of operability. |
| 05000282/FIN-2015007-03 | 30 September 2015 23:59:59 | Prairie Island | NRC identified | Replacement Containment Fan Cooling Unit Component Not Designed in Accordance with ASME Section III | The team identified a finding of very low safety significance, and an associated NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to design all components of the replacement Containment Fan Coil Units in accordance with Section III of the American Society of Mechanical Engineers Boiler and Pressure Vessel Code. Specifically, the licensee failed to use Section III design rules to evaluate the Containment Fan Coil Unit header box as specified in the replacement Containment Fan Coil Unit design specification. The licensee entered this finding into their CAP with a recommended action to perform a condition evaluation for the new Containment Fan Coil Units to be installed in the upcoming refueling outage to ensure proper design code alignment with the design specification and the design report. The performance deficiency was more than minor because it was associated with the Mitigating Systems cornerstone attribute of design control, and affected the cornerstone objective of ensuring the availability, reliability, and capability of mitigating systems to respond to initiating events to prevent undesirable consequences. The finding screened as of very low safety significance because it was a design or qualification deficiency that did not represent a loss of operability or functionality. Specifically, the licensees use of design rules from American Society of Mechanical Engineers, Section VIII, provided reasonable assurance for the Containment Fan Coil Unit header box pressure boundary integrity. The team did not identify a cross-cutting aspect associated with this finding because it was confirmed not to be reflective of current performance due to the age of the performance deficiency. |