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05000390/FIN-2018002-022018Q2Watts BarLicensee-Identified ViolationLER: 05000390, 391/2017-013-00, Incorrectly Adjusted Auxiliary Building Gas Treatment System Damper Leads to a Condition Prohibited by Technical Specifications, November 6, 2017. Violation: Watts Bar Unit 1 TS 3.7.12, Auxiliary Building Gas Treatment System (ABGTS), Condition A, requires that an inoperable ABGTS train to be restored to operable status within 7 days. Condition B of TS 3.7.12 requires the plant to be in Mode 3 within 6 hours and Mode 5 within 36 hours if one train of ABGTS is inoperable longer than 7 days. Contrary to the requirements of TS 3.7.12, ABGTS, train A was determined to be inoperable from July 7, 2017, at 2030 Eastern Daylight Time (EDT) to September 5, 2017, at 1645 EDT while the plant remained in Mode 1. Significance/Severity Level: This violation was characterized using traditional enforcement because the NRC determined that this violation was not reasonably foreseeable and preventable by the licensee and, therefore, is not a performance deficiency. The violation was assessed using Sections 2.2.4 and 6.1.d.1 of the NRCs Enforcement Policy and determined to be a SL IV violation. Corrective Action Reference(s): Condition Report (CR) 1335791
05000390/FIN-2018002-012018Q2Watts BarInadequate Procedure Results in Exceeding the Design Pressure of the RHR PipingA self-revealed Green NCV was identified when the licensee failed to consider potentially adverse system interactions when developing procedures affecting quality. Specifically, the licensee exposed Unit 1 residual heat removal system piping to higher than its design pressure while performing two evolutions simultaneously in accordance with associated procedures.
05000259/FIN-2017003-022017Q3Browns FerryFailure to Maintain Intake Building Flood BarrierAn NRC- identified NCV of Technical Specification (TS) 5.4.1, Procedures, was identified for the failure to follow procedure MCI -0-023- PMP003, Emergency Equipment Cooling Water (EECW) and Residual Heat Removal Service Water Pump (RHRSW) Removal and Reinstallation, Revision 22. The performance deficiency is more than minor because it affected the Mitigating Systems cornerstone attribute of Equipment Performance and adversely affected the cornerstone objective. A detailed risk evaluation by a regional SRA determined the finding was Green . The licensee entered the violation into the CAP as CR 1338684. The finding had a cross cutting aspect in the Avoid Complacency component of the Human Performance area because the maintenance staff chose to not refer to a previously related condition report (CR) (PER 599190) or the maintenance procedure that were corrective actions for a previous NRC finding. (H.12).
05000259/FIN-2017003-012017Q3Browns FerryDegraded EDG Flood Door SealsAn NRC- identified non- cited violation (NCV of 10 CFR Part 50, Appendix B, Criterion V was identified for the licensee's failure to use appropriate procedural surveillance criteria to ensure the diesel generator buildings were protected against flood- water up to the design basis flood elevation. The annual door inspection procedure did not contain instructions with appropriate acceptance criteria to determine whether the diesel generator building doors would create a watertight seal when closed. The performance deficiency is more -than -minor because it was associated with the protection against external factors attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective. A detailed risk evaluation by a regional Senior Risk Analyst ( SRA ) determined the finding was of very low safety significance (Green) . The licensee entered the violation into the corrective action program (CAP) as CR 1306268. The inspectors determined that the finding had a cross -cutting aspect in the Self -Assessment area of the Problem Identification and Resolution aspect (P.6), because recent self - assessments had not been self -critical of the external flood protection program and practices.
05000250/FIN-2017002-022017Q2Turkey PointInadequate Foreign Materials Exclusion Controls for Thermo-Lag Activities Renders Electrical Equipment Inoperable and Results in a High Energy Arc FlashGreen: A self-revealing Green (NCV) of Technical Specification (TS) 6.8.1.a., Procedures and Programs, was identified for the failure to appropriately implement foreign material exclusion (FME) controls during Thermo-Lag fire barrier modifications. Specifically, maintenance procedure 0-GMP-102.21, Installation, Modification and Maintenance of Thermo-Lag Fire Barrier System, Rev. 0C, did not include instructions in sufficient detail to prevent foreign material used in the installation of Thermo-Lag fire barriers from entering nearby electrical equipment and was a performance deficiency (PD) which affected the operation of two redundant safety-related battery chargers and caused a high energy arc fault (HEAF) that damaged the 3A 4kV switchgear bus. After the HEAF, the licensee promptly ceased all Thermo-Lag installation activities. The licensee completed a root cause evaluation in Action Request (AR) 2192198 and revised the installation procedure to prevent foreign material from entering nearby electrical equipment. The PD was more than minor because it caused both a reactor trip and resulted in the unavailability of the 3A 4kV switchgear bus. The inspectors evaluated the significance of this finding by utilizing IMC 0609 Attachment 4, Initial Characterization of Findings, and IMC 0609 Appendix A, The Significance Determination Process for Findings At-Power, and determined the findings significance could not be screened to Green because it caused both a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. Therefore a detailed risk evaluation was required to complete the significance determination. Based upon the results of the evaluation the finding was considered to be Green, or equivalent to low safety significance. The cross-cutting aspect (CCA) that best corresponds to the root cause as described in IMC 0310, Aspects Within the Cross-Cutting Areas, was Resources; leaders ensure that personnel, equipment, procedures, and other resources are available and adequate to support nuclear safety (H.1).
05000250/FIN-2017002-032017Q2Turkey PointFailure to Implement Fire DetectionGreen: A NRC-identified Green finding was identified for the licensees failure to follow plant procedure O-ADM-016, Fire Protection Program, Rev. 19. Specifically, the licensee failed to properly implement fire watches following a HEAF on the 3A 4kV switchgear bus. 3 The inspectors determined that the licensees failure to implement fire detection was a PD. This PD was more than minor because it was associated with the reactor safety mitigating systems cornerstone, and if a fire was not detected in the 3B 4kV switchgear room there was a potential for the B train of equipment to lose function which could have resulted in the unavailability of both the A and B trains of equipment post incident. The finding is not greater than Green because a risk analysis of the PD was performed and determined the risk increase in core damage frequency due to the PD was equivalent to a Green finding of very low safety significance due to the short exposure period. Because site personnel failed to reset fire detectors and implement fire watches in appropriate areas following the incident; and during interviews, inspectors identified that fire drills did not emphasize post incident activities, the inspectors concluded the finding had a CCA in the area of Human Performance associated with the Training; the organization provides training and ensures knowledge transfer to maintain a knowledgeable, technically competent workforce and instill nuclear safety values (H.9).
05000250/FIN-2017002-012017Q2Turkey PointFailure to Perform 100 Percent General Visual Examinations of Containment Moisture Barriers Associated with Containment Liner Leak Chase Test ConnectionsGreen: A NRC-identified Green NCV of 10 CFR 50.55a, Codes and Standards, was identified for the failure to perform general visual examinations of moisture barrier materials in the reactor containment leak-chase channel test connections in accordance with the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel (BPV) Code, Section XI, Subsection IWE. The licensee performed the required examinations in Unit 3 during the April 2017, refueling outage and initiated corrective actions to revise the physical configuration of leak chase areas and review the In-service Inspection (ISI) Plan. This issue has been entered into the licensees corrective action program as AR 02196637. The failure to conduct the required visual examination of all moisture barriers in accordance with the ASME BPV Code requirements was a PD. The PD was more than minor significance per IMC 0612, Appendix B, Issue Screening, because the current Containment ISI Plan did not adequately implement the ASME BPV Code inspection requirements for the examination of moisture barriers, and if left uncorrected, had the potential to lead to a more significant concern. The finding was of very low safety significance, or Green, per IMC 0609 because it did not, based on inspections performed following discovery, represent an actual open pathway in the physical integrity of the reactor containment. Because the licensee did not effectively evaluate and appropriately implement the ASME BPV Code requirements in the Containment ISI Plan when a reasonable opportunity was available through the licensees review of NRC Information Notice (IN) 2014-07 and Regulatory Issue Summary (RIS) 2016-07, the inspectors determined the finding had a CCA in the operating experience component of the problem identification and resolution cross-cutting area, in that the organization systematically and effectively collects, evaluates, and implements relevant internal and external operating experience in a timely manner (P.5).
05000325/FIN-2017009-012017Q2BrunswickInoperability of EDG1 due to Cyclic Fatigue Failure of Hydraulic Fuel Rack ControlGreen . A self -revealing Green non- cited violation ( NCV ) of 10 CFR 50 Appendix B Criterion XVI, Corrective Actions, was identified on February 19, 2017, when emergency diesel generator ( EDG ) number one was determined to be inoperable due to an oil leak o n the linkshaft hydraulic control assembly. This violation of regulatory requirement existed from October 27, 2015 u ntil February 20, 2017. The licensee entered this issue in their corrective action program as nuclear condition report ( NCR) 02101084. The inspectors determined that the finding was more than minor because it was associated with the Mitigating Systems cornerstone attribute of Equipment Performance 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, failu re to correct a condition adverse to quality led to the inoperability of EDG1. The inspectors screened this finding using IMC 0609, Appendix A, The Significant Determination Process (SDP) For Findings At -Power, dated June 19, 2012, Based on Exhibit 2, Q uestion A3, the inspectors determined that a detailed risk evaluation was necessary given the uncertainty over how long EDG1 would have operated while leaking oil. A regional senior reactor analyst (SRA) conducted the risk assessment and screened the issu e to Green based on an increase in risk of less than 1E -6. The inspectors determined that this finding did not have an associated cross cutting aspect because this finding was not reflective of current licensee performance due to enhancements of site procedures guiding creation of work orders.
05000335/FIN-2017001-012017Q1Saint LucieInadequate Procedure Results in Adding an Incorrect Lubrication Oil to the 1B CS Motor Inboard BearingAn NRC-identified Green, non-cited violation (NCV) of Technical Specification (TS) 6.8.1, Procedures and Programs, was identified for the licensees failure to establish, implement, and maintain written procedures covering activities referenced in NRC Regulatory Guide 1.33, Revision 2, dated February 1978. Specifically, the licensees failure to maintain a plant lubrication manual with correct lubrication oil specifications for the 1B containment spray (CS) pump motor resulted in adding unacceptably low viscosity lubrication oil to the inboard bearing of the 1B CS pump motor. Immediate corrective actions included restoring the 1B CS pump inboard bearing with the correct lubrication oil and placing the issue in the licensees corrective action program.The licensees failure to correctly specify the 1B CS pump motor inboard bearing lubrication requirements in licensee general maintenance procedure GMP-22 was a performance deficiency (PD). The PD was more than minor because it was associated with the procedure quality 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 (i.e., core damage). Specifically, the inadequate procedure resulted in adding the incorrect lubrication oil to the 1B CS pump motor bearing, causing the pump to be declared inoperable for approximately 56.5 hours. The finding screened to Green because the failure did not: (1) affect the design or qualification of the systems, structures and components, (2) represent an actual loss of function, and (3) represent an actual loss of function of at least a single train for greater than its TS allowed outage time. The finding involved the cross-cutting area of human performance, in the aspect of avoid complacency, in that, the individuals involved with the procedure revision did not implement appropriate error reduction tools to ensure the procedure was appropriately changed to reflect the new lubrication oil requirement (H.12).
05000250/FIN-2017008-012017Q1Turkey PointPotential Failure of Fire Detection Capability on Credited Train of Equipment Following High Energy Arc Flash EventInspection Scope The team reviewed the fire brigade response after an explosion and smoke was reported coming from the Unit 3 safety -related 3A 4kV switchgear to determine and assess whether : (1) the brigade response was adequately staffed ; (2) there was timely arrival of the required amount of dressed- out fire brigade members ; (3) the required firefighting equipment and communication equipment and procedures were taken to and or available at the scene to adequately plan and execute a fire fighting strategy; and (4) that the brigades fire -fighting actions and communications were appropriate in accordance with the established procedures and the licensees fire brigade program requirements. The team also reviewed whether the licensees fire brigade had requested assistance from the Miami -Dade Fire and Rescue Department , the basis for assistance and if Miami -Dade Fire and Rescue provided any firefighting assistance. The team interviewed the responsible fire brigade team leader and the SRO that responded to the switchgear room to obtain the details regarding the as found conditions and actions taken by the brigade to address the smoke and potential fire in the switchgear room . The team reviewed the licensees fire pre -plan to assess whether the licensee adequately ventilated the smoke from the Unit 3A switchgear given the circumstances. Specifically , the Unit 3 EDG had automatically started and was blowing high velocity air from the radiator exhaust into the direction of the 3A and 3B switchgear room door entrances. The team walked down the Unit 3 4kV switchgear rooms with the responsible SRO that had assisted in decision making to direct smoke ventilation during the incident, to understand the circumstances regarding the strategy used for ventilation. The team reviewed the licensees fire risk management actions implemented after the licensee identified the fire door had been damaged, including the establishment of a fire watch in the 3A 4kV switchgear room. The team reviewed the licensees fire brigade response report and CAP database to determine if the licensee was adequately addressing any unresolved issues identified during the fire brigade response. 12 b. Findings and Observations On March 18, 2017 , at approximately 11: 07 a.m. EDT , as a result of an arc f lash in switchgear room 3A, eleven out of eleven spot detectors and two out of two very early warning detectors activated in switchgear room 3B. The spot detectors activated spatially from the first detector closest to Fire Door D070- 3, which separates switchgear Room 3A and 3B , to the last spot detector activating closest to the exit door on the east side of the room. The licensee acknowledged the alarms at Fire Alarm Control Panel 3C286 after the incident; however, the licensee did not reactivate the smoke detectors until sixty two hours later on March 21, 2017 , at 12:51 a.m. EDT. The team confirmed with the licensee that the detectors would not have activated between the times they were acknowledged and reactivated. The 3B 4kV switchgear was the protected train after the arc f lash in the 3A 4kV switchgear. Procedure 0 -ADM -016, Fire Protection Program , Rev . 19, Table 5.6.3 -1, denotes Fire Zone 70 ( 3B 4kV switchgear) to include fire detection instruments in the maintenance rule (a)(4) monitored fire zone and specified required risk -informed interim compensatory actions for degraded equipment. Section 5.6.3.3. d outlined these compensatory actions as the following: ...all detection instruments must be in service when required to be functional. If any single detector instrument is declared out of service, within one hour, a continuous fire watch shall be established and maintained until the detection instrument is returned to service... Smoke removal activities immediately after the inc ident credits personnel in the switchgear room 3B for nearly four hours. Thereafter, based on the security access logs, at 2 :43 p.m. EDT, two maintenance personnel were placed on fire watch duty until 5:22 p.m. EDT . However, these individuals monitored switchgear room 3A and were not placed inside the room with the credited train, 3B. The following fire watch shift arrived at approximately 6:00 p.m. EDT and maintained presence outside of both switchgear rooms 3A and 3B with the entry doors closed. The licensee informed the team that the crew was fearful of the persistent odor that was emanating after the incident in switchgear 3A. Since this crew did not maintain logs nor access the doors, the licensee confirmed to the team they were present outside. AR 2194579 was generated to document fire watches located outside the room do not meet the intent of 0 -ADM -016.4, Fire Watch Program. The first documented log of a continuous fire watch occurred at 1:15 p.m. EDT on March 19, 2017. This log continues until the smoke detectors were reactivated at 12:51 a.m. EDT on March 21 , 2017 ; however these individuals were located in switchgear room 3A. The team interviewed fire watch personnel and determined that the individuals , which did not maintain fire watch logs and stationed themselves outside the switchgear rooms , were Florida Power and Light (FP&L) employees who recently started fire watch activities; whereas, the individuals that maintained logs and placed themselves inside switchgear room 3A were experienced contractors. The team did not have an opportunity to interview FP&L fire watch employees; the contractors that were interviewed were trained and experienced to sufficiently perform the duties. In addition, the single smoke detector in the 480V Load Center 3A, 3B room (Fire Zone 95) located directly above the switchgear rooms did activate during the incident and was not reactivated until 12: 51 a.m. EDT on March 21, 2017 . The detector is assumed to have activated by smoke travelling from switchgear room 3A to switchgear room 3B to 13 the fire door located on the second level of switchgear room 3B. According to 0- ADM - 016.4, Fire Watch Program, for a deactivated detector in the 480V Load Center 3A, 3B room, the following requirement applies: ...restore the non- functional instruments to functional status within 14 days or within the next 1 hour establish a fire watch patrol to inspect the zones with the non- functional instruments at least once per hour. The licensee maintained an hourly roving fire watch in switchgear rooms 3A, 3B and 3 A/B/C/D 480V Load Centers rooms before the incident that was temporarily suspended for the 11:00 a.m., 12:00 p.m., 1:00 p.m. & 2:00 p.m. hours on March 18, 2017, due to scene safety and subsequent investigation. The hourly rove was reinstated in switchgear rooms 3A, 3B and 3 A/B/C/D 480V Load Center rooms for the 3:00 p.m. hour. The team interviewed licensee fire managers regarding the fire response activities after the incident. The managers were cognizant of the issues and attributed them partly to the false fire alarms in other areas of the plant that occurred shortly after the event . AR 2194706 was generated to enhance fire procedures that would address functionality of suppression, detection and barriers; and consideration of compensatory measures post incident. Overall, the team concluded that the licensees fire brigade response and communications were adequate following the event. However, the team identified issues with regards to the establishment of a fire watch for the 4kV switchgear rooms following the event and therefore opened an Unresolved Item (URI) as documented below . URI 05000250, 251/ 2017008- 01, Potential Fai lure of Fire Detection Capability on Credited Train of Equipment Following High Energy Arc Flash Event Introduction: The team identified an URI associated with the licensees actions to implement fire watches following the 3A 4kV switchgear high energy arc flash . These actions potentially resulted in inadequate fire detection capability in the 3B 4kV switchgear room for a period of up to 58 hours following the event on March 18, 2017. Description : The arc flash in the 3A 4kV switchgear room activated all spot type and early warning smoke detectors in the 3A 4kV switchgear, 3B 4kV switchgear and 3/A/B 480V Load Center rooms. These detectors were not reactivated until 62 hours later on March 21, 2017, (58 hours following completion of smoke removal activities) . After the event , the 3B 4kV switchgear was the protected train of equipment. Due to the risk significance of switchgear room 3B, Procedure 0 -ADM -016.4, Fire Watch Program, require d a continuous fire watch with one smoke detector out of service. For the 3/A/B 480V Load Center, Procedure 0 -ADM -016.4 required an hourly fire rove for detectors out of service. The licensee had established an hourly fire rove before the incident for all the affected rooms that was temporarily suspended for scene safety and subsequent investigation. The licensee was unable to document a continuous fire watch for 58 hours following the smoke removal activities in switchgear room 3B until the detectors were reactivated. Fire watches were posted after the incident to cover switchgear room 3A , which was the non- credited train of equipment. In addition, for approximately 22 hours following smoke removal activities, the individuals covering switchgear room 3A did not keep fi re watch 14 logs and for a period of time the individuals stayed outside the room with the entry door closed. The team noted the cause of this deficiency was primarily due to lack of training and guidance for individuals performing the fire watches. As a result of inactive smoke detectors and no fire watches in switchgear room 3B, the credited train was without smoke detection for approximately 58 hours following smoke removal activities. Due to the risk significance of the room, licensee procedures required a continuous fire watch with one detector out of service. An URI has been opened for additional review to identify whether a performance deficiency existed related to the licensees fire watch actions following the arc flash event on March 18 . (URI 05000250, 251/2017008- 01, Potential Failure of Fire Detection Capability on Credited Train of Equipment Following High Energy Arc Flash Even
05000250/FIN-2017008-032017Q1Turkey PointPotential Failure to Implement Adequate Foreign Material Exclusion ControlInspection Scope The team reviewed licensee documents, performed walk downs associated with the safety -related 3A 4kV switchgear located inside room 071, and interviewed licensee personnel to determine the conditions leading up to the internal bus fault event on the morning of March 18, 2017. The documents reviewed included procedures, work orders, drawings of floor plans, one line diagrams, specifications, correspondence, photographs, licensees NRC Inspection Team Briefing document, and Root Cause Charter description AR 02192198. b. Findings and Observations The team initiated the review by performing a walk down of the 3A 4kV switchgear room to establish an understanding of the conditions inside the room that may have affected the 3A 4kV switchgear. The room , which was significantly smaller than the 3B 4kV switchgear room, provided minimally adequate access around the equipment, such as the switchgear , motor control center s (MCC s), a sequencer panel, a sump pump, and floor mounted air handling units. The current limiting reactor (CLR) , or reactor coil, associated with the event was located in section 3AA06 of the 3A 4kV switchgear. The front of this section is across from a room air handler unit, which directs its air towards the ventilation louvers in the CLR section. The team interviewed members of the licensees failure investigation process team and determined their evaluation of the potential causes for the failure of the reactor coil included: Bus fault in reactor coil cubicle 3AA06 Failed insulator in cubicle 3AA06 19 Fault in reactor coil Bus fault external to the 3AA06 cubicle Load fault with failure to isolate Magnetic properties of the reactor coil interacting with erected scaffold. 3AA06 side panels pushed in from outside reducing air gap Foreign material from internal and/or external sources Bolts installed with nuts facing towards grounded surfaces. Large quantities of conductive dust suspended in air from sweeping prior to fault Each of the potential causes were dismissed for lack of any evidence with the exception of those issues that would have contributed to a reduction in the air gap between uninsulated busses and ground surfaces. The installation of the Thermo-Lag was in progress just prior to the bus fault and according to statements from the installing contractor personnel, they had just exited the room to prepare to go to lunch and had been cleaning up the space before leaving. One of the workers had gone back into the room to check on one last item when the bus fault occurred and suffered injuries as a result of the explosion. Based on interviews and photographs provided, it was determined that the mesh, used to make up the joining pieces of insulation, was conductive. That mesh material was also light weight and made out of carbon fiber. The protective relays operated as expected for almost all components , including the 174/TDO relay in the trip circuit that operated the lockout relay, which in turn opened all the breakers in the 3A 4kV switchgear bus. The lockout relay operation prevented the 3A EDG from closing in on the 3A 4kV switchgear bus. The loss of the bus initiated a loss of steam flow on the turbine. The Unit 3 turbine and generator were motoring for approximately 30 seconds with the transmission system experiencing power swings associated with the loss of the main generator. After 30 seconds, the Unit 3 generator 286/G3 lockout tripped followed by the switchyard breakers opening and isolating the generator in 1.8 cycles. The reactor coil separates the high and low sides of the 3A 4kV switchgear bus. The high side, which was upstream of the reactor coil, had a higher withstand capability for short circuits that the low side of the switchgear bus. There is a slight difference between the overcurrent relays for phases A and B compared to phase C. Tracings provided with the details of current and voltage conditions prior to, during , and after the bus fault reveal an increase in the fault current of phase C preceding the increase in phase A. Photographs of the effects of the bus fault indicated an initial arc located next to what appeared to be phase C bus. However, the target flags in the overcurrent relay s failed to indicate a phase C trip. The entire overcurrent protection system worked as expected except for the delay on the phase C components. The team reviewed procedures and methods prescribed by the licensee to control foreign material contamination. A number of the methods indicated included cutting the Thermo-Lag material outside the switchgear room approximately 15ft from the east door to the room. Some of the final cutting and trimming of the carbon fiber mesh was done inside the switchgear room on top of the scaffolding, which had been fitted with Grifflon net to protect from foreign material particles. In addition, a Pearl Weave material was 20 used to protect against falling objects to the space below. The team was able to confirm a number of these methods used by the conditions of the space during the walk down of the room and the interview transcripts provided by the licensee of the Thermo- Lag installation personnel. However, these methods appear to cover larger pieces of material that would be appropriately captured by the Pearl Weave or the Grifflon but not the smaller pieces of carbon fiber mesh that could become airborne and migrate around the room. The only apparent control provided for airborne particulate would be the air filter in the air handling unit. This would require the material to be at an elevation low enough to get sucked in by the air return at the bottom of the air handler. Any material suspended in air would be blown out from the air handler and potentially be blown through the louvers in the reactor coil cabinet. Overall, the team concluded that the licensee was taking appropriate actions to evaluate the potential causes for the failure of the 3A 4kV bus. The most likely potential causes of the event involve the introduction of foreign material into the switchgear as well as the configuration and design of the switchgear. Additional review of information related to these potential causes will be required following the conclusion of the licensees root cause evaluation, which had not yet been completed at the time of the inspection. Therefore the team opened two URI s as documented below. i. URI 05000250, 251/2017008- 03, Potential Failure to Implement Adequate Foreign Material Exclusion Controls Introduction: The team identified an URI associated with the licensees potential failure to properly control the spread of airborne particulates generated from the installation of the Thermo-Lag insulation material on cable trays and conduits inside the 3A switchgear room. Description : The documentation provided to install the Thermo-Lag insulation was prescribed in work order 40464284- 03, EC 283459 Install T -Lag of MCC -3B Power Cables in 3A SWGR , dated the 10th of March 2017. This work order refer red to procedure MA -AA- 101- 1000, Foreign Material Exclusion Procedure, for job supervisor to review and approve the foreign material exclusion ( FME ) controls under item 2.3. The supervisor signature was provided on the 17 th of October 2016 for this particular task. However, the signature date was prior to this work order issue date. Section 4.3 of the FME procedure in paragraph 10 stated that , Special precautions need to be taken when work activities (spray painting, sand blasting, grinding, cutting, welding, insulating, chemical cleaning etc.) may generate airborne dust, debris or chemical fumes that could be introduced into operating plant equipment such as motors, switchgear, control panels and electrical cabinets . In addition, section 4.5.1 , Electrical Cabinets , paragraph 1 , directed personnel to visually inspect the surrounding area, particularly overhead, for potential sources of foreign material and to note any nearby ventilation system that may introduce foreign material into the cabinet. In paragraph 2, it indicated that , Where practical, covers should be installed on open electrical enclosures, cabinets, and boxes required to be left open by procedure, plant operations, or maintenance . Section 4.5.2, Switchgear , directed the personnel to follow the measures identified above. In addition, the conductivity of this mesh may have played a significant factor in the resulting bus fault when it migrated into the reactor coil cabinet through the open louvers and formed a low impedance path from the exposed phase C bus to the metal enclosure of the cabinet. Pieces of the black mesh were discovered inside the reactor 21 coil insulated windings, which indicated an absence of screening material or a means to block foreign material migration into the inside of the reactor coil cabinet with its exposed busses. Procedure 0- GMP -102.21, Installation, Modification and Maintenance of Thermo-Lag Fire Barrier Systems , did not contain an engineering evaluation of the carbon fiber mesh used with the system installed inside the 3A 4kV switchgear room. Material safety data sheet (MSDS -0012821) from Cytec Engineered Materials with product name Thornel Pan Based Standard Modulus Carbon Fiber provided a hazard identification of Electrically Conductive Fibers Airborne fibers can short circuit electrical equipment . This URI was initiated to further review the environment created during the installation of the Thermo-Lag in 3A 4kV switchgear room. This environment may have contributed to a degraded isolation of exposed medium voltage bus bars inside the reactor coil cabinet . Following the completion of the licensees root cause evaluation, inspectors will determine whether performance deficiencies exist ed related to the licensees evaluation of the carbon fiber mesh and the foreign material exclusion controls in effect at the time of the event. (URI 05000250, 251/2017008- 03, Potential Failure to Implement Adequate Foreign Material Exclusion Controls)
05000390/FIN-2016003-032016Q3Watts BarLicensee-Identified ViolationWatts Bar Nuclear Plant Units 1 and 2 Technical Specification 5.7.1.1.d requires, in part, that written procedures be established, implemented, and maintained covering the activities involved with Fire Protection Program implementation. The Watts Bar Fire Protection Report lists compensatory actions that must be implemented when there are impaired fire protection systems, including, under some circumstances, a continuous fire watch. TVA Corporate Procedure NPG-SPP-18.4.6, Control of Fire Protection Impairments, Rev. 0006, is the implementing/controlling process for all Fire Protection impairments, and establishes the process for implementing compensatory actions for fire impairments as directed by the Fire Protection Report. NPG-SPP-18.4.6, Section 3.2.6.A, states that Fire watches are utilized for the surveillance of areas where fire protection systems are impaired. The compensatory fire watch process is described in Attachment 7 of NPG-SPP-18.4.6. Contrary to the above, on April 27, 2015, the licensee failed to perform a continuous fire watch as required for fire protection systems that were impaired. Specifically, the licensee failed to establish the compensatory continuous fire watch required by Fire Protection Impairment Permit C10-0639, which authorized an impairment of fire detection systems to allow for welding work on the 713 elevation of the auxiliary building of Watts Bar Nuclear Power Plant. This violation is of very low safety significance (Green). This issue was determined to be of very low safety significance based on the results of the IMC 0609, Appendix F, Fire Protection Significance Determination Process, Phase I Screening Approach. The inspectors determined that the fire finding did not affect the Unit 1 reactors ability to reach and maintain safe shutdown (either hot or cold) condition. Therefore, the finding screened as Green. Specifically, the only equipment important to safety in the affected fire area was associated with the construction unit (Unit 2), and would not have impacted the safe shutdown of Unit 1. This violation was documented in the licensees corrective action program as CR 1019953.
05000390/FIN-2016003-012016Q3Watts BarFalsified Fire Watch RecordsSeverity Level IV. The NRC identified a Severity Level IV violation of 10 CFR 50.9 Completeness and Accuracy of Information, for the failure to maintain continuous compensatory fire watch information that was complete and accurate in all material respects. The licensees actions of creating falsified fire watch completion records for the 713 elevation of the Auxiliary Building was a performance deficiency. The licensee entered this issue into the corrective action program as CR 1019953 and took remedial action against the involved individuals commensurate with the circumstances. The NRC evaluated this issue under the traditional enforcement process because it involved willfulness. In consideration of the fact that the individuals were contract fire watch personnel with minimal supervisory responsibilities, and that the underlying safety significance of the missed fire watch was low, the NRC concluded that this violation should be characterized at Severity Level IV in accordance with Section 2.2.1.d of the Enforcement Policy. Furthermore, because this violation involved willfulness and lack of supervisory oversight, the non-cited violation criteria of paragraph 2.3.2.a.4.(c) was not satisfied, such that this violation will be cited. This violation was evaluated under the traditional enforcement process and thus does not have a cross cutting aspect.
05000390/FIN-2016003-022016Q3Watts BarInappropriate Procedure used for Work Order Scope Change Results in Loss of 1B-B Shutdown Board.A self-revealed non-cited violation (NCV) of 10 Code of Federal Regulations (CFR) 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified for the licensees failure to use a procedure appropriate to the circumstances when work scope changed which contributed to the loss of the 1B-B shutdown board on May 17, 2016. The violation was entered into the licensees CAP as CR 1172243. The failure to use a procedure appropriate to the circumstances, such as NPG-SPP-07.6, NPG Work Management Planning Procedure, Revision (Rev.) 14, for a work scope change associated with a design change work order on the 1B-B shutdown board on May 17, 2016, was a performance deficiency. The performance deficiency was more than minor because it affected the equipment performance attribute of the mitigating systems cornerstone objective because the loss of the 1B-B shutdown board caused the inoperability of the B train of the onsite electrical distribution system and also resulted in the inoperability of all B train structures, systems, or components (SSCs) powered from the 1B-B shutdown board. The inspectors performed an initial screening of the finding and determined that this finding was of very low safety significance (Green) because the finding did not represent an actual loss of function of a single train for greater than its technical specification (TS) allowed outage time. The finding had a cross-cutting aspect in the Work Management component of the Human Performance area because the licensee failed to implement a process of planning, controlling, and executing work activities such that nuclear safety is the overriding priority. Specifically, the process of planning and executing the work activities for Design Change Notice (DCN) 64063 failed to identify and manage the risk associated with system restoration due to either equipment failure or personnel error (H.5).
05000250/FIN-2016003-032016Q3Turkey PointImproper ECC Fuse InstallationA self-revealed Green finding and associated Non-cited Violation (NCV) of Technical Specification (TS) Limiting Condition for Operation (LCO) 3.6.2.2 was identified for the failure to properly insert the control power fuse for the 3B Emergency Containment Cooler (ECC) fan. The ECC unit was determined to be inoperable for greater than the allowed outage time of 72 hours and the actions required by TS LCO 3.6.2.2, Action A, were not taken. An immediate corrective action was taken to adjust the fuse holder clips on the 3B ECC breaker to provide a tight fit. Additional corrective actions initiated by the licensee in AR 2108256 included a review of recently replaced similar breakers on Units 3 and 4 to identify and schedule inspection of fuse tightness. The inspectors determined that the finding was more than minor because it was associated with the Mitigating Systems cornerstone attribute of Equipment Performance and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the 3B ECC was not available to automatically start upon receipt of a safety injection signal, and during periods with two ECCs concurrently inoperable, the ECC system would not have been able to perform its specified safety function. To determine the significance of the finding, a Senior Reactor Analyst performed a bounding risk assessment by failing all three containment coolers in the Turkey Point Standardized Plant Analysis Risk (SPAR) model for the entire exposure time of 72 days. The dominant accident sequence was a very small loss of coolant accident (LOCA) where high head safety injection fails for independent reasons. The delta-core damage frequency (CDF) due to the performance deficiency was 1E-8. The low risk result was driven by the low frequency of LOCAs, the limited exposure time, and the low risk value of the containment coolers themselves. The finding was determined to be of very low safety significance (Green). This finding was assigned a cross cutting aspect associated with the avoid complacency element of the human performance area because the licensee failed to confirm fuse holder tightness following implementation of breaker maintenance. The licenee failed to recognize and plan for the possibility of mistakes, latent issues, and inherent risk, even while executing successful outcomes.
05000251/FIN-2016003-012016Q3Turkey PointFailure to provide adequate flood protection for the 4A RHR trainThe NRC inspectors identified a non-cited violation (NCV) of Technical Specification (TS) 6.8.1, for the licensees failure to implement required housekeeping controls in the 4A residual heat removal (RHR) pump room to ensure flood protection devices would not be damaged or otherwised clogged. Specifically, the licensees failure to adequately implement station housekeeping procedure MA-AA-100-1008 to ensure flood protection devices in the 4A RHR pump room were not challenged was a performance deficiency. Immediate corrective actions included removing the debris, entering this issue into the corrective action program (CAP), and initiating a past-operability review. The inspectors determined the performance deficiency to be more than minor because it was associated with the protection against external factors attribute of the mitigating systems cornerstone and there was reasonable doubt of operability which if left uncorrected could have adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Using Manual Chapter 0609, Appendix A, The Significance Determination Process for Findings-At-Power, the inspectors screened the finding as Green because it did not involve the total loss of any safety function. The inspectors assigned a cross cutting aspect in the area of human performance associated with the work management element because the organization failed to adequately implement a process to control work activities in a high-risk flood area, and did not adequately identify and manage risk associated with the flood-sensitive area (H.5) (Section 1R06).
05000250/FIN-2016003-022016Q3Turkey PointCommunication of an NRC Inspector Presence by Security PersonnelThe NRC identified an NCV of 10 CFR 50.70, Inspections, paragraph (b)(4), for the licensees failure to ensure that the arrival and presence of an NRC inspector is not communicated to persons at the facility. The licensees actions of announcing the presence and location of an NRC inspector during an unannounced inspection in the protected area was a performance deficiency. Interim corrective actions included providing a site-wide communication to all employess and providing training briefs during shift turnovers informing employees of the regulation. The licensee entered this issue into the CAP as AR 2155881. The NRC evaluated this issue under the traditional enforcement process because the act of announcing NRC presence could impact NRC ability to perform its regulatory function. Specifically, the NRC relies on its ability to perform unannounced inspections to evaluate licensee performance, and communicating the presence and location of NRC inspectors affects their ability to perform these inspections, and as such the regulatory function is impacted. Because the violation was determined to be of very low safety significance, was not repetitive or willful, and was entered into the CAP, this violation is being treated as a Severity Level IV non-cited violation consistent with the NRC Enforcement Policy. This violation was evaluated under the traditional enforcement process and thus does not have a cross cutting aspect (Section 4OA2).
05000346/FIN-2013002-012013Q1Davis BesseFailure to Maintain Station Blackout Diesel Generator Output Cables in an Environment Consistent with DesignThe inspectors identified a finding of very low safety significance for the licensees failure to maintain normally energized medium voltage cables BPGD302C, C1, D, and D1 in an environment consistent with the cable design. The cables, which are output cables for the station blackout diesel generator (SBODG), were not designed for long-term water submergence, and were in an electrical manhole that was flooded for a period of several months, perhaps as long as a year or more. Continuous water submergence of energized medium voltage cables not designed for water submergence can accelerate deterioration of such cables and potentially affect the ability of the cables to withstand electrical transients. The licensees procedures and programs for medium voltage cables did recognize the issue and provided a sump pump to address water intrusion into the electrical manhole, but did not provide for any preventative maintenance (PM) or operational checks of the sump pump to ensure its capability to meet its intended function. In response to the finding the licensee increased the frequency of monitoring for water in the manhole. No violation of NRC requirements was identified. The finding was determined to be more than minor because the finding was associated with the Mitigating Systems Cornerstone attribute of equipment performance and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the SBODG was to provide electrical power to emergency core cooling systems in the event of a loss of all alternating current power. The inspectors determined that the finding was of very low safety significance because it was not a deficiency affecting the design or qualification of the SBODG and there was no loss of any system or function due to the flooded conditions of the cables. The finding was determined to have a cross-cutting aspect in the area of Human Performance, Work Control Component, because the licensee failed to appropriately coordinate the impact of changes to the work scope or activity on the plant. Specifically, although the licensees intent was to address potential water submergence of energized medium voltage risk-significant cables to reduce the risk of early cable failure through the installation of a permanent sump pump, the licensee failed to schedule and coordinate the appropriate PM for the pump when it was installed.
05000346/FIN-2013002-022013Q1Davis BesseContainment Isolation Valve Rendered Inoperable by Wrong Component Operator ErrorA self-revealed finding of very low safety significance and associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, Drawings, were identified for the licensees failure to properly implement the procedure for the Hydrogen Dilution System Train 1 quarterly surveillance test. Specifically, a non-licensed operator inadvertently repositioned the incorrect motor-operated valve (MOV) and caused an unplanned entry into Technical Specifications (TS) Limiting Condition for Operation (LCO) 3.6.3, Condition A, for an inoperable component cooling water (CCW) containment isolation valve (CIV). Upon identification, the valve was tested and returned to operable status within the TS allowable time. The finding was determined to be more than minor because, if left uncorrected, the failure to follow plant procedures and the mispositioning of plant equipment would have the potential to lead to a more significant safety concern. This finding was associated with the Barrier Integrity Cornerstone because a CIV forms part of the containment pressure boundary that provides reasonable assurance that the physical design barriers protect the public from radionuclide releases caused by accident or events. The inspectors evaluated the finding using IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power. The inspectors used Exhibit 3 Barrier Integrity Screening Questions for the reactor containment. The finding screened as very low safety significance (Green) because there was no actual open pathway in the physical integrity of reactor containment, containment isolation system, or heat removal components; and there was no impact on the hydrogen control function in containment. This finding had a cross-cutting aspect in the area of Human Performance, Work Practices Component, because personnel failed to use human error prevention techniques to ensure that work was performed safely.
05000346/FIN-2013002-032013Q1Davis BesseLicensee-Identified ViolationThe requirements of the NRC Maintenance Rule, 10 CFR 50.65(a)(4) state, in part, that the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activities. Contrary to this requirement, on January 28, 2013, the licensees probabilistic risk assessment did not accurately reflect the increase in online probabilistic risk associated with startup transformer X01 being unavailable during planned maintenance. Specifically, while removing the 345 kV Lemoyne transmission line from service for planned maintenance, startup transformer X01 unavailability during switchyard manipulations was inadvertently omitted from the stations risk assessment. Re-performance of the risk assessment after the switchyard manipulations were already completed indicated that an elevated yellow risk category that required additional work controls had actually existed for approximately 16 minutes during the switchyard manipulations. Licensee personnel initiated CR 2013-01309 to document the issue. The objective of the Mitigating Systems Cornerstone of Reactor Safety is to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). A key attribute of this objective is equipment performance and availability. Using IMC 0609, Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process, the inspectors determined that the violation was of very low safety significance since the incremental core damage probability deficit calculated for the issue was less than 1E-6.
05000346/FIN-2013002-042013Q1Davis BesseLicensee-Identified ViolationTechnical Specification 5.4.1(a) requires the licensee to establish, implement, and maintain applicable written procedures for the safety-related systems and activities recommended in Regulatory Guide (RG) 1.33, Revision 2, Appendix A. Section 9(a), Procedures for Performing Maintenance, of RG 1.33, Revision 2, Appendix A, further states, in part, that: Maintenance that can affect the performance of safety-related equipment should be properly preplanned and performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances. Contrary to this requirement, during the 17th midcycle outage in the fall of 2011 for DH Train 1 and the 17th refuel outage in the spring of 2012 for DH Train 2, the licensees instructions for replacing the DH pump mechanical seal flow cyclone separators failed to provide sufficient details to ensure that required internal spacers were installed as required. The omission of the spacers subjected the DH pump mechanical seal flow cyclone separators to potential debris-induced clogging, thereby reducing the reliability of the DH pumps themselves. The objective of the Mitigating Systems Cornerstone of Reactor Safety is to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). A key attribute of this objective is human performance, and specifically, procedure quality. In accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, and Appendix A, The SDP for Findings At-Power, the inspectors determined that the violation was of more than minor significance in that it had a direct impact on this cornerstone objective. The licensees failure to provide adequately detailed written procedures and instructions for the replacement of the DH pump mechanical seal flow cyclone separators adversely impacted the reliability of each DH pump, as discussed in the paragraph above. The licensee had entered this issue into their CAP as CR 2012-18831. Corrective actions planned or completed by the licensee included revisions to the applicable drawings and work instructions associated with this activity.
05000346/FIN-2012005-022012Q4Davis BesseDecay Heat Pump Cyclone Separators Incorrectly InstalledOn December 3, 2012, while servicing the No. 2 DH pump mechanical seal, the licensee identified that the cyclone separator had been installed upside down during a past maintenance activity dating back to May 12, 2012. Additionally, on December 6, 2012, while correcting the orientation of the cyclone separator, licensee mechanical maintenance personnel discovered that spacers were also missing from the inlet and dirty drain lines of the cyclone separator. The spacers are intended to fill unused space between the body of the separator and the tube fittings that connect the tubing. Empty spaces in these areas could collect debris under accident conditions and prevent cooling flow to the mechanical seal. An extent of condition inspection was performed on the No. 1 DH pump on December 14, 2012, which identified the spacers were also missing from the cyclone separators. The most recent maintenance activity on the No. 1 DH pump cyclone separators occurred during the last quarter of 2011, during a mid-cycle outage to replace the reactor vessel closure head. On December 14, 2012, the licensee made a voluntary report to the NRC via telephone regarding the potential impact to the past operability of both DH pumps. A subsequent investigation by the licensee determined the condition did not render the DH pumps inoperable. However, a considerable amount of engineering analysis/judgment was used to predict the consequences of running the DH pumps without seal cooling from the cyclone separators and achieve this conclusion. Based on the expected pump operating conditions during an accident, the licensees analyses concluded that breakage of the seal faces would not occur. As such, leakage out from the pump seals would remain below the allowable leakage rate determined by the licensees design basis calculations. An update was made to the voluntary report to the NRC reflecting this position. The cyclone separator condition was immediately corrected for each pump upon discovery. The licensee has entered the conditions into the CAP and assigned a root cause analysis to CR 2012-18831. Because the licensees root cause analysis was still in progress at the end of this inspection period, the issue is being treated as an unresolved item (URI) pending the inspectors review of the licensees root cause report and completion of the inspectors review of the licensees evaluation into the past operability of the DH pumps. (URI 05000346/2012005-02).
05000346/FIN-2012005-042012Q4Davis BesseLicensee-Identified ViolationTechnical Specification 5.4.1(a) requires the licensee to establish, implement, and maintain applicable written procedures for the safety-related systems and activities recommended in Regulatory Guide (RG) 1.33, Revision 2, Appendix A. Section 9(a), Procedures for Performing Maintenance, of RG 1.33, Revision 2, Appendix A, further states, in part, that: Maintenance that can affect the performance of safety-related equipment should be properly preplanned and performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances. Contrary to this requirement, during the week ending November 17, 2012, the licensees instructions for replacing the lube oil cooler left bank side jacket water inlet o-ring seal on EDG No. 1 via WO no. 200493894 improperly called for a metal-to-metal joint fit up. Specifically, the EDG vendors instructions, which were translated into the licensees work instructions to maintenance personnel, were imprecise and confusing. In one location, the vendors instructions specified a metal-to-metal joint fit up, while in another location a 1/16th inch gap was specified. This lack of clarity in the work instructions caused the joint to leak three times before it was finally able to be properly sealed on the fourth iteration. The additional iterations for the performance of this work added significant time to the periods of inoperability and unavailability for EDG No. 1, and caused the licensee to make an unplanned entry into an elevated (i.e., Orange) plant risk awareness state.
05000346/FIN-2012005-032012Q4Davis BesseLicensee-Identified ViolationAppendix B of 10 CFR Part 50, Criterion III, Design Control, requires, in part, that measures shall be established to assure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions. Contrary to this, on October 17, 2012, the licensee identified the requirements associated with dynamic loading contained in the original construction code of the CS ring header were not incorporated into the specifications of the system and initiated CR 2012-16439. Specifically, the licensee failed to determine the resultant dynamic loads introduced on CS ring header upon system actuation. The performance deficiency was determined to be more than minor because it was associated with the Containment Barrier cornerstone attribute of structures, systems, components, and barrier performance and affected the cornerstone objective of providing reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. The finding screened as of very low safety significance because the dynamic loading was verified to be within the capability of the piping design.
05000346/FIN-2012005-012012Q4Davis BesseOperator Error in Response to a Small Power Transient Momentarily Renders TS Equipment InoperableA self-revealed finding of very low safety significance and an associated NCV of Technical Specification (TS) 5.4.1(a) were identified following the control room crews response to a small power rise that occurred while shifting the plants Integrated Control System (ICS) to the track mode of operation on October 24, 2012. Specifically, the Unit Supervisor, a licensed senior reactor operator (SRO), directed an on-shift reactor operator (RO) to place the Steam Generator/Reactor Demand control station for the ICS in manual and lower power in response to the observed reactor power increase. However, because the plants control rod drive (CRD) control station (known as the Diamond panel) was already in manual as part of the planned ICS transfer to track mode, the signal from the Steam Generator/Reactor Demand control station only was passed through to the Feedwater (FW) System and not to the CRD System. As a result, average coolant temperature and pressurizer level both rose due to a mismatch between reactor power and steam generator power and caused an unplanned short-duration entry into TS Limiting Condition for Operation (LCO) 3.4.9, Condition A, for pressurizer level above the TS limit of 228 inches. The condition was corrected and corrective action program documents generated to review the event. This finding was associated with the Initiating Events Cornerstone of reactor safety and was of more than minor significance because it directly impacted 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. The inspectors reviewed this finding using the guidance contained in Appendix B, Issue Screening, of IMC 0612, Power Reactor Inspection Reports. The inspectors determined that the licensees incorrect actions in attempting to respond to the power transient by taking the Steam Generator/Reactor Demand control station for the ICS to manual and attempting to reduce power using that station with the Diamond panel in manual was a performance deficiency that was reasonably within the licensees ability to foresee and correct and should have been prevented. The finding screened as very low safety significance (Green) because it did not adversely impact any of the following parameters: Loss-of-Coolant Accident initiators; Transient initiators; Support System Loss initiators; Steam Generator Tube Rupture initiators; or External Event Initiators. The finding had a cross-cutting aspect in the area of problem identification and resolution, corrective action program (CAP) component, because the licensee failed to take corrective action for the ICS/Unit Load Demand (ULD) power error anomaly in a timely manner, commensurate with the issues safety significance and complexity.
05000346/FIN-2012004-042012Q3Davis BesseLicensee-Identified ViolationInadequate Design Control Results in Reactor Coolant System Pressure Boundary Leakage From Reactor Coolant Pump Seal Piping Socket Weld Appendix B to 10 CFR Part 50, Criterion III, Design Control, requires, in part, that the licensee establish measures for the selection and review for suitability of application of materials, parts, equipment, and processes that are essential to the safety-related functions of SSCs. Criterion III further requires that design changes, including field changes, shall be subject to design control measures commensurate with those applied to the original design. As discussed in Section 4OA3.2 of this report, contrary to this requirement, licensee personnel failed to properly review the suitability of a modification that was performed to their RCP seal cavity vent lines to accommodate a new style of RCP seal package in 1990. Specifically, the RCP seal cavity vent lines were lengthened by approximately five inches, and the licensees engineering design personnel failed to consider what the impact of changing the small bore (i.e., 34 inch diameter) piping length would have on the piping resonance frequencies and the piping socket welded connections. Industry operating experience has shown that minor changes to small bore piping can result in higher amplitude vibrations, potentially resulting in high-cycle fatigue failure. A licensee causal evaluation team concluded that a pinhole leak through a socket weld on the RCP 1-2 first stage seal cavity vent line that occurred on June 6, 2012, was most probably this kind of high-cycle fatigue failure. The objective of the Barrier Integrity Cornerstone of Reactor Safety is to provide reasonable assurance that physical design barriers (fuel cladding, RCS, and containment) protect the public from radionuclide releases caused by accidents or events. Key attributes of this objective are design control, and specifically plant modifications, and RCS equipment and barrier performance. In accordance with NRC IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, the inspectors determined that the violation was of more than minor significance in that it had a direct impact on this cornerstone objective. The licensees failure to consider what the impact of changing the small bore piping length would have on the piping resonance frequencies and the piping socket welded connections resulted in a pinhole failure of the RCS pressure boundary, and compromised the RCS barrier performance. The inspectors also determined that since the licensees performance deficiency had occurred in 1990, the licensee-identified violation constituted an Old Design Issue, as defined by the NRC Enforcement Policy, which was not indicative of current licensee performance. As discussed in Section 4OA3.2 of this report, the licensee had entered this issue into their CAP as CR 2012-09381. Immediate corrective actions taken by the licensee included repair of the leak on the RCP 1-2 first stage seal cavity vent line, as well as inspections of all similar RCP seal cavity vent lines for any signs of leakage. The licensee has plans to replace all of the current RCP seal cavity vent lines with flex hose connections during the next refuel outage in 2014.
05000346/FIN-2012004-032012Q3Davis BesseLicensee-Identified ViolationInadequate Administrative Controls Result in Inoperable Emergency Diesel Generator and Essential Direct Current Distribution Equipment During Movement of Irradiated Fuel Assemblies Technical Specification 3.8.2, AC Sources Shutdown, LCO 3.8.2(b) requires that one EDG capable of supplying one train of the onsite Class 1E ac electrical power distribution subsystems required by LCO 3.8.10 be maintained operable in Modes 5 and 6, and during the movement of irradiated fuel assemblies. Inadequate Administrative Controls Result in Inoperable Emergency Diesel Generator and Essential Direct Current Distribution Equipment During Movement of Irradiated Fuel Assemblies As discussed in Section 4OA3.1 of this report, contrary to this requirement, licensee personnel failed to maintain EDG No.1 operable during the movement of irradiated fuel assemblies from approximately 10:31 p.m. on May 19, 2012, until all movement of irradiated fuel was completed at approximately 6:00 p.m. on May 20, 2012, and then again during the movement of irradiated fuel assemblies in the SFP during various periods on May 21 22, 2012. A licensee causal evaluation team concluded that this error resulted from less than adequate administrative controls for maintaining dc system power source operability with the distribution network cross-tied while in the cold shutdown and refueling plant conditions. The objective of the Mitigating Systems Cornerstone of Reactor Safety is to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). A key attribute of this objective is configuration control, and specifically, control of operating and shutdown equipment alignment. In accordance with NRC IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, the inspectors determined that the violation was of more than minor significance in that it had a direct impact on this cornerstone objective. The licensees failure to maintain adequate administrative control over the operability of DC Train No. 1, such that it was allowed to be realigned to support EDG No. 1 operability without first being declared operable itself, caused EDG No. 1 to be rendered inoperable when it was required by TS to be operable during periods of irradiated fuel movement. As discussed in Section 4OA3.1 of this report, the licensee had entered this issue into their CAP as CR 2012-08422. Immediate corrective actions taken by the licensee included placing a hold on the movement of irradiated fuel assemblies in the SFP, and initiation of a Mode 6 entry hold to preclude core refueling until the issue could be resolved. In addition, the licensee immediately began performing the reviews necessary to support TS operability for DC Train No. 1. Other subsequent corrective actions performed by the licensee included a revision to the station DC switching procedure to ensure operability prior to distribution panel transfers, revision to applicable pre-job briefings, enhancements to the outage schedule to address DC power source availability, and a case study on DC system restoration during outages.
05000346/FIN-2012004-022012Q3Davis BesseFailure to Use Material Specified Minimum Yield Stress in Structural DesignThe inspectors identified a finding of very low safety significance and associated NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to use material specified minimum yield stress in accordance with American Institute for Steel Construction design standards in evaluations of safety-related structural components. The licensee entered this issue into their corrective action program (CAP) as condition reports (CRs) 2011-98333 and 2012-13249 and initiated corrective actions to resolve identified design standard non-conformance. The finding was determined to be more than minor because the finding was associated with the Barrier Integrity Cornerstone attribute of design control and affected the cornerstone objective of providing reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, compliance with the design standards ensured safety-related structures would function as designed during accident and maximum seismic conditions. The finding was considered to be of very low safety significance since this was a design deficiency confirmed to not result in a loss of operability or functionality. The inspectors determined there was no cross-cutting aspect associated with this finding because the cause of the performance deficiency was the licensees revision to the Updated Safety Analysis Report (USAR) that allowed certified material test report yield strength in structural design calculations which was not reflective of current licensee performance due to the age of the revision.
05000346/FIN-2012004-012012Q3Davis BesseOperator Error Restoring Essential MCC to Service Renders TS Equipment InoperableA self-revealed finding of very low safety significance and an associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, were identified for the licensees failure to properly implement the procedure for restoring power to motor control center (MCC) E16B. Specifically, the operator repositioned circuit breakers at the incorrect MCC, inadvertently removing power from plant equipment supplied by MCC E16A and causing an unplanned entry into Technical Specification (TS) Limiting Condition for Operation (LCO) 3.3.15, Condition A, for an inoperable channel of station vent normal range radiation monitoring. As an immediate corrective action, the operating crew performed steps to restore the unintentionally lost loads associated with MCC E16A and exited LCO 3.3.15 Condition A in a timely manner. This finding was associated with the Barrier Integrity Cornerstone because a high radiation level in the station vent, as measured by the radiation monitors, is used to detect a potential threat to control room personnel and automatically isolate the control room normal ventilation system. The inspectors determined that the finding was more than minor because, if left uncorrected, the failure to follow plant procedures and the mispositioning of plant equipment would have the potential to lead to a more significant safety concern. The inspectors evaluated the finding using IMC 0609, Appendix A, the Significance Determination Process for Findings At-Power. The inspectors used Exhibit 2 Barrier Integrity Screening Questions for the Control Room, Auxiliary, Reactor, or Spent Fuel Pool Building. The finding screened as very low safety significance (Green) because it only represented a degradation of the radiological barrier function provided for the control room. The finding had a cross-cutting aspect in the area of human performance, work practices component, because personnel failed to use human error prevention techniques to ensure that work was performed safely.
05000346/FIN-2012003-012012Q2Davis BesseOil Sample Drawn from Running RCP Resulted in Entry Into Abnormal Operating Procedure and RCP ShutdownA self-revealed finding of very low safety significance was identified for the licensees failure to establish and implement technically appropriate work instructions for the drawing of oil samples from the reactor coolant pump (RCP) lower bearing reservoirs, such that when an oil sample was drawn from the RCP 1-2 lower motor bearing on May 6, 2012, the lower motor bearing was damaged by the excessive heat generated due to a lack of adequate lubrication, and control room operators were forced to conduct a rapid shutdown of the pump. Specifically, the approved work instructions called for the oil sample to be obtained with the RCP running, a practice contrary to the manufacturers recommendations. A self-revealed finding of very low safety significance was identified for the licensees failure to establish and implement technically appropriate work instructions for the drawing of oil samples from the reactor coolant pump (RCP) lower bearing reservoirs, such that when an oil sample was drawn from the RCP 1-2 lower motor bearing on May 6, 2012, the lower motor bearing was damaged by the excessive heat generated due to a lack of adequate lubrication, and control room operators were forced to conduct a rapid shutdown of the pump. Specifically, the approved work instructions called for the oil sample to be obtained with the RCP running, a practice contrary to the manufacturers recommendations. licensees own nuclear fleet, that indicated the risk associated with obtaining oil samples from running RCPs, but these risk insights were not utilized. (H.3(a))
05000346/FIN-2012003-022012Q2Davis BesseN/AThe NRC Maintenance Rule, 10 CFR 50.65(a)(4), states that before performing maintenance activities (including but not limited to surveillance, post-maintenance testing and corrective and preventive maintenance), the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activities. Contrary to the above, on June 27, 2012, the licensee failed to assess and manage the risk associated with having Startup Transformer 02 and HPI Pump 1 unavailable at the same time. The two activities were not originally scheduled to occur simultaneously, and the licensees probabilistic risk assessment (PRA) separately evaluated these activities as Green PRA risk. However, the maintenance to the Ohio Edison offisite power line (causing Startup Transformer 02 unavailability) was moved up one day in the schedule. Also, the HPI Pump 1 testing ran later than expected and crossed into the time when Startup Transformer 02 was unavailable. The station was in Yellow PRA risk for approximately 14 minutes. Although the appropriate oversight for each activity was already assigned, risk was not managed correctly because plant personnel remained unaware of the change to Yellow risk. The licensee failed to make procedurally required communications such as unit log entries, plant public address system announcements, and changes to the station risk status display at the sites Primary Access Facility. The inspectors reviewed this issue using the guidance contained in Appendix B, Issue Screening, of Inspection Manual Chapter (IMC) 0612, Power Reactor Inspection Reports. The inspectors determined that the violation was more than minor because the performance deficiency was sufficiently similar to the more-than-minor example 7.e in Appendix E of IMC 0612. Specifically, the overall elevated plant risk put the plant into a higher licensee-established risk category. The finding screened as very low safety significance (Green) using IMC 0609, Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process, using flowchart 1 for the assessment of risk deficit. The licensee had entered this issue into their CAP as CR 2012-10360. A late entry into the unit narrative log was made on June 28, 2012, documenting the unscheduled yellow PRA risk.
05000341/FIN-2012003-032012Q2FermiFailure to Monitor Reactor Pressure during Reactor Pressure Vessel Hydrostatic TestA self-revealed Green finding and associated NCV of Technical Specification (TS) 5.4.1.a was identified for the licensees failure to establish and implement procedures recommended by Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Specifically, the licensee failed to control reactor pressure in the band specified in the reactor pressure vessel hydrostatic test procedure. A valid high pressure reactor scram actuation was received after operators failed to recognize that the reactor pressure vessel pressure instrument being monitored became inaccurate. Immediately after the scram, operators stabilized the plant at approximately 600 psig and reset the reactor scram. The licensee entered this issue into their corrective action program as CARD 12-23824. The inspectors evaluated the finding using IMC 0609, Appendix G, Attachment 1, Shutdown Operations Significance Determination Process - Phase 1 Operational Checklists for Both Power Water Reactors (PWRs) and Boiling Water Reactors (BWRs). The inspectors consulted Checklist 8, BWR Cold Shutdown or Refueling Operation; Time to Boil > 2 Hours: RCS Level < 23\' Above Top of Flange. The inspectors determined the finding did not adversely impact any shutdown defense-in-depth or mitigation attributes on the checklist, nor did it meet any of the checklist specific requirements for a Phase 2 or Phase 3 SDP analysis. Consequently, the finding was determined to be of very low safety significance. This finding has a cross-cutting aspect in the area of human performance, work practices component, because the licensee failed to use human error prevention techniques commensurate with the risk of the assigned task, such that activities are performed safely. Specifically, the licensee failed to monitor the specified primary instrumentation for critical plant parameters.
05000341/FIN-2012003-022012Q2FermiEnergizing Bus 65E with Ground Truck Installed and Subsequent Loss of Shutdown CoolingA self-revealed Green finding and associated NCV of 10 CFR 50 Appendix B, Section V, Instructions, Procedures, and Drawings, for failure to follow procedures when the licensee energized a safety-related electrical bus with a ground truck installed in bus 65E breaker position E4. This resulted in the loss of the safety-related bus and a temporary loss of shutdown cooling. The licensee failed to comply with sequence step 61 of Safety Tagging Record 2012-001122, which had connected a ground truck in bus 65E position E4 and installed a red danger tag. The Operations Conduct Manual, Chapter 12 (MOP12), 3.6.2 specifies that red tagged equipment is not to be operated. The licensee entered this item into their corrective action program as CARD 12-23118. The inspectors determined this finding was more than minor because it was associated with the configuration control attribute of the Mitigating Systems Cornerstone and impacted the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). This finding was determined to be of very low safety significance because, following IMC 0609, Appendix G, Attachment 1, Shutdown Operations Significance Determination Process Phase 1 Operational Checklist for both PWRs and BWRs, concluded the finding did not require quantitative assessment. Therefore, the finding was determined to be of very low safety significance. This finding has a cross-cutting aspect in the area of Human Performance, Work Practices, supervisory and management oversight aspect because the licensee failed to appropriately oversee the proper clearance of Safety Tagging Record 2012-001122
05000341/FIN-2012003-012012Q2FermiControl Rod 10-35 Failure to ScramOn October 24, 2010, control rod 10-35 failed to insert upon actuation of an automatic reactor scram caused by loss of condenser vacuum (CARD10-29509). An emergent issue team was formed to investigate this event. The apparent cause was determined to be a hydraulic lock caused by blockage in the flow path between the control rod drive mechanism and the scram discharge volume. The investigation never found any foreign material, but postulated that the likely foreign material was discharged into the scram discharge volume, ultimately ending up in the torus room sump. As a corrective action, for cycle 15 the licensee increased the frequency of performing TS surveillance SR 3.1.4.2 scram time testing to every 100 days, adjusted the representative sample size to assure all rods would be tested during cycle 15, and included control rod 10-35 in each quarterly scram time testing sample. On November 18, 2011, the control rod failed to fully insert during scram time testing. The rod was fully inserted and remained there for the rest of the cycle. The inspectors are waiting for the licensees evaluation of this event, specifically their conclusions regarding the foreign material found, and their evaluation of how the foreign material could have been present, causing the first event, but migrated to allow successful scram time testing on November 11, 2010, and the first three quarters of 2011 before finally causing the failure identified on November 18, 2011. Because the licensee had not completed their evaluation, this issue is being treated as an unresolved (URI) item.
05000346/FIN-2012002-012012Q1Davis BesseSeismic Instrumentation Unavailable for Emergency Event ClassificationThe inspectors identified a finding of very low safety significance and an associated NCV of 10 CFR 50.54(q) for failing to follow and maintain an emergency plan that meets the requirements of emergency planning standard 10 CFR 50.47(b)(4). Specifically, the licensee failed to maintain configuration control of seismic instrumentation necessary for the declaration of emergency events. The seismic instrumentation was out of service without the knowledge of the on-shift operating crew and no compensatory measures were in place. The licensee entered this performance deficiency into their corrective action program (CAP) as condition report (CR) 2012-01950 and CR 2012-01984. The inspectors determined that the issue was a performance deficiency as it was within the licensees ability to foresee and correct. This finding was determined to be more than minor because it was associated with the emergency response organization (ERO) performance attribute of the Emergency Preparedness Cornerstone. This finding affected the cornerstone objective of ensuring the licensee is capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. The finding is of very low safety significance because it did not result in the loss or degradation of a risk significant planning standard. One Alert and one Notification of Unusual Event Emergency Action Level (EAL) initiating condition would have been rendered ineffective such that a seismic event would have been declared in a degraded manner. This finding was also associated with the cross-cutting area of human performance. Specifically, the licensees work control process failed to appropriately control work on the seismic monitoring system. This resulted in a loss of configuration control and of instrumentation necessary to classify a seismic event without compensatory measures in place.
05000346/FIN-2012002-022012Q1Davis BesseFailure to Maintain SAFETY-RELATED DC Systems Design ControlThe inspectors identified a finding, with two examples, of very low safety significance and associated Non-Cited Violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the failure to maintain the electrical separation of the redundant safety-related direct current (DC) systems in compliance to the design and licensing bases. The licensee initiated corrective actions including opening the breakers to the non-safety-related loads inside containment and setting the automatic transfer switches (ATSs) to prevent auto-transfer of loads. The performance deficiency was determined to be more than minor because the issue was associated with the Mitigating Systems Cornerstone attribute of design control, and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to address the impact of high-impedance ground faults in non-safety equipment on safety-related DC sources and the failure to maintain compliance to RG1.6 when installing ATSs between redundant DC power sources impacted the reliability of the DC power system. The inspectors evaluated the finding to be of very low safety significance (Green) using IMC 0609, Appendix A, Attachment 1, Significance Determination of Reactor Inspection Findings for At-Power Situations. Using the Phase 1 SDP worksheet for the Mitigating Systems Cornerstone, the inspectors answered no to all five screening questions. Based on the date of occurrence of this violation (more than 20 years old), the inspectors did not identify a cross-cutting aspect as the finding was not representative of current performance.
05000346/FIN-2012002-032012Q1Davis BesseAdditional Emergency Diesel Generator Inoperability Caused by Inadequate Maintenance Procedure InstructionsTS 5.4.1(a) requires the licensee to establish, implement, and maintain applicable written procedures for the safety-related systems and activities recommended in Regulatory Guide (RG) 1.33, Revision 2, Appendix A. Section 9.a, Procedures for Performing Maintenance, of RG 1.33, Revision 2, Appendix A, further states, in part, that: Maintenance that can affect the performance of safety-related equipment should be properly preplanned and performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances. Contrary to this requirement, on January 26, 2012, licensee personnel failed to properly connect a strip chart recording device needed to support a planned TS surveillance on EDG No. 2. Specifically, the improper connection on the recording equipment caused test data essential to the completion of the TS surveillance to be lost, which resulted in the need to perform the surveillance a second time. This additional performance of the surveillance added significant time to the periods of inoperability and unavailability for EDG No. 2, and caused the licensee to make an unplanned entry into an elevated (i.e., Orange) plant risk awareness state. Upon investigation into the matter, the licensee identified that the applicable maintenance procedure controlling the connection of the strip chart recording equipment only contained detailed connection instructions for the test connections on the EDG itself; the proper configuration for the test connections on the recording equipment was not specified within the procedure, but instead was left to the skill and knowledge of the technician performing the equipment setup. The objective of the Mitigating Systems Cornerstone of Reactor Safety is to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). A key attribute of this objective is human performance, and specifically, procedure quality. In accordance with NRC IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, the inspectors determined that the violation was of more than minor significance in that it had a direct impact on this cornerstone objective. The licensees failure to provide technically adequate written procedures and instructions for the connection of the strip chart recording device needed for the EDG No. 2 TS surveillance resulted in the need to perform that surveillance a second time and added significant time to the periods of inoperability and unavailability for EDG No. 2. The licensee had entered this issue into their CAP as CR 2012-01367. Corrective actions planned or completed by the licensee include revision to the EDG TS surveillance procedure to provide enhanced details on the proper connection of the strip chart recording device.
05000346/FIN-2012002-042012Q1Davis BesseInadequate Control of Locked High Radiation Area KeyTS 5.7.2(a)(1) requires that High Radiation Areas with dose rates greater than 1.0 rem/hour at 30 centimeters from the radiation source or from any surface penetrated by the radiation, but less than 500 rads/hour at 1 meter from the radiation source or from any surface penetrated by the radiation be provided with a locked or continuously guarded door, gate, or other barrier that prevents unauthorized entry, and in addition, that the door and/or gate keys to these areas be maintained under the administrative control of the shift supervisor, radiation protection manager, or his/her designee. Contrary to this requirement, on February 15, 2012, licensee personnel failed to properly control the key to a Locked High Radiation Area vault storing a high integrity container loaded with primary resin. Specifically, a Radiation Protection (RP) technician checked out the subject key at the beginning of the work shift in order to access the Locked High Radiation Area vault for a planned evolution. At the end of the shift, the RP technician failed to return the key to the appropriate secure key storage cabinet, instead leaving it in an unsecured desk drawer. Several hours later when the key was identified as being missing, the RP technician, who had left the plant, was contacted and the key was recovered. At no point during the time the key was uncontrolled was the Locked High Radiation Area vault, which can only be accessed by the removal of a twenty-two ton cover, opened and improperly accessed. The objective of the Occupational Radiation Safety Cornerstone of Radiation Safety is to ensure the adequate protection of the worker health and safety from exposure to radiation from radioactive material during routine civilian nuclear reactor operation. A key attribute of this objective is human performance, and specifically, procedure use and adherence. In accordance with NRC IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, the inspectors determined that the violation was of more than minor significance in that it had a direct impact on this cornerstone objective. The licensees failure to appropriately control the key to a Locked High Radiation Area vault storing a high integrity container loaded with primary resin per established plant procedures resulted in the potential for unauthorized access to a High Radiation Area with a dose rate greater than 1.0 rem/hour at 30 centimeters from the radiation source or from any surface penetrated by the radiation, but less than 500 rads/hour at 1 meter from the radiation source or from any surface penetrated by the radiation. The licensee had entered this issue into their CAP as CR 2012-02489. Corrective actions planned or completed by the licensee include the performance of a formal apparent cause evaluation, enhancements to procedural controls for Locked High Radiation Area keys, and additional training for RP personnel.
05000341/FIN-2012002-022012Q1FermiLicensee-Identified ViolationTS 3.3.1.2, Table 3.3.1.2-1 requires functional testing of TS 3.3.1.2. Table 3.3.1.2-1 requires functional testing of the source range monitors (SRMs) to be conducted within 12 hours following shutdown. Enclosure A, Section 2.E.1 of MWC 13, Outage Nuclear Safety specifies requirements that, in Mode 4, at least three SRM channels are maintained operable. Enclosure D, Risk Assessment, of MWC 13 requires written risk management actions to operate with less than three operable SRMs. Contrary to the above, on March 26, 2012, the licensees operators failed to properly assess the risk impact of losing three SRMs in Mode 4 due to a failure of the SRM drive-in pushbutton in accordance with Title 10 CFR 50.65(a)(4). Specifically, the licensee did not properly recognize the risk impact on the outage defense-in-depth requirements of declaring three SRMs inoperable that led to orange nuclear safety risk for reactivity management. The inspectors reviewed this issue using the guidance contained in Appendix B, Issue Screening, of IMC 0612, Power Reactor Inspection Report. The inspectors determined the violation was more than minor because it was associated with the Mitigating Systems Cornerstone attribute of Configuration Control and was similar to the not-minor-if statement of example 4.e of IMC 0612, Appendix E, Examples of Minor Issues. Specifically, the inoperability of three SRMs placed the overall plant risk in a higher licensee-established risk category. The inspectors determined the finding could be evaluated using the Significance Determination Process in accordance with IMC 0609, Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process. The finding screened as very low safety significance (Green)
05000341/FIN-2012002-012012Q1FermiLicensee-Identified ViolationTS 5.4.1 requires the licensee to establish, implement, and maintain applicable written procedures for the safety-related systems and activities recommended in Regulatory Guide 1.33, Revision 2, Appendix A. Section 9.a, Procedures for Performing Maintenance, of Regulatory Guide 1.33, Revision 2, Appendix A, further states, in part, that: Maintenance that can affect the performance of safety-related equipment should be properly preplanned and performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances. Revision 20 of the licensees Work Conduct Manual, MWC10, Work Package Preparation, describes requirements for configuration control. Step 4.10.2.3.e states, Upon completion of the maintenance activity or prior to completing the work package (work activity), all temporary alterations shall be removed and the equipment/SSCs shall be returned to the As-Designed condition. Contrary to the above, on February 22, 2012, the licensee failed to properly restore the configuration of Division 1 H2O2 sample pump following maintenance. Specifically, the pump discharge tubing hoses were left unconnected causing the system to trip when it was attempted to be restarted. The inspectors reviewed this issue using the guidance contained in Appendix B, Issue Screening, of Inspection Manual Chapter 0612, Power Reactor Inspection Reports. The inspectors determined the violation was more than minor because it was associated with the Barrier Integrity Cornerstone attribute of Configuration Control and affected the cornerstone objective of providing reasonable assurance that physical design barriers (containment) protect the public from radionuclide releases caused by accidents or events. Specifically, the as-found condition of the H2O2 sample pump discharge tubing potentially introduced a leakage path from the primary containment to the secondary containment. The inspectors evaluated the finding using IMC 0609, Attachment 4, Phase 1 Initial Screening and Characterization of Findings, using the Phase 1 Significance Determination Process worksheet for the Barrier Integrity Cornerstone. The finding screened as very low safety significance (Green) because the inspectors answered No to the screening questions under the Containment Barrier column of Table 4a. Specifically, because maintenance had installed Swagelok fittings on the ends of the discharge tubing, an actual open pathway in the physical integrity of the primary containment did not exist. The licensee had entered this issue into their corrective action program as CARD 12 21428. A local leak rate test was performed for the as-found condition which measured the leakage at 28.1 scfh (standard cubic feet per hour), which added a small amount to the existing primary containment total leakage rate (70.44 scfh). The total leakage rate remained below the TS 3.6.1.1 limit of La (296.3 scfh).
05000346/FIN-2011005-012011Q4Davis BesseInadequate Control of Weld Filler Metal ElectrodesA finding of very low safety significance and an associated NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings were identified by the inspectors for the licensees failure to control weld rod oven temperature in accordance with procedure WFMC-1 during a rebar splice weld completed for restoration of the shield building access opening. As a corrective action, the licensee removed the welders certification to weld rebar and documented this issue in CR 2011-05536. To ensure that the horizontal rebar splice weld 2H-03R was not affected by delayed hydrogen cracking, the licensees vendor examined the weld splice 48 hours after fabrication and did not identify cracks. The finding was determined to be more than minor because the finding was associated with the Barrier Integrity Cornerstone attribute of Configuration Control and adversely affected the cornerstone objective to provide reasonable assurance that the physical design barriers (e.g., containment) protect the public from radionuclide releases caused by accidents or events. The shield building is part of the containment system. Absent NRC identification, rebar welds would have been fabricated with electrodes exposed to ambient temperatures for excessive periods of time creating a condition that results in hydrogen-induced weld cracking. Rebar splice material with cracks returned to service would increase risk for shield building failure during design basis events such as wind-driven missile impact or earthquake-induced loads. The inspectors completed a significance determination, in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, Table 4a for the Containment Barrier. Because the issue was corrected promptly, prior to introduction of weld material with hydrogen-induced cracks, the inspectors answered no to each of the four Phase 1 screening questions. Therefore, the finding screened as having very low safety significance. This finding had a cross-cutting aspect in the area of Human Performance, Work Practices because the licensee did not provide adequate supervisory and management oversight of work activities including contractors such that nuclear safety was supported. Specifically, the failure to control the weld rod oven temperature in accordance with procedure WFMC-1 was caused by inadequate licensee oversight of the contracted welder.
05000346/FIN-2011005-022011Q4Davis BesseDecay Heat Pump 1-1 Damaged and Rendered Inoperable By Personnel Climbing on EquipmentA self-revealed finding of very low safety significance (Green) was identified when low pressure injection equipment was damaged by operators attempting to access an overhead valve. Specifically, by climbing and standing on sensitive plant equipment, the licensee failed to comply with the standards and expectations for accessing plant equipment contained in procedure NOP-OP-1002, Conduct of Operations . An immediate corrective action was taken to repair the damaged temperature element and restore low pressure injection pump no. 1 to operable status. A long-term solution to providing access to the overhead valve is under evaluation in the corrective action program. The inspectors determined that the finding was more than minor because it was associated with the Mitigating Systems Cornerstone attribute of Human Performance 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 damage caused when falling from plant equipment rendered low pressure injection train 1 inoperable. The inspectors evaluated the finding using IMC 0609, Attachment 4, Phase 1 Initial Screening and Characterization of Findings, using the Phase 1 SDP worksheet for the Mitigating Systems Cornerstone. The finding screened as very low safety significance because the inspectors answered no to the screening questions in Table 4a. Specifically, the finding was not a design or qualification deficiency, did not represent a loss of system safety function, did not represent actual loss of safety function of a single train for greater than its TS allowed outage time, and the finding did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. This finding had a cross-cutting aspect in the area of Human Performance, Work Control Component, because the licensee did not plan and coordinate work activities consistent with nuclear safety. Specifically, the licensee did not appropriately plan for job site conditions impacting human performance since an appropriate available method for accessing CC258 was not evaluated.
05000346/FIN-2011005-032011Q4Davis BesseAir Voids in Component Cooling Water System Caused By Inadequate Fill and Vent ProcedureA finding of very low safety significance and an associated NCV of TS 5.4.1(a) were identified by the inspectors for the licensees failure to establish, implement, and maintain technically adequate procedures to cover the restoration (i.e., filling and venting) of the component cooling water (CCW) system following maintenance activities. Specifically, a complex series of fill and venting evolutions to restore the system had been required following extensive maintenance activities; these evolutions did not ensure that all the air was vented from the system, such that later ultrasonic testing performed by the licensee identified a significant air void, approximately 19 cubic feet, in a CCW pump 3 horizontal suction piping segment. The issue was entered into the licensees CAP as CRs 2011-05542 and 2011-05831. The finding was determined to be of more than minor safety significance because the issue was associated with the Mitigating Systems Cornerstone attribute of procedure quality, and had adversely affected the associated cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, CCW, a mitigating system, had its reliability adversely impacted by the lack of appropriate fill and venting procedural guidance. The inspectors evaluated the finding using IMC 0609, Attachment 4, Phase 1 Initial Screening and Characterization of Findings. Because the finding involved reactor shutdown operations and conditions, the inspectors transitioned to IMC 0609, Appendix G, Attachment 1, Shutdown Operations Significance Determination Process - Phase 1 Operational Checklists for Both PWRs and BWRs. Since the finding was associated with an issue that occurred during the time the licensee was conducting RCS fill and venting activities and plant conditions were in transition, the inspectors consulted both Checklist 2, PWR Cold Shutdown Operation: RCS Closed and Steam Generators Available for Decay Heat Removal (Loops Filled and Inventory in the Pressurizer); Time to Boiling Less Than 2 Hours, and Checklist 3, PWR Cold Shutdown and Refueling Operation: RCS Open and Refueling Cavity Level Less Than 23 Feet or RCS Closed and No Inventory in the Pressurizer; Time to Boiling Less Than 2 Hours. The inspectors determined that the finding did not adversely impact any shutdown defense-in-depth or mitigation attributes on either checklist, nor did it meet any of the checklist specific requirements for a Phase 2 or Phase 3 SDP analysis. Consequently, the finding was determined to be of very low safety significance. This finding had a cross-cutting aspect in the area of Human Performance, Resources component, because the licensee did not ensure that personnel, equipment, procedures, and other resources were available and adequate to assure nuclear safety. Specifically, the licensees procedures and guidance for the restoration of the CCW system following outage maintenance activities did not ensure that the system was fully filled and properly vented prior to operation.
05000346/FIN-2011005-052011Q4Davis BesseInadequate Information on Valve Interlocks Resulted in Inadvertent Operation and Loss of Component Cooling Water Surge Tank InventoryA finding of very low safety significance and an associated NCV of TS 5.4.1(a) were identified by the inspectors for the licensees failure to establish, implement, and maintain technically adequate procedures and drawings to cover the restoration (i.e., motor controller re-energization) of components in the CCW system following maintenance activities. Specifically, as circuit breaker BE1161 was closed to restore power to motor-operated valve (MOV) CC2645, the train 1 auxiliary building return header isolation valve, the MOV unexpectedly stroked open resulting in a rapid loss of CCW system inventory and a low level alarm for the CCW surge tank. Subsequent investigation revealed that notes describing the operating logic for CC2645 on approved operational drawings were less than adequate. The issue was entered into the licensees CAP as CR 2011-04078. The finding was determined to be of more than minor safety significance because the issue was associated with the Mitigating Systems Cornerstone attribute of procedure quality, and had adversely affected the associated cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, CCW, a mitigating system, had its reliability adversely impacted by the inadequate procedural guidance for motor controller restoration. The inspectors evaluated the finding using IMC 0609, Attachment 4, Phase 1 Initial Screening and Characterization of Findings. Because the finding involved reactor shutdown operations and conditions, the inspectors transitioned to IMC 0609, Appendix G, Attachment 1, Shutdown Operations Significance Determination Process Phase 1 Operational Checklists for Both PWRs and BWRs. Since the finding was associated with an issue that occurred during the time the reactor was in a defueled condition, the inspectors conservatively consulted all four PWR checklists (i.e., Checklists 1 4). The inspectors determined that the finding did not adversely impact any shutdown defense-in-depth or mitigation attributes on any checklist, nor did it meet any of the checklist specific requirements for a Phase 2 or Phase 3 SDP analysis. Consequently, the finding was determined to be of very low safety significance. This finding had a cross-cutting aspect in the area of Human Performance, Resources component, because the licensee did not ensure that personnel, equipment, procedures, and other resources were available and adequate to assure nuclear safety. Specifically, the licensees procedures, drawings and guidance for the restoration of the CCW system following outage maintenance activities did not ensure that the system was properly aligned prior to restoration of electrical power to MOV CC2645.
05000346/FIN-2011005-062011Q4Davis BesseInadequate Procedure Resulted in Water Intrusion Into Safety-Related Motor Control CenterA self-revealed finding of very low safety significance was identified for the licensees failure to establish, implement, and maintain technically adequate procedures to permit the proper switching of feedwater sources for the stations auxiliary boiler, such that when the switching of feedwater sources from demineralized water to the stations normal condensate system took place per approved procedures, there were detrimental results. Specifically, the approved procedures for this activity relied upon a check valve to keep the demineralized water header from being exposed to greater pressure than its design. When that check valve failed to function as designed, failure of demineralized water system components and the inadvertent deluge and failure of safety-related electrical equipment resulted. A self-revealed finding of very low safety significance was identified for the licensees failure to establish, implement, and maintain technically adequate procedures to permit the proper switching of feedwater sources for the stations auxiliary boiler, such that when the switching of feedwater sources from demineralized water to the stations normal condensate system took place per approved procedures, there were detrimental results. Specifically, the approved procedures for this activity relied upon a check valve to keep the demineralized water header from being exposed to greater pressure than its design. When that check valve failed to function as designed, failure of demineralized water system components and the inadvertent deluge and failure of safety-related electrical equipment resulted. RCS Closed and No Inventory in the Pressurizer; Time to Boiling Less Than 2 Hours. The inspectors determined that the finding did not adversely impact any shutdown defense-in-depth or mitigation attributes, nor did it meet any of the checklist specific requirements for a Phase 2 or Phase 3 SDP analysis. Consequently, the finding was determined to be of very low safety significance. This finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Corrective Action Program (CAP) component, because the licensee did not take appropriate corrective actions to address the safety issue in a timely manner, commensurate with the safety significance and complexity. Specifically, the licensee had multiple previous opportunities to have appropriately diagnosed and corrected the issue, but failed to do so.
05000346/FIN-2011005-072011Q4Davis BesseIncomplete Surface Examination of the RRVCHA finding of very low safety significance and an associated NCV of 10 CFR 50, Appendix B, Criterion VII, Control of Purchased Material, Equipment, and Services, were identified by the inspectors for the licensees failure to perform an adequate review of fabrication records to ensure material procured from a contractor (replaced reactor vessel closure head) met the construction code (CC). Specifically, the accessible surfaces of the 60 closure head flange stud holes were not subjected to dye penetrant or magnetic particle examinations as required by the CC. As a corrective action, the licensee completed magnetic particle examination of the accessible surfaces of the 60 flange stud holes prior to placing the vessel head into service. The finding was determined to be more than minor because it was associated with the Initiating Events Cornerstone attribute of Equipment Performance and affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions. Absent NRC identification, the licensee would not have completed surface examination of the 60 flange stud holes to ensure unacceptable material flaws (e.g., cracks) were not placed in service. Because material flaws such as cracks serve as stress risers that reduce the ability of the replacement reactor vessel closure head to withstand failure by crack propagation during design basis events (e.g., pressurized thermal shock), they would place the reactor coolant system at an increased risk for through-wall leakage and/or failure. The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, Table 4a for the Initiating Events Cornerstone. Because this finding was identified prior to placing the replacement reactor vessel closure head in service and no fabrication flaws were identified, the inspectors answered no to the SDP Phase 1 screening question Assuming worst case degradation, would the finding result in exceeding the Technical Specification (TS) limit for any reactor coolant system leakage or could the finding have likely affected other mitigation systems resulting in a total loss of their safety function assuming the worst case degradation? Therefore, the finding screened as having very low safety significance. This finding had a cross-cutting aspect in the area of Human Performance, Decision Making because the licensee staff failed to demonstrate that nuclear safety was an overriding priority in decisions affecting the replacement reactor vessel closure head. Specifically, the failure to perform an adequate review of the replacement reactor vessel closure head fabrication records was caused by the licensees decision to not review the manufacturers interpretations and application of the CC rules.
05000346/FIN-2011005-042011Q4Davis BesseReactivity Manipulations Performed By Non-Licensed IndividuaLThe inspectors identified a SL IV NCV of 10 CFR 54(i) when a non-licensed member of the licensees engineering staff was observed operating switches that directly caused the insertion of various control rods that were being subjected to timing tests. Specifically, the inspectors observed that key switches used to interrupt power to the control rod drives and cause control rod insertion were manipulated by a member of the licensees engineering staff, and not a licensed individual. The issue was entered into the licensees CAP as CR 2011-06318. The issue was determined to be associated with the Mitigating Systems Cornerstone attribute of procedure quality. However, the inspectors subsequently determined that the issue had not adversely affected the associated cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Because of several factors, the inspectors determined that the issue was of minor safety significance and, as such, did not constitute a finding. These factors included: All control rod group withdrawal activities were accomplished from the control room by an on-watch licensed reactor operator; All activities in the electrical penetration room were performed in accordance with an approved written test procedure, and under the direct supervision of a licensed Senior Reactor Operator; The operation of the local key switches in the electrical penetration room, albeit by a non-licensed individual, could only cause control rod insertion. There was no withdrawal capability; and. The individual operating the local key switches in the electrical penetration room was always in continuous communication with the on-watch licensed reactor operator in the control room. The inspectors determined that the issue was subject to the NRCs traditional enforcement process as an issue that had the potential to impact the agencys ability to perform its regulatory function. Specifically, the NRCs Reactor Oversight Process fundamentally assumes that only duly licensed individuals are allowed to manipulate reactor controls and alter core reactivity or make changes to reactor power, and that all licensed individuals perform their licensed duties in accordance with any restrictions associated with their individual licenses. The inspectors conferred with NRC Region III management and members of the enforcement staff and determined that, because of the factors noted above, the issue constituted a SL IV violation that resulted in no, or relatively inappreciable, safety consequences. Because this issue was dispositioned through the traditional enforcement process and had no Reactor Oversight Process aspects, there was no cross-cutting aspect associated with the violation.
05000346/FIN-2011004-062011Q3Davis BesseLicensee-Identified ViolationTS 5.4.1(a) requires the licensee to establish, implement, and maintain applicable written procedures for the safety-related systems and activities recommended in RG 1.33, Revision 2, Appendix A. Section 9.a, Procedures for Performing Maintenance, of RG 1.33, Revision 2, Appendix A, further states, in part, that: Maintenance that can affect the performance of safety-related equipment should be properly preplanned and performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances. Contrary to this requirement, on September 2, 2011, licensee personnel failed to properly rig and lift a new safety-related battery charger (DBC1PN) into position. Specifically, the personnel conducting the rigging activity switched from a four-point lift configuration to a two-point lift configuration when one of the lifting bolts atop the battery charger cabinet was inadvertently sheared off. This lifting configuration change was performed with an approved lift plan that contained inadequate technical/engineering guidance. When the-component was subsequently lifted, unbalanced forces resulting from the two-point lifting configuration caused several welds on the cabinet to crack, rendering the cabinet seismically unqualified. The objective of the Mitigating Systems Cornerstone of Reactor Safety is to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). A key attribute of this objective is human performance, and specifically, procedure use and adherence. In accordance with NRC IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, the inspectors determined that the violation was of more than minor significance in that it had a direct impact on this cornerstone objective. The licensees failure to use technically adequate written procedures or instructions for the rigging and lifting configuration resulted in damage to safety-related battery charger DBC1PN that rendered it seismically unqualified and added significant time to it being inoperable. The licensee had entered this issue into their CAP as CRs 2011-02288 and 2011-02290. Corrective actions planned by the licensee include either weld repairs to the cabinet to restore its seismic qualification or replacement of the entire battery charger, and a re-examination of lifting and rigging practices.
05000346/FIN-2011004-052011Q3Davis BesseCode Surface Examination Requirements Not Applied to Closure Head Stud HolesThe RVCH is a single piece forging fabricated to the SA 508 material standard with an ASME NPT stamp to document that this pressure boundary part was fabricated to the requirements of the 1989 Edition of the ASME Code Section III. The requirements for examination of forgings are contained in the ASME Code Section III, Article NB 2540 Examination and Repair of Forgings and Bars. Specifically, NB-2541(a) requires in part that, In addition, all external surfaces and accessible internal surfaces shall be examined by a magnetic particle (MT) method (NB 2545) or a PT method (NB-2546). Also, NB-4121.3 Repetition of Surface Examinations After Machining required If, during the fabrication or installation of an item, materials for pressure containing parts are machined, then the Certificate Holder shall re-examine the surface of the material in accordance with NB-2500 when: (a) the surface was required to be examined by the MT or liquid penetrant method in accordance with NB-2500; and (b) the amount of material removed from the surface exceeds the lesser of 1/8 inch or 10 percent of the minimum required thickness of the part. For the 60, 7-inch diameter stud holes drilled through the vessel head flange, no surface examinations (e.g., MT or PT) were conducted on the interior bore surfaces of the stud holes. The inspectors observed a licensee demonstration of the potential accessibility of the flange stud holes for MT examination. Specifically, a licensee MT qualified examiner positioned an AC yoke used for MT examinations on the interior bore surfaces of an RVCH flange stud hole. Based on this demonstration, the inspectors estimated that it would be possible to perform an MT exam for accessible portions of the interior bore surfaces for a depth of about 2 inches from the top and bottom flange faces for each of the 60 stud holes. Because this accessible interior surface on the RVCH forging had not been examined by MT or PT, the inspectors were concerned that the RVCH did not meet the requirements of NB-2541(a) and NB-4121.3 discussed above. In response to the inspectors questions, the licensee established a position that accessible interior surfaces of the RVCH stud holes did not require a surface examination. The licensee position was based on Code Interpretation III-1-77-162, which states in part that drilled holes are not considered to be material form surfaces and the requirement for examination of holes (if any) resides in NX-4000 and NX-5000. The licensee concluded that the reexamination of machined surfaces as discussed in NB-4121.3 did not apply to the accessible interior surfaces of the flange stud holes because they were not material form surfaces. This issue is considered an unresolved item pending completion of an NRC staff review to determine an Agency position on the licensees interpretation of these Code requirements. The licensee documented this issue in CR 2011-01739.
05000346/FIN-2011004-012011Q3Davis BessePlant Transient During HPI Flow Instrument String ChecksOn September 15, 2011, instrumentation and controls (I&C) technicians replaced the HPI 3A and 3B flow instrument signal monitors with refurbished modules. Upon insertion of the module into the cabinet, the control room received an unexpected alarm for ICS Input Mismatch. The alarm immediately cleared and was attributed to a slight disruption in voltage when the modules were inserted. A decision was made to continue replacement activities. On September 16, 2011, I&C technicians commenced PMT of the signal monitors. During the string check of the HPI flow instrument alarms, annunciator alarm 14-4-E, ICS Input Mismatch, was received. The alarm initially cleared, then returned. Coincident with ICS Input Mismatch alarm, the plants ICS began reducing reactor power without any operator input. On-watch plant operators entered procedure DB-OP-02526, Primary to Secondary Plant Upset, and went through actions of placing ICS stations in manual control. The I&C technicians performing the HPI flow instrument signal monitor refurbishment were directed to stop their activities. Reactor power initially dropped to approximately 95 percent before operators stabilized the plant, and then returned reactor power to approximately 100 percent using manual controls. The refurbished HPI flow instrument signal monitor modules were removed from the system and taken to the I&C shop for inspection and testing, while the original signal monitor modules were reinstalled. Inspection and testing of the refurbished modules in the I&C shop did not reveal any issues. The modules have been sent to the licensees testing laboratory for further analysis. The inspectors continued to review the circumstances surrounding the event to determine if the issue was within the licensees ability to foresee and correct and should have been prevented. Pending further review of the licensees cause analysis, the issue is considered an unresolved item.
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