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| 05000250/FIN-2016009-01 | 2016Q2 | Turkey Point | Inaccurate Fire Watch Logs | 10 CFR 50.9(a), Completeness and accuracy of information, states, in part, that information required by statute or by the Commissions regulations, orders, or license conditions to be maintained by...the licensee shall be complete and accurate in all material respects. NRC Licenses DPR-31 (Turkey Point Unit 3) and DPR-41 (Turkey Point Unit 4), License Condition D, Fire Protection, states, in part, that FP&L shall implement and maintain in effect all provisions of the approved Fire Protection Program as described in the Updated Final Safety Analysis Report (UFSAR) for Turkey Point Units 3 and 4. . . . Section 7.1 of Appendix 9.6A of the UFSAR for Turkey Point Units 3 and 4 states that (t)he Fire Protection Program was established by procedures (citing Procedure 0-ADM- 016). These procedures identify the various positions responsible for the fire protection program implementation, and outline requirements for fire prevention, detection, and suppression. Section 7.2 of Appendix 9.6A of the UFSAR states that Fire protection specifications are presented in the Fire Protection Program (Procedure 0-ADM-016). Section 3.13.1 of FP&L Procedure 0-ADM-016 states that The Fire Watch is responsible for being constantly alert and watchful for flames, smoke, the odor of burning materials, any safety hazards and/or poor housekeeping practices. Additional duties and responsibilities are described in 0-ADM-016.4, Fire Watch Program. Section 2.2.2 of Procedure 0-ADM-016.4 states that hourly fire watch logs and badge transaction reports are to be kept for one year following the origination date. Contrary to the above, on multiple occasions between November 2014 and April 2015, the licensee maintained records of hourly fire watch logs required by FP&L Procedure 0- ADM-016.4 that were not complete and accurate in all material respects. Specifically, Fire Watch Shift Supervisors (FWSS) initialed and signed hourly fire watch logs indicating that hourly fire watches had been completed, with all required areas checked, when on multiple occasions some areas had not been checked or hourly fire watches had not been performed at all. The hourly fire watch patrol records are material to the NRC because they provide evidence of compliance with regulatory requirements. |
| 05000250/FIN-2017001-02 | 2017Q1 | Turkey Point | Failure of Vital Battery Chargers Due to Conductive Dust / Particulate Foreign Material Exclusion | Annual Sample: (Opened) Unresolved Item (URI): Failure of Battery Chargers Due To Conductive Dust / Particulate Foreign Material Exclusion 18 a. Inspection Scope: The inspectors performed an in-depth review of AR 2183537 that documented an equipment apparent cause evaluation (EACE) associated with three Unit 3 battery chargers that tripped while in service. Thermo-Lag was being installed in support of fire protection modifications for Turkey Points transition to a risk-informed fire protection program, i.e. NFPA 805. The inspectors reviewed the associated corrective actions to verify they were completed as prescribed and that open actions were scheduled to complete commensurate with the safety significance of the activity. The inspectors walked down the battery chargers to verify selected corrective actions were completed and walked down the modification to HVAC unit V78 that was installed to prevent air from blowing directly into the battery charger ventilation louvers. The inspectors reviewed ARs that were generated during the EACE and evaluated the licensees disposition of these ARs to verify the licensees actions were in accordance with licensee procedure, PI-AA-104-1000, Corrective Action. During this inspection, on March 18, 2017, in a separate location of the plant, the 3A 4kV switchgear bus arc flashed in the reactor coil cubicle causing the 3A 4kV switchgear bus protective relay circuits to automatically deenergize the bus. The inspectors attended the licensees RCE failure investigation team meetings on this issue to obtain updates and gather facts on the arc flash and failed switchgear. The licensees RCE related to the 3A 4kV switchgear failure was in process at the end of this inspection period. The 3A 4kV switchgear room was undergoing Thermo-Lag passive fire barrier installation which was similar to the work in the new electrical equipment room (NEER) that housed the battery chargers. Documents reviewed are listed in the Attachment. This inspection constitutes one sample. b. Findings: Introduction: A URI was opened to determine if there is a performance deficiency related to the battery charger trips in the NEER and failure of the 3A 4kV switchgear bus. Description: On February 2, 2017, the 3A2 vital battery charger input breaker and motor control center (MCC) supply breaker tripped. Four minutes later, the D51 battery charger input breaker tripped. Subsequently, on February 8, 2017, the 3B2 vital battery charger input breaker and MCC supply breaker tripped, and a loud bang and possible flash were reported to have occurred in the lower level near the 4D MCC which supplies 480 Vac to the 3B2 charger. On February 13, the 4A2 and 4B2 battery chargers had difficulty load sharing with redundant battery chargers operating on their associated battery busses. The ARs associated with these separate issues include: AR 2184506, AR 2183540, AR 2183773, and AR 2185218. The licensee initiated an EACE on these issues, AR 2183537. For the battery charger trips that occurred on February 2, the licensee noted that Thermo-Lag work was in progress near the chargers in the NEER. At the time of the breaker trips, several employees were in the NEER performing cleanup from the Thermo-Lag activities. The licensee discovered a notable level of dust on horizontal surfaces in the NEER as well as inside the 3A2 and D51 battery charger cabinets. The licensee concluded the dust was conductive. The 3A2, D51 and 3B2 chargers, which were all located near each other and in the same room elevation, were cleaned and returned to service. The 4A2 and 4B2 battery chargers were also cleaned but it was noted those 19 chargers were in the same room but at a lower elevation. On February 8, the 3B2 charger tripped, despite it having been previously cleaned. It was noted at the time of the 3B2 charger trip that there were several employees installing Thermo-Lag in the NEER. The licensee concluded that the apparent cause of the breaker trips was conductive dust/particulate that may have been created by Thermo-Lag passive fire barrier installation in the vicinity of the battery chargers. The dust/particulate became airborne and settled on charger components. Corrective actions included cleaning all the chargers in the room and installing a modification which provided a sheet metal barrier on top of the D51, 3A2 and 3B2 battery chargers to deflect air from HVAC Unit V78 being blown directly into the louvered charger electrical cabinets. On March 18, 2017, in a separate location of the plant, the Unit 3A 4kV switchgear room, the 3A 4kV switchgear bus arc flashed in the reactor coil cubicle. The arc flash resulted in an explosion and the 3A 4kV switchgear bus was automatically deenergized by protective relay circuits. Similar to the NEER that housed the battery chargers, the 3A 4kV switchgear room was undergoing Thermo-Lag passive fire barrier installation. The deenergized 3A 4kV switchgear bus resulted in a Unit 3 automatic reactor trip. This event and NRC follow-up is described in section 4OA3 of this report. The licensee promptly chartered an RCE team to investigate the failure of the 4kV bus. The licensee noted that prior to the arc flash there were several employees in the 3A 4kV switchgear room performing similar Thermo-Lag installation. As an immediate corrective action, the licensee stopped all Thermo-Lag installation work in the entire fleet. The licensees RCE plan included determining if there were any common causes with the battery charger trips and the 4KV switchgear failure due to Thermo-Lag installations. A URI was identified because additional review is needed to determine if there were any common causes between the battery charger trips and anomalies and the 3A 4kV switchgear bus arc flash and to determine if this issue of concern constitutes a violation. Specifically, the inspectors will review the licensees RCE of the failed 4kV switchgear to determine if there are causes and corrective actions which were not identified during the investigation of the battery charger trip EACE, and if corrective actions could have prevented the 3A 4kV switchgear bus arc flash. (URI 05000250/2017001-02, Failure of Vital Battery Chargers Due to Conductive Dust / Particulate Foreign Material) |
| 05000250/FIN-2017002-01 | 2017Q2 | Turkey Point | Failure to Perform 100 Percent General Visual Examinations of Containment Moisture Barriers Associated with Containment Liner Leak Chase Test Connections | Green: 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). |
| 05000250/FIN-2017002-02 | 2017Q2 | Turkey Point | Inadequate Foreign Materials Exclusion Controls for Thermo-Lag Activities Renders Electrical Equipment Inoperable and Results in a High Energy Arc Flash | Green: 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-2017002-03 | 2017Q2 | Turkey Point | Failure to Implement Fire Detection | Green: 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-2017008-01 | 2017Q1 | Turkey Point | Potential Failure of Fire Detection Capability on Credited Train of Equipment Following High Energy Arc Flash Event | Inspection 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-2017008-03 | 2017Q1 | Turkey Point | Potential Failure to Implement Adequate Foreign Material Exclusion Control | Inspection 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) |
| 05000259/FIN-2007003-01 | 2007Q2 | Browns Ferry | Reactor Core Isolation Cooling System Loss of Configuration Control | The inspectors identified an unresolved item (URI) involving a mispositioned and faulted switch on the 1C 250 VDC Reactor Motor-operated Valve (RMOV) Board used for Unit 1 RCIC operation from outside the main control room. Description: On June 15, while conducting a system alignment walkdown, inspectors found two out-of-position RCIC barometric condenser pump emergency handswitches on the 1C 250 VDC RMOV Board with respect to the 1-OI-71, Reactor Core Isolation Cooling System, Attachment 2, Panel Lineup Checklist. Both handswitches were found in the STOP position versus the required START position per the checklist. To address this problem, the licensee initiated PER 126345. The specific handswitches in question were: 1-HS-71-31C, RCIC Vacuum Pump 1-HS-71-29C, RCIC Vacuum Tank Condensate Pump Upon notification of the mispositioned switches, Operations commenced an independent performance of 1-OI-71, Attachment 2, RCIC Panel Lineup Checklist which would reposition the above handswitches in addition to verifying all other RCIC panel components. While performing this checklist, operators discovered that the RCIC Barometric Condenser Vacuum Pump Backup Control Switch, 1-HS-71-31C, on the 1C 250 V RMOV Board, was mechanically bound in the STOP position. The licensee initiated Work Order (WO) 07-719158-000 to repair the switch and PER 126352 to document an unplanned 30-day LCO entry into Technical Specification 3.3.3.2.A.1 for an inoperable backup control system function of the RCIC Barometric Condenser Vacuum Pump. After further review, Operations also discovered a difference between the 1-OI-71, Attachment 2 checklist and the Monthly Emergency Control Switch Verification 0-GOI- 300-1, Operator Round Log, Attachment 15.12, Monthly Emergency Control Switch Verification - Unit 1, which had placed the aforementioned handswitches in the STOP position. The inspectors verified that the correct switch positions were START, as required by 1-OI-71, Attachment 2. The licensee initiated Procedure Change Request (PCR) 07002587 to correct the GOI-300-1 attachment. In evaluating the implications of past operability of the Unit 1 RCIC system given the mispositioned switches (one of which was faulted), the inspectors first reviewed drawings and wiring schematics to verify that the emergency control handswitches in question would not have adversely impacted the RCIC pump automatic and manual control circuit when other emergency control handswitches in the circuit, separate switches from those in question, were in the NORMAL position. Based on this review, the inspectors concluded that the mispositioned switches would not have adversely affected RCIC pump automatic operation, or manual operation from the main control room (MCR). However, with the emergency control handswitches in EMERGENCY, the Start/Stop handswitches in question would be in the control circuits. Therefore, the inspectors examined whether the RCIC system would be capable of performing its safety function during an event necessitating MCR abandonment (requiring th emergency control handswitches in EMERGENCY) with a loss of the RCIC Vacuum Pump due to the faulted switch. In particular, the inspectors needed additional information from the licensee in order to determine whether a sufficiently high temperature environment (turbine gland seals and valve packing exhausting to the RCIC room) could be created that would cause an automatic isolation of the RCIC System steam supply thereby rendering RCIC inoperable. In order to fully assess the enforcement implications and safety significance of this issue, additional information from the licensee will be needed. Consequently, pending the receipt of additional information and further review by the NRC (e.g., determination of the safety significance), this issue will be identified as URI 05000259/2007003-01, Reactor Core Isolation Cooling System Loss of Configuration Control. |
| 05000259/FIN-2011012-01 | 2011Q4 | Browns Ferry | Degraded Electrolytic Capacitor Test Results Not Entered into Corrective Action Program | The team identified a finding of very low safety significance (Green) and associated Non-Cited Violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, for the failure to promptly identify and correct a condition adverse to quality related to the electrolytic capacitors on the battery charger for main battery number 3. Specifically, the licensee failed to identify and correct results from ripple tests conducted on August 8, 2010, that showed degradation until questioned by the team on November 20, 2011. When the capacitors were retested in December 2011, similar results were obtained and the battery charger was determined to be degraded and was removed from service. The licensee entered this finding into their Corrective Action Program, removed the affected battery charger from service, initiated actions to expedite replacement of the electrolytic capacitors, and improved the capacitor testing procedure. The performance deficiency was determined to be more than minor because it was associated with the Mitigating Systems Cornerstone attribute of Equipment Performance, and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, failing to identify the test results that indicated the electrolytic capacitors were degraded and take corrective actions could have resulted in the failure of the battery chargers to perform their safety function and respond to initiating events. The safety significance of the finding was characterized using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP), Appendix A, and determined to be of very low safety significance because the finding was not a design.deficiency confirmed not to result in a loss of safety function of a system or a train. The cause of this finding was directly related to the cross-cutting aspect of maintenance in the Resources component of the Human Performance area, because the licensee did not ensure that personnel, equipment, procedures, and other resources are available and adequate to assure nuclear safety. Specifically, the licensee did not have complete, accurate, up-to-date procedures and work orders for periodic testing and replacement of the electrolytic capacitors in the battery chargers. |
| 05000269/FIN-2014005-01 | 2014Q4 | Oconee | Failure to Update FSAR for Mode 4 LOCA | An NRC identified Severity Level IV violation of 10 CFR 50.71(e), "Maintenance of Records, Making of Reports," was identified for the licensees failure to update the final safety analysis report (FSAR) after the licensee adopted the improved technical specifications (ITS). The licensee adoption of ITS introduced the possibility of a Mode 4 loss of cooling accident (LOCA), which was an accident of a different type than previously evaluated in the FSAR. The licensee initiated PIP O-15-00260 in order to determine future corrective actions. Continued non-compliance does not present an immediate safety concern because the inspectors assessed this as a very low safety significant issue. The licensees failure to update the FSAR as required by 10 CFR 50.71(e) was a performance deficiency. The performance deficiency impacted the ability of the NRC to perform its regulatory oversight function and was dispositioned using traditional enforcement. Specifically, a failure to update the UFSAR challenges the regulatory process because it serves as a reference document used, in part, for recurring safety analyses, evaluating license amendment requests, and in preparation for and conduct of inspection activities. This violation was determined to be a Severity Level IV violation per Section 6.1.d.3 of the NRC Enforcement Policy, revised July 9, 2013, because the lack of up-to-date information has not resulted in any unacceptable change to the facility or procedures. The NRC Enforcement Policy also requires disposition of findings in the significance determination process, which determined the finding was not more than minor. Since this issue was dispositioned using traditional enforcement, there was no cross-cutting aspect associated with this violation. |
| 05000269/FIN-2014005-02 | 2014Q4 | Oconee | Keowee Hydro Unit 2 Inoperable for Longer Than Allowed TS Outage Time | A self-revealing Green NCV of Oconee Nuclear Station Technical Specification (TS) 3.8.1, AC Sources Operating, was identified for Keowee Hydro Unit 2 being inoperable for longer than allowed TS outage time. The licensee modified Keowee Hydro Unit 2 electrical protection circuitry with a faster response relay which was susceptible to an existing degraded system condition and ultimately caused Keowee Hydro Unit 2 to be inoperable. The licensee implemented engineering change (EC111358) which moved the 86E2X relay to another cabinet which was not susceptible to the vibration from the governor oil system. The licensee entered this issue in their corrective action program (CAP) as PIP-O-13-09152. The licensees failure to properly evaluate a modification to the electrical control circuit of the governor oil system, which resulted in Keowee Hydro Unit 2 being inoperable for longer than allowed TS outage time, was a performance deficiency. The issue is more than minor because it was associated with the equipment performance attribute of the mitigating system cornerstone and it 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 modification of the governor oil system, including the addition of the 86E2X governor TXS catastrophic relay, resulted in Keowee Hydro Unit 2 being inoperable for longer than allowed TS outage time. The finding was screened in accordance with NRC IMC 0609, Significance Determination Process (SDP), Attachment 4 and Attachment A and determined to require a detailed risk evaluation. A regional Senior Reactor Analyst performed a risk analysis of the performance deficiency which was found to be Green (CDF < 1E-6/year). The dominant accident sequence was a loss of offsite power where Keowee Unit 1 fails independently and unrelated to the performance deficiency and power is not successfully restored by Oconee operators. The influential factors in the Green result were the limited exposure time (19 days) and the ability to quickly restore power to the unit via the Lee Station gas turbines via the Fant Line. This finding was determined to have a cross-cutting aspect in the problem identification and resolution cross cutting area because the licensees organization failed to take effective corrective actions to address the issue in a timely manner commensurate with its safety significance. Specifically, the licensee failed to take effective corrective actions to address system interactions (i.e. high vibrations) which ultimately had an adverse effect upon modifications to the governor oil system of the Keowee Hydro Unit 2. |
| 05000280/FIN-2009007-01 | 2009Q2 | Surry | Qualification of Fire Barrier Floor/Wall Penetration of Aluminum Conduit Through Sleeve | The team identified an unresolved item (URI) involving the qualification documentation for wall and floor fire barrier penetration seals. While inspecting the wall and floor fire barrier penetration seals, the team requested the licensees documentation for the qualification of a particular penetration seal configuration. That configuration was for one aluminum schedule 40 conduit (of various sizes as applicable) penetrating a 6 in. diameter floor or wall sleeve where the floor or wall was of poured concrete construction and the sleeve void around the conduit was filled with foamed silicon to the thickness of the floor or wall. The documentation package requested should establish a 3-hour fire rating, since the rated fire barrier walls and floors were required to have a 3-hour rating. In response, the licensee presented Impell Corporation Calculation No. 1250-111-C01, Penetration Seal Configuration Documentation Package, 10 in. Dow Corning Q3-6548 Silicone RTV Sealing Foam/North Anna and Surry, Rev.1. The qualification package or calculation was based on a tested configuration similar to that described above, except that the conduit was 3 in. or 4 in. galvanized steel. The team informed the licensee that this calculation was not valid to qualify aluminum conduit due to the lower melting temperature and greater heat conductance of aluminum as compared to steel. The licensee later transmitted supplemental information which included a fire barrier penetration seal fire test report for large diameter aluminum conduits through a sleeve. This new information was not a formal calculation comparing it to any installed penetration seal configuration at Surry. Moreover, certain aspects of the test data such as the temperature rise on the unexposed surfaces may not meet the licensing basis. At the time of issuance of this report, the team did not have sufficient information to determine the design criteria of that penetration seal. The team was aware that the fire barrier penetration seal configurations in question could probably be qualified by existing nuclear industry penetration seal testing data; therefore, there was no immediate safety concern. The licensee Initiated CR 339567 with an action item to establish a valid qualification package for the penetration configuration described above. URI 05000280, 281/2009007-01, Qualification of Fire Barrier Floor/Wall Penetration of Aluminum Conduit Through Sleeve, was established to track this issue until the final qualification package is reviewed |
| 05000280/FIN-2011003-01 | 2011Q2 | Surry | Unplanned Dilution of Unit 2 RCS | On May 28, 2011, while Unit 2 was operating in Intermediate Shutdown (>200 F, 310 psi), a control room operator noticed a decreasing level trend in the primary grade water tank over the past 2.5 hours. Additionally, it was noted that volume control tank and pressurizer level trends were increasing and charging seal injection flow was 101 gpm with letdown flow of 85 gpm. The licensee entered their abnormal procedure for emergency boration and conducted two emergency borations of the RCS while sampling RCS boron concentration and monitoring shutdown margin. Subsequently, it was identified that the cation demineralizer primary grade header isolation valve, 2-CH-19, indicated closed but was allowing primary grade water to leak by. This caused reverse flow through the cation demineralizer and introduced primary grade water into the RCS via the VCT. The licensee estimated that up to 30,000 gallons of PG water could have entered the RCS. Just prior to this event maintenance was conducted on 2-CH-19 and the valve was returned to service in a condition that allowed the primary grade water leakage flow path described above. The licensee entered this issue into their CAP as CR428947, and initiated Root Cause Evaluation (RCE) 001054. The inspectors require additional information, including the licensees completed investigation in RCE001054, to determine if there is a performance deficiency which is more than minor. This issue is identified as URI 05000281/2011003-01, Unplanned Dilution of Unit 2 RCS. |
| 05000280/FIN-2011003-02 | 2011Q2 | Surry | Failure to Classify and Declare a Notification of Unusual Event | A Green non-cited violation was identified by the inspectors for the licensees failure to classify and declare a Notification of Unusual Event when conditions warranted as required by 10 CFR 50.54(q) and 10 CFR 50.47(b)(4). The inspectors reviewed IMC0612, Appendix B, and determined that the finding was more than minor because it adversely affected the Emergency Response Organization performance attribute of the Emergency Preparedness cornerstone objective to ensure that the licensee is capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. Since the finding involved a failure to comply with regulatory requirements during an actual event, the inspectors reviewed IMC0609, Appendix B, Sheet 2, and determined that this was a finding of very low safety significance (Green) because it involved the failure to declare a Notification of Unusual Event. The cause of this finding involved the cross-cutting area of human performance, the component of decision making, and the aspect of conservative assumptions and safe actions, H.1(b), because the licensee failed to use conservative assumptions in the decision to not classify and declare the event as an Unusual Event. |
| 05000280/FIN-2011003-03 | 2011Q2 | Surry | Inadequate Qualification Testing of Fire Barrier Penetration Seals | A Green non-cited violation of Surry Units 1 and 2 Operating License Condition 3.I, Fire Protection, was identified by the inspectors for failure to have adequate qualification testing results, as directed by Appendix A to Branch Technical Position APCSB 9.5-1. Specifically, the licensee did not have sufficient testing results to qualify certain aluminum conduit configurations that penetrate 3-hour fire rated barriers separating fire areas containing redundant equipment required for safe shutdown. As part of the corrective actions, the licensee performed testing to determine the qualification of aluminum conduit penetrations, and performed modifications, as appropriate, to restore compliance. The finding is more than minor because it is associated with the reactor safety Mitigating Systems cornerstone attribute of protection against external factors (i.e., fire) and it affects the cornerstone objective of ensuring the reliability and capability of systems that respond to initiating events. Specifically, not having qualification testing results for aluminum conduits that penetrate fire rated barriers adversely affected the fire confinement capability defense-in-depth element because subsequent testing revealed some conduit configurations that did not meet the penetration seal criteria established in Branch Technical Position APCSB 9.5-1. The inspectors used the guidance of NRC Inspection Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process, and determined that the performance deficiency represented a finding of very low safety significance (Green). Specifically, the fire areas in question either contained a non degraded automatic gaseous or water-based fire suppression system, or the exposed fire areas did not contain potential damage targets that are unique from those in the exposing fire areas. Inspectors determined that no cross cutting aspect was applicable to this performance deficiency because this finding was not indicative of current licensee performance. |
| 05000280/FIN-2011003-04 | 2011Q2 | Surry | Licensee-Identified Violation | Licensee Technical Specification, 3.1.B.3, requires, in part, that the spray shall not be used if the temperature difference between the pressurizer and the spray fluid is greater than 320 deg F. Contrary to this, the licensee identified that this specification was exceeded on Unit 1 on April 17, 2011. The licensee created Engineering Technical Evaluation ETE-SU-2011-0042 to evaluate the acceptability of the Pressurizer for continued operation. The evaluation concluded that the structural integrity impact of the transient was within design fatigue analysis margin and therefore did not affect Pressurizer operability. The inspectors determined the finding was more than minor because it adversely impacted the Barrier Integrity cornerstone objective to provide reasonable assurance that physical design barriers (reactor coolant system) protect the public from radionuclide releases caused by accidents or events. The inspectors determined that this finding was a low safety of significance (Green) because there was no actual degradation of the barrier function of the control room against radiological hazards, smoke, or toxic atmosphere. The inspectors determined that licensee correctly evaluated the finding and developed appropriate corrective action as documented in the licensees CAP as CR422769. |
| 05000280/FIN-2011003-05 | 2011Q2 | Surry | Licensee-Identified Violation | Licensee Technical Specification, 3.1.B.3, requires, in part, that the spray shall not be used if the temperature difference between the pressurizer and the spray fluid is greater than 320 deg F. Contrary to this, the licensee identified that this specification was exceeded on Unit 2 on April 17, 2011. The licensee created Engineering Technical Evaluation ETE-SU-2011-0058 to evaluate the acceptability of the Pressurizer for continued operation. The evaluation concluded that the structural integrity impact of the transient was within design fatigue analysis margin and therefore did not affect Pressurizer operability. The inspectors determined the finding was more than minor because it adversely impacted the Barrier Integrity cornerstone objective to provide reasonable assurance that physical design barriers (reactor coolant system) protect the public from radionuclide releases caused by accidents or events. The inspectors determined that this finding was a low safety of significance (Green) because there was no actual degradation of the barrier function of the control room against radiological hazards, smoke, or toxic atmosphere. The inspectors determined that licensee correctly evaluated the finding and developed appropriate corrective action as documented in the licensees CAP as CR422778. |
| 05000280/FIN-2011003-06 | 2011Q2 | Surry | Licensee-Identified Violation | Licensee Technical Specification, 3.1.B.3, requires, in part, that the pressurizer heatup rate shall not exceed 100 degF per hour. Contrary to this, the licensee identified that this specification was exceeded on Unit 1 on April 20, 2011. The licensee created Engineering Technical Evaluation ETE-CEM-2011-0005 to evaluate the acceptability of the Pressurizer for continued operation. The evaluation concluded that the structural integrity impact of the transient was within design fatigue analysis margin and therefore did not affect Pressurizer operability. The inspectors determined the finding was more than minor because it adversely impacted the Barrier Integrity cornerstone objective to provide reasonable assurance that physical design barriers (reactor coolant system) protect the public from radionuclide releases caused by accidents or events. The inspectors determined that this finding was a low safety of significance (Green) because there was no actual degradation of the barrier function of the control room against radiological hazards, smoke, or toxic atmosphere. The inspectors determined that licensee correctly evaluated the finding and developed appropriate corrective action as documented in the licensees CAP as CR423197. |
| 05000280/FIN-2011003-07 | 2011Q2 | Surry | Licensee-Identified Violation | Licensee Technical Specification, 3.1.B.3, requires, in part, that the pressurizer heatup rate shall not exceed 100 degF per hour. Contrary to this, the licensee identified that this specification was exceeded on Unit 2 on May 26, 2011. The licensee created Engineering Technical Evaluation ETE-SU-2011-0073 to evaluate the acceptability of the Pressurizer for continued operation. The evaluation concluded that the structural integrity impact of the transient was within design fatigue analysis margin and therefore did not affect Pressurizer operability. The inspectors determined the finding was more than minor because it adversely impacted the Barrier Integrity cornerstone objective to provide reasonable assurance that physical design barriers (reactor coolant system) protect the public from radionuclide releases caused by accidents or events. The inspectors determined that this finding was a low safety of significance (Green) because there was no actual degradation of the barrier function of the control room against radiological hazards, smoke, or toxic atmosphere. The inspectors determined that licensee correctly evaluated the finding and developed appropriate corrective action as documented in the licensees CAP as CR428788. |
| 05000280/FIN-2011003-08 | 2011Q2 | Surry | Licensee-Identified Violation | NUHOMS Certificate of Compliance 1030, Amendment 0, Technical Specifications 2.1.c, Functional and Operating Limits, requires, in part, that the spent nuclear fuel stored in each 32PTH DSC/HSM-H at the Independent Spent Fuel Storage Installation (ISFSI) is to be qualified for four (4) heat load zones designated as Zones 1a, 1b, 2 and 3. Contrary to this requirement, the licensee identified that it failed to properly load fuel assemblies into four NUHOMS Dry Shielded Canisters (DSCs) resulting in the fuel assemblies exceeding the decay heat limit for the loading zones in two of the four center zones. Specifically, the Zone 1a and Zone 1b locations were reversed, resulting in the DSC Zone 1b heat load limits being slightly exceeded (less than one per cent in the worst case) at the time of loading. An evaluation performed by the licensee showed that all of the affected DSCs are currently in a safe condition as loaded in the HSMs. This issue is in the licensees CAP as CR419237, NUHOMS DSCs Loaded to Incorrect Heat Load Limits for Specific Orientation. This Severity Level IV violation is being treated as a non-cited violation (NCV), consistent with Section 2.3.2.b of the NRC Enforcement Policy; specifically, the violation was identified by the licensee, the issue was placed into the licensees CAP, the violation was not repetitive as a result of inadequate corrective action, and the violation was not willful. |
| 05000281/FIN-2011002-01 | 2011Q1 | Surry | Reactor Coolant System Instrumentation Erratic Level Indication | On February 2, 2011, while Unit 2 was operating at 100% power, the C loop RCS cold leg loop isolation valve, 2-RC-MOV-2595, experienced stem to disc separation resulting in a low RCS flow condition in the C RCS loop and subsequent automatic reactor trip. The licensee decided to repair the valve in Cold Shutdown by draining the RCS to mid-loop. The RCS standpipe is relied upon to provide both local and remote indication of RCS level during reduced inventory and mid-loop configurations. The licensee drained to reduced inventory and was forced to re-fill the RCS due to the unreliable level indication of 2-RC-LR-200A. Troubleshooting was performed on the 13 Enclosure electronics of the level recorder and associated circuitry and the instrument was tested before a second attempt at draining to mid-loop was commenced. During the second attempt 2-RC-LR-200A again became unreliable and operators were again forced to refill the RCS. The licensee then performed more in-depth troubleshooting of the instrumentation and performed a third drain down to mid-loop conditions once it had been returned to service. The third attempt was successful, although the instruments still experienced several instances of erratic indication. The licensee entered this issue into their CAP as CR413227, and initiated Apparent Cause Evaluation (ACE) 018543. The inspectors require additional information, including the licensees completed investigation in ACE018543 to determine if there is a performance deficiency which is more than minor. This issue is identified as URI 05000281/2011002-01, Reactor Coolant System Instrumentation Erratic Level Indication. |
| 05000302/FIN-2004009-02 | 2005Q1 | Crystal River | Single Failure Vulnerability of Common Electrical Protection and Metering Circuits | The team identified a violation of 10 CFR 50, Appendix B, Criterion III, Design Control, for installing and modifying electrical protection and monitoring circuits that did not meet the general design criteria for single active failures. A common electrical protection and metering circuit was installed such that a single active failure of a component in the circuit could trip and lock out all feeder breakers to both 4160V ES busses, resulting in a loss of all safety-related alternating current power. This finding was an immediate safety concern and the licensee made modifications to correct the nonconforming condition before the inspection team left the site. This finding is unresolved pending the completion of a significance determination. The finding is greater than minor because it is associated with the design control and equipment performance attributes of the reactor safety mitigating systems cornerstone. The finding adversely affects the objectives of availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. |
| 05000302/FIN-2004009-04 | 2005Q1 | Crystal River | No Cooling to Reactor Coolant Pump Seals for up to Eight Hours | The team noted that the licensees Appendix R Fire Study and post-fire SSD procedures relied on reactor coolant pump (RCP) seals remaining intact, without leaking, without cooling for up to eight hours. Because this practice differed significantly from general industry RCP seal design capabilities, this issue is unresolved pending further NRC review of the technical basis for acceptability. Crystal River 3 had Byron-Jackson (now Flowserve) N-9000 seal cartridges installed in the RCPs. Further, the licensee had a vendor analysis titled RCP N-9000 Seal Appendix R Evaluation supporting the ability of the seals to go without any cooling for up to eight hours without failing or leaking. Because RCP seals are not generally designed for eight hours without cooling and without failing or leaking, the team determined that NRC review of the vendor analysis was necessary. This issue is identified as URI 05000302/2004009-004, No Cooling to Reactor Coolant Pump Seals for up to Eight Hours. |
| 05000302/FIN-2008002-01 | 2008Q1 | Crystal River | Inoperable Fire Penetration Seal | The inspectors identified a Green non-cited violation (NCV) of Crystal River Unit 3 Operating License Condition 2.C(9), Fire Protection Program. The NCV was associated with an inoperable fire penetration seal in the 3-hour fire rated ceiling of the makeup system valve alley. The licensee declared the penetration seal inoperable. Corrective actions included establishing an hourly fire watch and repairing the penetration to its designed condition. The finding adversely affected the fire confinement capability defense-in-depth element. The finding is greater than minor because it is associated with the protection against external factors attribute, i.e., fire, and degraded the mitigating systems cornerstone objective to ensure the availability of systems that respond to initiating events. Using NRC Inspection Manual Chapter (IMC) 0609, Appendix F, Fire Protection Significance Determination Process, the finding was determined to have a very low safety significance since the gap in the fire penetration seal was small (less than 1/8 inch in width) |
| 05000302/FIN-2008002-02 | 2008Q1 | Crystal River | Failure to Implement Adequate Equipment Protection Resulted in a Plant Transient | A self-revealing finding was identified for failure to prevent inadvertent bumping of the condensate pump control switch during maintenance activities. As a result of bumping the control switch, a condensate pump had to be secured and reactor power was rapidly reduced to 61 percent to prevent a reactor trip. Corrective actions included removing the control switch handle to prevent it from being bumped. The finding was more than minor since it affected the equipment performance attribute of the Initiating Events Cornerstone and affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenged critical safety functions. The inspectors referenced Inspection manual Chapter 0609.04, Significance Determination process (SDP), Phase 1 screening and determined the finding to be of very low safety significance (Green) because the finding did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions will not be available. A contributing cause of this finding is related to the crosscutting area of human performance, with a work control component. Specifically, the licensee did not adequately plan work activities to protect the condensate pump control switch from being bumped |
| 05000302/FIN-2008002-03 | 2008Q1 | Crystal River | Licensee-Identified Violation | Improved Technical Specification (ITS) 3.3.17, Post Accident monitoring (PAM) Instrumentation, requires, in part, that both channels of the function, Degrees of Subcooling, shall be operable in MODES 1, 2, and 3. ITS 3.3.17, Condition C, states that with one or more functions with two required channels inoperable, restore one channel to operable within 7 days. Contrary to the above, on January 25, 2008, during surveillance testing, the licensee determined that both channels of the function, Degrees of Subcooling, had been inoperable since a software change on August 13, 2007. The inspectors determined that the failure to comply with ITS was of very low safety significance since the Degrees of Subcooling function would have remained available during the most limiting accident conditions (incore temperatures less than 1250oF ). The software change only affected the Degrees of Subcooling function above incore temperatures of 1250oF. This issue is documented in the licensees corrective action program as NCR 263310 |
| 05000302/FIN-2008002-04 | 2008Q1 | Crystal River | Licensee-Identified Violation | 10 CFR 55.33 (b) states that if an applicants general medical condition does not meet the minimum standards under 55.33(a)(1), the Commission may approve the application and include conditions to accommodate the medical defect. Contrary to the above, one licensed operator stood watch in a TS position as Operator at the Controls on 19 different occasions between July 9 and August 30, 2007, without complying with a newly issued license condition to take prescribed medication while performing licensed duties. Because of the extenuating circumstances that resulted in the operator not being properly informed of the new restriction, compliance with his license was reasonably beyond his control. This finding is of very low safety significance because other licensed operators were available to man the controls and the restricted operator was under supervision at all times. This event is documented in the licensees corrective action program as NCR 244615 |
| 05000302/FIN-2008002-05 | 2008Q1 | Crystal River | Licensee-Identified Violation | 10 CFR 50, Appendix B, Criterion V, Instructions Procedures and Drawings, requires that activities affecting quality shall be prescribed by documented instructions, procedures or drawings of a type appropriate to the circumstances and these instructions, procedures and drawings shall include appropriate quantitative or qualitative acceptance criteria for determining that the important activities have been satisfactorily accomplished. Contrary to these requirements, there were no written instructions to inform personnel implementing dissimilar metal weld inspections on what to do if the coverage of greater than 90 percent required by MRP-139 is not obtained. This resulted in the plant returning to power from RFO 15 without the ultrasonic examinations being conducted in accordance with the requirements of MRP-139. This finding is determined to be of very low safety significance because the deficiency was identified and examinations that met the requirements of MRP- 139 were performed during a forced outage prior to the due date in MRP-139. The licensee entered the finding into their corrective action program as NCR 270077 |
| 05000302/FIN-2008004-01 | 2008Q3 | Crystal River | Licensee-Identified Violation | The following violation of very low safety significance (Green) was identified by the licensee and is a violation of NRC requirements which meets the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as NCV. License Condition 2.C.(9) states, in part, that Florida Power Corporation shall implement and maintain in effect all provisions of the approved fire protection program as described in the FSAR. The FSAR, section 9.8.4, states, in part, that administrative controls covering CR3\'s Fire Protection Program are provided by the Fire Protection Plan. The Fire Protection Plan, section 1.6.2, Implementing Documents, references SP-367, Fire Service Valve Alignment and Operability Check, to verify semiannually the operability of Post Indicator Valves (PIV). SP-367, Revision 33, section 4.2.1.1 contains instructions to cycle PIVs listed in Enclosure 3 and to leave the valves in the required position. Enclosure 3 specifies a required position for fire service valve FSV-604 as Sealed Open. Contrary to the above, on January 19, 2008, during performance of the semiannual PIV operability check FSV- 604 was left in the closed position. This issue was more than minor because the fire protection for several fire areas were considered to be degraded and not in compliance with the fire protection plan. Since several fire areas were affected, a Phase 3 evaluation was required. A regional Senior Reactor Analyst performed a Phase 3 evaluation of this performance deficiency under the Significance Determination Process. Based upon the results of this evaluation, the performance deficiency was characterized as of very low safety significance (Green). The dominant accident sequence(s) involved a hypothetical fire of one circuit breaker in either the 3A or B 4160 VAC Engineered Safeguards Compartment that could have been suppressed prior to cable damage by manual suppression, had the isolation valve been in the correct position. This was followed by an independent failure of the safe shutdown train that was unaffected by the fire. Thus, core damage ensued. Major assumptions included that the fire service isolation valve could not be recovered, no credible ignition source was present on the 164 elevation of the control complex that would require evacuation of the Main Control Room and a train of mitigation equipments failure probability was on the order of 1 in 100. The exposure time used for the evaluation was 30 days. The licensee entered this issue in the CAP as NCR 266866 |
| 05000302/FIN-2009002-01 | 2009Q1 | Crystal River | Failure to Have Adequate Controls in Place to Ensure the Temperature of the Emergency Diesel Room was Maintained to Support EGDG Operability | A self-revealing finding was identified for failing to have adequate controls in place to ensure the temperature of the emergency diesel room was maintained to support emergency diesel generator (EGDG) operability. As a result, during cold weather conditions, licensee personnel did not close an access door which caused a low EGDG-1B lube oil temperature condition and inoperability of the EGDG. Corrective actions include: posting signs on all external doors of both safety and non-safety EGDGs rooms indicating that the doors should not be left open, discussing the event with site personnel; and initiation of changes to the sites cold weather checklist to check closed EGDG room doors during cold weather conditions. The finding was more than minor since it affected the equipment availability attribute of the Mitigating System Cornerstone and resulted in an unavailable emergency diesel generator train for approximately 13 hours. The inspectors assessed the finding using the SDP and determined that the finding was of very low safety significance (Green) since it was not a design or qualification deficiency, did not result in a loss of a system safety function, did not result in an actual loss of safety function of a single train for greater than allowed by improved technical specifications (ITS), did not represent an actual loss of safety function of risk-significant, non-technical specification equipment, and did not screen as risk significant due to external events. The inspectors found that the cause of this finding was not reflective of current performance since the EGDG door lacked the proper signage since initial plant operation. Therefore, a cross-cutting aspect was not assigned |
| 05000302/FIN-2009002-02 | 2009Q1 | Crystal River | Failure to Take Timely and Effective Corrective Actions Resulted in a Repeat Failure of a Main Feedwater Isolation Valve due to Magnesium Rotor Oxidation/Corrosion | The inspectors identified a NCV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Actions, for failure to take timely and effective corrective actions to prevent a second failure of a main feedwater isolation valve (MFIV) due to corrosion of the valve actuators magnesium rotor. Specifically, corrective actions associated with a similar failure of a MFIV in 2005 were not enhanced when additional information became available through NRC Information Notice (IN) 2006-026, Failure of Magnesium Rotors in Motor-Operator Valve Actuators. As a result, in December 2008, a MFIV failed to operate due to magnesium rotor degradation. Corrective actions for the failure of FWV- 30 include: installation of a new motor; development and implementation of engineering changes to replace the stations motor-operated valve (MOV) magnesium rotor motors with aluminum rotor motors (when available); ensuring the engineering staff is trained on effective correction action plans; and revision of MOV maintenance procedures to include information obtained from IN 2006-026 prior to the next MOV inspections. The finding was more than minor because it affected the equipment availability attribute of the Mitigating System cornerstone and resulted in a MFIV being inoperable for a period of time greater than allowed by ITS. Since the valve would not have performed its safety function for greater than the ITS allowed outage time, a SDP Phase 2 analysis was required. Based upon the Phase 2 results, a regional senior reactor analyst performed a Phase 3 evaluation. The Phase 3 evaluation concluded that the finding was of very low safety significance (Green). A contributing cause of the finding is related to the cross-cutting area of Problem Identification and Resolution with an operating experience component (P.2(b)). Specifically, the licensee did not implement and institutionalize, in a timely manner, IN 2006-26 in station procedures and training programs associated with magnesium rotor inspections |
| 05000302/FIN-2009002-03 | 2009Q1 | Crystal River | Inadequate Peer and Peer Checking Resulted in Connecting Improper Test Equipment and a Manual Plant Trip | A self-revealing finding was identified for the failure to follow procedure HUMNGGC- 0001, Human Performance Program, which required workers to perform self and peer checks to ensure the correct action is performed on the correct component. Specifically, during meter calibration activities, workers performing voltage checks failed to perform adequate self and peer checks when connecting test equipment. As a result, incorrect test equipment was connected resulting in blown fuses, the loss of several secondary plant pumps, and ultimately a manual plant trip. Corrective actions include: move relay work identified in the extent of condition review from on-line to outage to prevent recurrence, revise maintenance procedures associated with calibration of meters and relays to incorporate human factoring from lessons learned from this event, and perform an analysis of and incorporate best practices in procedures regarding how plant risk is assessed for activities that could cause transients. The finding was more than minor since it affected the human performance attribute of the Initiating Event Cornerstone and resulted in an event that upset plant stability. Specifically, the failure to properly utilize human performance tools such as self and peer checking as specified in HUM-GGC-0001, Revision 2, resulted in the connection of incorrect test equipment, the loss of several secondary plant pumps and ultimately led to a manual reactor trip. The inspectors assessed the finding using the SDP and determined that the finding was of very low safety significance (Green) since it did not contribute to the likelihood of a loss of coolant accident, did not contribute to a loss of mitigation equipment, and did not increase the likelihood of a fire or internal/external flood. The cause of the finding is related to the cross-cutting area of Human Performance with a work practices aspect (H.4(a)). Specifically, workers did not utilize proper self and peer checking |
| 05000302/FIN-2009004-01 | 2009Q3 | Crystal River | Inadequate Risk Assessments When Performing Surveillance Testing | The inspectors identified a non-cited violation (NCV) of 10 CFR 50.65(a)(4) for the failure to perform adequate risk assessments associated with a number of surveillance tests. Specifically, it was determined that risk assessments were not being properly performed for equipment that became unavailable as a result of surveillance testing. This condition has existed since implementation of the Equipment out of Service (EOOS) risk assessment software more than 10 years ago. Short term corrective actions include performance of additional peer reviews of upcoming performance and surveillance tests (PTs and SPs) to ensure they are included in the plant risk assessment and a similar independent review by the corporate probabilistic risk assessment staff. Long term corrective actions include: screen all SPs and PTs to evaluate for risk impact; develop a methodology to include risk significant SPs and PTs in the plant risk assessment, either automatically from the work schedule or a manual process; incorporate risk assessment process changes in licensee procedures; and provide additional EOOS training to the plant staff. Utilizing IMC 0612, Appendix B, Issue Screening, the finding was determined to be more than minor since licensee risk assessments failed to consider risk significant systems and support systems that were unavailable during maintenance. In order to determine the risk significance of this finding, the inspectors selected two recently performed surveillance procedures for two high risk systems that were not included in the licensees risk assessment. The SPs selected were decay heat system (DHR) SP-340B, DHP-1A, BSP-1A and Valve Surveillance and emergency feedwater (EFW) system SP-146A, EFIC Monthly Functional Test (During Modes 1, 2, 3). The risk deficit for SP-340B was determined to be less than 1E-6 incremental core damage probability deficit (ICDPD). The risk associated with SP-146A was not quantified since it was determined that the system did not lose its functionality during the SP. Utilizing IMC 0609, Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process (SDP), Flow Chart 1, the finding was determined to be of very low safety significance. This finding was not assigned a cross cutting aspect since the issue existed for greater than 10 years and is not indicative of current licensee performance |
| 05000302/FIN-2009005-01 | 2009Q4 | Crystal River | Failure to Follow a Plant Procedure Resulted in an Inoperable HPI System | A self-revealing Non-Cited Violation (NCV) of Improved Technical Specification (ITS) 5.6.1.1.a was identified for the failure to follow a plant procedure which resulted in a loss of a 480 volt engineered safeguards motor control center (ES MCC)-3B1. Concurrent with pre-existing conditions, the high pressure injection (HPI) system was declared inoperable and ITS 3.0.3 was entered for a period of one hour and 24 minutes. The licensee entered this issue into the corrective action program as nuclear condition report (NCR) 333515. The finding was more than minor since it affected the equipment availability attribute of the mitigating system cornerstone and resulted in ITS 3.0.3 entry for the HPI system being inoperable. The finding was evaluated against NRC Phase 1 Significance Determination Process (SDP) and Phase 2 SDP was required due to a loss safety function of the HPI system. A Regional Senior Reactor Analyst performed a Phase 3 SDP evaluation and concluded this finding was of very low safety significance (Green). The major assumptions of the evaluation were that the HPI function was out of service for exposure period (1 .5 hours) and there would be no recovery of the de-energized motor control center. The dominant accident sequence involved a support system failure of the Emergency Feedwater (EF) Indication and Control System rendering Main Feedwater and automatic control of EF unavailable, operators were unable to manually control EF flow causing its failure and with the HPI function lost due to the performance deficiency, core damage ensued. The inspectors determined the cause of the finding is related to the cross-cutting area of Human performance with a work practices aspect H.4 (c)). Specifically, work scope changes involving safety-related equipment did not receive the appropriate level management oversight resulted in a plant procedural violation |
| 05000302/FIN-2009005-02 | 2009Q4 | Crystal River | Manual Reactor Trip Due to Group 7 Control Rods Insertion Caused by Inadequately Protected Test Jumper | A self-revealing NCV of Improved Technical Specification (ITS) 5.6.1.1.a was identified for the failure to follow the provisions of preventative maintenance procedure PM-126, Electrical Checks of CRD (Control Rod Drive) Power Train. Failure to follow PM-126 caused the failure of the Group 7 control rod programmer during maintenance and resulted in the unexpected insertion of the Group 7 control rods fully into the core. This unexpected insertion of these control rods into the core caused control room operations personnel to manually trip the reactor from 100 percent power. The licensee entered this issue into the corrective action program as NCR 351705. This finding was determined to be more than minor because it was associated with the initiating events cornerstone attribute of Human Performance, and adversely affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during at-power operations. The finding was evaluated using Phase 1 of the At-Power SDP, and was determined to be of very low safety significance (Green) because it did not contribute to both the likelihood of a reactor trip and the likelihood that mitigating equipment or functions were not available. The cause of this finding was directly related to the cross-cutting area of Human Performance with a work practices aspect (H.4 (b)). Specifically, the workers failed to follow the preventative maintenance procedure |
| 05000302/FIN-2009005-03 | 2009Q4 | Crystal River | Licensee-Identified Violation | The following issue of very low safety significance (Green) was identified by the licensee and was a violation of NRC requirements. This issue met the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as a Non-Cited Violation. 10 CFR 26.205(d) requires, in part, that individuals subject to work hour controls do not exceed 26 work hours in any 48-hour period and 72 work hours in any 7-day period; requires a 34-hour break in any 9-day period; and a 10-hour break between successive work periods. During the period of October 12 to October 19, 2009, one worker exceeded 26 hours in a 48-hour period; nine workers exceeded 72 hours in a 7-day period; five workers did not have a 34-hour break in a 9-day period; and two workers did not have the required 10-hour break between successive work periods. The violation was limited to one work group, Florida Transmission Personnel, who were on-site to support outage work. The licensee determined that the Transmission personnel did not have a firm understanding of the revised 10 CFR Part 26 requirements. The finding was more than minor because, if left uncorrected, it would become a more significant safety concern. Specifically, the excessive work hours would increase the likelihood of human performance errors during plant maintenance activities that could affect equipment performance. The finding is of very low safety significance because no significant events or human performance issues were directly linked to personnel fatigue as a result of the hours worked. This issue was documented in the licensees corrective action program as NCR 361777 |
| 05000302/FIN-2010002-01 | 2010Q1 | Crystal River | Failure to Take Compensatory Actions When a MCR to CSR Floor/Ceiling Interface Access Hatch Was Open. | The inspectors identified a non-cited violation of Crystal River Unit 3 Operating License Condition 2.C.(9), for failure to take compensatory actions when a main control room (MCR) and cable spreading room (CSR) floor/ceiling interface access hatch was open rendering the CSR Halon fire extinguishing system inoperable. Once identified, the licensee initiated nuclear condition report (NCR) 266356 in the corrective action program to address this issue. The finding is more than minor because it is associated with the protection against external factors attribute, i.e., fire, and degraded the Mitigating Systems cornerstone objective to ensure the availability of systems that respond to initiating events. Specifically, the finding adversely affected the suppression fire extinguishing system capability defense-in-depth element. The inspectors evaluated this finding under NRC Inspection Manual Chapter (IMC) 0609, Appendix F, Fire Protection Significance Determination Process (SDP). The inspectors determined that a Phase 2 SDP was required for this finding because the CSR Halon concentration was highly degraded; a fire could occur due to non-qualified cables or transient combustibles while the hatch between the MCR and CSR was open; a duration factor (exposure time) was between 3 and 30 days; and control room operators evacuated the MCR in response to the fire. However, Phase 2 SDP of IMC 0609 Appendix F does not currently include explicit treatment of fires leading to MCR abandonment, either due to fire in the MCR or due to fires in other fire areas. Therefore, a Phase 3 SDP evaluation for this type of finding was needed. A Regional Senior Reactor Analyst performed a Phase 3 SDP for this finding and concluded that the finding was of very low safety significance (Green). The major assumptions and the dominant accident sequence were discussed in the 4OA5 analysis section of this report. The inspectors did not identify a cross-cutting aspect associated with this finding because it does not reflect current licensee performance. |
| 05000302/FIN-2010002-02 | 2010Q1 | Crystal River | Licensee-Identified Violation | The following issue of very low safety significance (Green) was identified by the licensee and was a violation of NRC requirements. This issue met the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as a non-cited violation. Improved Technical Specification (ITS) 3.7.1 states that MSSVs shall be operable as specified in ITS Table 3.7.1-1 in Modes 1, 2 and 3. Contrary to the above, on September 22, 2009, while performing SP-650, ASME Code Safety Valves Test, on the A OTSG in Mode 1, the as-found set points of three MSSVs were found outside the ITS 3.7.1 acceptance criteria of +/- 3 percent of the nominal set point. The valves were returned to operable status by adjusting their set point to within +/- 1 percent. The licensee concluded that the three MSSVs were inoperable for a period longer than allowed by plant ITS. The licensee determined that this ITS violation was a result of a failure, in past years when MSSVs were found out of tolerance, to provide adequate instructions to the vendor refurbishing the valves to determine the root causes of the out of tolerance condition. This lack of adequate vendor instructions was the result of the licensees failure to follow Corrective Action Program procedures which require that physical evidence and important information that is essential to identifying cause(s) be preserved. The finding was evaluated using Phase 1 of the At-Power SDP, and was determined to be of very low safety significance (Green) because the inspectors responded no to all questions in the mitigating systems cornerstone column of Table 4a, Manual Chapter 0609, Attachment 0609.04. This issue was documented in the licensees corrective action program as NCR 356521 |
| 05000302/FIN-2010003-01 | 2010Q2 | Crystal River | Degraded Fire/Flood Barriers | As required by Inspection Procedure 71152, Identification and Resolution of Problems, the inspectors performed a review of the licensees CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors review was focused on repetitive equipment issues, but also considered the results of daily inspector CAP item screening discussed in section 4OA2.1 above, plant status reviews, plant tours, and licensee trending efforts. The inspectors review nominally considered the six month period of January 2010 through June 2010. The review also included issues documented in the licensees Plant Health Committee Site Focus List June 2010, various departmental CAP Rollup & Trend Analysis reports, various nuclear assessment section reports and maintenance rule (MR) reports. Corrective actions associated with a sample of the issues identified in the licensees corrective action program were reviewed for adequacy. No findings were identified. The inspectors evaluated the licensees trend methodology and observed that the licensee had performed a detailed review. The inspectors review of licensee performance over the last six months noted one negative trend associated with degraded fire penetrations. In April, the inspectors found a degraded flood/fire penetration in the floor between the auxiliary building 95 elevation and the auxiliary building 75 elevation B train DHR/BS vault. In June, the inspectors found two degraded fire penetrations in the wall between the intermediate building and the turbine building. These penetrations are associated with the A train main steam piping. In both cases, the licensee declared the penetrations inoperable, initiated fire watches and entered the issues into the CAP (NCRs 396095 and 406215). As a result of these NRC inspector observations, the licensee indicated that they will perform an extent of condition inspection of all fire/flood penetrations to determine whether the fire barrier inspection frequency needs to be adjusted. The issue associated with these degraded fire barriers is unresolved pending completion of NRC review and analysis of licensee corrective actions and is identified as Unresolved Item (URI) 05000302/2010003-01, Degraded Fire/Flood Barriers. |
| 05000302/FIN-2010004-01 | 2010Q3 | Crystal River | Flood Calculations did not Reflect Plant Configuration | The inspectors identified a non-cited violation (NCV) of 10 CFR 50 Appendix B, Criterion III, Design Control, regarding the licensees failure to ensure that the design bases of two components were correctly translated into specifications, drawings, procedures, and instructions. Specifically, licensee personnel failed to ensure that two floor penetration flood barriers (metal sleeves) were of the proper height to prevent water from entering the A train decay heat removal (DHR)/building spray (BS) vault during a design basis internal flooding event. The design basis did not assume any leakage to the vault. The licensee initiated nuclear condition report (NCR) 409263 in the corrective action program to address the issue. This finding is more than minor because it affects the design control attribute of the mitigating system cornerstone, and affected the cornerstone objective of ensuring availability, reliability, and capability of systems that respond to initiating events. Using Manual Chapter 0609, Phase 1 screening worksheet, the inspectors determined that the finding has very low safety significance because it did not result in a loss of any system safety function. The inspectors found that the cause of the finding is not reflective of current performance and therefore, a cross-cutting aspect will not be assigned. |
| 05000302/FIN-2010004-02 | 2010Q3 | Crystal River | Inoperable Fire Barrier Penetration Seals | The inspectors identified an NCV, with five examples, of Crystal River Unit 3 Operating License Condition 2.C (9), fire protection program. The NCV was associated with one inoperable fire penetration seal in the ceiling of the B train decay heat and building spray pump vault and four inoperable fire penetration seals associated with the main steam piping in the wall between the intermediate building and the turbine building. Once identified, the licensee initiated an hourly watch and entered the issue in the corrective action program as nuclear condition reports 369096, 406215, and 418755. The finding is more than minor because if left uncorrected, the fire seals could experience further degradation and potentially lead to a more significant safety concern. Using NRC IMC 0609, Appendix F, Fire Protection Significance Determination Process, the inspectors assessed the defense-in-depth (DID) element of each fire barrier degradation in the fire confinement category. One penetration was determined to have a low degradation rating and was determined to be of very low safety significance. The other four degraded penetrations were determined to have moderate degradation and were screened to be very low safety significance due to having non-degraded automatic full area water-based fire suppression system available in the exposing fire area. A contributing cause of the finding is related to the cross-cutting area of Problem Identification and Resolution with an evaluation aspect (P.1.(c)). Specifically, the licensee had the opportunity to evaluate the need to change the frequency of main steam line fire penetration inspections after finding degradation of main steam piping penetrations in 2007. |
| 05000302/FIN-2010004-03 | 2010Q3 | Crystal River | Failure to Submit Production Splices of Swaged Mechanical Splices for the Testing | The inspectors identified a finding of very low safety significance and an associated NCV of 10 CFR Part 50, Appendix B, Criterion IX, Control of Special Processes, for the licensees failure to establish measures to assure that testing of rebar splices would adhere to the requirements of American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code. Specifically, licensee procedures for containment building repairs did not accommodate rebar production splice testing, which was required by Code. As part of their immediate corrective actions, the licensee revised their procedures to include production splice testing and also entered the issue into their corrective action program. The inspectors determined that the finding was more than minor because it was associated with the human performance attribute of the barrier systems cornerstone and affected the cornerstone objective of ensuring the reliability of containment wall barrier system. Failure to adhere to ASME Code testing requirements can adversely affect assurance that the rebar splices would meet strength requirements as part of the containment barrier. The inspectors completed a Phase 1 screening of the finding using Inspection Manual Chapter 0609, Significance Determination Process, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings and determined that the performance deficiency represented a finding of very low safety significance (Green). Specifically, the finding did not result in the actual loss of function of the Unit 3 Containment Wall. This finding has a cross-cutting aspect in the area of Human Performance under the Effectiveness Reviews aspect of the Decision-Making component because the licensee failed to validate assumptions used as a basis for their decision to pursue an alternative testing plan. (H.1(b)) |
| 05000302/FIN-2010005-01 | 2010Q4 | Crystal River | Licensee-Identified Violation | 10 CFR 50 Appendix B, Criterion III, Design Control, requires, in part, that measures shall be established to assure that applicable regulatory requirements and design basis for those structures, systems, and components are correctly translated into specifications, drawings, procedures and instructions. Engineering corporate procedures EGR-NGGC-0011, Engineering Rigor; and EGR-NGGC-0155, Specifying Electrical / I&C Modification Related Tests, implement those requirements. Contrary to the above, the licensee failed to translate the design basis into drawings and procedures when performing design modification EC 71897. This resulted in an electrical circuit error in the A EDG breaker logic circuitry. The inadequate EC removed a switchgear internal control wire that supplied DC control power to the following: 1) OPT differential lockout relay to trip breaker 3211, 2) MCB control switch open contacts to trip breaker 3211, and 3) emergency safety A-bus under-voltage trip circuit to trip breaker 3211. As a result of breaker 3211 not being able to trip under any of these three signals, the A EDG would not have been able to meet the logic required to load onto the safety bus when required. The licensee determined that engineering personnel did not have an adequate understanding of assessing the correct engineering depth and detail involved in designing and implementing the EC. The process deficiency of failing to provide adequate depth and detail on the EC is more than minor because, if left uncorrected, would have the potential to lead to a more significant safety concern. The finding was determined to be of very low safety significance (Green) because there were no diesel operability requirements during the time the inadequate EC had been installed. Additionally, the inadequate EC was identified and corrected by the licensee prior to the emergency generator being required by plant technical specifications to be available to support a change in mode. This issue was documented in the licensees corrective action program as NCR 431407. Additional information regarding this issue can be found in Section 4OA2.3. |
| 05000302/FIN-2011002-01 | 2011Q1 | Crystal River | Operating Crew Failures on the 2011 Annual Requalification Operating Test | A self-revealing Green finding, associated with operating crew performance on the simulator during facility-administered requalification examination was identified. Two of the eight crews evaluated failed to pass their simulator examinations. As immediate corrective action, the failed operating crews were remediated (i.e., the operating crews were re-trained and successfully retested) prior to returning to shift. The licensee has entered this issue into the corrective action program as Nuclear Condition Report (NRC) 450196. The inspectors determined that the crew failures constituted a performance deficiency based on the fact that licensed operators are expected to operate the plant with acceptable standards of knowledge and abilities demonstrated through periodic testing as required by 10 CFR 55.59(a)(2). Two out of eight crews of licensed operators failed to demonstrate a satisfactory understanding of the required actions and mitigating strategies required to safely operate the facility under normal, abnormal, and emergency conditions. The finding is greater than minor because the performance deficiency potentially affects the Human Performance attribute of the Mitigating Systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the finding reflected the crews potential inability to take timely actions in response to actual abnormal and emergency conditions. The cause of this finding was directly related to the cross-cutting aspect of personnel training and qualifications in the Resources component of the Human Performance area, in that the licensee failed to ensure the adequacy of the training provided to operators to assure nuclear safety. |
| 05000302/FIN-2011002-02 | 2011Q1 | Crystal River | Licensee-Identified Violation | Improved Technical Specification (ITS) 3.4.9 states that two pressurizer code safety valves (PCSVs) shall be operable in Modes 1, 2 and 3. To be operable, the lift setpoints must be within +/- 2 percent of 2500 psig. Contrary to the above, on September 1, 2010 and on October 5, 2010, Progress Energy was notified that the as-found lift setpoints of PCSVs RCV-9 and RCV-8 were outside ITS setpoint limits, respectively. The as-found lift setpoint of RCV-9 was 5.32 percent above the lift setpoint and RCV-8 was 2.08 percent above the lift setpoint. The licensee identified a selected cause associated with the licensees failure to manage vendor quality. The performance deficiency, failure to provide proper relief valve specifications to the vendor, was determined to be greater than minor because if left uncorrected, the performance deficiency would have the potential to lead to a more significant safety concern regarding the integrity of the reactor coolant system (RCS) barrier during plant transients. Corrective actions planned or completed include: changing the as-left setpoint to +0/-1 percent of the nominal setpoint; installing PCSVs with +0/-1 percent of nominal setpoint prior to unit startup; creation of a test procedure for steam testing the PCSV to meet the licensees standards; and revision of specifications associated with PCSV repairs. As documented in Section 4OA3, the finding was determined to be of very low safety significance (Green) because there was no loss of safety function due to the lift setpoints being outside of the ITS limit. This issue was documented in the licensees corrective action program as NCR 426852. |
| 05000302/FIN-2011003-01 | 2011Q2 | Crystal River | Licensee-Identified Violation | 10 CFR 50 Appendix B, Criterion III, Design Control, requires, in part, that measures shall be established to assure that applicable regulatory requirements and design basis for those structures, systems, and components are correctly translated into specifications, drawings, procedures and instructions. Licensee corporate engineering procedures EGR-NGGC-0005, Engineering Change; and Administrative Corporate procedure ADM-NGGC-0116, Nuclear Planning, implement those requirements. Contrary to the above, the licensee failed to translate the design basis requirements of modifications MAR 86-09-15, Raw Water Joint Encapsulation Sleeve, and MAR 90-08-16, Circulating Water Joint Encapsulation Sleeve, into work orders or procedures to ensure continued maintenance of design basis requirements. As a result, the raw water and circulating water encapsulation sleeves were found to have a larger gap than allowed by design, and consequently would have caused a greater internal flood rate into the auxiliary building had the expansion joints failed. The performance deficiency of failing to maintain the gaps within the required tolerances on the raw water and circulating water encapsulation sleeves is more than minor because, if left uncorrected, would have the potential to lead to a more significant safety concern during a rupture of a raw water or circulating water expansion joint. The licensees corrective actions include revising maintenance procedures to add acceptance criteria for the encapsulation sleeve gaps. The finding was determined to be of very low safety significance (Green) because after performing additional engineering evaluations and calculations, it was concluded that the auxiliary building internal design basis flood requirements were not exceeded. This issue was documented in the licensees corrective action program as NCRs 456729, 457510, and 457181. |
| 05000302/FIN-2011005-01 | 2011Q4 | Crystal River | Licensee-Identified Violation | The following violation of very low safety significance (Green) was identified by the licensee and was a violation of NRC requirements which met the criteria of the NRC Enforcement Policy for being dispositioned as a Non-Cited Violation: • Improved Technical Specification 5.6.1.1a requires that written procedures recommended in Regulatory Guide (RG) 1.33, Revision 2, Appendix A, be established, implemented, and maintained. RG 1.33, Appendix A, includes general operating procedures for Refueling & Core Alterations in the list of recommended procedures. Plant Operating Manual FP-601A, Operation of the Main Fuel Handling Bridge FHCR-1, Section 3.2.22, requires, in part, that a refueling SRO be stationed during a core alteration. Contrary to this requirement, the licensee secured the refueling SRO during activities determined to be a core alteration for approximately seven-hours on May 24, 2011. The licensee entered this issue into their CAP as CR 467392. The significance of the finding was determined using Manual Chapter 0609, Significance Determination Process, Appendix G, Checklist 4 (PWR Refueling Operation, RCS level > 23 ft) and determined to be of very low safety significance (Green), because it did not cause the loss of mitigating capability of core heat removal, inventory control, power availability, containment control, or reactivity control. Additional information regarding this NCV is discussed in Section 4OA2 of this inspection report. |
| 05000302/FIN-2012005-01 | 2012Q4 | Crystal River | Licensee-Identified Violation | The inspectors reviewed the reportability evaluations associated with the unsatisfactory penetrations. The inspectors questioned the adequacy of these evaluations in that they estimated that a significant level of water (approximately three to four feet) would accumulate in the turbine building during PMH conditions, but concluded that none of this flood water would pass through the set of fire doors from the turbine building to the auxiliary building. The subject fire doors are rated for 2 feet of water pressure. The reportability evaluations heavily relied upon actions taken in the licensees adverse weather procedure EM-220, Violent Weather, to sandbag the fire doors prior to hurricane conditions. The inspectors did not have confidence in the adequacy of sandbagging instructions in EM-220 or that the door could withstand three to four feet of turbine building flooding to preclude flooding in auxiliary building. As a result of the inspectors concerns, the licensee initiated CR 563931 to re-evaluate the expected flood levels in the turbine building during PMH conditions. The inspectors reviewed the completed evaluation and noted that more reasonable external flooding conditions were used and the evaluation took credit for other actions in the adverse weather procedure such as use of dewatering pumps. The inspectors also noted that the evaluation included the estimated flooding contribution from two additional unsatisfactory penetrations which were identified in August 2012 during the licensees Fukushima flooding walkdowns and documented in CRs 556385 and 557156. The inspectors concluded that, due to the location and condition of the two penetrations, their overall flooding contribution was negligible when compared to the overall flood level due to the 29 penetrations previously identified by the licensee. The new evaluation concluded that the resulting flood level through the 29 penetrations during PMH conditions would be 1.27 feet of water in the turbine building, which is within the rating of the fire doors. The inspectors concurred with the licensees conclusion that this flood level would not adversely impact the allowable flood limit in the auxiliary building. The inspectors verified that the licensee had performed an adequate extent of condition review to identify the unsatisfactory below grade penetrations and that appropriate actions were being taken to correct the issue. The inspectors verified that, as of the end of this inspection period, 19 of the 28 unsatisfactory penetrations had been repaired. The remaining were scheduled for repair. |
| 05000324/FIN-2011004-01 | 2011Q3 | Brunswick | Inadequate Configuration Control Resulted in Rainwater Intrusion into the Unit 2 Reactor Building | A self-revealing Green non-cited violation of TS 5.4.1, Procedures, was identified for failure to implement procedural requirements of the equipment configuration control program to ensure that temporary power cables routed through an open manhole and into the reactor building north RHR (NRHR) room did not adversely impact the flood mitigation function of the storm drain system. This finding resulted in rainwater intrusion into the unit 2 reactor building. Upon discovery of this condition, the licensee resealed the manhole. The condition was entered into the licensees CAP as AR #483473. The failure to implement the requirements of the equipment configuration control program to ensure that the temporary cable routing did not adversely impact external flood protection features was a performance deficiency. The performance deficiency was more than minor because it was associated with the Mitigating Systems cornerstone attribute of Protection Against External Factors - Flood Hazards and adversely affected the cornerstone objective in that the temporary change impacted the storm drain system which was credited for external flood protection. Using Inspection Manual Chapter 0609, Significance Determination Process, Attachment 0609.04, Phase 1 Screening Worksheet, the finding screened as very low safety significance (Green) because it: (1) was not a design or qualification deficiency that was confirmed not to affect equipment operability; (2) did not represent a loss of safety function; (3) did not represent an actual loss of a single train of equipment for more than its Technical Specification allowed outage time; (4) did not represent a loss of risk significant non-Technical Specification equipment; and (5) did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The finding did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event per table 4b of the worksheet because the leakage did not degrade the RHR system. The cause of the finding was directly related to the appropriately planning work activities cross-cutting aspect in the Work Control component of the Human Performance area because the licensee failed to incorporate environmental conditions which may impact plant structures, systems, and components into the temporary change. |
| 05000324/FIN-2011004-02 | 2011Q3 | Brunswick | Inadequate Corrective Actions for Control Building Air Conditioning Failures | The inspectors identified a Green non-cited violation of 10 CFR 50 Appendix B, Criteria XVI, Corrective Action, for the licensees failure to promptly identify and correct a condition adverse to quality related to the Control Room Air Conditioning (AC) system. Specifically, the licensee failed to identify and correct repetitive failures of nonconforming low ambient temperature damper actuators for the 2D control building air cooled condenser unit. This resulted in multiple control building AC refrigerant circuit failures. Upon discovery of the issue, the licensee placed the control building AC system in a safe condition for summer operation and initiated actions to procure acceptable damper actuators prior to the onset of low seasonal temperatures. The condition was entered into the licensees CAP as AR #462873. The inspectors determined that the licensees failure to promptly identify and correct the failures of the 2D control room AC system low ambient temperature damper actuators was a performance deficiency. This finding is more than minor because it is associated with the Equipment Performance attribute of the Mitigating Systems Cornerstone, and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage). Specifically, the finding reduced the reliability of the control building AC system and its ability to maintain control building equipment within specified temperature limits. The significance of the finding was evaluated using Phase 1 of the significance determination process in accordance with the Inspection Manual Chapter 0609 Attachment 4. The finding was determined to be of very low safety significance (Green) because the finding was a design or qualification deficiency that was confirmed not to affect equipment operability. The cause of this finding was directly related to the cross cutting aspect of thorough evaluation of problems in the Corrective Action Program component of the Problem Identification and Resolution area, because the licensee failed to promptly evaluate the failures of the low ambient temperature damper actuators and eliminate the adverse condition. |