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	Quarter	Site	Title	Description
05000374/FIN-2018003-07	2018Q3	LaSalle	Potential Failure to Promptly Correct the Unit 2 Primary Containment Wall Cavity Leakage Condition and to Follow Corrective Action Program Process	Condition description in AR 2420888 indicated that leakage through the Unit 2 primary containment wall has been a longstanding open issue. The leak was initially identified in 1998 when water leakage was noticed on the external side of the primary containment wall. The leakage was approximately 2025 drops per minute at the primary location and multiple areas near the 180 degree azimuth at construction joints on elevations 813 and 795. Another minor leak was noticed at a similar location near the 0 degrees azimuth. The condition was documented in AR 2269. The source of water leakage was determined to be a weld on a 2 fuel pool cooling drain line and work order 98109950 was initiated to repair the weld. The work was not scheduled and the work order was eventually cancelled. In 2010, the leakage was documented again in AR 1086083. A technical evaluation documented as ATI14709531847 in 2014 concluded that there was no adverse impact on structural adequacy of the containment. The technical evaluation stated that the leakage was to be repaired in the upcoming outage through work order 855785. Action request 2420888 was written in December 2014 to re-enter the condition in the CAP. It recommended corrective actions for liner ultrasound testing every other refueling outage, completion of weld repair, and performance of a technical evaluation for structural impact on the concrete, reinforcing steel, tendons, and liner. The technical evaluation assignment was closed to the evaluation documented under ATI14709531847 discussed above. The corrective action assignment for the weld repair was closed to a work order which has not been completed to-date. Based on the inspectors review, the licensee has deferred the actions to correct this condition identified in 1998. The inspectors question whether the continuous leakage could lead to deterioration of the concrete, corrosion of the reinforcement, or degradation of post tensioned tendons if it enters the tendon sheath or trumpet area; and therefore a condition adverse to quality. This unresolved item remains open pending additional inspector review of the issue with respect to regulatory requirements. Planned Closure Action: Inspectors will seek additional information from the licensee and the NRC will perform internal reviews to evaluate compliance with NRC regulations
05000373/FIN-2018003-06	2018Q3	LaSalle	Potential Failure to Inspect Containment Post-Tensioned Tendons per Code Requirements and to Follow Corrective Action Program Process	Vertical and horizontal post tensioned tendons, along with reinforcing steel, are required to maintain structural integrity of the primary containment. There are a total of 120 vertical post tensioned tendons along the periphery of the primary containment wall, including 60 Group C tendons and 30 each of Groups A and B. Section 5.5.6 of the Technical Specifications describes the Inservice Inspection (ISI) program for post tensioning tendons and states that the Tendon Surveillance Program shall be in accordance with ASME Section XI, Subsection IWL as required by 10 CFR 50.55a. One Group B tendon (V213B) on Unit 1 was inspected in 1999 and according to the inspection records, water was identified on all components of the tendon. No presence of water is one of the acceptance criteria per Subsection IWL of the ASME Section XI. No condition report was found for this adverse condition. Subsequently, a condition involving degraded vertical tendons was identified during inspections in 2003 and documented in AR 157920. The degradation consisted of broken wires. The Root Cause Report (RCR) for this condition noted that 11 Group A tendons were found degraded and water induced corrosion was the root cause for tendon degradation. The evaluation concluded that five Group A tendons and all 30 Group B tendons in each unit were not susceptible to water intrusion because they were protected by welded covers. These tendons with welded covers were also determined to be inaccessible, and therefore exempt from future inspections requirements in accordance with provisions of ASME Section XI, IWL. The RCR did not address the condition of water found during the Group B tendon inspection in 1999. Additionally, to verify this assumption of welded covers providing protection from water intrusion, a corrective action was generated to inspect one Group A and one Group B inaccessible tendons during the next outage. Pertaining to inaccessible tendons, the inspectors noted the following requirements of 10 CFR 50.55a(b)(2)(viii)(E): Concrete containment examinations: Fifth provision. For Class CC applications, the applicant or licensee must evaluate the acceptability of inaccessible areas when conditions exist in accessible areas that could indicate the presence of or the result in degradation to such inaccessible areas. For each inaccessible area identified, the applicant or licensee must provide the following in the ISI Summary Report required by IWA6000: (1) A description of the type and estimated extent of degradation, and the conditions that led to the degradation; (2) An evaluation of each area, and the result of the evaluation; and (3) A description of necessary corrective actions. After the licensee identified degraded group A tendon locations, to comply with the provision of 10 CFR 50.55a, the licensee documented in its 90 day post outage ISI reports information on the degraded A tendons in 2004 and 2005 for units 1 and 2, respectively. This information included an assumption that the extent of degradation did not apply to the Group B tendon locations because of a welded cover at locations that precluded entry of water. Additionally, a corrective action, CA 15792033, was generated to inspect one Group A and one Group B tendon during the next refueling outage to verify this assumption. The corrective action was closed without inspection of any Group B tendon based on a management decision following satisfactory inspection of a Group A tendon in 2006. The licensees decision failed to take into account the fact that the most recent inspection of a Group B tendon showed presence of water on tendon components and also that the welded closure details were different for tendons in the two groups. Subsequently, the licensee identified a concern regarding inadequate closure of this corrective action during its reviews for the license renewal application in 2014. Specifically, the licensee wrote AR 1658189 to document that due to the differences in the welded cover designs, the results of the Group A tendon inspection may not be applicable to Group B tendons. Therefore the critical assumption regarding the adequacy of Group B tendon covers remained unverified. In particular, the Group B tendon cover used dissimilar metal welds and water was found inside the cover during the most recent inspection. The licensee identified actions to perform inspections on two of the Group B tendons on each unit in addition to inspecting the tendon V213B where water was initially found. These actions were categorized as action tracking items (ACITs), items that do not represent conditions adverse to quality. Since water was found on all tendon components during the last inspection of a Group B tendon, and water induced corrosion was found to be the root cause of many tendon failures, the assumption in the RCR that the welded covers would prevent water intrusion needed to be validated through inspections. This unresolved item remains open pending additional inspector review of the issue with respect to regulatory requirements. Planned Closure Action: Inspectors will seek additional information from the licensee and the NRC will perform internal review to evaluate compliance with NRC regulations.
05000373/FIN-2018003-05	2018Q3	LaSalle	Failure to Translate Fuel Oil Relief Valve Setting into Design Drawing of Record.	The inspectors identified a finding of very low safety significance (Green) and an associated NCV of 10 CFR 50, Appendix B, Criterion III, Design Control, for the licensees failure to assure that applicable regulatory requirements and the design basis were correctly translated into specifications, drawings, procedures, and instructions. Specifically, the licensee failed to accurately translate the Division III EDG fuel oil relief valve set point from the design drawing of record, VPF341110, to the fuel oil pressure operator rounds alert value in the Division III EDG operating procedures.
05000373/FIN-2018003-04	2018Q3	LaSalle	Failure to Manage the Increase in Risk During a Battery Charger Capacity Tes	The inspectors identified a finding of very low safety significance (Green) and an associated NCV of 10 CFR 50.65(a)(4) for the failure to manage risk when the licensee failed to adhere to procedure WCAA101, Revision 28, On-line Work Control Process. Specifically, procedural requirements regarding a dedicated operator for manual restoration actions and written instructions to credit the availability of the A RHRSW pump during the battery charger testing were not met.
05000341/FIN-2018003-03	2018Q3	Fermi	Failure to Identify a Condition Adverse to Quality on Division 2 Residual Heat Removal Service Water Outlet Flow Control Valve	A finding of very low safety significance and associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, and TS 3.7.1 Residual Heat Removal Service Water (RHRSW) System, were self-revealed for the licensees failure to identify a condition adverse to quality on the Division 2 RHRSW outlet flow control valve E1150F068B. Specifically, troubleshooting and the associated post maintenance testing failed to identify and correct a failed anti-rotation key which resulted in an inoperable Division 2 RHRSW system for longer than its TS 3.7.1 allowed outage time.
05000373/FIN-2018003-03	2018Q3	LaSalle	Failure to Establish Goals to Monitor Steam Tunnel Check Dampers	Introduction: The inspectors identified a finding of very low safety significance (Green) and an associated NCV of 10 CFR 50.65(a)(1) for the licensees failure to establish goals to monitor the performance of steam tunnel check dampers. Specifically, the licensees goals for functional failure and condition monitoring could always be satisfied given a two years monitoring period with only one testing opportunity.
05000341/FIN-2018003-02	2018Q3	Fermi	Failure to Ensure Electrolytic Capacitors Installed in the Plant Did Not Have Expired Shelf Lives	A finding of very low safety significance with an associated non-cited violation of 10 CFR 50, Appendix B, Criterion VIII, Identification and Control of Materials, Parts, and Components was self-revealed when the reactor water cleanup system inlet flow square root converter failed, resulting in a failure of the reactor water cleanup (RWCU) differential flow instrument and loss of automatic isolation function of the RWCU isolation valves. Specifically, electrolytic capacitors were installed in the RWCU system logic that had expired shelf lives, resulting in failures of the automatic isolation function of the RWCU system.
05000373/FIN-2018003-02	2018Q3	LaSalle	Failure to Establish an Appropriate Inservice Testing Procedure	The inspectors identified a finding of very low safety significance (Green) and an associated NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensees failure to prescribe procedures that were appropriate to the circumstances, for activities affecting quality, that included appropriate quantitative or qualitative acceptance criteria for determining that important activities had been satisfactorily accomplished. Specifically, the CSCS bypass line isolation valve IST procedure did not contain acceptance criteria to verify the necessary valve obturator movement.
05000341/FIN-2018003-01	2018Q3	Fermi	Failure to Apply Torque Values Described in Maintenance Procedure for Flexible Couplings on Emergency Diesel Generator 12	A finding of very low safety significance with an associated non-cited violation of Technical Specification 5.4.1.a was self-revealed when plant operators discovered a pencil-thick lube oil leak coming from a flexible coupling on emergency diesel generator 12 during planned surveillance testing. Specifically, a lube oil leak developed when the flexible coupling located between the engine driven lube oil pump and the lube oil filter failed due to improper torque applied to the coupling On April 20, 2018, the licensee was performing a routine slow start surveillance of emergency diesel generator 12 (EDG12), when plant operators noted a pencil-thick lube oil leak from the flexible coupling fastener located between the engine driven lube oil pump and the lube oil filter with the engine running in idle. Plant operators subsequently shut down the engine, discontinued the surveillance, and EDG12 was declared inoperable. The licensee performed an investigation and found the flexible coupling fastener was torqued to 120 in/lbs. Maintenance procedure 35.307.008, Emergency Diesel Generator Engine General Maintenance, Enclosure X, Revision 44 required a torque value of 240260 in/lbs for the size of piping the fastener was on. The coupling was last disturbed in 2011, and the maintenance procedure at that time did not contain information regarding torque values for flexible couplings. A similar flexible coupling fastener failed in 2016 due to inadequate work instructions for torqueing flexible couplings (NCV 05000341/201600401, ADAMS Accession Number ML17030A328), and corrective actions were developed to use the vendor recommended values that had already been added to the maintenance procedure as Enclosure X in 2014. However, the corrective actions did not require all flexible couplings to be checked to ensure they were appropriately torqued. Opportunities existed for the licensee to ensure these flexible couplings were properly torqued according to vendor recommendations, either through scheduled maintenance online or during refueling and forced outages. Therefore, on April 20, 2018, another flexible coupling that was not checked as an extent of condition failed due to an under torqued condition.
05000373/FIN-2018003-01	2018Q3	LaSalle	Failure to Establish Heat Exchanger Inspection Procedures Appropriate for the Circumstances	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 ensure that activities affecting quality were prescribed by documented procedures of a type appropriate to the circumstances. Specifically, the licensee failed to ensure that procedure ERAA3401002 appropriately accounted for partially blocked HX tubes identified during HX inspections.
05000440/FIN-2018003-01	2018Q3	Perry	Application of ASME Code Case N5133 for the Emergency Service Water Piping Degradations	The inspectors identified an Unresolved Item concerning the Title 10 of the Code of Federal Regulations (10 CFR), Part 50, Appendix B, and ASME Code requirements for the ESW piping systems with regards to the licensees application of ASME Code Case N5133, Evaluation Criteria for Temporary Acceptance of Flaws in Moderate Energy Class 2 or 3 Piping, Section XI, Division 1. Updated Safety Analysis Report (USAR) Section 9.2.1 describes that the function of ESW system is to provide a reliable source of water to safety-related components required for normal and emergency reactor operation. USAR Table 3.21, Equipment Classification, delineates that the ESW piping system is safety-related and designed in accordance with the requirements of ASME Section III, Subsection ND (Class 3). The regulation in 10 CFR 50.55a(g) requires, in part, that Class 3 components and their supports meet the requirements of ASME Section XI of the ASME Boiler and Pressure Vessel (BPV) Code or equivalent quality standards. The ASME also publishes Code Cases, which provide alternatives to existing Code requirements. The NRC Regulatory Guide (RG) 1.147 identifies that Code Case N5133 provides acceptable alternatives to applicable parts of Section XI, provided it is used with any identified conditions or limitations. Code Case N5133, Section 2(d) requires that a flaw evaluation shall be performed to determine the conditions for flaw acceptance. Section 3 provides accepted methods for conducting the required analysis. In addition, Section 3 requires, in part, that nonplanar flaws shall be evaluated in accordance with the requirements in 3.2. Additionally, Section 5 requires that an augmented volumetric examination or physical measurement to assess degradation of the affected system shall be performed as follows: (a) From an engineering evaluation, the most susceptible locations shall be identified. A sample size of at least five of the most susceptible and accessible locations, or, if fewer than five, all susceptible and accessible locations shall be examined within 30 days of detecting the flaw. (b) When a flaw is detected, an additional sample of the same size as defined in 5(a) shall be examined. (c) This process shall be repeated within 15 days for each successive sample, until no significant flaw is detected or until 100 percent of susceptible and accessible locations have been examined. On June 13, 2018, a through-wall leakage on the 20 ESW piping was identified in CR 201805504. As a result, the licensee invoked the Code Case to evaluate this flaw and permit the degraded ESW piping system to remain in service for a limited period without repair/replacement. The licensees evaluation involved characterization of this flaw as nonplanar, and subsequently, the methodology as described in Section 3.2 of the Code Case was utilized for this nonplanar flaw. Additionally, the licensee identified the five most susceptible and accessible locations in the ESW system and performed examination in accordance with Section 5(a). From the examination of the five additional locations, another localized wall degradation was identified on the 8 ESW pipe elbow on July 10, 2018. The licensee initiated CR 201806205 to document this condition. The licensee characterized this degradation also as a nonplanar flaw, and this degradation represented approximately 80 percent wall loss from its nominal thickness. During the review of the licensee evaluation of this degraded pipe elbow, the inspectors identified that the methodology as described in Section 3.2 of the Code Case had not been utilized. Instead, the licensee elected to use an alternate methodology to evaluate and disposition for its acceptability. Furthermore, the inspectors identified that the licensee essentially redefined the term flaw in the Code Case to reflect the ASME Section XI, IWA9000 definition of the term defect. The ASME Section XI, IWA9000 defines a flaw as an imperfection or unintentional discontinuity that is detectable by nondestructive examination. It also defines a defect as a flaw (imperfection or unintentional discontinuity) of such size, shape, orientation, location, or properties as to be rejectable. With respect to the Code Case, the licensee essentially restricted the criteria for examination scope expansion only to the flaws that were rejectable; therefore, the licensee had not expanded the scope to perform examination of additional locations in accordance with Section 5(b). In essence, two items are to be further evaluated and addressed: (1) whether the use of methodology not described in the Code Case Section 3.2 was appropriate for evaluation of the nonplanar flaw on the 8 ESW pipe elbow, and (2) whether the stopping of scope expansion for examination as required by the Code Case Section 5(b) was appropriate based on the licensees redefining of the term flaw. In response to the inspectors concern, the licensee initiated CR 201808483, NRC ID: Code Case N5133 Interpretation, September 26, 2018. The licensee also plans to perform examination of five additional locations in November of 2018. This represents an item where the inspectors identified Code interpretation issues that resulted in a disagreement with the licensee. This will require additional review to determine whether a violation exists. Therefore, this issue is considered an unresolved item pending completion of inspector review and evaluation and discussion with the Office of Nuclear Reactor Regulation. Licensee Action: The licensee plans to perform examination of five additional locations in November of 2018. Corrective Action Reference: CR 201808483
05000373/FIN-2018003-08	2018Q3	LaSalle	Failure to Implement Engineering Change Results in Reactor Coolant Boundary Leakage	The inspectors documented a self-revealed finding of very low safety significance (Green) and associated NCVs of TS 5.4.1 Procedures, and TS 3.4.5 for the failure to implement EC 354539 to perform the final piping weld for the 1B33F067B bonnet vent line in the field, resulting in pressure boundary leakage when the weld failed at power.
05000373/FIN-2018002-04	2018Q2	LaSalle	Minor Violation - Follow-up of Events and Notices of Enforcement Discretion	Minor Violation: For S/RV 2B21F013L, serial number N63790050012 (hereafter referred to as S/RV 12), the licensee completed a work group evaluation as documented in AR 03975216ACIT No. 3 to investigate the cause for two S/RVs that failed a set pressure lift test out of specification low. For ACIT No. 3, the licensee staff incorporated a vendor letter that documented the results of the S/RV vendors review of the S/RV 12 condition and which recorded an out of tolerance spring condition. It stated that The spring was measured and rate tested. The free height was found to be below the minimum original equipment manufacturer specified tolerance. The licensees vendor subsequently replaced the nonconforming spring with a new spring. In prior vendor correspondence with the licensee (reference E-mail dated June 24, 2015), the vendor stated that Typically we contribute a low as-found lift to an out-of-tolerance spring rate or free height dimension. Therefore, the nonconforming spring free height dimension may have caused the low as-found lift setpoint failure for this valve and as such was relevant (e.g. material) to the determination of a failure cause that was reported in LER 05000374/201700400 and 01. However, the licensee failed to identify this during their cause investigation and erroneously reported in LER 05000374/201700400 and 01 that The vendor reported for both valves that all the spring tolerances were within the acceptance limits. The licensee documented this violation in AR 04134591, Potential Minor Violation for Unit 2 LER 20170401. The licensee also submitted a revision to the LER as LER 05000374/201700402 Screening: The significance determination process does not specifically consider the regulatory process impact in its assessment of licensee performance. Therefore, it is necessary to address this violation which could impede the NRCs ability to regulate using traditional enforcement to adequately deter non-compliance. The inspectors determined that this issue was a Severity Level IV violation based on Example 6.9.d.10 in the NRC Enforcement Policy which states, A failure to identify all applicable reporting codes on a Licensee Event Report that may impact the completeness or accuracy of other information (e.g. performance indicator data) submitted to the NRC. In accordance with the Section 2.2.1.c of the NRC enforcement policy, the severity level of a violation involving the failure to make a required report to the NRC will depend on the significance of and the circumstances surrounding the matter that should have been reported. The NRC had not relied on information in this LER report to make a regulatory decision, and the inspector answered no to each of the more than minor screening questions in Appendix B of IMC 0612 for the issue of concern. Therefore, the NRC determined this was a minor violation because it was associated with a minor performance deficiency. Violation: Failure to comply with 10 CFR 50.9 Completeness and accuracy of information and accurately report the nonconforming S/RV 12 spring tolerance in LER 05000374/201700400 and 01 to the NRC constitutes a minor violation that is not subject to enforcement action in accordance with the NRCs Enforcement Policy.
05000373/FIN-2018002-03	2018Q2	LaSalle	Licensee-Identified Violation	This violation of very low safety significant was identified by the licensee and has been entered into the licensee corrective action program and is being treated as a Non-Cited Violation, consistent with Section 2.3.2 of the Enforcement Policy. Violation: Technical Specification LCO 3.4.4 (applicable for Modes 1, 2 and 3) states: The safety function of 12 safety relief valves (S/RVs) shall be OPERABLE, and Action Statement A states that One or more required S/RVs inoperableA.1 be in mode 3 in 12 hours and A.2 be in Mode 4 in 36 hours. Technical Specification SR 3.4.4.1 states that Verify the safety function lift setpoints of the required S/RVs are as follows Number of S/RVs Setpoint (psig 2 1205 36. 3 1195 35. 2 1185 35. 4 1175 35. 2 1150 34. Contrary to the above, during portions of previous Unit 1 and 2 operating cycles from 2012 through January of 2017, two main steam S/RVs did not meet these lift pressure setpoint requirements. Specifically S/RV 2B21F013C lifted at 1131 psig instead of from 1139.8 to 1210.2 psig and S/RV 2B21F013L lifted at 1130 psig instead of from 1159.2 to 1230.8 psig (reference: Licensee Event Report 05000374/201700400; 01, Two Main Safety Relief Valves Failed Inservice Lift Inspection Pressure Test. Significance/Severity: This licensee identified finding affected the Initiating Events Cornerstone and was screened in accordance with Exhibit 1 of IMC 0609, Appendix A, The Significance Determination Process for Findings At Power. The two affected SRVs lifted low outside of their setpoint band, which was conservative with respect to maintaining the reactor coolant system overpressure protection safety function of these valves. Therefore, the inspectors determined that this finding is of very low safety significance (Green) because after a reasonable assessment of degradation, the finding would not have resulted in exceeding the reactor coolant system leak rate for a small LOCA and did not affect other systems used to mitigate a loss-of-coolant accident. Corrective Action Reference: AR 3974669
05000440/FIN-2018002-01	2018Q2	Perry	Failure to Control Transient Combustible Materials in a Designated Combustible Control Zone	The inspectors identified a finding of very low safety significance (Green) and an associated non-cited violation (NCV) of Perry Operating License Condition 2.C(6), Fire Protection, for the licensees failure to control transient combustible materials in a designated combustible control zone within fire area 1AB1g on Auxiliary Building elevation 574 10. Specifically, on May 16, 2018, the inspectors identified transient combustible materials left unattended in the designated combustible control zone in the corridor outside the emergency core cooling system (ECCS) pump rooms, which exceeded the ten pound limit established in the Fire Protection Program document, PAP1910, for ordinary combustibles (loose) in designated combustible control zones without a transient combustible permit.
05000373/FIN-2018002-02	2018Q2	LaSalle	Failure to Follow Procedure and Perform Database Revision Review Requirements	The inspectors identified a Green finding of very low safety significance for the licensees failure to follow procedure NSWPWM03, Predefine Database Revisions, Revision 0, for retiring procedure LESGM108, Inspection of 480V Motor Control Center Equipment, that performed bus bar inspection on Division 3 motor control centers. Specifically, instead of completing NSWPMW03, step 6.5, Database Revision Review Requirements, to retire the bus bar inspections for Division 3 motor control centers, the licensee retired the procedure based solely on having previously retiring the bus bar inspections for Division 1 and Division 2 in 2002,and did not performthe required review.
05000373/FIN-2018002-01	2018Q2	LaSalle	Failure to Implement a Preventative Maintenance Strategy for Residual Heat Removal Service Water Pump Shorting Relays	A self-revealed Green finding of very low safety significance was identified for the licensees failure to implement a preventative maintenance (PM) strategy for the residual heat removal service water (RHRSW) pump shorting relays in accordance with procedure MAAA716210, Performance Centered Maintenance (PCM) Process, Revision 11. Specifically, a PCM template was issued in 2002 that required periodic as-found testing and calibration for control and timing relays, but a maintenance strategy was never implemented. As a result, one of the normally closed contacts on the Unit 1 D RHRSW pump shorting relay developed a high contact resistance and prevented the Unit 1 D RHRSW pump from starting.
05000373/FIN-2018001-01	2018Q1	LaSalle	Post-Maintenance Testing Failed to Demonstrate Testable Check Valve Function	A self-revealed Green finding of very low safety significance and an associated Non-Cited Violation (NCV) of 10 CFR 50, Appendix B, Criterion XI, Test Control, was documented by the inspectors for the licensees failure to perform post-maintenance testing that would demonstrate that structures, systems and components (SSCs) would perform satisfactorily in service. Specifically, following maintenance on the Unit 2 B residual heat removal (RHR) shutdown cooling (SDC) return testable check valve, 2E12F050B, and the Unit 1 A RHR SDC return testable check valve, 1E12F050A, the post maintenance test performed failed to identify that they would not open fully when in service, resulting in the valves being unable to pass full flow during SDC mode of RHR operation.
05000373/FIN-2018001-02	2018Q1	LaSalle	Failure to Update Throttle Valve Position in Accordance with Station Procedures	The inspectors identified a Green finding of very low safety significance and an associated Non-Cited Violation (NCV) of LaSalle Technical Specifications 5.4.1, Procedures, for the licensees failure to implement station procedures recommended in Regulatory Guide 1.33, Appendix A, Section 9. Specifically, on two separate occasions while performing a flow balance on the Unit 1 A diesel generator (DG) cooling water system, procedural errors resulted in the licensee failing to update the throttle valve position to be used during manual backwash of the Unit 1 A DG cooling water strainer with the correct position.
05000440/FIN-2018001-01	2018Q1	Perry	Failure to Notify the NRC within 60 Days of a Condition Prohibited by Technical Specifications	The inspectors identified a Severity Level IV Non-Cited Violation of 10 CFR 50.73, Licensee Event Report System, for the licensees failure to report a condition that was prohibited by the plants Technical Specifications to the U.S. Nuclear Regulatory Commission (NRC) within 60 days. Specifically, the licensee did not report a condition that, as determined by the NRC, rendered the Division 2 Diesel Generator (DG) inoperable for a period longer than the Technical Specification allowed completion times of its associated required actions.
05000341/FIN-2018001-01	2018Q1	Fermi	Failure to Incorporate Vendor Recommendations into Maintenance Instructions on the Division 1 Control Complex Heating Ventilation and Air Conditioning Supply Fan Motor	A finding of very low safety significance and associated non-cited violation of 10CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was self-revealed for the licensees failure to include instructions for maintenance on the Division 1 Control Complex heating ventilation and air conditioning (CCHVAC) supply fan motor requiring a matching belt set per the recommendation in the vendor manual. Specifically, by installing an unmatched belt set, vibrations degraded past the shutdown limit, rendering Division 1 CCHVAC inoperable.
05000373/FIN-2018001-03	2018Q1	LaSalle	Enforcement Action (EA) 18035: Licensee Implementation of Enforcement Guidance Memorandum 15002, Enforcement Discretion for Tornado-Generated Missile Protection Noncompliance	On June 10, 2015, the NRC issued Regulatory Issue Summary (RIS) 201506, Tornado Missile Protection (ML15020A419), focusing on the requirements regarding tornado-generated missile protection and required compliance with the facility-specific licensing basis. The RIS also provided examples of noncompliance that had been identified through different mechanisms and referenced Enforcement Guidance Memorandum (EGM) 15002, Enforcement Discretion For Tornado Generated Missile Protection Non-Compliance, which was also issued on June 10, 2015 (ML15111A269) and revised on February 7, 2017 (ML16355A286). The EGM applies specifically to an SSC that is determined to be inoperable for tornado generated missile protection. The EGM stated that a bounding risk analysis performed for this issue concluded that tornado missile scenarios do not represent an immediate safety concern because their risk is within the LIC504, Integrated Risk-Informed Decision-Making Process for Emergent Issues, risk acceptance guidelines. The EGM provided for enforcement discretion of up to three years from the original date of issuance of the EGM. The EGM allowed NRC staff to exercise this enforcement discretion only when a licensee implements, prior to the expiration of the time mandated by the LCO, initial compensatory measures that provided additional protection such that the likelihood of tornado missile effects were lessened. In addition, licensees were expected to follow these initial compensatory measures with more comprehensive compensatory measures within approximately 60 days of issue discovery. The comprehensive measures should remain in place until permanent repairs are completed, or until the NRC dispositions the non-compliance in accordance with a method acceptable to the NRC such that discretion is no longer needed. Appendix A to 10 CFR 50, General Design Criteria for Nuclear Power Plants (GDC), Criterion 4, Environmental and Dynamic Effects Design Basis, states in part that SSCs important to safety shall be adequately protected against dynamic effects including missiles. On February 15, 2018, during evaluation of protection for Technical Specifications (TS) equipment from the damaging effects of tornado generated missiles, LaSalle County Station identified a non-conforming condition in the plant design such that specific TS equipment is considered to not be adequately protected from tornado generated missiles. Specifically, tornado generated missiles could strike the components supporting the operation of Control Room (VC) and Auxiliary Electric Room (VE) ventilation. This could result in inoperable VC/VE systems, which provide a protected environment for occupants to control the unit following an uncontrolled release of radioactivity, hazardous chemicals, or smoke if a tornado were to occur. In addition, the Unit 2 Division 2 motor control center (MCC) 236X1 was affected, which impacted various loads on Unit 2 including the Unit 2 standby gas treatment, Unit 2 Division 2 post LOCA system, B main control room area filtration system supply and exhaust fan, reactor building Division 2 isolation damper control logic, Unit 2 Division 2 battery room exhaust fan and Unit 2 24/48 Volt battery rooms exhaust fans. This would result in a loss of power to components and systems rendering them inoperable. The condition was reported to the NRC in Event Notice (EN) 53213 as an unanalyzed condition and potential loss of safety function. Corrective Actions: The licensee documented the inoperability of the SSCs and the affected TS Limiting Conditions for Operation (LCOs) in the CAP and in the control room operating log. The shift manager notified the NRC resident inspector of the implementation of EGM 15002, and documented the implementation of the compensatory measures to establish the SSCs operable but nonconforming prior to expiration of the LCO required action. Initial (immediate) compensatory measures were established by an operations standing order that included: Procedures were verified to be put in place, with associated current training, for performing actions in response to a tornado. Procedures were verified to be put in place, with associated current training, for actions to be taken if a tornado watch is issued for the area. Procedures were verified to be put in place, with associated current training, for actions to be taken if a tornado warning is issued for the area. Verification that training was up to date for individuals responsible for implementing preparation and response procedures; and Established a heightened station awareness and preparedness level relative to identified tornado missile vulnerabilities. The comprehensive (60 day) compensatory measures were established by incorporating the standing order actions and adding additional detail to operating procedure LOATORN001, High Winds/Tornado, Revision 22, for completing additional inspections and restoration actions on equipment vulnerable to tornado missile damage. Corrective Action Program References: AR 4104401; AR 4104391; AR 4104393; AR 4104396; AR 4104397. Enforcement: Violation: The enforcement discretion was applied to the required shutdown actions of the following TS LCOs for both units: TS 3.7.4, Control Room Area Filtration (CRAF) System; TS 3.7.5, Control Room Area Ventilation Air Conditioning (AC); TS 3.6.4.2, Secondary Containment Isolation Valves (SCIVs); TS 3.6.4.3; Standby Gas Treatment (SGT) System; and TS 3.8.7, Distribution SystemsOperating. Severity/Significance: The subject of this enforcement discretion, associated with tornado missile protection deficiencies was determined to be less than red (i.e., high safety significance) based on a generic and bounding risk evaluation performed by the NRC in support of the resolution of tornado-generated missile non-compliances. The bounding risk evaluation is discussed in Enforcement Guidance Memorandum 15002, Revision 1, Enforcement Discretion for Tornado-Generated Missile Protection Non-Compliance, and can be found in ADAMS, Accession No. ML16355A286. Basis for Discretion: The NRC exercised enforcement discretion in accordance with Section 2.3.9 of the Enforcement Policy and EGM 15002 because the licensee initiated initial compensatory measures that provided additional protection such that the likelihood of tornado missile effects were lessened. The licensee implemented actions to track the more comprehensive actions to resolve the nonconforming conditions within the required 60 days. These comprehensive actions were to remain in place until permanent repairs were completed, which for LaSalle were required to be completed by June 10, 2018, or until the NRC dispositioned the non-compliance in accordance with a method acceptable to the NRC such that discretion was no longer needed
05000373/FIN-2017004-04	2017Q4	LaSalle	Failure of Offsite Power Backfeed Procedure to be Appropriate to the Circumstances Caused Unit 1 Scram	A finding of very low safety significance and an associated NCV of LaSalle Technical Specification (TS) 5.4.1, Procedures, occurred on February 13, 2017, for the stations failure to maintain instructions of a type appropriate to the circumstances for energizing offsite electrical systems during a Unit 2 backfeed evolution (an activity affecting quality per Regulatory Guide 1.33). Specifically, the steps of backfeed procedure, LOPAP01, Revision 35, led to a Unit 1 scram because the prescribed switchyard configuration left both units connected to the 345 kilovolt (kv) ring bus, leaving the operating unit susceptible to the large in-rush current induced by the backfeed energization of the Unit 2 main power transformer. As a corrective action from Action Request (AR) 03973724, the licensee revised the backfeed procedure to eliminate the tie between the units on the ring bus when main power transformers are energized. This performance deficiency was more than minor because it was associated with the Procedure Quality attribute of the Initiating Events Cornerstone, and adversely affected the Cornerstone objective of limiting the likelihood of events that upset plant stability because it resulted in a Unit 1 Scram. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 1 of IMC 0609, Appendix A, The Significance Determination Process for Findings At Power, issued June 19, 2012, the inspectors determined that this finding was of very low safety significance because, although the performance deficiency caused a reactor scram, it did not result in the loss of mitigation equipment relied upon to transition the plant from the onset of the scram to a stable shutdown condition. The inspectors determined there was no cross-cutting aspect because the performance deficiency was not indicative of licensees current performance since the design modification occurred greater than 3 years before the event. This inspection report will also bring to closure the associated Licensee Event Report, (LER) 05000373/201700300.
05000373/FIN-2017004-03	2017Q4	LaSalle	Primary Containment Structure, Suppression Pool Columns, Downcomer Vent and Downcomer Vent Bracing Did Not Meet Seismic Category I Requirements	A finding of very low safety significance and an associated NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, was identified by the inspectors for the failure to ensure the adequacy of the design for the primary containment, suppression pool columns, downcomer and downcomer vent bracing. Specifically, the inspectors identified three representative examples where the licensee failed to perform adequate design calculations resulting in the design not being in conformance with Seismic Category I requirements as defined in Updated Final Safety Analysis Report (UFSAR) Sections 3.8.1.4.1, 3.8.1.5 and 3.8.6. The licensee documented these violation examples in ARs 4070065, 4074674 and 4070067 and initiated actions to restore compliance. 4 The inspectors determined the licensees failure to perform adequate evaluations to demonstrate Seismic Category I compliance for the primary containment structure, suppression pool columns, downcomer vents and downcomer vent bracing was contrary to the design control measures per 10 CFR Part 50, Appendix B, requirements and was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the Barrier Integrity Cornerstone attribute of design control and adversely affected the Cornerstone objective to provide reasonable assurance that physical design barriers (fuel cladding, reactor coolant system, and containment) protect the public from radionuclide releases caused by accidents or events. The inspectors determined the finding could be evaluated using the SDP in accordance with Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process for Findings At-Power, dated June 19, 2012, Exhibit 3, Barrier Integrity Screening Questions, for the Barrier Integrity Cornerstone (r\eactor containment). The inspector answered no to the Barrier Integrity questions for reactor containment. The finding screened as having very low safety significance (Green). The inspectors determined there was no cross-cutting aspect associated with this finding because the deficiency was a legacy design calculational issue and, therefore, was not indicative of licensees current performance.
05000373/FIN-2017004-02	2017Q4	LaSalle	Failure to Establish Brazing Repair Procedures with Appropriate Acceptance Criteria	A finding of very low safety significance and an associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified by the inspectors for the failure to establish instructions with acceptance criteria that were appropriate to the circumstances for the brazing repair of the Unit Common Division I diesel generator (DG) starting air system. Specifically, through worker skill of the craft, the use of a heat sink device was relied upon to ensure that the adjacent joint of a brazed connection did not cross a temperature threshold that could have melted or otherwise unacceptably weakened the filler material; however, the procedure used did not contain any quantitative acceptance criteria for the adjacent joint temperature to determine that this important activity had been satisfactorily accomplished. The finding was considered more than minor because if left uncorrected it had the potential to lead to a more significant safety concern. Specifically, without quantitative acceptance criteria for temperature of the adjacent joints in close proximity of a brazed connection it is possible that joints could be reheated to near the solidus temperature of the filler material, resulting in joint weakening and potential failure. The licensee entered the issue into its CAP as AR 04090775. Corrective actions included revising procedures associated with brazing repairs to include a temperature value as a quantitative acceptance criteria for determining that important activities have been satisfactorily accomplished and to address the physical condition of the adjacent joint by verifying its conditions under work order (WO) 4702099 performance. The inspectors determined that the finding could be evaluated using the Significance Determination Process (SDP) in accordance with IMC 0609, Attachment 0609.04, Initial Characterization of Findings, dated October 7, 2016. Because the finding impacted the Mitigating Systems Cornerstone the inspectors screened the finding through IMC 0609, Appendix A, The SDP for Findings At-Power, dated June 19, 2012. The finding screened as very low safety significance (Green) because it did not result in the loss of operability or functionality; thus, the inspectors answered No to all of the mitigating system screening questions. The inspectors determined that the finding had a cross-cutting aspect in the area of Human Performance, under the aspect of Work Management. Specifically, WO 4702099 designated DG air start system repair activities as non-code when an American Society of Mechanical Engineers (ASME) code brazing procedure specification, (BPS) 107107BR Revision 0, was being used to satisfy the standard of record, the diesel engine manufacturers standards. (H.5)
05000341/FIN-2017004-03	2017Q4	Fermi	Failure to Perform Fit Testing on Self-Contained Breathing Apparatus Respirators	A finding of very-low safety significance (Green) and associated NCV of Title 10 of the Code of Federal Regulations (CFR), Part 20.1703(c)(6) was identified by the inspectors for the licensees failure to perform fit testing for the self-contained breathing apparatus (SCBA) style of respirators utilized. The licensee entered this issue into the Corrective Action Program as Condition Assessment Resolution Document (CARD) 1725155. Corrective actions included working with MSA to get both the air purifying and SCBA respirators National Institute for Occupational Safety and Health approved for both the rubber and Kevlar harnesses, and replacing all face pieces with the same style harness. The performance deficiency was determined to be more-than-minor because it was associated with the program and process attribute of the Occupational Radiation Safety cornerstone and adversely affected the cornerstone objective to ensure adequate protection of the worker health and safety from exposure to radiation from radioactive material during routine civilian nuclear reactor operation. Specifically, the respirator fit testing was being used to verify respirator protection factors for workers and the failure to verify the appropriate protection factor for the SCBA style of respirator affected the licensees ability to control and limit the intake of airborne radioactivity and other hazards. The finding was determined to be of very-low safety significance (Green) because the finding did not involve: (1) as-low-as-reasonably-achievable planning and controls, (2) a radiological overexposure, (3) a substantial potential for an overexposure, or (4) a compromised ability to assess dose. The inspectors determined that the finding had a cross-cutting aspect of human performance, conservative bias. Specifically, although the licensee questioned the practice on multiple occasions, the licensee was not able to determine that the practice was unsafe, and therefore continued the practice (IMC 0310, H.14).
05000341/FIN-2017004-02	2017Q4	Fermi	Division 2 Residual Heat Removal Service Water System Outlet Flow Control Valve Lower Bonnet (Backseat) Bushing Failure	The inspectors evaluated the licensee's handling of selected degraded performance issues involving the following risk-significant structures, systems, and components (SSCs):Residual heat removal service water system. 13 The inspectors assessed performance issues with respect to the reliability, availability, and condition monitoring of the SSCs. Specifically, the inspectors independently verified the licensee's handling of SSC performance or condition problems in terms of:appropriate work practices;identifying and addressing common cause failures;scoping of SSCs in accordance with 10 CFR 50.65(b);characterizing SSC reliability issues;tracking SSC unavailability;trending key parameters (condition monitoring);10 CFR 50.65(a)(1) or (a)(2) classification and reclassification; andappropriateness of performance criteria for SSC functions classified (a)(2) and/or appropriateness and adequacy of goals and corrective actions for SSC functions classified (a)(1).In addition, the inspectors verified problems associated with the effectiveness of plant maintenance for risk-significant SSCs were entered into the licensee's corrective action program with the appropriate characterization and significance. Selected CARDs were reviewed to verify corrective actions were appropriate and implemented as scheduled.This inspection constituted one quarterly maintenance effectiveness inspection samples as defined in IP 71111.12.FindingsDivision 2 Residual Heat Removal Service Water System Outlet Flow Control Valve Lower Bonnet (Backseat) Bushing FailureIntroduction. The inspectors identified an unresolved item (URI) to further evaluate the events and causes of a failure of the Division 2 RHRSW system outlet Flow Control Valve (FSC) lower bonnet (backseat) bushing. Specifically, additional information was needed to determine if one or more performance deficiencies exist.Description. On October 23, 2017, the Division 2 RHRSW system was started to support weekly addition of biocide to the Division 2 RHR reservoir (ultimate heat sink) as a preventative measure to minimize raw water system fouling, which typically entailed running both Division 2 RHRSW pumps for approximately 12 hours. Approximately 20 minutes after system startup, the control room received an overhead annunciator alarm for reactor building south west quad leakage to floor drain sump high along with indication that the reactor building south west quad sump pumps were running. A non-licensed operator was dispatched to the field to investigate the alarms and identified the Division 2 RHRSW outlet Flow Control Valve (FCV) (E1150F068B), located in the Division 2 RHR heat exchanger room in the reactor building, had a significant packing leak calculated to be approximately 16 gallons per minute. The leakage did not impact any other plant equipment in the local area and was captured by the Division 2 RHR heat exchanger room floor drains, which discharge into the reactor building south west quad room sump. Control room operators subsequently shutdown the Division 2 RHRSW pumps to stop the packing leakage and declared the Division 2 RHRSW system inoperable 14 The licensee formed an emergent issues team to further investigate the issue.Following valve disassembly and inspection, the licensee identified the valve lower bonnet (backseat) bushing no longer had sufficient thread engagement to remain in place and that the valve packing had been ejected from the valve stuffing box. A temporary modification was implemented to install a new backseat bushing welded directly to the valve bonnet. The system was subsequently returned to service on October 27, 2017.The Division 2 RHRSW outlet FCV is a safety-related, 24inch Powell globe valve with a motor operator. The primary safety function of the outlet FCV is to fully open to support heat transfer from the Division 2 RHR heat exchanger to the ultimate heat sink. The valve remains fully open during RHRSW pump operation (combined pump flow on the order of 10,000 gallons per minute) and generally is not throttled other than during initial startup of the pumps for a short period of time to help mitigate any potential water hammer events.The licensee completed a root cause analysis documented in CARD 1728611 at the end of the inspection period. The direct cause of the Division 2 RHRSW outlet FCVpacking leakage was determined to be the valve bonnet carbon steel threads corroded to the point of no longer functioning as an adequate mechanical connection. This resulted in the backseat bushing detaching from the valve bonnet allowing the packing to be ejected. The root cause was determined to be previous operating experience resolution for galvanic corrosion for valves in the safety-related service water systems was less than adequate resulting in a failure to recognize the vulnerability of galvanic corrosion on passive valve components. Contributing causes consisted of (1) RHRSW system operation produces significant valve vibration levels and periodic wetting and then drying conditions promoting a corrosive environment and (2) high levels of ionic impurities, as measured by chloride concentration, in RHRSW accelerate galvanic corrosion.The inspectors reviewed the root cause analysis report and several previous issues associated with the Division 2 RHRSW outlet FCV. Those events included, but were not limited to:On May 22, 2017, while placing Division 2 RHRSW in service for biocide treatment of the Division 2 RHR reservoir, the Division 2 RHRSW outlet FCVfailed to fully open. Troubleshooting discovered the direct cause was failure of the anti-rotation bushing stem key due to broken tack welds caused by high vibration during system operation. Previous troubleshooting on what was believed to be an indication issue on May 5, 2017 for the Division 2 RHRSW outlet FCV was inadequate and did not identify the failure of the anti-rotation key. As a result, the RHRSW FCV was returned to service on May 7, 2017, and subsequently failed on the next on-demand stroke on May 22, 2017. The licensee submitted Licensee Event Report 05000341/201700300 to report this event in accordance with 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by Technical Specification 3.7.1 and 10 CFR 50.73(a)(2)(v)(B) as a condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to remove residual heat. The system was returned to service on May 24, 2017. On September 28, 2017, while Division 2 RHRSW was out of service for planned valve performance monitoring, a partial stem-to-disc separation was detected.This additional monitoring was put in place based on previous industry operating experience of potential stem-to-disc separation following anti-rotation key failures. Upon further investigation and valve-disassembly, the stem-to-disc jam nut tack welds were found broken and the stem had unthreaded approximately 0.225 inches from the disc. Repairs were performed to replace the broken tack welds on the disc jam nut. The disc guide pin was also identified to be damaged and the licensee performed an engineering evaluation to permanently remove the disc guide pin. A broken tack weld was also noted on the backseat bushing which was repaired. The system was returned to service on October 3, 2017.The inspectors questioned the potential relationships between the aforementioned events given the potential for each event to have influenced the eventual failure of the backseat bushing. The inspectors needed additional information to determine whether or not the valve, including the backseat bushing, was subject to an over thrust condition as a result of one or a combination of irregular limit switch settings, anti-rotation key failure, broken and subsequent removal of the disc guide pin, stem-to-disc unthreading, and various broken tack welds. Other additional information was needed in order to determine:if the Division 2 RHRSW outlet FCV was of appropriate design for the known conditions of high vibrations, periods of cavitation on startup and shutdown, and a highly susceptible corrosive environment due to periods of wet and dry conditions with known dissimilar metals highly susceptible to galvanic corrosion;the technical basis behind not including globe valves in the corrosion monitoring program following previously noted and evaluated concerns of RHRSW system susceptibility from years past; andthe technical basis and management of chemistry controls on the RHR reservoirs.Because the licensee completed their root cause evaluation at the end of the inspection period and additional information was required to determine if one or more performance deficiencies exists associated with the various Division 2 RHRSW outlet FCV problems, this issue is being treated as an unresolved item pending receipt of additional information and subsequent inspector review. (URI 05000341/201700402, Division 2 Residual Heat Removal Service Water System Outlet Flow Control Valve Lower Bonnet (Backseat) Bushing Failure)
05000341/FIN-2017004-01	2017Q4	Fermi	Reactor Recirculation Motor-Generator Set ABrush Gear Failure	Inspection ScopeDuring the course of the inspection period, the inspectors performed several observations of licensed operator performance in the plants control room to verify that operator performance was adequate and that plant evolutions were being conducted in accordance with approved plant procedures. Specific activities observed that involved a heighted tempo of activities or period of elevated risk included, but were not limited to:Planned downpower, performance of turbine stop and control valve testing, and main steam isolation valve testing on November 4 and 5, 2017;Subsequent response to a manual trip of reactor recirculation motor-generatorset A and single loop operation on November 26, 2017; andPower suppression testing on December 30, 2017. The inspectors evaluated the following areas during the course of the control room observations: licensed operator performance;crews clarity and formality of communications;ability to take timely actions in the conservative direction;prioritization, interpretation, and verification of annunciator alarms (if applicable); correct use and implementation of procedures;control board (or equipment) manipulations;oversight and direction from supervisors; andability to identify and implement appropriate TS actions and Emergency Plan actions and notifications (if applicable). The performance in these areas was compared to pre-established operator action expectations, procedural compliance and task completion requirements. Documents reviewed are listed in the Attachment to this report.These observation activities by the inspectors of operator performance in the plants control room constituted one quarterly licensed operator heightened activity/risk sample as defined in IP 71111.11.b. Findings Reactor Recirculation Motor-Generator Set A Brush Gear Failure Introduction. The inspectors identified an unresolved item (URI) to further evaluate the events and causes of a failure of the reactor recirculation motor-generator set A brush gear assembly. Specifically, the licensee had not yet completed their root cause evaluation of the event at the end of the inspection period.Description. On November 26, 2017, at approximately 2:38 p.m. while the plant was operating at 100 percent reactor thermal power, the control room unexpectedly received a Recirculation System A Generator Field Ground alarm with no other abnormal indications noted in the control room. A non-licensed operator was dispatched to the reactor recirculation motor-generator room in the reactor building and immediately noted an acrid odor along with significant arcing and sparking on the generator end of reactor recirculation motor-generator set A. Subsequently, at 2:56 p.m., control room operators manually tripped reactor recirculation motor-generator set A and entered abnormal operating procedure 20.138.01, reactor recirculation pump trip. In accordance with the abnormal operating procedure the control room operators promptly inserted control rods and stabilized the plant at approximately 35 percent reactor thermal power in single loop operation. The abnormal operating procedure was exited at 4:37 p.m. following completion of associated operator actions and plant stabilization.The licensee formed an emergent issues team to further investigate the issue. Significant damage was identified on the brush gear assembly mounted on the generator end of the reactor recirculation motor-generator set A including, but not limited to, severely worn slip rings, damaged carbon brushes and holders, and melted insulating materials. Initial evaluation by the licensee indicated the carbon brushes had inadequate spring tension to remain in contact with the slip rings, potentially as a result of a brush gear inspection procedure change that allowed for increased wear on the carbon brushes prior to replacement. Additionally, it was determined that sparks were observed on the brush gear assembly the day before the event, however, no discernable action was taken to address the issue.The brush gear assembly was repaired, however, multiple attempts were made to restart reactor recirculation motor-generator set A unsuccessfully. Further troubleshooting identified that the reactor recirculation motor-generator set A starting circuitry voltage was too low to support a restart during single loop operations. Additionally, a rectifier diode pigtail connection in the automatic voltage regulator was found damaged. The rectifier diode pigtail connection was subsequently repaired. A temporary modification was developed and implemented to increase the reactor recirculation motor-generator set A starting circuitry voltage. The reactor recirculation motor-generator set A was successfully restarted on December 5, 2017. Single loop operations were subsequently exited and the unit returned to 100 percent rated thermal power on December 6, 2017.The licensee entered this issue in the corrective action program as CARD 1729439. Because the licensee had yet to complete their root cause investigation and analysis of the event, the issue is being treated as an unresolved item pending the inspectors review of the licensees completed cause evaluation and proposed corrective actions. (URI 05000341/201700401, Reactor Recirculation Motor-Generator Set A Brush Gear Failure)
05000373/FIN-2017004-01	2017Q4	LaSalle	Complete versus Truncated Shifts on Proficiency Watches	The inspectors identified an unresolved item (URI) related to the adequacy of the shifts for proficiency watches stood by specific reactor operators (ROs). Clarification was requested for whether the 8-hour proficiency watches stood by only these specific ROs, should be considered complete or truncated watches, which may not meet the requirements of 10 CFR 55.53(e). Description: Title 10 CFR 55.53(e) states, in part: To maintain active status, the licensee shall actively perform the functions of an operator or senior operator on a minimum of seven 8hour or five 12hour shifts per calendar quarter. In NUREG 1021, Revision 11, ES-605 further explains that: In accordance with 10 CFR 55.53(e), to maintain an active status, licensed operators are required to maintain their proficiency by actively performing the functions of an operator or senior operator on at least seven 8hour or five 12hour shifts per calendar quarter. This requirement may be completed with a combination of complete 8 and 12hour shifts (in a position appropriately credited for watch-standing proficiency as discussed below) at sites having a mixed-shift schedule, and watches shall not be truncated when the operator satisfies the minimum quarterly requirement (56 hours). Overtime may be credited if the overtime work is in a position appropriately credited for watch-standing proficiency. As documented in AR 04070501, dated November 3, 2017, it has been LaSalle Stations practice to use an individuals normal shift work hours to determine the length of his/her proficiency watch. While the operating shift crews were assigned to 12hour shifts, those licensed ROs assigned to other staff positions at LaSalle normally worked 8 hours per day. LaSalle refers to these individuals as Administrative ROs. Thus, when 14 LaSalles Administrative ROs stood their proficiency watches, they stood 8hour watches, and turned over to another operator to complete the normal 12hour operating shift. As stated in this AR, 8hour shifts minimized the overtime costs to maintain active licenses for these individuals. The Operator Licensing and Training Branch was requested via Regional Office Interaction ROI1725, Clarification of Complete vs. Truncated Shift for Proficiency Watches, because Administrative ROs stood 8hour proficiency watches, while all other operators stood 12hour shifts. Clarification is needed from the Operator Licensing and Training Branch and the Office of the General Counsel to determine if the current practice meets the requirements of 10 CFR 55.53(e) to maintain an operating license in an active status. (URI 050000373/201700401; 050000374/201700401, Complete versus Truncated Shifts on Proficiency Watches)
05000282/FIN-2017003-04	2017Q3	Prairie Island	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-2017003-03	2017Q3	Prairie Island	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-2017003-02	2017Q3	Prairie Island	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-2017003-01	2017Q3	Prairie Island	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)
05000341/FIN-2017003-02	2017Q3	Fermi	Technical Specification Allowed Outage Time Exceeded for Electrical Power Distribution Systems Due to Auxiliary Equipment Out of Service	The inspectors identified a Non-Cited Violation (NCV) of Technical Specification (TS) 3.8.7 Distribution Systems Operating, for the licensees failure to either restore inoperable Division 1 and Division 2 AC electrical power distribution subsystems to operable status within 8 hours or be in Mode 3 in 12 hours. Specifically, electrical power distribution subsystems required by the above limiting condition for operation were inoperable due to their respective subdivisions of Residual Heat Removal (RHR) switchgear room ventilation systems being out of service and therefore unavailable to provide the technical specification support function of attendant cooling that was needed for the associated electrical systems to perform their specified safety functions. The licensee entered the issue into its corrective action program as CARD 1726749.The failure to comply with TS 3.8.7 by either restoring inoperable electrical power subsystems to operable status within 8 hours, or be in Mode 3 in 12 hours was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it was associated with the Configuration Control attribute of the Mitigating Systems Cornerstone, and adversely affected the associated cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors determined that the finding was of very low safety significance (Green) because it did not represent an actual loss of function of at least a single train for greater than its technical specification allowed outage time, or two separate safety systems out-of-service for greater than its technical specification allowed outage time. The inspectors determined that the violation had a cross-cutting aspect in the area of human performance, resources, because the licensee failed to ensure that the RHR Complex Heating and Ventilation procedure was adequate to support nuclear safety (H.1).
05000341/FIN-2017003-01	2017Q3	Fermi	Failure to Satisfy 10 CFR 50.73 Reporting Requirements for Primary Containment Isolation Valve Actuations	The inspectors identified a Severity Level IV NCV of the NRCs reporting requirements Title 10 of the Code of Federal Regulations (CFR), Part50.73(a)(1), Licensee Event Report (LER) System. The licensee failed to submit a required LER or provide a telephone notification within 60 days after discovery on March 24, 2017, of a condition that resulted in the invalid actuation of containment isolation signals affecting containment isolation valves in more than one system. The licensee entered this issue into its corrective action program to evaluate the cause for its failure to satisfy the reporting requirements and to identify appropriate corrective actions.Subsequently, the licensee made a telephone notification on July 14, 2017 to the NRC Operations Center via the Emergency Notification System to report the event (Event Notice 52859).Consistent with the guidance in IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, dated September 7, 2012, the inspectors determined the performance deficiency was of minor significance based on No answers to the more-than-minor screening questions. In accordance with Section 6.9.d.9 of the NRC Enforcement Policy, this violation was categorized as Severity Level IV because the licensee failed to report as required by 10 CFR 50.73(a)(1). No cross-cutting aspect is associated with this traditional enforcement violation because the associated performance deficiency was determined to be of minor significance and therefore not a finding.
05000315/FIN-2017007-01	2017Q3	Cook	Failure to Correct Operable, but Non - Conforming Conditions	The inspectors identified a finding of very low safety significance and an associated non -cited violation of 10 Code of Federal Regulations ( CFR ) Part 50, Criterion V for three examples where the licensee failed to follow procedures associated with the licensees quality assurance program. This issue resulted in the licensee not properly classifying some structures, systems and components (SSCs) as operable, but non- conforming, consistent with station procedures . The inspectors determined that the failure to properly classify the above SSCs as operable, but non -conforming, was within the licensees ability to foresee and correct and was, therefore, a performance deficiency. This performance deficiency was considered more than minor, because it adversely affected the Design Control attribute 3 of Reactor Safety Barrier Integrity, ensuring that SSCs would remain functional during a design basis event. Specifically, station procedures required that prompt action be taken to address operable, but non -conforming conditions. The inspectors evaluated the finding using the Significance Determination Process in accordance with IMC 0609, Appendix A, The Significance Determination Process for Findings At -Power, Exhibit 3, dated June 19, 2012. The finding was of very low safety significance (Green), because there was no actual loss of safety function for the affected SSCs. The inspectors determined this finding affected the cross -cutting area of problem identification and resolution in the aspect of resolution, specifically to ensure that the organization takes effective corrective actions to address issues in a timely manner commensurate with their safety significance. (P.3)
05000282/FIN-2017002-04	2017Q2	Prairie Island	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-2017002-02	2017Q2	Prairie Island	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-2017002-01	2017Q2	Prairie Island	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)
05000263/FIN-2017010-01	2017Q2	Monticello	Failure to Ensure Adequate Design Controls During Installation of Flexible Hose on High Pressure Coolant Injection Auxiliary Oil System	Green. A finding of very low safety significance and associated Non-Cited Violation (NCV) of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion III, Design Control, was self-revealed as a result of an equipment cause investigation following failure of a pipe nipple in the safety-related piping for the HPCI system on March 22, 2016. Specifically, during original installation of the HPCI system, the licensee failed to correctly install a flexible hose to isolate vibrations in the system. Immediate corrective actions taken by the licensee included installing the flexible hose in the correct location to ensure isolation of vibrations in the system and performing walkdowns of other risk-significant systems to verify flexible hoses were installed in accordance with design. The issue was captured in the licensees corrective action program under CAP 1516361. 3 The inspector determined that the failure of the licensee to implement adequate design control measures and assure any deviations from Design Drawing NX82928 were properly controlled during installation of the flex ible hose in the HPCI system was contrary to 10 CFR Part 50, Appendix B, Criterion III, Design Control, and was a performance deficiency. The performance deficiency was determined to be more than minor, and thus a finding, because it was associated with the Mitigating Systems Cornerstone attribute of Design Control and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensees failure to install the flexible hose in the correct location in the HPCI oil system resulted in increased vibrations and loads throughout the HPCI system which had the potential to further degrade and decrease the reliability of the system. The finding was screened using Inspection Manual Chapter 0609, Appendix A, against the Mitigating Systems Cornerstone and determined to be of very low safety significance (Green), because the inspectors answered No to all of the questions in Exhibit 2, Mitigating Systems Screening Q uestions, Section A, Mitigating SSCs and Functionality. A cross-cutting aspect was not assigned to this finding since the performance deficiency occurred during the origi nal installation of the HPCI system and was determined not to be indicative of current licensee performance.
05000263/FIN-2017002-02	2017Q2	Monticello	Licensee-Identified Violation	The licensee identified a finding of very low safety significance (Green) and associated NCV of TS 3.7.1, Residual Heat Removal Service Water (RHRSW) System; which requires, in part, that two RHRSW subsystems shall be operable in Modes 1, 2, and 3 or per Condition A, One RHRSW subsystem inoperable; the RHRSW subsystem must be restored to OPERABLE status within 7 days or the applicable conditions and required actions of Limiting Condition forOperations 3.4.7, Residual Heat Removal Shutdown Cooling System Hot Shutdown, for RHR shutdown cooling made inoperable by RHRSW System must be entered. Contrary to the above, on March 27, 2017, the licensee exited the requirements in TS 3.7.1, with a Tag Section still hanging, rendering B RHRSW subsystem inoperable, while in Mode 1. This was identified by the licensee when the maintenance organization notified operations that work was complete, and the Tag Section was released. The licensee reentered TS 3.7.1, Condition A, entered the issue as CAP 1554105 and assigned a Human Performance Event Investigation. A crew clock reset was also taken as well as communicating lessons learned to the entire plant organization.This finding was more-than minor because the performance deficiency wasassociated with the equipment performance attribute of the Mitigating Systems Cornerstone and adversely affected its objective to ensure the availability and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, RHRSW System is designed to provide cooling water for the RHR System heat exchangers, required for a safe reactor shutdown following a Design Basis Accident or transient. Two RHRSW subsystems are required to be OPERABLE to provide the required redundancy to ensure that the system functions to remove post-accident heat loads, assuming the worst case single active failure occurs coincident with the loos of offsite power. The finding was of very low safety significance (Green) because it was not a design or qualification deficiency, did not involve an actual loss of safety system, did not represent actual loss of a safety function of a single train for greater than its TS allowed outage time, and did not represent an actual loss of function of one or more non-Tech Spec Trains of equipment designated as high safety-significant in accordance with the licensees maintenance rule program for >24 hours.
05000263/FIN-2017002-01	2017Q2	Monticello	Low Reactor Water Level During Shutdown of 11 Reactor Feedwater Pump	A self-revealed finding of very-low safety significance and a Non-Cited Violationof Technical Specification 5.4.1.a occurred on April 15, 2017, due the licensees failure to establish, implement and maintain procedures regarding shutdown operations. Specifically, Operations Manual B.06.05-05 did not account for the state of the opposite train of feedwater when shutting down the 11 Reactor Feedwater Pump. Licensee use of the inadequate procedure placed equipment in a configuration where no condensate flow path to the reactor existed causing reactor water level to lower to a point where trip/isolation set-points were reached. This caused an unplanned Reactor Protection System (RPS) trip and Partial Group II Isolation. The licensee initiated Corrective Action Program (CAP) 1555785 to document the reactor water level transient, RPS trip and Partial Group II Isolation. Immediate corrective actions includedopening the 11 Reactor Feedwater Pump discharge valve to restore reactor water level allowing reset of the Group II isolation and RPS trip. Subsequent licensee actions included development of expectations via an Operations Memo and revision to Operations Manual B.06.0505 as well as Procedure 2204 and Procedure 2167 to ensure abnormal equipment lineups are addressed such that unexpected procedure interactions are avoided.The inspectors determined the failure to establish, implement and maintain procedures regarding shutdown operations as required by Technical Specification 5.4.1.a was a performance deficiency that required an evaluation. The inspectors assessed the significance of this finding using IMC 0609, Attachment 4, and IMC 0609, Appendix A, Exhibit 1, Section B, and determined a detailed risk evaluation was required because the finding caused a reactor trip and loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition (e.g., loss of feedwater). A Senior Reactor Analyst performed a detailed risk evaluation using bounding assumptions and the change in Core Damage Frequency was calculated to be 9E7/year (Green). The inspectors determined that the contributing cause that provided the most insight into the performance deficiency was associated with the cross-cutting area of Human Performance, Change Management aspect, because licensee leaders did not use a systematic process for evaluating and implementing change so that nuclear safety remains the overriding priority.
05000341/FIN-2017007-01	2017Q2	Fermi	Failure to Correct a Design Deficiency that Mis-Quantified Unidentified Leakage	Green . The inspectors identified a finding of very low safety significance with an associated NCV of Title 10 of the Code of Federal Regulations (10 CFR) , Part 50, Appendix B, Criterion XVI, Corrective Actions , for the licensees failure to correct a design deficiency that mis -quantified unidentified leakage from reactor coolant system (RCS ) pressure boundary . Specifically, in April 2007, the licensee identified that the driver mount drain for the reactor recirculation pump could potentially drain leakage from nearby pipe cracks to the identified leakage collection point. However, the licensee had 3 not correct ed this design deficiency as of the start of this inspection. The licensee documented this issue into the CAP as Condition Assessment Resolution Document (CARD) 17 25489 and developed a night order to direct the operators how to calculate unidentified leakage. The licensee also planned to revise procedure 24.000.02 as an interim measure until the modification was implemented. The inspectors determined that the licensees failure to correct the design deficiency that mis-quantified unidentified leakage is a performance deficiency that is reasonably within the licensees ability to foresee and correct. The inspectors determined that this issue is more than minor because if left uncorrected, the performance deficiency has the potential to lead to a more significant safety concern. Specifically, leakage that would normally be collected and measured as unidentified leakage could be collected and measured as identified leakage, leading to a potential violation of the TS unidentified leakage rate . Because the finding did not represent a loss of system or function, or represent an actual loss of function of at least a single train for greater than its Technical Specification (TS) Allowed Outage Time, or represent an actual loss of function of one or more non TS trains of equipment designated as high safety -significant in the licensees Maintenance Rule Program, it was screened as very low safety significance. The inspectors did not identify a cross -cutting aspect since the issue originated more than three years ago.
05000341/FIN-2017002-02	2017Q2	Fermi	Unacceptable Preconditioning of High Pressure Coolant Injection System Air Operated Valve Prior to Stroke Time Test Measurement	Green . The inspectors identified a finding of very low safety significance with an associated Non -Cited Violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings. The licensee failed to establish an adequate procedure to perform required stroke time testing for high pressure coolant injection (HPCI) turbine barometric condenser condensate drain line inboard isolation valve E4100 F026. The surveillance test procedure resulted in unacceptable preconditioning of the valve prior to the stroke time test measurement. The licensee entered this issue into its corrective action program for evaluation and initiated a corrective action to revise the test procedure. The finding was of more than minor significance because it was associated with the Procedure Quality attribute of the Barrier Integrity Cornerstone and adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, cycling the air -operated valve prior to performing the stroke time measurement masked the actual as -found condition of the valve, invalidating the test results. Because the preconditioning altered the as-found condition of the valve, the data collected through the performance of the surveillance test was not fully indicative of the true valve performance trend. Therefore, this performance deficiency had a direct effect on the licensees ability to trend as -found data for the purpose of assessing the reliability of the air -operated valve. The finding was a licensee performance deficiency of very low safety significance because it represented only a degradation of the radiological barrier function provided for the auxiliary building and was not an actual loss of the barrier function provided by the HPCI system pressure boundary as a closed system outside containment . The inspectors concluded this finding affected the cross - cutting area of problem identification and resolution, in particular the cross -cutting aspect of resolution. The organization takes effective corrective actions to address issues in a timely manner, commensurate with their safety significance. Corrective actions resolve and correct the identified issues, including causes and extent of condition. In this case, corrective actions for the previous inspector -identified preconditioning issue did not effectively address the extent of condition involving potential preconditioning of other HPCI system air -operated valve s in other surveillance testing procedures. (IMC 0310, P.3)
05000341/FIN-2017002-01	2017Q2	Fermi	Inadequate Work Instructions for Maintenance on EDG 14	Green . A finding of very low safety significance with an associated Non- Cited Violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was self -revealed when plant operators were not able to shut down emergency diesel generator (EDG) 14 using the manual emergency stop button during surveillance testing. Consequently, operators shut down the engine and removed it from service. The licensee failed to have work instructions for maintenance on the safety -related EDG appropriate to ensure the emergency overspeed switch (EOS) oil seal was properly installed to prevent oil intrusion into the switch housing. The licensee entered this violation into its corrective action program for evaluation and identification of appropriate corrective actions. The licensee replaced the EOS and revised the maintenance procedure and work order guidance for proper oil seal installation on the EOS. The finding was of more than minor safety significance because it was associated with the Equipment Performance at tribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the EO S failure during surveillance testing due to oil intrusion resulted in unplanned inoperability and unavailability of an onsite emergency power source. The finding was determined to be of very low safety significance because it did not represent an actual loss of function of a single train for greater than its Technical Specification (TS) allowed outage time nor did it represent a loss of function of a non- TS train designated as high safety significant in accordance with the licensees Maintenance Rule Program . The inspectors concluded this finding affected the cross - cutting area of human performance and the cross -cutting aspect of documentation. Plant activities are governed by comprehensive, high- quality, programs, processes and procedures. In this case , the licensee determined its maintenance procedure and work order guidance were not adequate to ensure the EOS oil seal and upper air start distributor gasket were properly installed to prevent oil leakage from the air start distributor from getting into the EOS housing. (IMC 0310, H.7)
05000315/FIN-2017002-05	2017Q2	Cook	Inadequate Design Control Measures to Ensure Leakage Remained Within Analysis	Green . 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 failure to have adequate design control measures verify that the Essential Service Water to Containment Spray (CTS) heat exchanger outlet valves were not leaking in excess of the limits of the Large Break Loss of Coolant Accident (LBLOCA) analysis. This finding was entered into the licensees CAP to evaluate adequate design control measures. The performance deficiency was determined to be more than minor because the finding was associated with the Mitigating Systems cornerstone attribute of design control and affected the cornerstone objective of ensuring the capability of the CTS system to respond to an initiating event 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 one of the trains of the CTS system. The inspectors did not identify a cross -cutting aspect associated with this finding because it was not reflective of current performance.
05000341/FIN-2017002-03	2017Q2	Fermi	Licensee-Identified Violation	Title 10 CFR 50.59(d)(1) requires, in part, that the licensee maintain records of changes to the facility, of changes in procedures, and of tests and experiments made pursuant 10 CFR 50.59(c). These records must include a written evaluation which provides the bases for the determination that the change, test, or experiment does 38 not require a license amendment pursuant to Paragraph (c)(2) of this section. 10 CFR 50.59(c)(2)(ii) requires that a licensee shall obtain a license amendment pursuant to 10 CFR 50.90 prior to implementing a proposed change, test, or experiment if the change, test, or experiment would result in more than a minimal increase in the likelihood of occurrence of a malfunction of a structure, system, or component important to safety previously evaluated in the FSAR (as updated). Technical Specification (TS) 3.3.1.1, Reactor Protection System Instrumentation, states the RPS instrumentation for each function in Table 3.3.1.1 1 shall be operable. As specified in Table 3.3.1.1 1, Function 5, Main Steam Isolation Valve - Closure (8 channels) and Function 9, Turbine Stop Valve - Closure (4 channels) are required to be operable in Mode 1. TS 3.3.1.1, Required Action C.1 states with one or more functions with RPS trip capability not maintained to restore RPS trip capability in 1 hour. Condition C was applicable to both the main steam isolation valve and turbine stop valve RPS logic functional testing. Contrary to the above, on or about August 19, 2016, the licensee failed to perform and maintain a written evaluation as required by 10 CFR 50.59(d)(1) to demonstrate a change to its facility did not require a license amendment. Specifically, the licensee incorrectly concluded no license amendment was required in its 10 CFR 50.59 evaluation prior to implementing surveillance test procedures 24.110.05, RPS Turbine Control and Stop Valve Functional Test, Revision 44 and 24.137.01, Main Steam Line Isolation Channel Functional Test, Revision 40. The revised procedures incorporated a change that resulted in more than a minimal increase in the likelihood of occurrence of a malfunction of a structure, system, or component important to safety previously evaluated in the FSAR (as updated) as specified by Section (c)(2)(ii). Specifically, the use of the test box resulted in the loss of two RPS trip functions by bypassing m ore than the TS minimum allowed inputs per channel to maintain functionality, violating the requirements of TS 3.3.1.1 during testing on September 22 and 23, 2016. In accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, Table 3, SDP Appendix Router, the inspectors determined this finding affected the Mitigation Systems Cornerstone, specifically the Reactivity Controls Systems contributor , and would require review using IMC 0609, Append ix A, The Significance Determination Process (SDP) for Findings At -Power, June 19, 2012. The inspectors performed a Phase 1 SDP review of this finding using the guidance provided in IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, and determined this finding was a licensee performance deficiency of very low safety significance ( Green ) because it did not affect a single RPS trip signal to initiate a reactor scram AND the function of other redundant trips or diverse methods of reactor shutdown. Violations of 10 CFR 50.59 are dispositioned using the traditional enforcement process because they are considered to be violations that potentially impede or impact the regulatory process. This violation was also associated with a finding t hat has been evaluated by the SDP and communicated with a SDP color reflective of the safety impact of the deficient licensee performance. The SDP, however, does not specifically consider regulatory process impact. Thus, although related to a common regulatory concern, it is necessary to address the violation and finding using different processes to correctly reflect both the regulatory importance of the violation and the 39 safety significance of the associated finding. In accordance with Section 6.1.d.2 o f the NRC Enforcement Policy, this violation was categorized as Severity Level IV. This violation was entered into the licensees corrective action program as CARD 17 20163.
05000282/FIN-2017002-03	2017Q2	Prairie Island	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.
05000315/FIN-2017002-04	2017Q2	Cook	Failure to Report Deficiencies as Required by 10 CFR 50.46	SL IV. The inspectors identified a Severity Level IV Violation of 10 CFR Part 50.46, Acceptance Criteria for Emergency Core Cooling Systems for Light -Water Nuclear Power Reactors. Specifically, the licensee failed to report the effects of the errors in the 5 LBLOCA Evaluation Model for the Unit 1 emergency core cooling systems. The inspectors determined that the failure to estimate and report the errors in the LB LOCA analyses were contrary to the requirements of 10 CFR 50.46 and was a performance deficiency. The performance deficiency was determined to be minor because the failure to report was not willful, did not impact a performance indicator, was not a material condition issue which could lead to a more significant safety issue, and did not impact the Mitigating Systems cornerstone objectives. The inspectors determined the failure to report was a Severity Level IV violation in accordance with Section 6.9 of the Enforcement Policy. A cross -cutting aspect was not assigned since the performance deficiency is minor.
05000315/FIN-2017002-07	2017Q2	Cook	Licensee-Identified Violation	Title 10 CFR 50.71(e) required that the UFSAR be updated to assure that the latest information developed was in the UFSAR. In AR 2010 4194, Unit 1 and Unit 2 Small Break Loss of Cooling Accident (SBLOCA) Analyses, the licensee identified the March 2007 Unit 1 SBLOCA analysis had not incorporated into the UFSAR and was not included in the October 2008 UFSAR update provided to the NRC. The inspectors determined the failure to update the UFSAR by incorporating the newest SBLOCA analyses was contrary to 10 CFR 50.71e. The inspectors reviewed this issue in accordance with NRC IMC 0612 and the NRC Enforcement Policy. Violations of 10 CFR 50.71(e) are disposed using the traditional enforcement process because they are considered to be violations that potentially impede or impact the regulatory process. The inspectors reviewed Section 6.1.d.3 of the NRC Enforcement Policy and determined this violation was Severity Level IV because the licensees failure to update the UFSAR as required by 10 CFR 50.71(e) had not yet resulted in any unacceptable change to the facility or procedures. The inspectors determined the performance deficiency was minor in that failure to update the UFSAR was not willful; did not impact a performance indicator; was not a material condition issue which could lead to a more significant safety issue, and did not impact the Mitigating Systems cornerstone objectives .

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