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| Quarter | Site | Title | Description | |
|---|---|---|---|---|
| 05000338/FIN-2018003-01 | 2018Q3 | North Anna | Licensee-Identified Violation | This 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 a Non-Cited Violation, consistent with Section 2.3.2.a of the Enforcement Policy. Violation: TS 5.4.1.a, requires in part, that written procedures shall be established per Revision 2 of Regulatory Guide 1.33, Appendix A, of which part 9.a requires written procedures and documented instructions appropriate to the circumstances for performing maintenance that can affect the performance of safety related equipment. Contrary to the above, on June 12, 2018, the licensee failed to adequately establish a procedure appropriate to the circumstances during maintenance on the safety-related main control chillers. Specifically, licensee mechanical preventative maintenance procedure, 0-MPM-0806-02, Inspection of Control Room Chillers, Revision 0, did not provide a proper method to adequately monitor the Freon level in main control room chillers. Consequently, the licensee discovered a low Freon level condition on main control room chiller 1-HV-3-4B, which rendered the chiller inoperable. Significance: The inspectors reviewed Exhibit 2 Mitigating Systems Screening Questions of IMC 0609 Appendix A, The Significance Determination Process (SDP) for findings at Power and determined this finding was of very low safety significance, Green, because there was no design deficiency, it did not represent a loss of system or function, and did not represent an actual loss of function for greater than its TS allowed outage time. Corrective Action Reference: CR109958 |
| 05000324/FIN-2018002-02 | 2018Q2 | Brunswick | Enforcement Action 18-080: Implementation of EGM 11-003, Revision 3, Enforcement Guidance Memorandum on Dispositioning Boiling Water Reactor Licensee Noncompliance with Technical Specification Containment Requirements during Operations with a Potential for Draining the Reactor Vessel (OPDRV) | During the Unit 1 spring 2018 refueling outage, the OPDRVs activities are listed below: March 7, 2018: 148 gallons per minute (gpm) leakage associated with local leak rate testing (LLRT) of valves 1-G31-F001 and -F004.March 8, 2018: 82 gpm leakage for A RHR loop draining to support maintenance.March 12, 2018: 81.2 gpm leakage to replace the local power range monitors and intermediate power range dry tubes.March 14, 2018: 71.2 gpm leakage to replace the local power range monitors.March 15, 2018: 25 gpm leakage to replace A recirculation pump seal package.March 22, 2018: 25 gpm leakage to replace A recirculation pump seal package.March 27, 2018: 164 gpm leakage to facilitate control rod drive system venting.March 28, 2018: 288 gpm leakage to account for leakage past scram discharge and vent valves during testing.These activities took place without secondary containment being operable. Corrective Actions: EGM 11-003 allows enforcement discretion regarding secondary containment operability during Mode 5 OPDRV activities provided the licensee meets certain requirements. The licensee met the stipulations of the EGM by executing their procedure 1SP-16-100, EGM 11-003 OPDRV Activities, Rev 001, for each OPDRV activity during the Unit 1 Spring 2018 refueling outage. Additionally, as required by the EGM, the licensee submitted a license amendment request (BSEP 17-0060) on June 29, 2017. The amendment was approved on April 13, 2018, and will be implemented prior to the 2019 Unit 2 spring refueling outage. Corrective Action Reference: The issue was entered into the licensees corrective action program as NCR 2189536. Violation: TS 3.6.4.1, Secondary Containment, requires that secondary containment be operable and is applicable during OPDRVs. The required action if secondary containment is inoperable in this condition is to initiate actions to suspend OPDRVs immediately. Contrary to the above, on activities listed above, the licensee failed to maintain secondary containment operable while performing OPDRVs on Unit 1. Severity/Significance: According to EGM 11-003, the NRC considers enforcement discretion related to secondary containment operability during Mode 5 OPDRV activities provided the licensee meets certain requirements such as monitoring vessel level, maintaining capability to isolate leakage paths, providing minimum makeup flow rate, etc. These requirements provide a reasonable assurance of public health and safety during draining activities in Mode 5 while the secondary containment is inoperable 13 Enclosure Discretion Basis: The NRC exercised enforcement discretion in accordance with Section 3.5, Violations Involving Special Circumstances, of the NRC Enforcement Policy and, therefore, will not issue enforcement action for this violation. These violations were identified during the discretion period described in EGM 11-003, Revision 3, and the licensee met the criteria established in the EGM prior to and during these activities. |
| 05000325/FIN-2018002-01 | 2018Q2 | Brunswick | Automatic Reactor Trip due to Perceived Loss of Stator Cooling Water | A self-revealing Green finding (FIN) was identified for the failure to properly implement a modification to the turbine control system (TCS). The modification ultimately resulted in an automatic reactor trip on April 7, 2018, due to a turbine trip caused by a perceived loss of stator cooling water. The TCS system improperly generated a loss of stator cooling turbine trip when the TCS measured higher than expected stator cooling water flow rates |
| 05000324/FIN-2018001-01 | 2018Q1 | Brunswick | Inadequate Instruction to Perform Inspections on Emergency Ventilation Dampers | A self-revealing Green NCV of TS 5.4.1a, Procedures, was identified when the licensee failed to properly provide adequate work instructions associated with the control room emergency damper inspections. Specifically, the licensee disconnected the damper air supply line without adequate work instruction guidance, which caused a loss of Control Building Heating, Ventilation and Air Conditioning (HVAC) and Control Room Emergency Ventilation (CREV) Systems resulting in a safety system functional failure. |
| 05000324/FIN-2017004-01 | 2017Q4 | Brunswick | Loss of Emergency 4160V Bus Due to Failure to Implement Procedure | A self-revealing non-cited violation (NCV) was identified for the licensees failure to properly transfer power to the E-4 4160 volt emergency bus from the E-4 emergency diesel generator (EDG), to the normal switchgear bus 2C, as required by procedure 0OP-50.1 Diesel Generator Emergency Power System Operating Procedure. This resulted in a momentary under voltage condition followed by a re-energization of the E-4 emergency bus by EDG-4. This was entered into the licensees corrective action program (CAP) as nuclear condition report (NCR) 2151329.The licensees failure to parallel across (i.e., reclose) the normal feeder breakers prior to unloading the EDG-4 and opening the EDG-4 output breaker, which resulted in a valid and automatic actuation of the EDG-4, was a performance deficiency. The finding was determined to be greater than minor because it was associated with the human performance attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during power operations. Using IMC 0609.04, Initial Characterization of Findings, Exhibit 1, the issue was classified as a transient initiator contributor because it was associated with a loss of offsite power (LOOP). Finally, using Appendix A of IMC 0609, SDP for Findings at-Power, the finding was determined to be of very low safety significance (Green) because it did not contribute to both the likelihood of a reactor trip and the likelihood that mitigating systems would not be available. Using Manual Chapter 0310, Aspects Within the Cross-Cutting Areas, the inspectors identified a cross-cutting aspect in the procedural adherence of the human performance area, because the operators failed to properly utilize an existing procedure pertinent to their particular situation and this directly resulted in the momentary loss of an emergency 4160 volt bus. (H.8) |
| 05000324/FIN-2017004-02 | 2017Q4 | Brunswick | Licensee-Identified Violation | The following violation of very low safety significance (Green) was identified by the licensee and is a violation of NRC requirements which met the criteria of the NRC Enforcement Policy, for being dispositioned as a NCV. Unit 1 and Unit 2 facility operating license DPR-71 and DPR-62 condition 2.B.(6)requires, in part, that the licensee shall implement and maintain in effect all provisions of the approved fire protection program. Procedure AD-EG-ALL-1522, Duties of a Fire Watch, requires periodic fire watches to be performed within their designated time periods including any allowed grace periods. Contrary to the above, during the spring 2017 Unit 2 refueling outage, between March 1 and March 19, selected periodic fire watches were missed or not performed within the required grace periods. The finding was screened using IMC 0609, Appendix F Fire Protection Significance Determination Process, and was determined to be of very low safety significance (Green), because the reactor was able to reach and maintain safe shutdown. This issue was documented in the licensees CAP as NCR 2115035. |
| 05000324/FIN-2017003-01 | 2017Q3 | Brunswick | Licensee-Identified Violation | 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, states in part that activities affecting quality shall be accomplished in accordance with these instructions, procedures, or drawings. Contrary to the above, from August 2015 until April 2017, Unit 2 SRV pilot valves did not incorporate precision grinding to remove micro -cracking layer as described in licensee procedure OCM -VSR509 , Main Steam Relief Valves Target Rock Model 7567 Air Operators and Pilot Assembly, Disassembly , Inspection, and Reassembly. This resulted in 3 of the 11 SRVs being out of tolerance. Since less than 10 SRVs were operable, Unit 2 operation was prohibited by TS 3.4.3. The licensee took corrective action to replace all of the pilot valves with the correct surface finish. This violation was determined to be of very low safety significance (Green) because the violation did not represent a loss of safety function since this condition was supported by the Brunswick Unit 2 Cycle 22 Reload Safe ty Analysis. Specifically, the analysis concluded that with at least five total SRVs operable, the overpressure safety function would not be challenged. The licensee entered this issue into their CAP as CR 2129416. |
| 05000327/FIN-2017002-02 | 2017Q2 | Sequoyah | Licensee-Identified Violation | Unit 1 and Unit 2 facility technical specifications LCO 3.6.10 required two operable EGTS systems in Modes 1 through 4. Contrary to the above, on August 2, 2016,during a system review, plant engineers noted a design flaw that could have resulted in one train of EGTS being rendered inoperable since initial plant operation. This problem was entered into the licensees CAP as CR 1198440 and CR 1200028. The TVA probabilistic risk assessment model does not consider the EGTS in core damage and large early release frequencies. The EGTS system is designed to maintain the shield building at a negative pressure and filter any leakage past the steel liner during a design basis event. With the EGTS inoperable, dose would still remain below 10 CFR 100 limits. The finding was screened using IMC 0609, Appendix A At Power Operation, and was determined to be of very low safety significance (Green). According to Exhibit 3, an issue related to degradation of the radiological barrier function of the reactor building is considered to be of very low safety significance. |
| 05000327/FIN-2017002-01 | 2017Q2 | Sequoyah | Licensee-Identified Violation | Unit 1 and Unit 2 technical specifications LCO 3.7.10 required that if both trains of CREVS become inoperable than LCO 3.0.3 shall be immediately entered. Additionally, LCO 3.0.3 requires both units to be placed in Mode 3 within seven hours if the condition was not rectified. Contrary to the above, on August 10, with both trains of CREVS rendered inoperable, both units remained in Mode 1 for a period of approximately 24 hours. The finding was entered into the licensees CAP as CR 1201905. This finding was assessed using NRC Inspection Manual Chapter (IMC) 0609, Attachment 4, and was determined to be of very low safety significance (Green) due to the finding only representing a degradation of the radiological barrier function provided for the control room. |
| 05000327/FIN-2017001-01 | 2017Q1 | Sequoyah | Degraded Fire Barrier Penetration | Green . The NRC identified a non -cited violation ( NCV ) of the facilitys operating license for the failure to identify a non functional fire barrier penetration and enter it into the corrective action program (CAP) when the initial damage to the fire barrier occurred. The licensee also failed to implement required compensatory measures for a nonfunctional fire barrier penetration contrary to the approved fire protection report . The licensee entered the issues into their CAP as Condition Report (CR) 1263322 . The performance deficiency was determined to be more than minor because it was associated with the protection against external events (fire) attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective in that there was no assurance the fire barrier would prevent the spread of fire through the cable penetration during a design basis fire. The finding was of very low safety significance (Green) due to fully functional automatic suppression systems on either side of the fire barrier . T he inspectors identified a cross- cutting aspect in the identification component of the Problem Identification and Resolution area because the licensee failed to enter the damaged fire barrier into their CAP after it was initially damaged . (P.1) |
| 05000327/FIN-2016004-01 | 2016Q4 | Sequoyah | Degraded Fire Barrier Penetrations | Green. The NRC identified a non-cited violation (NCV) of the facilitys operating license for the licensees failure to ensure that all fire barrier penetrations in fire zones boundaries protecting safety related areas are functional at all times. Specifically, on eight separate fire barrier penetrations, the licensee failed to recognize that the barrier had become damaged to the point of being nonfunctional. The licensee also failed to implement required compensatory measures for a nonfunctional fire barrier penetration contrary to the approved fire protection report (FPR). The licensee entered the issues into their corrective action program (CAP) as Condition Reports (CRs) 1229468, 1229470, 1243550, 1243970, 1243552, 1243554, 1243555, and 1243557. The performance deficiency was determined to be more than minor because it was associated with the protection against external events (fire) attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, with the fire barriers being damaged to the point of declaring the fire barrier penetrations nonfunctional, there was no assurance that the fire barrier would prevent the spread of fire through the cable penetration during a design basis fire. The inspectors performed the SDP using NRC Inspection Manual Chapter 0609, Significance Determination Process, Appendix F, Attachment 2, Degradation Rating Guidance Specific to Various Fire Protection Program Elements, and assigned a High degradation rating, giving no credit for Barrier Protection in accordance with the Fire Barrier Degradation section. The inspectors concluded, that the finding was of very low safety significance (Green) due to fully functional automatic suppression systems on either side of the fire barrier (Question 1.4.3-C). Using Manual Chapter 0310, Aspects Within the Cross-Cutting Areas, the inspectors identified a cross-cutting aspect in the Identification component of the Problem Identification and Resolution area, because the licensee failed to enter the damaged fire barrier into their CAP after it was initially damaged (P.1) |
| 05000327/FIN-2016003-01 | 2016Q3 | Sequoyah | Hydrogen Mitigation System Inoperable Longer than Allowed by Technical Specifications | A self-revealing NCV of Technical Specification 3.6.8, Hydrogen Mitigation System (HMS), was identified for the licensees failure to restore an inoperable train of HMS within the 7 day completion time or place the unit in Mode 3 within the action time of 6 hours. Each train of HMS has 34 hydrogen igniters and SR 3.6.8.1 defines an operable train as one that has at least 33 igniters operable. A review of the operating history revealed the A train HMS had only 31 operable igniters for a period of 91 days due to a mispositioned circuit breaker. Upon discovery of the unexpected condition, the circuit breaker was closed to restore operability to the HMS train. The licensee entered the issue into their CAP as CR 1179126. The licensees failure to preclude an inoperable HMS train for more than 7 days without a subsequent plant shutdown was a performance deficiency. The performance deficiency was more than minor because it was associated with the Configuration Control attribute of Barrier Integrity cornerstone and adversely affected the cornerstones objective to ensure the structural integrity of the containment boundary. Specifically, the finding challenged containment integrity as hydrogen igniters have a high risk significance in ice condenser style containments. The finding was screened to Green based on the fact that the loss of igniters did not affect multiple igniters in adjacent compartments. The inspectors determined that the finding had a cross cutting aspect of Avoid Complacency within the Human Performance area because the licensee failed to implement appropriate error reduction tools while working near the HMS circuit breakers (H.12). |
| 05000327/FIN-2016003-02 | 2016Q3 | Sequoyah | Isolation of Fire Suppression System to a Significant Portion of the Plant Site | A self-revealing non-cited violation (NCV) of the facility operating licenses DPR-77 and DPR-79 conditions 2.C.(16) and 2.C.(13), respectively, was identified for the licensees failure to properly implement the clearance process such that the fire suppression system was rendered non-functional for approximately 41 hours. The licensee inappropriately expanded an existing clearance on March 29, 2016 in order to attempt to reduce boundary valve leakage affecting existing maintenance on the fire suppression system within a valve pit. Subsequently on March 30, 2016 during fire system testing, technicians noted a lack of system pressure and it was ultimately concluded the clearance expansion had inadvertently isolated fire suppression water to a significant portion of the site. Upon discovery of the clearance error, the system was restored to a functional status. The licensee entered the issue into their corrective action program (CAP) as CR 1155763. The licensees failure to properly assess the system impact of a clearance revision for the High Pressure Fire Protection (HPFP) suppression header and enter the required FPR Operating Requirement (FOR) Action was a performance deficiency. The performance deficiency was more than minor because it was associated with the protection against external events (fire) attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inability to pressurize the HPFP system from either the electric or diesel-driven fire pumps rendered the fire suppression system inoperable. Based on the complexities of this particular event, the inspectors concluded that Appendix M, Significance Determination Process Using Qualitative Criteria, of IMC 0609 should be performed in lieu of a Phase 3 analysis. Under appendix M, the Senior Reactor Analyst (SRA) performed an initial bounding evaluation using qualitative methods. The licensee submitted a detailed analysis that estimated an upper bound for the risk of the finding which was less than 1E-6. The SRA performed a review of this screening analysis as part of this SDP evaluation. In addition to the SRA review, the resident inspectors performed an independent review of the licensees estimation of the success of actions used to recover the isolated fire header. To the extent reviewed, the methodology and results were determined to be acceptable for use in this SDP review of this Performance Deficiency. The SRA concurred with the submitted results of the licensees screening analysis, and has determined the finding to be GREEN. The inspectors determined that the finding had a cross cutting aspect of Procedural Adherence within the Human Performance area, because the licensee failed to consider the affect that changing a clearance order could have on the operability of the fire suppression system. |
| 05000327/FIN-2016002-01 | 2016Q2 | Sequoyah | Isolation of Fire Suppression System to a Significant Portion of the Plant Site | A self-revealing apparent violation (AV) of the facility operating licenses DPR-77 and DPR-79 conditions 2.C.(16) and 2.C.(13) was identified for the licensees failure to properly implement the clearance process such that the fire suppression system was rendered non-functional for approximately 48 hours. The licensee inappropriately expanded an existing clearance on March 29 in order to attempt to reduce boundary valve leakage affecting existing maintenance on the fire suppression system within a valve pit. Subsequently, on March 30, during fire system testing, technicians noted a lack of system pressure and it was ultimately concluded the clearance expansion had inadvertently isolated fire suppression water to a significant portion of the site. Upon discovery of the clearance error, the system was restored to a functional status after being isolated for approximately 48 hours. The licensee entered the issue into their corrective action program as condition report (CR) 1155763. The performance deficiency was determined to be more than minor because it was associated with the protection against external events (fire) attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inability to pressurize the high pressure fire protection (HPFP) system from either the electric or diesel-driven fire pumps rendered the fire suppression system inoperable. The finding could not be screened to Green and is pending a significance determination. The inspectors determined that the finding had a cross-cutting aspect of Procedural Adherence within the Human Performance area, because the licensee failed to consider the effect that changing a clearance order could have on the operability of the fire suppression system. (H.8). |
| 05000327/FIN-2016001-01 | 2016Q1 | Sequoyah | Inadequate Application of Flame Retardant on Cable Room Penetrations | The NRC identified a non-cited violation (NCV) of Unit 1 and 2 Technical Specification 5.4.1 for the licensees failure to adequately implement fire protection procedures. Specifically, the inspectors identified several cables located within a cable tray that penetrated the floor of the cable spreading room that were not adequately coating with fire retardant material as required by plant procedures. The licensee placed the issue into the corrective action program (CAP) and implemented a fire watch for the degraded condition. The inspectors determined that the failure to adequately implement all requirements of the licensees fire protection program procedures was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the protection against external events (fire) attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors determined the finding was of very low safety significance (Green) because of the fire protection defense in depth concept provided other barriers to prevent the spread of fires. The cause of this finding was related to the procedural adherence component of the human performance area, because the licensee failed to properly install cable bundles through wall penetrations. |
| 05000327/FIN-2016001-02 | 2016Q1 | Sequoyah | Inadvertent Safety Injection Due to Inadequate Main Steam Procedure | A self-revealing NCV of Units 1 & 2 Technical Specification, 5.4.1 was documented for the licensees failure to implement an adequate procedure associate with the startup of the main steam system. Specifically, the licensee caused an inadvertent safety injection which unnecessarily challenged the operators due to an inadequate draining of the main steam header during system start up. The licensee placed the issue into the CAP. The failure of the licensee to adequately drain condensate from the main steam header resulted in an inadvertent safety injection (SI) and was a performance eficiency. The finding was determined to be greater than minor because it adversely effected the Procedure Quality attribute of the Initiating Events Cornerstone to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. The significance of this finding was evaluated in accordance with the Manual Chapter 0609 Appendix A, The Significance Determination Process for Findings At-Power. Although the unit was in Mode 3 at the time, this appendix was chosen because the plant did not meet the entry conditions for residual heat removal system operation. The inspectors concluded that the finding was of very low safety significance (Green) because no significant initiating event prompted this transient. The finding was determined to have a cross-cutting aspect in the operating experience component of the problem identification and resolution area, because the licensee failed to evaluate and implement relevant internal and external operating experience. |
| 05000327/FIN-2015004-01 | 2015Q4 | Sequoyah | Failure to Recognize and Submit for Approval a Reduction in Effectiveness of the Emergency Plan | The inspectors identified a Severity Level IV Non-cited Violation (NCV) of Title 10 of the Code of Federal Regulations, Part 50.54(q), for changes to the licensees radiological emergency plan, effective December 18, 2014, that reduced the effectiveness of the plan and therefore, should have received NRC approval prior to making the change. Specifically, the effectiveness of TVAs Radiological Emergency Plan (Generic Part), Revision 104, was reduced by the inadvertent removal of the offsite telephone communications description for the Health Physics Network and Emergency Notification System communication tools, as well as the monthly testing of those devices. The licensees failure to recognize that Revision 104 reduced the effectiveness of the emergency plan was a performance deficiency. The licensee entered this issue into their corrective action program (CAP) as Condition Report (CR) 1093684 This finding is more than minor because it brings into question the thoroughness of the licensees review process when making changes to the emergency plan and adversely affects the procedure quality attribute of the emergency preparedness cornerstone objective. This finding is a violation of NRC requirements and because it has the potential for impacting the NRCs ability to perform its regulatory function, traditional enforcement is applicable in accordance with IMC 0612, Appendix B. This finding is determined to be a Severity Level IV violation in accordance with Section 6.6.d.1 of the Enforcement Policy because it involves the licensees ability to meet or implement a regulatory requirement not related to assessment or notification such that the effectiveness of the emergency plan is reduced. |
| 05000327/FIN-2015003-01 | 2015Q3 | Sequoyah | Inadequate Clearance Causes damage to A train SSPS | A self-revealing Green NCV of Unit 1 Technical Specification (TS) 6.8.1.a was identified for the licensees failure to adequately establish a clearance boundary during plant maintenance. Specifically, the licensee caused damage to a safety-related component during maintenance as a result of a failure to de-energize all electrical sources during maintenance troubleshooting activities. The licensee placed the issue into their corrective action program (CAP) and corrected the identified deficiencies. The inspectors determined that the failure to adequately implement clearance procedures was a performance deficiency. The inspectors determined that the performance deficiency was more than minor because it was associated with the human performance attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors determined the finding was of very low safety significance (Green) as the affected safety significant component was repaired within 24 hours. The cause of this finding was related to the cross-cutting aspect of leaders ensuring that personnel, equipment, procedures, and other resources were available and adequate to support nuclear safety. |
| 05000327/FIN-2015003-02 | 2015Q3 | Sequoyah | Failure to Implement Work Risk Activity and Oversight of Supplemental Personnel Procedures | A self-revealing Green NCV of TS 6.8.1.a, Administrative Controls of Procedures and Programs, was identified for the licensees failure to implement procedures related to quality during the surveillance capsule relocation activity. Specifically, procedures NPG-SPP-07.3, Work Activity Risk Management, and NPG-SPP.07.7, NPG TCM Role and Oversight of Supplemental Personnel, were not appropriately implemented. The deficiency was entered into the licensees CAP as Problem Evaluation Report (PER) 1016839. This finding was determined to be greater than minor because it was associated with the Human Performance attribute of the Barrier Integrity Cornerstone, 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. Specifically, the performance deficiency resulted in the failure to properly secure reactor vessel surveillance capsules and the subsequent damage to the reactor vessel pressure boundary, reactor internals and fuel filter screens. The proper higher risk categorization would have led to enhanced contractor oversight, and the ability to detect when the contractors were performing actions outside the approved procedure. These additional oversights would reasonably be expected to prevent the events that led to the surveillance capsule ejections, and eliminate any potential to cause damage to the reactor vessel pressure boundary, reactor internals, and fuel filter screens. The inspectors identified a cross-cutting aspect in the Human Performance Consistent Process cross-cutting area. Specifically, the licensee failed to consistently incorporate risk insights, as required by procedure NPG-SPP-07.3, which resulted in less than conservative classification for an infrequently performed activity inside the reactor vessel performed by contract personnel. |
| 05000328/FIN-2015002-01 | 2015Q2 | Sequoyah | Failure to Adequately Follow Foreign Material Control Procedures | A self-revealing NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, was identified for the licensees failure to follow a foreign material exclusion procedure and precluded foreign material from entering the safetyrelated Essential Raw Cooling Water (ERCW) system. This resulted in wood debris within the ERCW that ultimately migrated to the 2B2 emergency diesel heat exchanger. Immediate corrective actions included removal of the foreign material and the performance of an engineering analysis to ensure the wood debris did not affect the system operability. The licensee placed this issue into their corrective action program as CR 1033792. The performance deficiency was determined to be more than minor because it was associated with the human performance attribute of the mitigating systems cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the performance deficiency allowed a piece of wood to enter into the 2B2 emergency diesel heat exchanger blocking 11 tubes. Because the finding was a deficiency affecting the design of a mitigating structure, systems, or components (SSCs) that was confirmed not to have resulted in the loss of operability, it was determined to be of very low safety significance (Green). The inspectors determined that no cross-cutting aspect will be assigned to this performance deficiency since it occurred in 2008 and is therefore not indicative of current licensee performance. |
| 05000327/FIN-2015002-03 | 2015Q2 | Sequoyah | Licensee-Identified Violation | Unit 1 Technical Specifications Section 3.3.1.1 requires two channels of intermediate range nuclear instrumentation in Mode 2 to provide the input to the P-6 interlock. This interlock allows the operator to block the source range channels during a reactor startup. This is done to prevent damage to the detectors as power is elevated to levels that could damage the detector. Contrary to the above, between March 11 and March 27, the P6 interlock was inoperable due to a non-conservative bias, concurrent with Unit 1 being in Mode 2 on March 14 from 0558 to 1010. This problem was entered into the licensees corrective action program as CR 1005422. The finding was screened using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process for Findings At-Power, and was determined to be of very low safety significance (Green). |
| 05000327/FIN-2015002-02 | 2015Q2 | Sequoyah | Spilled Specimen Capsule | The inspectors identified an unresolved item (URI) associated with the control of specimen capsules inside the reactor vessel. During this refueling outage, the licensee noted that two specimen capsules had become dislodged from their location on the core barrel. This particular outage required a 10 year ISI inspection and the core barrel was removed as part of the outage plan. The two capsules were noted to have been moved during the last refueling outage. A formal root cause evaluation was performed. The root cause team included industry experts independent of the licensee organization. The root cause team noted several procedural violations during the previous capsule move. The team concluded that these significant errors led to the improper seating of the capsules in the specimen baskets and ultimately allowed the capsules to dislodge from the core barrel. A significant foreign object retrieval evolution was completed during the outage and the core barrel, lower internals, and lower vessel head were inspected by the licensee and the NRC. The specimen parts were collected and placed in storage containers and transferred to the spent fuel pool. The unit was restarted on May 15 without a full accountability of the specimen parts. The inspectors determined that more inspection of this issue is required in order to understand all aspects of the incident. This issue will be tracked as URI 05000327/2015002-02, Spilled Specimen Capsule. |
| 05000327/FIN-2015001-01 | 2015Q1 | Sequoyah | Failure to Follow Procedure Results in an Inadvertent Sprinkler Deluge in the Cable Spreading Room | A self-revealing Green non-cited violation (NCV) of Technical Specification (TS) 6.8.1.f, Fire Protection Program Implementation, was identified for the licensees failure to follow a fire protection procedure. Specifically, the licensee failed to isolate the fire main from the cable spreading room (CSR) header during testing as required by procedure. This resulted in pressurization of the fire header to the cable spreading room which then caused a rupture of one of the sprinkler heads in the room. The licensee entered this issue into their corrective action program (CAP) as problem evaluation report (PER) 1001695. As immediate corrective actions, the licensee replaced the failed sprinkler head and conducted a formal review of the incident. The finding was determined to be more than minor because it was associated with the human performance attribute of the initiating events cornerstone and affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the excessive amount of water sprayed in the CSR increased the likelihood of a plant transient due to the potential impact on non-waterproof junction boxes located in the CSR as well as safety-related instrument racks located in the auxiliary instrument room (AIR) directly below the CSR. Using Appendix A, Exhibit 1, Initiating Events Screening Questions, the finding was determined to be of very low safety significance because the deficiency did not cause a reactor trip nor a loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. The finding was determined to have a cross-cutting aspect in the avoid complacency component of the human performance area (H.12), because the technicians failed to properly implement appropriate error reduction techniques while performing a fire protection procedure. |
| 05000327/FIN-2014005-01 | 2014Q4 | Sequoyah | Licensee-Identified Violation | Licensee Event Report (LER 2-2014-001-00) was submitted following the licensees discovery that Sequoyah Unit 2 operated in a condition prohibited by Technical Specifications (TS). During mode 1 operation, train B containment purge had been operated without the minimum required operable radiation monitoring channels. TS Limiting Condition for Operation (LCO) 3.3.3.1 and TS LCO 3.3.2 required with less than the minimum channels operable, plant operation may continue provided the containment purge supply and exhaust valves are maintained closed. Contrary to the above during plant operations from April 8 and April 28, 2014, train B containment purge supply and exhaust valves were opened to place purge in service three times with containment purge air exhaust radiation monitors (SQN-2-RM-090-130 and SQN-2-RM-090-131) being incorrectly aligned to train A purge. This was licensee identified and entered into the CAP as PER 878321. The finding was screened using Inspection Manual Chapter (IMC) 0609, Significance Determination Process, Appendix A, The Significance Determination Process (SDP) For Findings At-Power, Exhibit 3 Barrier Integrity Screening Questions and determined the finding to be of very low safety significance (Green) because it does not represent an actual open pathway in the physical integrity of reactor containment, containment isolation system, and heat removal components, or involve an actual reduction in function of hydrogen igniters. |
| 05000259/FIN-2014004-02 | 2014Q3 | Browns Ferry | Inappropriate Amendment of License Conditions | The NRC identified a Severity Level IV (SL-IV) NCV of 10 CFR 50.90, Application for amendment of license, construction permit, or early site permit, and an associated Green NCV of Technical Specification (TS) 3.8.7 Distribution System Operating for the licensees failure to obtain a license amendment prior to implementing changes to the Technical Requirements Manual (TRM) that affected TS 3.8.7 for Units 1, 2, and 3. Specifically, the addition of TRM 3.7.6, Electric Board Room (EBR) Air Conditioning (AC) system resulted in a violation of T.S. 3.8.7 Distribution- Operating for the C and D 4kV shutdown boards (supported by the Unit 2 EBR AC system) being inoperable in mode 1 for longer than the allowed outage time and the action statement not complied with. The licensees immediate corrective action was to issue administrative guidance to operators for the determination of operability of the 4kV shutdown boards with the Electric Board Room air conditioning system inoperable and initiate actions to submit a TS amendment request as documented in PER 846040. The performance deficiency was more than minor because it adversely affected the mitigating systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the performance deficiency resulted in the licensee not declaring Unit 1 and 2 4kV shutdown boards inoperable and taking actions required by TS 3.8.7 action statement E on multiple occasions. The finding was screened using IMC 0609 Appendix A Exhibit 2, dated June 19, 2012, and was determined to be of very low safety significance (Green) because the finding did not represent an actual loss of function of one or more non-Tech Spec Trains of equipment designated as high safetysignificant in accordance with the licensees maintenance rule program for >24 hrs. The violation was determined to be a Severity Level IV violation using the Enforcement Policy example 6.1.d.2, because it resulted in a condition having a very low safety significance. No cross cutting aspect was assigned in association with the ROP finding because the change to the TRM was performed greater than three years ago and did not reflect current licensee performance. |
| 05000327/FIN-2014004-02 | 2014Q3 | Sequoyah | Licensee-Identified Violation | Unit 1 SR 4.7.3.b requires in part that at least once per 18 months, each CCS pump start automatically on a SIS signal. Contrary to the above, the C-S (swing) CCS pump was never tested to automatically start using a Unit 1 SIS signal. The licensee considered this to be a never performed surveillance rather than simply a missed surveillance since no testing records since initial operation in 1980 could be located. The pump had been successfully tested every 18 months from the Unit 2 SIS as this pump is normally powered from Unit 2. As an alternate and abnormal lineup, the pump could be powered from Unit 1 and thus the requirement for start testing using the Unit 1 SIS. This finding was considered more than minor because it was associated with the mitigating system cornerstone and affected the cornerstones reliability due to the failure to fully test the CS CCS pump for over 30 years. The finding was considered of very low safety significance as it remained operable and available during the affected period due to successfully passing the initial surveillance test performed on January 13, 2014. The issue was entered into the CAP as PER 826482. Note that this issue is also discussed under Section 4OA3 of this report as it involved a LER. |
| 05000327/FIN-2014004-03 | 2014Q3 | Sequoyah | Licensee-Identified Violation | TS 3.9.4.c requires in part that during fuel movement, all containment penetrations shall be closed or capable of being closed by an automatic valve. In addition, TS 3.9.4.c allows exceptions to this requirement for penetrations that traverse to the auxiliary building secondary containment enclosure (ABSCE) where these penetrations may be open under administrative controls during fuel movement. Contrary to the above, on several instances between 2000 and 2014, the licensee opened penetrations (between containment and ABSCE) during fuel movement without adequate administrative controls in place. The finding was considered more than minor because it was associated with the Barrier Integrity cornerstone and affected the cornerstones ability to preserve the containment boundary. The inspectors determined that, although the finding involved a violation of the containment control, TS 3.9.4, the finding did not: 1) involve a loss of reactor coolant system (RCS) inventory; 2) degrade ability to terminate a leak path or add RCS inventory as needed; or 3) degrade the ability to recover RHR once it was lost. Therefore, according Appendix G, the finding did not require a quantitative (phase 2 or 3) analysis. Findings in the shut-down condition that do not require a quantitative analysis are considered to be of very low safety significance (Green). This issue was entered into the CAP as PER 886970. Note that this issue is also discussed under Section 4OA3 of this report as it involved a LER. |
| 05000259/FIN-2014004-01 | 2014Q3 | Browns Ferry | Failure to maintain Fire Doors in their Rated Configuration | The NRC identified a Green non-cited violation (NCV) of Browns Ferry Operating License Conditions 2.C for the licensees failure to maintain fire doors in their rated configuration required by the Fire Protection Report. Specifically, the licensee failed to ensure that fire doors 497, 501, and 506, for Units 1, 2, and 3 respectively, were latched closed as required for the doors to meet their designed fire rating. The licensee entered this issue in the CAP as PER 921571 and initiated corrective actions to replace the degraded fire doors. The inspectors determined that the licensees failure to maintain fire doors 501, 506 and 497 in their rated configuration as required by the Browns Ferry Nuclear Plant Fire Protection Report was a performance deficiency. The finding was more than minor because it was associated with the protection against external factors (fires) attribute of the mitigating systems cornerstone and affected the objective to maintain the reliability and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, failure to ensure fire doors were closed and latched could have resulted in the door opening during a fire, thereby allowing a fire to affect additional equipment important to safety in the exposed fire zone. The finding was screened in accordance with IMC 0609, Appendix F, Fire Protection Significance Determination Process (SDP), issued September 20, 2013. The inspectors conducted a Phase I SDP screening utilizing Figure F.1 in Appendix F. Per the Phase I screening criteria, the finding was assigned the category of Fire Confinement. The inspectors assigned a Moderate Degradation Rating to the fire barrier door in accordance with Attachment 2 of Appendix F, because the latching mechanism for the door was non-functional. In accordance with Appendix F, Supplemental Screening for Fire Confinement Findings, task 1.4.2, this finding screened as very low safety significance (Green) because the there was a fully functional automatic suppression system on either side of the fire barrier. The cause of this finding was directly related to the aspect of trending in the problem identification and resolution cross-cutting area. Specifically, over the past several years the licensee documented multiple examples of fire doors failing to consistently latch, in the CAP. The licensee failed to analyze this information in the aggregate to identify and correct the issue (P.4). |
| 05000259/FIN-2014004-03 | 2014Q3 | Browns Ferry | TRM Allowances for Electric Board Room Air Conditioning Units conflicting with Technical Specifications | The NRC identified a Severity Level IV (SL-IV) NCV of 10 CFR 50.90, Application for amendment of license, construction permit, or early site permit, and an associated Green NCV of Technical Specification (TS) 3.8.7 Distribution System Operating for the licensees failure to obtain a license amendment prior to implementing changes to the Technical Requirements Manual (TRM) that affected TS 3.8.7 for Units 1, 2, and 3. Specifically, the addition of TRM 3.7.6, Electric Board Room (EBR) Air Conditioning (AC) system resulted in a violation of T.S. 3.8.7 Distribution- Operating for the C and D 4kV shutdown boards (supported by the Unit 2 EBR AC system) being inoperable in mode 1 for longer than the allowed outage time and the action statement not complied with. The licensees immediate corrective action was to issue administrative guidance to operators for the determination of operability of the 4kV shutdown boards with the Electric Board Room air conditioning system inoperable and initiate actions to submit a TS amendment request as documented in PER 846040. The performance deficiency was more than minor because it adversely affected the mitigating systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the performance deficiency resulted in the licensee not declaring Unit 1 and 2 4kV shutdown boards inoperable and taking actions required by TS 3.8.7 action statement E on multiple occasions. The finding was screened using IMC 0609 Appendix A Exhibit 2, dated June 19, 2012, and was determined to be of very low safety significance (Green) because the finding did not represent an actual loss of function of one or more non-Tech Spec Trains of equipment designated as high safetysignificant in accordance with the licensees maintenance rule program for >24 hrs. The violation was determined to be a Severity Level IV violation using the Enforcement Policy example 6.1.d.2, because it resulted in a condition having a very low safety significance. No cross cutting aspect was assigned in association with the ROP finding because the change to the TRM was performed greater than three years ago and did not reflect current licensee performance. |
| 05000259/FIN-2014004-04 | 2014Q3 | Browns Ferry | Inadequate NPSH Calculations for Standby Liquid Control Pumps | The NRC identified a Green non-cited violation (NCV) of 10 CFR Part 50 Appendix B, Criterion III, Design Control, for the licensees failure to maintain adequat control measures for verifying or checking the adequacy of design of the Standby Liqui Control (SLC) system. Specifically, the licensees calculations and system testing wer both inadequate to demonstrate that the SLC system could meet design requirement under all required operating conditions. The licensee entered this in their CAP as PE 920418 and initiated corrective actions to perform a modification to the SLC system an update design calculations. The inspectors determined that the licensees failure to maintain adequate control measures for verifying or checking the adequacy of design of the SLC system as required by 10 CFR 50, Appendix B, Criterion III, Design Control, was a performance deficiency (PD). Specifically, the licensees calculations and system testing were both inadequate to demonstrate that the SLC system could meet design requirements under all required operating conditions. The PD was more than minor because it affected 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, there was not an adequate method for ensuring the capability of the design of the SLC system following a design basis accident. The inspectors screened this finding in accordance with IMC 0609, Appendix A, Significance Determination Process, Exhibit 2-Mitigating Systems Screening Questions, dated June 19, 2012, and determined the finding was of very low safety significance (Green) because the design deficiency did not result in a loss of operability or functionality. The inspectors determined that no cross cutting aspect was applicable because this finding was not indicative of current licensee performance and occurred more than three years ago. |
| 05000259/FIN-2014004-05 | 2014Q3 | Browns Ferry | Licensee-Identified Violation | Technical Specification 3.8.1 required in part, that if one Emergency Diesel Generator becomes inoperable that it be restored to service within seven days. Contrary to Technical Specification 3.8.1, the EDG A was determined to be inoperable from March 5, 2013, until November 23, 2013. The inoperability was due to a 100 drop per minute fuel oil leak on the engine driven fuel oil pump that was discovered during a scheduled 24 hour surveillance run. The fuel oil leak was subsequently repaired and retested with the issue being documented in the licensees CAP as PER 822199. This finding was determined to be of very low safety significance using IMC 0609 Appendix A Exhibit 2 because the EDG remained capable of meeting its design function due to a redundant motor drive fuel oil pump being available. |
| 05000328/FIN-2014004-01 | 2014Q3 | Sequoyah | Failure to Perform Adequate Maintenance on Containment Vacuum Relief Valve | A Self-revealing Green Non-Cited Violation (NCV) of Technical Specification (TS) 6.8.1.a. was identified for the licensees failure to adequately implement a maintenance procedure associated with a vacuum relief containment isolation valve. Specifically, during a refueling outage on May 24, 2014, the licensee failed to properly install a locking wire associated with the spring tension bolts on the Unit 2 containment vacuum relief valve. This error ultimately led to a failure of the valve on June 24 at 1600 and entry into TS 3.6.3, Containment Isolation Valves. The valve was ultimately repaired and the valve was declared operable on June 26 at 0026. The inspectors determined that the licensees failure to adequately develop and implement a procedure governing the maintenance of a containment isolation valve was a performance deficiency. This finding was determined to be greater than minor because it was associated with the Configuration Control attribute of Barrier Integrity cornerstone and adversely affected the cornerstones objective to ensure the structural integrity of the containment boundary. Specifically, the finding challenged containment integrity. A screening analysis was conducted using the assumption that all core damage sequences would lead to a Large Early Release. This was an overestimation of risk, since actions to mitigate a release were possible. The short exposure time multiplied by the Core Damage Frequency for the plant resulted in less than a 1E-7 increase in Large Early Release Probability, and the finding is Green. The cause of this finding was determined to have a cross-cutting aspect in the Human Performance component, relating to the assurance by supervision that procedures are adequate to ensure nuclear safety. (H.1). |
| 05000327/FIN-2014003-01 | 2014Q2 | Sequoyah | Failure to Perform Visual Examination of the Unit 1 and Unit 2 CRDM Seismic Plate Supports | An NRC-identified Green non-cited violation (NCV) of 10 CFR 50.55a(g)(4), Inservice Inspection Requirements was identified for the licensees failure to perform visual examinations of the control rod drive mechanism (CRDM), American Society of Mechanical Engineers (ASME) Class 1, seismic plate supports as required by the ASME Code, Section XI. The licensee entered this issue into their corrective action program (CAP) as Problem Evaluation Report (PER) 889400. The licensee developed an operability evaluation and concluded that the supports remained functional. The licensee also initiated corrective actions to perform the required visual examinations of the CRDM seismic plate supports before the end of the current inservice inspection (ISI) interval in April 2016. The finding was more than minor because it was associated with the protection against external factors attribute of the mitigating systems cornerstone, and affected the cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequence. The inspectors screened this finding as Green because the finding did not involve the loss or degradation of equipment or function specifically designed to mitigate a seismic initiating event. A crosscutting aspect was not assigned to this finding in accordance with IMC 0612, Appendix B, because the exclusion of the CRDM seismic plate supports from the scope of the ISI Program occurred outside of the nominal 3-year period for present performance, and therefore it was not reflective of present licensee performance. |
| 05000259/FIN-2014003-02 | 2014Q2 | Browns Ferry | TRM Allowances Conflicting with Technical Specifications | Introduction: The inspectors identified an URI for Technical Requirements Manual (TRM) allowances that conflict with the supported system requirements to maintain equipment operability as described in technical specifications (TS). Description: On July 14, 1998, Browns Ferry received approval to use the Improved Technical Specifications (NUREG-1433) and develop a TRM by license amendment number 232 (Unit 1), 253 (Unit 2), and 212 (Unit 3) (ML020040291). The Browns Ferry Technical Specifications, Section 1.0, "Definitions," stated, in part, A system, subsystem, division, component, or device shall be operable when all necessary attendant instrumentation, controls, cooling, and other auxiliary equipment required for the component to perform its specified safety function are also capable of performing their related support function(s). The TRM is a licensee controlled document to control safety related equipment not covered by technical specifications (10CFR50.36) including: Reactor Zone Isolation Timers (TRM 3.3.2.2); Refuel Zone Isolation Timers (TRM 3.3.2.3); Low Pressure ECCS Area Cooler Instrumentation (TRM 3.3.3.2); EECW Pump Timers (TRM 3.3.3.7); Drywell Control Air System (TRM 3.6.3); and Electric Board Room Air Conditioning System (TRM 3.7.6). These TRMs, as written, potentially allowed the aforementioned attendant systems to become non-functional without causing the supported TS equipment to be declared inoperable. The licensee initiated PERs 846040 and 877729 to investigate and analyze these issues of concern. URI 05000259, 260, 296/2014-003-02, TRM Allowances Conflicting with Technical Specifications, is opened pending completion of licensee analysis and NRC inspection of this issue of concern to determine if a more than minor performance deficiency or violation exists. |
| 05000327/FIN-2014003-02 | 2014Q2 | Sequoyah | Failure to Comply with Entry requirements to a HRA | The inspectors identified a Green, self-revealing, NCV of Technical Specification (TS) 6.12.1, High Radiation Area, for two examples where workers made entries into High Radiation Areas (HRA) on May 16, 2014, without meeting the entry requirements specified therein. Specifically, these workers, while performing decontamination activities and moving materials in the upper reactor containment, entered a posted HRA: 1) without knowledge of the current radiological conditions in the actual work area, 2) not using a radiological work permit (RWP) approved for HRA entry, and 3) without wearing the prescribed electronic dosimetry for an HRA. The licensee entered these events into the Corrective Action Program (CAP) as Problem Evaluation Reports (PERs) Numbers 886668 and 886160. Immediate corrective actions included restricting worker access to the Radiologically Controlled Area (RCA) and issuance of communications to the site and within the Radiation Protection organization to reinforce roles in RWP adherence and access control. This finding was more than minor because it is associated with the Occupational Radiation Safety Cornerstone attribute of Human Performance and adversely affects the cornerstone objective of ensuring adequate protection of worker health and safety from exposure to radiation from radioactive material during routine civilian nuclear reactor operation. The finding was not related to As Low As Reasonably Achievable planning, nor did it involve an overexposure or substantial potential for overexposure and the ability to assess dose was not compromised. Therefore, the finding was determined to be of very low safety significance (Green). This finding involved the cross-cutting aspect of Human Performance, Avoid Complacency (H.12) because workers failed to apply appropriate error reduction tools during participation in the pre-job brief and prior to crossing the HRA boundaries. |
| 05000327/FIN-2014002-03 | 2014Q1 | Sequoyah | Licensee-Identified Violation | Failure to perform adequate post maintenance testing of the 1B EDG 10 CFR 50, Criterion XI, Test Control requires in part that an established testing program shall require that all testing of SSCs ensure that the SSC can perform its intended function. Contrary to the above, on February 23, 2014, adequate testing to ensure the EDG air start motors could fulfill their required functions was not performed. An adequate test was not performed until March 16 which was part of an annual testing program. This problem was entered into the licensees corrective action program as PER 859633. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, the finding was determined to be of very low safety significance (Green) because the 1B EDG retained the capability to automatically start despite the improper air hose configuration of the air start motors. |
| 05000327/FIN-2014002-02 | 2014Q1 | Sequoyah | Licensee-Identified Violation | Failure to comply with technical specifications during refueling operations Unit 1 technical specification (TS) 3.3.9.4.c requires that during refueling operations, each penetration providing direct access from the containment atmosphere to the outside atmosphere be closed by a manual valve (if so equipped). Contrary to the above, between October 19 and 22, 2013, there were several instances where a Unit 1 containment penetration, X-108, to the additional equipment building was open (including its associated manual valve) during movement of irradiated fuel. This problem was entered into the licensees corrective action program as PER 800432, 806293, and 824224. Using Inspection Manual Chapter 0609, Appendix G, Shut-down Operations Significance Determination Process dated February 28, 2005 the inspectors determined that, the finding was Green because it did not: 1) involve a loss of reactor coolant system (RCS) inventory; 2) degrade ability to terminate a leak path or add RCS inventory as needed; or 3) degrade the ability to recover RHR once it was lost. This issue is also discussed under Section 4OA3 of this report. |
| 05000327/FIN-2014002-01 | 2014Q1 | Sequoyah | Inadequate Clearance Causes Control Air System Transient | A self-revealing non-cited violation of Units 1 and 2 Technical Specification 6.8.1.a, Administrative Controls (Procedures), was documented for the licensees failure to establish an adequate clearance in preparation for maintenance activities on the B station air compressor. Implementation of this inadequate clearance on February 21, 2014, resulted in a reduction of control air pressure and a plant transient which challenged control room operators. Immediate corrective action was to revise the clearance to establish an adequate boundary. The licensee entered the issue into the corrective action program (CAP) for resolution as PER 850331. The performance deficiency was more than minor because it was associated with the configuration control and human performance attributes of the initiating events cornerstone and adversely affected the cornerstones objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the inadequate clearance caused a plant transient during power operations that without operator action would have resulted in a loss of air operated plant components and ultimately require the operators to trip both units. The finding was determined to be of very low (green) safety significance based on Exhibit 1, Initiating Events Screening Questions, found in Inspection Manual Chapter 0609, Significance Determination Process, Appendix A, Significance Determination Process for Findings At-Power, because the finding did not result in a complete or partial loss of a support system that contributed to the likelihood of, or cause, an initiating event and affected mitigation equipment. The inspectors determined the cause of this finding was associated with a cross cutting aspect of Work Management in the Human Performance area. Specifically, the licensee failed to implement their clearance process such that nuclear safety was the overriding priority. |
| 05000327/FIN-2013005-01 | 2013Q4 | Sequoyah | Unit 1 Train A RHR Containment Suction Valve Failure | A self-revealing non-cited violation of 10 CFR 50 Appendix B, Criterion XVI, Corrective Action, was identified for the licensees failure to promptly correct a condition adverse to quality within a reasonable time. Timely corrective actions were not taken to correct a dual position indication (open and closed lights both illuminated) on the Unit 1 A train residual heat removal (RHR) containment sump suction flow control valve (FCV) 1-FCV-63-72. This licensee entered this issue into the corrective action program as problem evaluation report (PER) 772193 and performed repairs to the valve to restore the system to operable status. This finding was determined to be more than minor because it was associated with the Design Control attribute of the Mitigating Systems cornerstone and adversely affected the cornerstones objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the finding reduced the reliability and capability of the A train RHR system to perform its safety function as designed. The finding required a detailed risk analysis as the A RHR system was inoperable beyond its allowed outage time of 72 hours. The detailed risk analysis concluded that the finding was of very low safety significance (Green). This finding was determined to have a cross-cutting aspect relating to the proper classification, prioritization, and evaluation of operability and reportability of conditions adverse to quality in the Corrective Action component of the Problem Identification and Resolution area. |
| 05000327/FIN-2013004-02 | 2013Q3 | Sequoyah | Failure to Correct a Condition Adverse to Quality | The NRC identified a Green non-cited violation (NCV) of 10CFR50 appendix B, Criterion XVI, for the licensees failure to correct a condition adverse to quality (CAQ) per NPG-SPP-22.302, Corrective Action Program Screening and Oversight. Specifically, in April 2013, an NRC inspector identified that a lack of a vent hole in the 2B RHR pump room flood switch housing was a deficiency previously identified in June 2005 that was not corrected for a period of over seven years. The licensee took immediate corrective action to install the required vent hole. The licensee entered the finding into their corrective action program (CAP) as PER 739142. This finding was determined to be greater than minor because it was associated with the Design Control attribute of Mitigating Systems cornerstone and adversely affected the cornerstones objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the finding reduced the reliability and capability of the 2B RHR pump room flood switch to perform its safety function as designed. Using IMC 0609.04, Initial Characterization of Findings and IMC 0609 Appendix A, Exhibit 4 External Events Screening Questions, the finding screened as very low safety significance (Green) because the finding did not involve the total loss of any safety function, identified by the licensee through a PRA, IPEEE, or similar analysis, that contributes to external event initiated core damage accident sequences. The cause of this finding was determined to have a cross-cutting aspect in the Problem Identification and Resolution area, Corrective Action component, and the aspect of taking appropriate corrective actions in a timely manner because corrective actions were not implemented after over seven years from discovery of the CAQ. |
| 05000327/FIN-2013007-09 | 2013Q3 | Sequoyah | Insufficient EDG Starting Air Pressure Following SBO Coping Period | The team identified an unresolved item (URI) associated with licensee?s capability to meet their station blackout (SBO) mitigation strategy. Specifically, based on the allowable air start check valve leakage and the amount of air used during start attempts of the EDGs, the team found that the licensee did not ensure if adequate starting air pressure would exist to reliably start the EDGs following a SBO. Title 10 CFR 50.2, Definitions, defines a SBO as the complete loss of ac power to the essential and nonessential switchgear buses in a nuclear power plant, concurrent with turbine trip and unavailability of the onsite emergency power system. Essentially, this would involve the loss of the offsite power sources as well as the loss of emergency onsite AC power sources. The licensee is committed to coping with an SBO event for a duration of four hours, after which the licensee will recover AC power. The EDG air start system provides compressed air to start the EDGs. The compressed air is provided by non-safety related air compressors, and is stored in two safety-related air receiver tanks. Receiver tank ?A? is designed to maintain the air between 250 and 300 psig; tank ?B? is designed to maintain between 185 and 200 psig. The EDG air start system is equipped with check valves to maintain the integrity of the safety-related portion of the air start system. The licensee declares the EDG degraded if the receiver tank ?A? is less than 200 psig, due to the inability to meet the five start design basis requirement as described in UFSAR, Section 9.5.6, Diesel Generator Starting System. The EDG is declared inoperable at pressures below 150 psig on receiver ?B? due to the loss of start capability. This is based on the manufacturer?s value at which EDG starting and achieving rated speed and voltage has been demonstrated by testing. The team noted that the leak rate acceptance criterion outlined in procedure 0-PI-SXV- 082-203, Diesel Starting Air Valve Test, was 5 psig/minute for the EDG air start check valves. At this allowable leak rate, the EDG air start pressure could fall below 150 psig within 1 hour after an SBO and completely depressurize the air receiver within 3 hours after an SBO. This would not support the capability of the EDGs to start at the end of the 4-hour SBO coping period. In addition to concerns regarding check valve leak rate acceptance criteria, the team noted that postulated failed start attempts during an SBO event would also adversely impact the amount of air that would be available at the end of the 4- hour coping period. Specifically, in a SBO event, the initial failure of the onsite power sources would be followed by a failure of both onsite EDGs to start. The licensee?s procedures direct operators to attempt to start the EDGs a second time in the first few minutes of the SBO. The first and second start attempts are postulated to be unsuccessful during an SBO. The loss of offsite and onsite emergency ac power would prevent the air start compressors from recharging the tanks after the failed start attempts. Based on allowable check valve leakage and the amount of air used during two failed start attempts of the EDGs, the team found that the licensee did not ensure if adequate starting air pressure would exist to reliably start the EDGs in order to recover from an SBO after the 4 hour coping period. The team also found that the licensee had not developed procedural guidance to provide adequate air pressure to reliably start the EDG in order to recover from a SBO after the 4-hour coping period. The licensee captured these concerns in PER 763335. This issue remains unresolved pending inspector consultation with NRC headquarters technical staff for clarification of the licensee?s current license basis design requirements (with respect to 10 CFR 50.63 compliance), to determine if a performance deficiency exists. This issue is being identified as URI 05000327, 328/2013007-09, Insufficient EDG Starting Air Pressure following SBO Coping Period. |
| 05000327/FIN-2013004-01 | 2013Q3 | Sequoyah | Water Intrusion Into Actuator of Valve 1-FCV-63-72 | An excessive amount of water was noted inside the actuator for 1-FCV-63-72, A train RHR containment sump suction valve, which ultimately rendered the valve inoperable. On August 8, 2013 at 0709, the Unit 1 control room reactor operator noted that valve 1-FCV-63-72 showed dual indication on the control board. This valve is the A train RHR suction valve from the containment sump and is normally closed. The valve was verified locally to be in the closed position. No other activities were noted to cause the valve to open. This valve is only stroked during outages (every 18 months) as it is not readily stroked at power due to the system configuration. The licensee determined there was reasonable assurance to consider the valve operable. However, the position indication for the valve was declared inoperable per the post-accident monitoring (PAM) Technical Specification requirement. This was a 30 day Limiting Condition for Operation (LCO). Subsequently on August 14 at 2315, during a routine quarterly IST valve stroke activity, 1-FCV 74-3 failed to stroke in the closed direction from the main control room (MCR). 1-FCV-74-3 is the A train RHR suction valve from the RWST and is normally open. The valve was immediately declared OOS and the 72 hour ECCS tech specification (3.5.2) action statement was entered. Troubleshooting revealed that the actuator of 1-FCV-63-72 contained water and this valve was declared out-of-service. The water intrusion of 1-FCV-63-72 caused shorting of interlock contacts that in turn affected the operability of 1-FCV-74-3. Repairs were made to both valves and the RHR system was returned to operable status on August 17 at 0559. As of the end of the inspection period, the licensee had not completed its formal root cause. The inspectors determined that more inspection was required in order to fully evaluate this issue. Pending additional information from the licensee such that the failure mode of 1-FCV-63-72 can be evaluated, this item was identified as unresolved item (URI) 050000327/2013004-01, Water Intrusion into Actuator of Valve 1-FCV-63-72. |
| 05000327/FIN-2013004-03 | 2013Q3 | Sequoyah | Licensee-Identified Violation | Unit 1 Technical Specification 3.3.3.5 requires, in part, that the remote shutdown monitoring instrumentation channels shown in Table 3.3-9 shall be operable with readouts displayed external to the control room. With the number of operable remote shutdown monitoring instrumentation channels less than required by Table 3.3-9, restore the inoperable channel(s) to operable status within 7 days, or be in Hot Shutdown within the next 12 hours. One AFW Flow Rate instrumentation channel per steam generator is required per Table 3.3-9. Contrary to the above, on February 26, 2013, the licensee determined that they had two AFW flow indicators (1-FI-3-147C & 1-FI-3-163C) inoperable longer than 7 days. The licensee entered the issue into the corrective action program as PERs 683145, 688013, and 717323. The finding was determined to have very low safety significance (Green) because there was no actual loss of safety system function, and there was no significant increase in the likelihood of a fire. |
| 05000327/FIN-2013003-01 | 2013Q2 | Sequoyah | Lack of a Vent Hole on the 2B RHR Pump Room Flood Sensor | The inspectors identified the lack of a vent hole on the 2B RHR pump room flood level alarm switch protective housing. During a walkdown of the 2B RHR pump room, the inspectors noted that the protective housing that surrounded the room flood sensor, SQN-2-LS-040-0028, had no predrilled vent hole. A visual inspection of several other level sensors located in various other emergency core cooling pump rooms revealed that all sensors had an installed vent hole. A cursory inspection of the housing did not reveal a vent pathway for air. Thus, a rising water level in the room would not necessarily result in a rising level within the protective sensor housing. This non-vented condition could result in an air pocket within the sensors vicinity such that a flooding condition would not be detected by the sensor. A review of the design drawing 47W600-155, detail C155, indicated that a vent hole was required to be installed. Although the sensor protruded slightly (approximately 1/4 inch) below the housing, operability was not ensured. This issue was entered into the CAP as Problem Evaluation Report (PER) 739142. The inspectors also noted that this same condition was noted by an NRC inspector on June 30, 2005 and the corrective action from the associated PER 85204 was to drill a vent hole under work order (WO) #05-777741-000. Pending additional information from the licensee which can provide reasonable assurance that the flood sensor can perform its design function in the non-vented condition, this item was identified as unresolved item (URI) 050000328/2013003-01, Lack of a Vent Hole on the 2B RHR Pump Room Flood Sensor. |
| 05000327/FIN-2013003-03 | 2013Q2 | Sequoyah | Licensee-Identified Violation | Failure to Properly Rig MPC during DCS Campaign 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. Contrary to the above, on May 9, 2013, Dry Cask procedure SQN-DCS-200.1, SQN-Dry Cask Preparations, Revision 20, was not appropriate to the circumstances because it did not contain an appropriate verification step to ensure that the slings and shackles were properly aligned for the lift or connected to the proper lifting lugs or lift points. Specifically, during Dry Cask Campaign 8, an empty MPC was lifted with one of four shackles connected to an unapproved lift eye on the internal canister basket instead of 21 Enclosure the approved shell lifting lug as the other three were. This resulted in the MPC being out of level although within its six degree tolerance limit. No damage to permanent or temporary plant equipment occurred and personnel safety was not at risk. The Dry Cask Campaign work was stopped and a return to work plan was generated and completed. The licensee entered the issue into the corrective action program as PER 741390. In accordance with IMC 0609, Attachment 4, Phase 1, Initial Screening and Characterization of Findings, the finding was determined to be of very low safety significance (Green) by answering no to the questions in the Initiating Events column of Table 4a, since the finding does not contribute to both a reactor trip and the likelihood that mitigation equipment or functions will not be available. |
| 05000317/FIN-2013403-01 | 2013Q2 | Calvert Cliffs | Security | |
| 05000327/FIN-2013003-02 | 2013Q2 | Sequoyah | Licensee-Identified Violation | Failure to ensure proper configuration of 1A EDG light socket On March 10, 2013, during a monthly surveillance of the 1A EDG, the output breaker failed to close while attempting to parallel the 1A EDG to the grid. Two more breaker closures were attempted and again, the breaker failed to close (total of 3 times). The electrician reported the breaker cycled, current on the ammeter increased, but the breaker did not latch and immediately tripped. The control room operators noted that during the three closure attempts, the red light never energized. No trip flags were noted at the breaker cubicle. Bench testing of the breaker outside of its cubicle was performed and the breaker was able to be closed seven times without incident. Subsequent troubleshooting revealed the circuit breaker was exposed to a standing trip signal. The cause of the trip signal was an electrical short across the red-indicating light that resulted in the energization of the trip coil. This short effectively bypassed the internal resistor which allowed enough current in the circuit to energize the trip coil. The short was attributed to a failure of the red-indicating-light-socket assembly. The specific cause of the broken light socket was deemed to be age-related distortion of the plastic socket where under a high temperature environment (behind operating panel) successive retightening of the retaining nut can induce enough stress to exceed the yield stress of the socket material. In addition, the licensee noted that the vendor tech manual for the light-socket assembly recommended bending of the rear terminal tab up to 90 degrees (if necessary) to best suit the wiring configuration. Given a failure of the light-socket assembly, pre-bending of the tab could have decreased (or eliminated) the likelihood of a short circuit. 10CFR50 Appendix B, criterion III, requires in part, established measures shall ensure the design bases for safety-related components are translated into procedures and instructions. Contrary to the above, the licensee failed to incorporate vendor guidance into plant maintenance procedures to ensure the EDG could have performed its design function. The light-socket assembly was replaced and the 1A EDG was successfully tested and declared back in service on March 10, 2013. The licensee entered the issue into the CAP and developed several corrective actions including the initiation of a preventative maintenance program to periodically inspect the light sockets to ensure their continued operability. A risk analysis for this event was performed by the licensee. An exposure time of 15 days (one-half the time from the last successful EDG run, or 30 days) was utilized for this analysis. The results were reviewed by the inspectors and the conclusion was that the failure was of very low safety significance (Green). |
| 05000327/FIN-2013002-01 | 2013Q1 | Sequoyah | 1A EDG Breaker Failures | The inspectors noted that two consecutive 1A EDG monthly surveillance tests exhibited anomalies associated with the output breaker operation between February and March of 2013. On February 10, 2013, during the 1A EDG monthly surveillance, the 1A EDG breaker failed to close on the first attempt. The operators noted the red light illuminated momentarily and the breaker then opened. Local observation of the breaker cubicle noted no trip flags. A second attempt was made and the breaker successfully stayed closed. The one hour EDG run was completed successfully. Based on discussions between operations and engineering, the breakers reliability was questioned and the EDG was declared inoperable. The suspect 6.9 kilovolt (kV) breaker was removed from the cubicle for cause testing. Another breaker was installed in its place and the surveillance was successfully re-performed with the replacement breaker, and the EDG was declared operable. The removed breaker was moved to the electrical shop for further testing. The issue was entered into the CAP as PER 679474 which will include an apparent cause evaluation. On March 10, 2013, during the next scheduled monthly surveillance of the 1A EDG, the output breaker again failed to close while attempting to parallel the EDG to the grid. Note that this breaker was a different breaker from the February 10, 2013 incident. Operators requested an electrician to observe subsequent breaker operations. Two more breaker closures were attempted and again, the breaker failed to close (total of 3 times). The electrician reported the breaker cycled, current on the ammeter increased, but the breaker did not latch and immediately tripped. The control room operators noted that during the three closure attempts, the red light never energized. No trip flags were noted at the breaker cubicle. Bench testing of the breaker was performed and the breaker was able to be closed seven times without incident. At that point, the troubleshooting process began to examine causes external to the breaker. Subsequent troubleshooting revealed the circuit breaker was exposed to a standing trip signal. The cause of the trip signal was an electrical short across the red indicating light that resulted in the energization of the trip coil. The short was caused by a crack in the red indicating lamp socket assembly which allowed the positive and negative contacts on the socket to touch and short the light. The light socket assembly was subsequently replaced and the 1A EDG was successfully tested and declared operable on March 10, 2013. As of the end of the inspection period, the licensee had not completed a causal analysis of both failures. Pending additional information from the licensee which identifies the root cause of both failures, this item is identified as unresolved item (URI) 050000327/2013002-01, 1A EDG Breaker Failures. |
| 05000327/FIN-2013002-04 | 2013Q1 | Sequoyah | Failure of Ground Fault Relay Leads to Loss of RCP and Reactor Trip | A self-revealing Green NCV of Unit 2 Technical Specification (TS) 6.8.1, Procedures & Programs, was noted for the licensees failure to provide adequate procedures for maintenance and surveillance activities involving the RCP circuit breaker ground fault relay, GR-5. Specifically, the GR-5 relay continued to operate beyond its service life and ultimately failed causing a loss of a reactor coolant pump and a reactor trip on low system flow. No maintenance procedures were developed to periodically replace this relay. Failure to perform adequate preventative maintenance (e.g. periodic relay replacement) on the GR-5 relay at proper intervals was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the procedure quality attribute of the initiating event cornerstone and affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during power operations. This was self-evident as the relay failure ultimately led to a reactor trip which challenged the reactor protection system and led to a plant transient. The licensee has entered this issue into the corrective action program (CAP) as Problem Evaluation Report (PER) 596978. The significance of this finding was evaluated in accordance with the IMC 0609 Appendix A, The SDP Process for Findings at Power. According to Exhibit 1 of this procedure, for transient indicators, since the reactor trip did NOT include a loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition, the finding screened to Green. Thus, the inspectors concluded that the finding was of very low safety significance (Green) based on the fact that the reactor trip was uncomplicated. This finding was determined to have a cross-cutting aspect in the area of human performance, the component of work control, and the aspect of work activity coordination, H.3(b), due to the failure to provide work planning activities that ensure long term equipment reliability. Specifically, the GR-5 relays were essentially treated as run-to-failure components which led to a reactor trip. |
| 05000327/FIN-2013002-03 | 2013Q1 | Sequoyah | Failure to Promptly Identify and Correct Conditions Adverse to Quality | The inspectors identified a Green NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, associated with three examples of the licensees failure to promptly identify and correct conditions adverse to quality. Specifically, the licensee failed to promptly correct (1) the conduit penetration seals entering the ERCW building, (2) two penetrations in the wall of the ERCW building below the probable maximum flood level that were not sealed, and (3) two diesel generator drain lines that could not be isolated. The licensee entered the finding into the CAP as PERs 594536, 594568, 610005, and 622421. The failure to promptly identify and correct conditions adverse to quality was a performance deficiency. The performance deficiency was determined to be more than minor because if left uncorrected, the licensees continued failure to promptly identify and correct conditions adverse to quality could result in more risk significant equipment being inoperable for longer periods of time without the licensee realizing, and is therefore a finding. The inspectors performed the significance determination using NRC Inspection Manual Chapter 0609, Significance Determination Process. Because the finding affected the Mitigating Systems Cornerstone while the plant was at power, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, evaluates the finding using Appendix A. Using Appendix A, Exhibit 2, Mitigating Systems Screening Questions, the finding was determined to have very low safety significance because the finding: (1) was not a design or qualification issue confirmed not to result in a loss of operability or functionality; (2) did not represent an actual loss of safety function of the system or train; (3) did not result in the loss of one or more trains of nontechnical specification equipment; and (4) did not involve the loss or degradation of equipment or function specifically designed to mitigate a seismic, flooding, or severe weather initiating event. In addition, this finding had a human performance cross-cutting aspect associated with decision making. Specifically, the licensee failed to use conservative assumptions in decision making regarding the timely opening of manhole 33 for physical inspection to be able to quantitatively determine the in leakage value for the degraded condition and put in place an adequate comp measure. Also, the licensee incurred excessive delay in plugging of two ERCW building holes as well as evaluation of the potential water intrusion into the EDG building during flooding events |