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 QSiteSignificanceCCAIdentified byTitleDescription
05000282/FIN-2018003-012018Q3Prairie IslandGreenH.3NRC identifiedFailure to Repair a D2 EDG Jacket Water Leak per the Leak Management ProcessThe inspectors identified a finding of very low safety significance (Green) as of July 18, 2018, for the licensees failure to repair a D2 EDG jacket water leak per the Leak Management Process.
05000282/FIN-2018003-022018Q3Prairie IslandGreenNRC identifiedFailure to Maintain a Preventative Maintenance Strategy for 12 and 22 Cooling Water Pump Diesel EnginesThe inspectors identified a finding of very low safety significance (Green) and associated NCV of Prairie Island Technical Specification 5.4.1, Procedures, as of August 9, 2018, for the licensees failure to maintain a preventative maintenance strategy for sacrificial zinc anode plugs on the jacket water system for the 12 and 22 cooling water pump diesel engines (DDCLPs).
05000282/FIN-2018003-032018Q3Prairie IslandGreenP.2NRC identifiedFailure to Promptly Identify Degradation of the 122 DDCLP FOST Vent PipingThe inspectors identified a finding of very low safety significance (Green) and associated NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, as of November 28, 2017, for the licensees failure to promptly identify a condition adverse to quality associated with 122 DDCLP FOST vent piping.
05000306/FIN-2018003-042018Q3Prairie IslandGreenH.14NRC identifiedFailure to Promptly Identify and Correct 21 125 VDC Battery Lid Conditions Adverse to QualityThe inspectors identified a finding of very low safety significance (Green) and associated NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, as of February 15, 2018, for the licensees failure to promptly identify and correct conditions adverse to quality associated with the 21 125 VDC battery system.
05000282/FIN-2018411-012018Q3Prairie IslandGreenLicensee-identifiedLicensee-Identified Violation
05000282/FIN-2018411-022018Q3Prairie IslandGreenLicensee-identifiedLicensee-Identified Violation
05000331/FIN-2018003-022018Q3Duane ArnoldSeverity level MinorSelf-revealingMinor ViolationDuring Mode 1 power operations on July 9, 2018, the licensee had both doors of a secondary containment airlock open simultaneously, and a minor violation of Technical Specification (TS) 3.6.4.1 Secondary Containment was self-revealed. During the time both doors were open, approximately 3 seconds, the allowable penetration opening area was exceeded and rendered the secondary containment inoperable. Technical Specification 3.6.4.1 requires secondary containment to be operable in Modes 1, 2 and 3. Technical Specification Surveillance Requirement 3.6.4.1.2 supports secondary containment operability by verifying that either the outer door(s) or the inner door(s) in each secondary containment access opening are closed. The posted instructions at each secondary containment airlock door stated, ATTENTION Push Button To Be Held In For 2 Seconds Prior To Opening Door, to be of a type appropriate for traversing the containment airlock. Contrary to the above, at approximately 1:34 p.m. on July 9, 2018, while operating in Mode 1 at 97 percent power, two individuals simultaneously traversing through opposite doors of a secondary containment airlock each failed to hold the airlock interlock push button for two seconds prior to opening their respective doors resulting in a momentarily inoperability of secondary containment. Operability was restored upon the immediate closure of one of the two doors. Subsequently, maintenance was unable to recreate the condition and satisfactorily performed Surveillance Test Procedure (STP) 3.6.4.102, Secondary Containment Airlock Verification, and GMPELEC44,Section A5.1,Airlock Door Interlock Checks.The licensee entered this
05000331/FIN-2018003-012018Q3Duane ArnoldGreenLicensee-identifiedLicensee-Identified ViolationA violation of very low safety significance (Green)was identified by the licensee and has been entered into the corrective action program. This violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy. Title 10 of the Code of Federal Regulations (CFR) 50, Appendix B, Criterion III, states, in part, Measures shall be established to assure that applicable regulatory requirements and the design basis, as defined in 50.2 and as specified in the license application, for those structures, systems, and components to which this appendix applies are correctly translated into specifications, drawings, procedures, and instructions. System Design Specification APEDA61019, Pressure Integrity of Piping and Equipment Pressure Parts Data Sheet, required in the applicable castings section T1.3.3.b, all accessible surfaces including machine surfaces shall be examined by either the magnetic particle or liquid penetrant method in either the furnished or finished condition. Contrary to the above, in October 2016, measures were not established to assure that applicable design basis requirements as defined in 10 CFR 50.2 were translated into work instructions repairing the B inboard main steam isolation valve, CV 4415, during RFO 25. Specifically, instructions to perform a NDE of machined surfaces following the valve repair were not included in the work package. As a result, the non-destructive examination was not performed prior to placing the valve into service.
05000454/FIN-2018003-012018Q3ByronSeverity level MinorNRC identifiedMinor ViolationOn June 14, 2018, the licensee performed IST surveillance 2BOSR 5.5.8.DO1, Test of the Diesel Oil Transfer System, on the 2A diesel oil transfer pump. On June 19, 2018, the inspectors noted that an issue concerning the calibration of the Flexim ultrasonic flow meter used during the test had not been documented in the licensees Corrective Action Program (CAP). Specifically, the calibration sticker on the flow meter used during the surveillance test indicated that the instrument was calibrated to a 5 percent accuracy when the ASME OM Code required an instrument accuracy of 2 percent. The inspectors discussed the issue with licensee management. The licensee subsequently confirmed that the instrument calibration did not meet ASME OM Code requirements and entered this issue into their CAP.Title 10 CFR Part 50, Appendix B, Criterion XII, Control of Measuring and Test Equipment, requires that measures be established to assure that tools, gages, instruments, and other measuring and testing devices used in activities affecting quality are properly controlled, calibrated, and adjusted at specific periods to maintain accuracy within necessary limits. Licensee procedure ERAA321, Administrative Requirements for Inservice Testing,Section 4.10.3, states, in part, that instrument accuracy and range requirements are specified in the applicable ASME Code Edition/Addenda. ASME OM Code Paragraph ISTB-3510, General, states, in part, that instrument accuracy shall be within the limits of Table ISTB-35101, Required Instrument Accuracy. Table ISTB35101 states that the required instrument accuracy for determining flow rate is 2 percent. Screening: The failure to implement programmatic controls that ensured measurement and test equipment was calibrated to the accuracy requirements of the ASME OM Code was a performance deficiency. The instruments used in IST surveillances were later re-certified to meet the required 2 percent accuracy in the ASME OM Code with no required adjustments. As a result, the performance deficiency was determined to be minor because the inspectors answered No to all of the more-than-minor screening criteria in IMC 0612, Appendix B. The licensee generated Issue Report (IR) 04149294 to document this issue in their CAP. This issue was also incorporated into a corrective action program evaluation (CAPE) report evaluating an adverse trend identified with ASME test performance at the site (AR 04154533). Violation: The failure to comply with 10 CFR Part 50, Appendix B, Criterion XII, Control of Measuring and Test Equipment, constituted a minor violation that was not subject to enforcement action in accordance with the NRCs Enforcement Policy.
05000341/FIN-2018003-032018Q3FermiGreenH.11Self-revealingFailure to Identify a Condition Adverse to Quality on Division 2 Residual Heat Removal Service Water Outlet Flow Control ValveA 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.
05000263/FIN-2018012-032018Q3MonticelloGreenLicensee-identifiedLicensee-Identified ViolationThis violation of very-low safety significance was identified by the licensee and has been entered into the licensee CAP. Therefore, this finding being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy.Enforcement:Violation: Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, requires, in part, that measures be established to assure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions. Updated Final Safety Analysis Report, Appendix I,Evaluation of High Energy Line Breaks Outside Containment,Table I.5-2, Table of System Effects,Revision 36P, listed the Division II emergency power system as available during HELBs outside containment. Contrary to the above, on July 29, 1974, the licensee failed to assure that applicable regulatory requirements and the design basis were correctly translated into specifications, drawings, procedures, and instructions. Specifically,the Division II emergency power system would not be available during a HELB outside containment.Procedure B.09.07-05, Operations Manual Section 4.16 kV Station Auxiliary, Revision 53,had actions that required entry into the lower 4kV area to permit repowering Division II emergency power systems but this area would be inaccessible during the event. Significance: The performance deficiency was determined to be more-than-minor because it was associated with the Mitigating Systems cornerstone attribute of Design Control and affected the cornerstone objective of ensuring the availability, reliability, and capability of mitigating systems to respond to initiating events to prevent undesirable consequences.Specifically, the performance deficiency resulted in a condition were the Division II emergency power system would not be available during HELBs outside containment. The inspectors assessed the significance of the finding using the SDP in accordance with IMC 0609, 11 Appendix A, The Significance Determination Process for Findings At-Power, using Exhibit 2, Mitigating System Screening Questions,and concluded the violation was of very-low safety or security significance (Green)because the licensee reasonably demonstrated an alternate strategy was available to timely reach and maintain cold shutdown conditions. Corrective Action References: CAP501000011837, CAP 50100001593
05000263/FIN-2018003-012018Q3MonticelloGreenLicensee-identifiedLicensee-Identified ViolationThis 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. Enforcement: Violation: The licensee identified a finding of very low safety significance (Green) and associated NCV of 10 CFR 50.49, Environmental qualification of electric equipment important to safety for nuclear power plants; which requires, in part, that equipment qualified by test must be preconditioned by natural or artificial aging to its end of life or a shorter designated life considering all significant types of degradation which can have an effect on equipment function. Contrary to the above, on June 2, 2018, the licensee determined that EQ evaluation 608000000032, of MO2034, MO2035, MO2075, and MO2076 (HPCI and RCIC Steam Line Isolation Valves) internal actuator cables, failed to consider the temperature rise due to the high temperature process fluid in the vicinity of the affected components when aging (preconditioning) them and the unaccounted temperature rise shortened the life of some components to the point that they were no longer EQ qualified to the end of planned life. The unaccounted for process fluid temperature increases were verified by the licensee when thermography of the associated valves was performed. The licensee performed a prompt operability determination, entered the issue into the corrective action program (CAP) as CAP 501000012766 and performed a thermal life analysis engineering evaluation. Long-term corrective actions include replacement of the internal actuator cables during the next refueling outage. 10 Significance/Severity Level: This finding was more than minor because the performance deficiency was associated 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, HPCI and RCIC Steam Line Isolation Valves are designed to provide reactor coolant pressure boundary, required for a safe reactor shutdown following a Design Basis Accident or transient. The finding was of very low safety significance (Green) because it was 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 Technical Specification (TS) allowed outage time, and did not represent an actual loss of function of one or more non-TS trains of equipment designated as high safety-significant in accordance with the licensees maintenance rule program for >24 hrs. Corrective Action Reference: 501000012766
05000263/FIN-2018012-022018Q3MonticelloGreenP.2NRC identifiedFailure to Implement Adequate Freeze Protection Monitoring for Condensate Storage Tank Instrumentation Piping in Response to Industry Operating ExperienceThe inspectors identified a Green finding and an associated NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, for the licensees failure to establish measures to ensure conditions adverse to quality are promptly identified and corrected. Specifically, the licensee failed to identify that monitoring of the CST instrument line heat tracing performed every 30 days was inadequate to assure the safety-related CST level instrumentation remained operable during extreme cold weather conditions
05000263/FIN-2018012-012018Q3MonticelloGreenNRC identifiedInboard Main Steam Isolation Valve Closure Time Test Acceptance Criteria Did Not Account for the Design Basis Accident Containment Back Pressure and Pneumatic Supply Operating PressureThe inspectors identified a Green finding and an associated NCV of Title 10 of the Code of Federal Regulations(CFR), Part 50, Appendix B, Criterion XI, Test Control, for the failure to assure that applicable requirements and acceptance limits contained in the inboard main steam isolation valve (MSIV) design documents were incorporated into their test procedure. Specifically, the inboard MSIV closure time acceptance criteria contained in Functional Test Procedure 0255-07-IA-2, Main Steam Isolation Valve Functional Checks Test, did not account for the elevated containment pressure and the expected lower pneumatic supply pressure expected during design basis accidents.
05000341/FIN-2018003-022018Q3FermiGreenH.7Self-revealingFailure to Ensure Electrolytic Capacitors Installed in the Plant Did Not Have Expired Shelf LivesA 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.
05000341/FIN-2018003-012018Q3FermiGreenP.3Self-revealingFailure to Apply Torque Values Described in Maintenance Procedure for Flexible Couplings on Emergency Diesel Generator 12A 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.
05000440/FIN-2018010-012018Q3PerryGreenNRC identifiedFailure to Correctly Establish Maintenance/Replacement Frequencyfor the WeedTemperature Transmitters In Zone FB-7The inspectors identified a finding of very-low safety significance (Green), and associated Non-Cited Violation (NCV) of Title 10 of the Code of Federal Regulations(CFR), Part 50.49(e)(5), Environmental Qualification of Electrical Equipment Important to Safety for Nuclear Power Plants, for the licensees failure to correctly establish maintenance/replacement frequency for Weed temperature transmitters installed in harsh environment. Specifically, Calculation EQ-115, Qualified Life Calculation for Weed RTD/RTDT and TC Assemblies,incorrectly established a qualified life for Weed temperature transmitters installed in Zone FB-7. The calculation determined that the qualified life for these transmitters in Zone FB-7 as 18.9 years plus accident. However, the calculation failed to account for the accident time and temperature.
05000266/FIN-2018003-012018Q3Point BeachSeverity level IVNRC identifiedFailure to Perform Evaluations to Ensure that the Fabrication of Dry Cask Storage Systems Meets the Requirements of the Loading Certificate of ComplianceAn NRC-identified Severity Level IV NCV of 10 CFR 72.212 was identified when the licensee failed to perform written evaluations to ensure that the dry cask storage systems met the fabrication requirements of the Certificate of Compliance (CoC) to which they were loaded.
05000266/FIN-2018003-022018Q3Point BeachGreenLicensee-identifiedLicensee-Identified ViolationViolation: Point Beach Nuclear Plant, Units 1 and 2, Renewed Operating License Condition 4.F, requires the licensee to implement and maintain in effect all provisions of the approved fire protection program that comply with 10 CFR 50.48(a) and 10 CFR 50.48(c), National Fire Protection Association Standard NFPA 805, as specified in the license amendment requests and as approved in the safety evaluation report dated September 8, 2016.Section 1.5.1, Nuclear Safety Performance Criteria, of NFPA 805, stated in part, that fire protection features shall be capable of providing reasonable assurance that, in the event of a fire, the plant is not placed in an unrecoverable condition. To demonstrate this, the following performance criteria shall be met: (a) Reactivity Control; (b) Inventory and Pressure Control; (c) Decay Heat Removal; (d) Vital Auxiliaries; and (e) Process Monitoring.Section 1.5.1 (d), Vital Auxiliaries, of NFPA 805, stated that vital auxiliaries shall be capable of providing the necessary auxiliary support equipment and systems to assure that the systems required under (a), (b), (c), and (e) are capable of performing their required nuclear safety function. Contrary to the above, from March 16, 2018 through April 11, 2018, the licensee failed to ensure that vital auxiliaries were capable of providing the necessary auxiliary support equipment and systems to assure that the systems required under (a), (b), (c), and (e) are capable of performing their required nuclear safety function. Specifically, select 120 VAC instrument buses, needed as a vital auxiliary, would not have been energized during certain fire scenarios and compensatory measures were not implemented. Significance/Severity Level: The inspectors determined the performance deficiency was more than minor because it adversely affected the Mitigating Systems cornerstone attribute of Protection Against External Factors (Fire) and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). The inspectors assessed the significance of the finding using Inspection Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process. The finding did not screen to green using questions 1.5.1A and 1.5.1B and thus required a detailed risk evaluation. The Senior Reactor Analyst performed walkdowns of dominant fire sequences and conducted an onsite review of the licensee's fire calculation which confirmed that the increase in risk due to the finding was less than 1E6/year (Green).
05000266/FIN-2018003-032018Q3Point BeachGreenLicensee-identifiedLicensee-Identified ViolationViolation: Point Beach Nuclear Plant, Units 1 and 2, Renewed Operating License Condition 4.F, requires the licensee to implement and maintain in effect all provisions of the approved fire protection program that comply with 10 CFR 50.48(a) and 10 CFR 50.48(c), National Fire Protection Association Standard NFPA 805, as specified in the license amendment requests and as approved in the safety evaluation report dated September 8, 2016. Section 2.4.3.2, of NFPA 805, states that the PSA (Probabilistic Safety Assessment) evaluation shall address the risk contribution associated with all potentially risk-significant fire scenarios.Contrary to the above, from February 14, 2017 through June 14, 2018, the licensees PSA failed to address the risk contribution associated with all potentially risk-significant scenarios. Specifically, the licensee improperly excluded the risk contribution from 27 electrical panels because they had incorrectly concluded that internal fires would not propagate outside the panel walls due to them being misclassified as well-sealed. Significance/Severity Level: The inspectors determined the performance deficiency was more than minor because it adversely affected the Mitigating Systems cornerstone attribute of Protection Against External Factors (Fire) and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). The inspectors assessed the significance of the finding using Inspection Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process. The finding did not screen to green using questions 1.5.1A and 1.5.1B and thus required a detailed risk evaluation. The Senior Reactor Analyst performed walkdowns of dominant fire sequences and conducted an onsite review of the licensee's fire calculation which confirmed that the increase in risk due to the finding was less than 1E6/year (Green).
05000266/FIN-2018003-042018Q3Point BeachGreenLicensee-identifiedLicensee-Identified ViolationViolation: Title 10 CFR 72.150 states The licensee . . . shall prescribe activities affecting quality by documented instructions, procedures, or drawings of a type appropriate to the circumstances and shall require that these instructions, procedures, and drawings be followed. Contrary to the above, on June 5 and 6, 2018, the licensee failed to follow procedures for an activity affecting quality. Specifically, during a dry run in the primary auxiliary building (PAB) over the spent fuel pool (SFP), the pin lock for the pin which engages the Point Beach pool lift yoke to the PAB overhead crane was not correctly engaged when lifting the transfer cask (TC) out of the pool. After the TC was set down in the decon area, the lift yoke was then left unattended over the SFP over spent fuel. This is not in accordance with procedure RP 17 Part 4, Revision 26, Step 5.1.4 for engagement of the pin lock, and not in accordance with procedure MAAA2121000, Revision 16, Step 4.5.3 for leaving a load suspended and unattended.Severity Level: The inspector determined the violation was more than minor, as informed by Inspection Manual Chapter (IMC) 0612 Appendix E, Example 4.k., in that there was a credible load drop scenario that could impact safety-related equipment. In accordance with Section 2.2 of the Enforcement Policy and IMC 0612, Appendix B, Issue Screening, Independent Spent Fuel Storage Installations are not subject to the Significance Determination Process and are not subject to the Reactor Oversight Process, so violations identified at ISFSIs are assessed using traditional enforcement. Consistent with the guidance in Section 1.2.6.D of the Enforcement Manual, if a violation does not fit an example in the Enforcement Policy Violation Examples, it should be assigned a severity level: (1) commensurate with its safety significance; and (2) informed by similar violations addressed in the Violation Examples. The inspector found no similar violations in the violation examples. This violation was determined to be a Severity Level IV in that there was no load drop, and that the weight of any load on the pin would contribute to opposing any potential movement of the pin.
05000266/FIN-2018010-012018Q3Point BeachGreenLicensee-identifiedLicensee-Identified ViolationThis violation of very low safety significance was identified by the licensee and has been entered into the licensee corrective action program and is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Polic Violation: Title 10 CFR 50, Part B, Criterion XII requires that measures shall be established to assure that tools, gages, instruments, and other measuring and testing devices used in activities affecting quality are properly controlled, calibrated, and adjusted at specified periods to maintain accuracy within necessary limits.Contrary to the above, the licensee failed to assure that tools, gages, instruments, and other measuring and testing devices used in activities affecting quality were properly controlled. Specifically, the licensee did not include all M&TE devices in their control tracking program, which could result in instruments not being evaluated if associated M&TE fails its post-calibration.Significance/Severity Level: The inspectors determined the performance deficiency was more than minor because if left uncorrected, it would have the potential to lead to a more significant safety concern. The inspectors assessed the significance of the finding using SDP Appendix A and concluded the violation was of very low safety significance (Green).
05000461/FIN-2018003-012018Q3ClintonGreenH.3NRC identifiedFailure to Revise an Operability Evaluation When No Longer Meeting a Compensatory MeasureThe inspectors identified a Green finding for the failure to revise an operability evaluation when no longer meeting a compensatory measure, in accordance with OPAA115, Operability Determinations, Revision 21. Specifically, the licensee failed to revise the operability evaluation documented in EC 387664 when no longer maintaining the Division 1 and Division 2 safety-related buses in a split bus configuration from November 2017 through June 2018.
05000456/FIN-2018411-012018Q3BraidwoodGreenLicensee-identifiedLicensee-Identified Violation
05000461/FIN-2018003-022018Q3ClintonSeverity level MinorNRC identifiedMinor ViolationTitle 10 CFR 50, Appendix B,Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality be prescribed by documented procedures of a type appropriate to the circumstances and be accomplished in accordance with these procedures. The licensee established procedure CPS 8219.01, Personnel Airlock Maintenance, Revision 19, as the implementing procedure for performing maintenance on a safety-related personnel airlock, an activity affecting quality.Procedure CPS 8219.01, Section 2.1.4 states in part, Personnel Airlock Maintenance Checklist, shall be filed with completed work documents.Contrary to the above, on March 30, 2018, the licensee failed to follow Section 2.1.4 of procedure CPS 8219.01. Specifically, the licensee failed to file the personnel airlock maintenance checklist with the completed work documents. After the inspectors questioned the whereabouts of the checklist, it was discovered that it was not used when performing the repair or post maintenance test on the personnel airlock even though the procedure directs personnel to record pertinent data on the checklist during the maintenance activity. Screening: The inspectors determined the performance deficiency was minor because it was determined to be a documentation issue and the values required to be documented in the checklist were satisfactory, therefore, there was no adverse impact. The licensee documented this issue in AR 4126058, NRC ID: Documentation Deficiency Identified.Violation: This failure to comply with 10 CFR 50 Appendix B, Criterion V, Instructions, Procedures, and Drawings constitutes a minor violation that is not subject to enforcement action in accordance with the NRCs Enforcement Policy.Licensee Event Report 05000461/201800100 is closed.
05000461/FIN-2018412-012018Q3ClintonGreenH.2NRC identifiedSecurity
05000315/FIN-2018003-022018Q3CookLicensee-identifiedSite Specific Shielding and Barriers for HI-TRAC Transfer Cask Require NRC Approval Prior to UseCertificate of Compliance (CoC) 1014, Amendment 9, Design Feature, Section 3.9, Environmental Temperature Requirements, requires building ambient temperatures be less than 110 degrees Fahrenheit during canister processing based upon the thermal analysis in the Holtec HI-STORM Final Safety Analysis Report, Revision 13. The thermal model documented in the Final Safety Analysis Report, Revision 13, Section 4.5.1, HI-TRAC Thermal Model, states that heat is passively rejected to the ambient from the outer surface of the HI-TRAC transfer cask by natural convection and thermal radiation. However, at D.C. Cook, the licensee uses additional shielding materials for as low as reasonably achievable purposes that are in contact with and in the general area of the HI-TRAC. The licensee requested Holtec to perform a site-specific thermal analysis, HI2177676, Thermal Evaluation of Shielding Package around the HI-TRAC at DC Cook, to include the shielding material in the thermal model. The analysis contained inputs that were different than the design basis calculation inputs, which were previously incorporated into Design Feature Section 3.9 and Approved Contents Section 2.4. The licensee performed a 10 CFR 72.48 Screening and Evaluation 2018013902, which concluded that shielding could be used without prior NRC approval and subsequently issued 212CR0017, which revised the 72.212 Report. The licensee implemented administrative controls on building temperature and fuel assembly heat load limits based upon the site specific thermal analysis. This unresolved item is being opened to determine if: A) the licensee is in compliance with Design Feature, Section 3.9, Environmental Temperature Requirements; B) the Design Feature Section 3.9 and Approved Contents Section 2.4 are non-conservative at D.C. Cook; and C) the licensee is in compliance with 10 CFR 72.48. Planned Closure Actions: Region III will coordinate with the Division of Spent Fuel Management in the NRC Office of Nuclear Materials Safety and Safeguards. Corrective Action References: AR 20184056; AR 20186342; AR 20186642
05000316/FIN-2018003-012018Q3CookGreenH.5Self-revealingMisaligned Heater Level Column Valves Leads to Manual Reactor TripA self-revealed, Green finding was identified when the operators manually tripped the Unit 2 reactor in response to a hi-hi level in the Left Moisture Separator Drain Tank. On May 6, 2018, the Unit 2 reactor was at approximately 12 percent power following a startup at the conclusion of the spring 2018 refueling outage. While the station continued to make preparations to start the main turbine and synchronize with the grid, the moisture separator drain tank hi level alarm was received and remained standing for the better part of the shift. The drain tank collects condensed steam and water from the moisture separator reheater and associated high pressure turbine exhaust lines and routes it either to the condenser or #4 feedwater heaters. The day shift operators were hesitant to continue on with starting the main turbine until the cause of the alarm could be determined. Due to a series of miscommunications between day shift, night shift, the outage control center, and personnel performing troubleshooting, the night shift crew believed it was acceptable to continue with the turbine startup with the alarm still standing. The turbine was synchronized to the grid and power was stabilized at approximately 29 percent power with the alarm in for most of the turbine startup and synchronization. The alarm cleared for a period of time at 29 percent power, but then returned along with the hi-hi drain tank level alarm. Per the alarm response procedures, the operators tripped the reactor and main turbine to protect the turbine from excessive water in the system. Later investigation by the site revealed that the level columns for the #4 feedwater heaters had been left isolated following work and testing associated with the replacement of the #5 feedwater heaters. While the Operations Department had completed a valve lineup on the system per their startup procedures, which put the level columns in service, the Projects Department had not finished all of the work on the heaters at the time the lineup was performed. As a result, workers subsequently isolated the columns to complete testing after the Operations lineup was complete. A step in the Projects test procedure EC51366TP001 directed workers to specifically inform the operators that the level columns were isolated following testing and that the system was ready to be lined up per operations procedures. However, the workers did not provide that detail, and simply stated that the test was complete. As a result, operations did not know the valves had been taken out of alignment. Contributing to the issue, the outage schedule did not provide any logic ties to ensure all work was complete on the heaters before allowing operations to do their valve lineups. With the level columns isolated during startup, the #4 heaters indicated an erroneous level. This resulted in the operators believing that the heaters were at a normal operating level when in fact, they were full. Therefore, when the operators (per procedure) opened a high pressure turbine exhaust valve to the 4A heater, this created a pathway for water to flow from the #4 heaters, through the high pressure turbine exhaust lines, and into the moisture separator drain tank. The excessive flow of water caused the hi and hi-hi alarms in the drain tank which then led to the reactor/turbine trip.
05000255/FIN-2018411-022018Q3PalisadesGreenLicensee-identifiedLicensee-Identified Violation
05000255/FIN-2018411-012018Q3PalisadesGreenLicensee-identifiedLicensee-Identified Violation
05000315/FIN-2018010-012018Q3CookNRC identifiedRecord Retention Requirements of the Boron Injection Tank and its Associated Support StructureThe inspectors identified an Unresolved Item concerning the Title 10 of the Code of Federal Regulations, Part 50, Appendix B, and ASME Code requirements for the BIT and its associated support structure calculation of record. Updated Final Safety Analysis Report (UFSAR) Section 2.9.2 delineated the BIT Seismic Classification as Class 1. The BIT was part of the Emergency Core Cooling System piping system, and is Seismic Class I. In addition, UFSAR Table 6.2-1 and UFSAR Table 6.2-3 delineated the BIT was designed in accordance with ASME Boiler and Pressure Vessel Code, Section III, Class C. Additionally, Subsection C under Section IIII Article N-2111, stated, in part, The requirements of Section VIII of the Code shall apply to the materials, design, fabrication, inspection and testing, and certification of Class C vessels.... The inspectors reviewed Drawing No. 113E275; 900 Gallon BIT; Revision 5 which contained the design specification for the BIT. Also the inspectors reviewed Struthers Wells Calculation No. 2-70-07-30717; Seismic Stress Calculations for BITs; 07/02/1970 which contained the BIT support structure qualification. The inspectors reviewed Calculation No. DC-D-12-MSC-8 Attachment A, page A.10-10 and page A.9-28; Revision 2 which contained the applied nozzle loads at the BIT inlet and outlet nozzles. Lastly, the inspectors reviewed Document No. 546 CRI 109890; Westinghouse Purchase Order for BIT; 06/22/1970 which contained design requirements for the BIT. During the review of aforementioned design basis documents the inspectors identified the following examples in which the licensee did not have a calculation of record to address the following ASME code requirements: ASME Section VIII, Division 1, Subsection A, General Requirements, Part UG-22 titled Loading states, in part, the loadings to be considered in designing a vessel shall include: Internal or external design pressure (as defined in Par. UG-21), Impact loads, including rapidly fluctuating pressures: Weight of the vessel and normal contents under operating or test conditions. (This includes additional pressure due to static head of liquids), Superimposed loads such as other vessels, operating equipment, insulation, corrosion-resistant or erosion-resistant linings and piping, Wind loads, and earthquake loads where required, Reactions of supporting lugs, rings, saddles or other types of supports (see Appendices D and G) and the effects of temperature gradients on maximum stress. The inspectors identified that the licensee did not have a calculation of record to address the applied loadings due to dead weight of the vessel, fluid weight inside of the vessel, design temperature of 300 degrees Fahrenheit and earthquakes (Operating Basis Earthquake and Safe Shutdown Earthquake) on the BIT vessel shell and head ASME Section VIII, Division 1, Subsection A, General Requirements, Part UG-54 titled Supports states, in part, All Vessels shall be supported and the supporting members shall be arranged and/or attached to the vessel in such a way as to provide for the maximum imposed loadings (see Par. UG-22).. The inspectors identified that the licensee did not have a calculation of record to address the applied loadings due to the superimposed piping loads at the BIT inlet and outlet nozzle to the BIT support structure as well as the applied loading due to the design temperature of 300 degrees Fahrenheit. Secondly, the inspectors identified that no calculation of record existed for the welded connection between the support legs and the baseplate. Thirdly, no calculation of record existed for the welded connection between the support legs and the BIT. Lastly, the self-weight and self-weight seismic excitation of the support structure was not considered in the applied stresses of the support structure calculation of record. In response to the inspectors concern, the licensee initiated AR 2018-7104, Lack in Documentation for BIT 1-TK-11, 07/12/2018. In addition, the licensee performed an operability review and reasonably determined the BIT remained operable. Near the end of the inspection period, the licensee provided the inspectors additional information relevant to the calculation record retention requirements as defined by the ASME Code and the DC COOK Quality Assurance Program Document which 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 and Office of the General Counsel.
05000255/FIN-2018003-012018Q3PalisadesGreenH.12NRC identifiedWire Not Landed on Safety Injection Initiation Relay CircuitThe inspectors identified a Green finding and an associated non-cited violation (NCV)of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensees failure to accomplish an activity affecting quality in accordance with the implementing procedure. Specifically, only one of two required wires was landed on terminal 13 of relay SIS2 in the right channel of the safety injection system (SIS) actuation logic following surveillance testing that was performed on May 8, 2017. As a result, the right channel of the safety injection system actuation logic was inoperable until the problem was discovered during troubleshooting and the wire was subsequently re-landed onMay 3, 2018
05000440/FIN-2018003-012018Q3PerryNRC identifiedApplication of ASME Code Case N5133 for the Emergency Service Water Piping DegradationsThe 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
05000456/FIN-2018003-022018Q3BraidwoodSeverity level MinorNRC identifiedMinor ViolationAll Braidwood Station EDG governors were replaced during the late 1990s. During design testing, the licensee noted that the historical EDG frequency response had changed slightly due to installation of new electronic governors. Prior to these governor replacements, EDG frequency was always above 57 hertz (Hz) during load sequencing. However, with the newly installed electronic governors, 1A and 2A EDG frequency was observed to dip below the 57 Hz under frequency relay setpoint following start of the 1A and 2A motor-driven AF pumps. (Note that because the 1B and 2B AF pumps are diesel-driven, there is no corresponding impact on the 1B or 2B EDGs.) As a result, an external 2-second time delay, provided by an Agastat time delay relay, was incorporated into the under frequency trip logic for the 1A and 2A EDGs to provide an additional margin for frequency recovery following motor-driven AF pump load starts. The Braidwood governor modification was installed in 1998, with the external time delay added to the 1A and 2A EDGs as part of the design changes to prevent inadvertent actuations of the under frequency logic.During the licensees investigation into the issue discussed in the subject LER, it was identified that the external Agastat time delay was installed incorrectly on the 1A EDG. Specifically, the original trip logic wiring had not been properly removed, which permitted the actuation of the under frequency trip after the original 0.5 second internal time delay through the bypassing of the additional 2.0 second external time delay. The wiring error was introduced during the original modification installation in October 1998. Screening: The inspectors determined that the error was of minor safety significance. Absent the mechanical binding of the manual fuel trip lever and associated linkage, as discussed in NCV 05000456/201800301 in this report, the 1A EDG had performed reliably and satisfactorily during surveillance testing prior to the Unit 1 refueling outage testing in April of 2018. Additionally, the inspectors determined that the error, having occurred some 20 years ago, was not indicative of current licensee performance.Violation: This failure to comply with the requirements of 10 CFR Part 50, Appendix B, Criterion III , Design Control, constitutes a minor violation that is not subject to enforcement action in accordance with the NRCs Enforcement Policy.
05000456/FIN-2018003-012018Q3BraidwoodGreenH.7Self-revealingInadequate Detail in Maintenance Procedure for Emergency Diesel Generator 2-Year Inspection Contributed to 1A Emergency Diesel GeneratorFuel Rack BindingA self-revealed finding of very low safety significance (i.e., Green) and an associated Non-Cited Violation (NCV) of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified for the licensees failure to include adequate detail within their maintenance procedures to enable proper lubrication of the emergency diesel generator (EDG) fuel rack control linkage. Specifically, the preventative maintenance template for the fuel rack control linkage required that the manual fuel trip lever and associated linkage be lubricated every 2 years. However, the licensees implementing 2year maintenance procedure failed to include specific instructions to disassemble the lever assembly for lubrication. This lack of lubrication contributed to the mechanical binding of the emergency diesel generator fuel rack and failure of the 1A EDG during surveillance testing on April 22,2018.
05000237/FIN-2018003-022018Q3DresdenSeverity level IVLicensee-identifiedLicensee-Identified ViolationViolation: Dresden Technical Requirements Manual (TRM) Control Program (Appendix G of TRM), Section 1.5, Program Implementation, requires that proposed changes to the TRM are screened and reviewed under the 10 CFR 50.59 process in accordance with plant specific procedures. Contrary to the above, in October 2017 Dresden station approved and implemented an extension to the surveillance frequency of DIS 150020, Division I & II Low Pressure Coolant Injection (LPCI) Pumps Suction and Injection Valves Circuitry Logic System Functional Test, on Unit 2 per the Surveillance Frequency Control Program (SFCP) without the required 50.59 review.
05000249/FIN-2018003-012018Q3DresdenGreenH.7Self-revealingFailure to Follow Maintenance Procedures for Assembling Unit 3 HPCI Room Cooler FanA self-revealing, Green non-cited violation (NCV) of Technical Specification (TS) 5.4, Procedures, was identified for the licensees failure to follow maintenance procedures DMP 570004, LPCI and HPCI Room Cooler Maintenance, and DEP 570004, HPCI Room Cooler Fan Preventive Maintenance, when assembling the Unit 3 HPCI room fan. Specifically, on one occasion when maintenance was performed on the fan, technicians installed the cam locking collar in the opposite direction of the fan shaft rotation, and on the other occasion, technicians tensioned the fan belt to the wrong value and misadjusted the alignment of the shaft sheave. Over time, this improper maintenance caused the inboard and outboard fan bearings to wear on the shaft, causing increased vibrations, and eventually leading to HPCI being declared inoperable to emergently work on the fan
05000373/FIN-2018003-012018Q3LaSalleGreenH.12NRC identifiedFailure to Establish Heat Exchanger Inspection Procedures Appropriate for the CircumstancesThe 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.
05000373/FIN-2018003-022018Q3LaSalleGreenNRC identifiedFailure to Establish an Appropriate Inservice Testing ProcedureThe 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.
05000373/FIN-2018003-032018Q3LaSalleGreenNRC identifiedFailure to Establish Goals to Monitor Steam Tunnel Check DampersIntroduction: 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.
05000373/FIN-2018003-042018Q3LaSalleGreenH.13NRC identifiedFailure to Manage the Increase in Risk During a Battery Charger Capacity TesThe 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.
05000373/FIN-2018003-052018Q3LaSalleGreenNRC identifiedFailure 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-2018003-062018Q3LaSalleNRC identifiedPotential Failure to Inspect Containment Post-Tensioned Tendons per Code Requirements and to Follow Corrective Action Program ProcessVertical 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.
05000374/FIN-2018003-072018Q3LaSalleNRC identifiedPotential Failure to Promptly Correct the Unit 2 Primary Containment Wall Cavity Leakage Condition and to Follow Corrective Action Program ProcessCondition 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-2018003-082018Q3LaSalleGreenH.4NRC identifiedFailure to Implement Engineering Change Results in Reactor Coolant Boundary LeakageThe 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-2018201-012018Q3LaSalleGreenNRC identifiedSecurity
05000373/FIN-2018412-012018Q3LaSalleGreenLicensee-identifiedLicensee-Identified Violation
05000440/FIN-2018002-012018Q2PerryGreenH.12NRC identifiedFailure to Control Transient Combustible Materials in a Designated Combustible Control ZoneThe 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.
05000346/FIN-2018002-042018Q2Davis BesseGreenH.13NRC identifiedMisapplication of the Operability Determination ProcessThe NRC identified a finding of Green significance due to the licensees misapplication of NOPOP1009, Operability Determinations and Functionality Assessments. Specifically, the licensee failed to apply the Operability Determination process in accordance with procedures.
05000440/FIN-2018410-012018Q2PerryGreenH.3NRC identifiedSecurity
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