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05000338/FIN-2018003-012018Q3North AnnaLicensee-Identified ViolationThis violation of very low safety significance was identified by the licensee and has been entered into the licensee corrective action program and is being treated as a Non-Cited Violation, consistent with Section 2.3.2.a of the Enforcement Policy. Violation: TS 5.4.1.a, requires in part, that written procedures shall be established per Revision 2 of Regulatory Guide 1.33, Appendix A, of which part 9.a requires written procedures and documented instructions appropriate to the circumstances for performing maintenance that can affect the performance of safety related equipment. Contrary to the above, on June 12, 2018, the licensee failed to adequately establish a procedure appropriate to the circumstances during maintenance on the safety-related main control chillers. Specifically, licensee mechanical preventative maintenance procedure, 0-MPM-0806-02, Inspection of Control Room Chillers, Revision 0, did not provide a proper method to adequately monitor the Freon level in main control room chillers. Consequently, the licensee discovered a low Freon level condition on main control room chiller 1-HV-3-4B, which rendered the chiller inoperable. Significance: The inspectors reviewed Exhibit 2 Mitigating Systems Screening Questions of IMC 0609 Appendix A, The Significance Determination Process (SDP) for findings at Power and determined this finding was of very low safety significance, Green, because there was no design deficiency, it did not represent a loss of system or function, and did not represent an actual loss of function for greater than its TS allowed outage time. Corrective Action Reference: CR109958
05000400/FIN-2018001-012018Q1HarrisAdequacy of Fire Brigade Response During Fire DrilThe inspectors identified an URI during the March 21, 2018, announced fire drill that was observed. The drill involved an electrical failure inside the A transfer panel located in the RAB 286 elevation A cable spread room. The fire scenario assumed the electrical failure caused an explosion and fire in the room. The inspectors noted several performance weaknesses during the drill:The fire brigade leader directed three fire brigade members into the fire hot zone to fight the fire as the attack team. Since there is a 5-member fire brigade, only two fire brigade members remain, one of which is the fire brigade leader (who also serves as the site incident commander (SIC)), to be part of the designated 2-out rescue team, required when fighting internal building fires. This 2-out rescue team is responsible, if necessary, for providing assistance or rescue for any or all of the attack team members. The inspectors were concerned that this fire brigade strategy could result in challenges with fire brigade leader command and control, and with the effectiveness of conducting rescues. The fire brigade leader could be hampered in his primary role of directing a site fire response while serving as a rescue team member. Adding to this complication, in locations where radios are not allowed inside some buildings with electrical sensitive equipment during firefighting, as was the case for this fire drill, it would be difficult for the fire brigade leader to communicate and coordinate with the control room or others during a rescue situation. Regarding the actual rescue activity, its effectiveness could be challenged since a two-person rescue team would be faced with potentially assisting/removing three attack members out of the hot zone. Based on discussions with licensee fire brigade training personnel following the drill, theinspectors learned that this 3-in, 2-out deployment was the current manner in which all internal building firefighting strategies and fire training was based upon.The fire brigade leader allowed the 3-man attack team to enter the fire hot zone with permission to commence firefighting prior to the 2-man rescue team arriving at the fire scenes pre-established incident command post and available for implementing rescue. The inspectors later learned that the rescue team, including the fire brigade leader, had arrived at the incident command post approximately five minutes after the attack team had entered the fire area. This delay involved the fire brigade leader completing his thermal protective clothing dressout in the locker room. The inspectors were concerned that under actual circumstances, if the 2-man rescue team were not ready and prepared to fulfill their rescue responsibilities upon entry of the attack team into the fire hot zone, the effectiveness of the rescue team could be challenged.The inspectors observed that no fire hose or other form of fire suppression was pulled or readily available for the 2-man rescue team to take with them should they have needed to enter the hot zone to rescue the attack team. When questioned about this, the inspectors were told that on the same fire hose that the attack team was using, a 1-1/2 inch gated wye valve had been connected, and the rescue team could have connected another 50-foot, 1-1/2 inch fire hose to it and used that hose as a rescue hose. However, the inspectors determined this was inadequate since to get to this hose connection, the rescue team would have to enter into the hot zone prior to reaching it. In addition, the inspectors learned that the use of this 1-1/2 inch gatedwye valve to create two hose streams for either attack or rescue that essentially splits the available flow capacity through a single 1-1/2 inch hose station nozzlewas allowed in multiple fire pre-plan strategies. At the conclusion of the inspection, the inspectors were continuing to assess whether the use of these gated wye valves had been formally reviewed by the licensee in the past to ensure that the flow capacity of fire hose streams would not be adversely impacted by their use during a fire.Planned Closure Actions: Pending completion of additional evaluations needed to determine whether the above fire brigade issues of concern represented performance deficiencies and if so, whether the performance deficiencies were of more than minor significance, this issue was identified as an unresolved item.Licensee Actions: The licensee initiated an NCR to address the inspectors concerns. In addition, until a more thorough review of their fire brigade program could be performed against their NFPA 805 fire program requirements, an operator standing instruction (#18-009, Fire Brigade 2-Out Response) was developed and implemented. This standing instruction directed the following specific fire brigade required actions:The brigade attack team will consist of two fire members to ensure the fire brigade SIC is not normally utilized as one of the 2-out members. If a runner is needed based on the fire area, the SIC may serve as a 2-out member, but this should be the exception.The 2-out members will establish a ready method of suppression that is accessible outside the fire zone. This should be the identified backup hose in the fire pre-plan. This hose does not need to be charged but should be flaked out and ready for use.The attack team will not enter the fire area, except when search and rescue is necessary, until the 2-out team is in the area with the suppression method ready for use.The inspectors determined that the licensees interim actions were adequate to ensure the fire brigade response would be effective if called upon pending resolution of the issues. Corrective Action Reference: NCR 02194468NRC Tracking Number: URI 05000400/2018001-01
05000400/FIN-2017002-022017Q2HarrisB ESCW Chiller Failure to StartThe inspectors opened a URI to facilitate the completion of inspection and determination of whether a performance deficiency was associated with the start failure of the B ESCW chiller on May 13, 2017. Description: On May 13, 2017, while attempting to start the B ESCW chiller, the motor compressor immediately tripped on C phase instantaneous overcurrent relay actuation. The chiller was declared inoperable and immediate troubleshooting was conducted to determine the cause of the trip. The licensees initial investigation did not identify any electrical or mechanical issues with the compressor motor, supply breaker and electrical bus, or other chiller control components. While the calibration of the C phase instantaneous overcurrent relay was checked and found to be within specification, the licensee determined the most probable cause of the trip was an intermittent failure of this relay. The relay was replaced and subsequent post-maintenance testing of the chiller was successfully performed without any other chiller operational problems being identified. The chiller was returned to operability early May 14, 2017, following the completion of this post-maintenance testing. At the end of the inspection period, the licensees investigation into the cause of the start failure had just completed. A URI is being opened for the NRC to review the licensees failure analysis and causal evaluation to determine whether the chiller start failure was reasonably within the licensees ability to predict or prevent and therefore a performance deficiency. This issue is being tracked as URI 05000400/2017002-02, B ESCW Chiller Failure to Start
05000400/FIN-2017002-012017Q2HarrisEvaluate Fire Protection Discrepancies in RHR/CS Pump RoomsAn unresolved item (URI) was identified by the inspectors during the walkdown of the A and B RHR and CS pump rooms, involving the use of unapproved non-fire retardant plastic sheeting to contain contamination on the A RHR piping. Additionally, the inspectors identified that the fire pre-plan for fire brigade response delineates a hose station that did not contain adequate fire hose length.Description: The inspectors identified two issues of concern during the fire protection walkdown of the A and B RHR and CS pump rooms as follows: 1) Use of Unapproved Plastic for Contamination Control: The inspectors noted that an approximately 30 foot section of the A RHR pump suction piping had been wrapped with multiple layers of plastic sheeting materials that included radiation protection yellow Caution Radioactive Materials stamped plastic sheeting overlaid with clear stretch wrap plastic. The section of RHR piping where this plastic was installedincluded the motor-operated RHR suction valves from the containment recirculation sump (valve 1SI-310) and the refueling water storage tank supply (valve 1SI-322). The inspectors were concerned that these valves could be adversely impacted from a potential fire involving this plastic material. The inspectors questioned whether this plastic was fire retardant material or had been evaluated and allowed under the licensees transient combustible control procedure. The licensee subsequently determined that none of the plastic material was fire retardant or met the requirements of National Fire Protection Association (NFPA) 701, Standard Methods of Fire Tests for Flame Propagation of Textiles and Films, and no previous transient combustible evaluation could be found that allowed the use of the non-fire retardant plastic in the RHR pump room. In addition, radiation protection personnel indicated that there could be other areas where this plastic was used since it was a typical practice to use the material to prevent the spread of contamination from leaking piping connections, valves, and valve packing. The licensee subsequently removed the plastic from the A RHR piping and initiated NCR 02132781 to evaluate this issue of concern. 2) Inadequate Fire Hose Length in Hose Station Described in Fire Pre-Plan: During review of the fire pre-plan procedure (FPP-012-02-RAB190-216) for the A and B RHR/CS pump rooms on the RAB 190 elevation, the inspectors noted that the procedure described two fire hose stations intended to be used during fire brigade response for a fire in either of the pump rooms. These two hose stations were the respective hose stations located just inside the access door to each of the two RHR/CS pump rooms. The procedure states that an extra 100 feet of hose would be needed to account for the additional distance for the hose from the opposite train pump room. However, the inspectors identified that even with the extra 100 feet added to the existing 100 feet that is already in each hose station, there would still not be adequate length for this second hose to reach the opposite train pump room with the fire. The inspectors measured the actual distance between the two locations and estimated the hose would have to be over 300 feet in length in order to be effective in fighting a fire in either of the rooms. A separate hose station on the 216 RAB elevation may provide adequate backup coverage. However, the inspectors were concerned that the issue with the fire pre-plan hose station use could cause confusion or pose an unnecessary delay in fire brigade response for a fire in either of the rooms. The licensee subsequently initiated NCR 02134163 to evaluate this issue of concern.Pending completion of additional evaluations needed to determine whether the above issues of concern represented performance deficiencies and if so, whether the performance deficiencies were of more than minor significance, this issue is identified as URI 05000400/2017002-01, Evaluate Fire Protection Discrepancies in RHR/CS Pump Rooms.
05000324/FIN-2017001-052017Q1BrunswickLicensee-Identified ViolationTS limiting condition for operation (LCO) 3.3.3.1, Condition F, Post Accident Monitoring (PAM) Instrumentation, states in part , with the DWHRRMs inoperable, a Special Report shall be submitted to the Commission within the next 14 days. Contrary to the above, the licensee failed to identify the inoperability of the DWHRRMs after the NRC Information Notice 97 -45 Supplement 1 was issued. In particular, the DWHRRMs signals cables are susceptible to thermally induced currents which can degrade the accuracy of DWHRRMs . The required action of LCO 3.3.3.1 , action F, was not perf ormed from 1998 until December 5, 2016. Using IMC 0609, Appendix B, Emergency Preparedness Significance Determination Process, inspectors determined that this violation was of very low safety significance (Green) because the finding is related to Emergenc y Preparedness Requirements that are not associated with a planning standard function (e.g.,10 CFR 50.54(q), 10 CFR 50.54(t), and requirements in Appendix E to 10 CFR Part 50 that do not support a planning standard function ). Other parameters could be used to validate the indications from the DWHRRMs . The corrective action is to restore the monitors to operable. This issue was documented in the licensees CAP as NCR 2066681
05000324/FIN-2017001-042017Q1BrunswickFailure to Enter the Technical Specification for an Inoperable 1D Control Room Air Conditioning UnitGreen . An NRC- identified Green NCV of Technical Specification (TS) 3.7.4, Control Room Air Conditioning (AC) System, was identified for the failure to declare the 1D control room AC unit inoperable. Specifically, on December 1, 2016, the licensee failed to declare the 1D control room AC unit inoperable due to extensi ve corrosion on the support channels . As a result, the 1D control room AC unit was inoperable from December 1, 2016, until the next time it was inspected on January 30, 2017, and exceeded the TS allowed outage time. As corrective actions, the licensee replaced the supports of the 1D and 2D control room AC units and inspected the 2E control room AC unit for corrosion. The licensee entered this issue into the CAP as NCRs 2113799 and 2113800. The inspectors determined the licensees failure to declare the 1D control room AC unit inoperable on December 1, 2016, and enter TS 3.7.4 was a performance deficiency. The finding was more than minor because it was associated with the structures, systems, and components ( SSC ) att ribute of the Barrier Integrity Cornerstone and adversely affected the cornerstone objective of providing reasonable assurance that physical design barriers (fuel cladding, reactor coolant system, and containment) protect the public from radionuclide releases caused by accidents or events. Specifically, this resulted in the 1D control room AC unit being inoperable from December 1, 2016, to January 30, 2017. Using IMC 0609, Appendix A, issued June 19, 2012, the SDP for Findings At -Power, the inspectors det ermined the finding was of very low safety significance (Green) because the finding did not only represent a degradation of the radiological barrier function for the control room and the finding did not represent a degradation of the barrier function of the control room against smoke or toxic atmosphere. This finding had a cross cutting aspect in the area of problem identification and resolution associated with the resolution aspect because the licensee failed to take effective corrective actions to addres s issues in a timely manner commensurate with their safety significance. Specifically, the licensee did not correct the degradation of the 1D control room AC unit until the unit was inoperable. (P.3)
05000324/FIN-2017001-032017Q1BrunswickFailure to Install Flood Barrier Seals Around the EDG 2 Four -Day Fuel Oil Tank VentsGreen . An NRC- identified Green NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, was identified for the failure of the licensee to install flood barrier seals around the emergency diesel generator (EDG) 2, four -day fuel oil tank v ent as described in engineering change (EC) 400606. This result ed in a nonfunctional flood barrier into the EDG 2 four -day tank room. As an immediate corrective action, the licensee grouted the opening to prevent water intrusion into the EDG 2 four -day f uel oil tank room. The licensee entered this issue into the CAP as NCR 2093563. The inspectors determined the failure of the licensee to control the design of the installation of the new EDG 2 four -day fuel oil tank vent was a performance deficiency. Th e finding is more than minor because it is associated with the protection against external factors (i.e., flood hazard) attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability , and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., c ore damage). Specifically, the licensee failed to install flood barrier seals around the EDG 2 four -day fuel oil tank vent designed to mitigate a flood of the EDG 2 four -day fuel oil tank room. Using IMC 0609, Appendix A, issued June 9, 2012, The SDP for Findings At -Power, the inspectors determined the finding screened to Exhibit 4, External Events Screening Questions, since the finding involved the loss of equipment specifically designed to mitigate a flood. The inspectors determined the finding screened to Green since if the flood barrier is assumed to be completely failed, it 4 would not result in the inoperability or degradation of EDG 2, and would not involve the total loss of any safety function that contributes to external event initiated core damage accident sequences. The finding has a cross -cutting aspect in the area of human performance associated with the design margins attribute because the licensee failed to maintain equipment within design margins and failed to change margins through a systematic and rigorous process. Specifically, the licensee changed the installation of the EDG 2 fuel oil tank roof vent without ensuring flood protection during the modification. (H.6)
05000400/FIN-2017001-012017Q1HarrisLicensee-Identified ViolationThe following violation of very low safety significance (Green) was identified by the licensee and is a violation of NRC requirements which meet the criteria of the NRC Enforcement Policy, for being dispositioned as a NCV. Appendix B to 10 CFR Part 50, Criterion V, Instructions, Procedures, and Drawings, required in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. Contrary to the above, on March 22, 2017, the licensee identified that an environmental protection feature, 1EE-E668 (FHB 261 floor hatch), was removed from service withou stationing a dedicated attendant as required by licensee procedure AP-046, Control of Environmental Protective Features. The floor plug was removed for two days (March 20-22, 2017) to support maintenance activities before the condition was identified by licensee operations personnel while performing rounds. Using IMC 0609, Appendix A, Significance Determination Process for Findings At-Power, inspectors determined that this violation was of very low safety significance (Green) because the finding did not impact the frequency of a fire or internal flooding initiating event and all structures, systems, and components remained capable of performing there intended safety functions. This issue was documented in the licensees CAP as AR 20110596.
05000324/FIN-2017001-012017Q1BrunswickNonfunctional Sprinklers in the Service Water Building Without Compensatory MeasuresGreen . An NRC- identified Green non -cited violation ( NCV ) of License Condition 2.B.(6), Fire Protection Program, was identified for the licensees failure to implement compensatory measures for nonfunctional sprinklers. Specifically, from January 11, 2017, until January 14, 2017, fire sprinklers were impaired when scaffold ing was built over the service water (SW) system discharge valves without the proper fire protection evaluation and compensatory measures , as required by licensee procedure 0PLP -01.2, Fire Protection System Operability, Action, and Surveillance Requirements . The licensees corrective actions included declaring the sprinklers nonfunctional, and implementing an hourly fire watch and backup suppression until the scaffold could be removed. This issue was entered into the licensees corrective action program (CAP) as nuclear condition report (NCR) 2091795. The inspectors determined that the licensees failure to implement compensatory measures for nonfunctional sprinklers , in accordance with procedure 0PLP -01.2, was a performance deficiency. The finding was more than minor because it was associated with the Protection against E xternal Events attribute (i.e. fire) of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, this resulted in nonfunctional sprinklers in a safety -related area without compensatory measures. The finding was screened using NRC IMC 0609, Appendix F, Fire Protection Significance Determination Process, dated September 20, 2013, because the finding affected the fixed fire protection system capability. Using IMC 0609, Appendix F, Attachment 1, Fire Protection S DP Phase 1 Worksheet, dated September 20, 2013, the finding was assigned to the Fixed Fire Protection System category because the nonfunctional sprinklers affected the automatic fire suppression system. Proceeding to Task 1.3.1 of IMC 0609, Appendix F, Attachment 1, the inspectors determined the finding was of very low safety significance (Green), because with the sprinklers nonfunctional, the reactor was able to reach and maintain safe shutdown. The finding has a cross -cutting aspect in the area of human performance associated with the field presence attribute because leaders did not observe, coach, and reinforce standards and expectations regarding scaffolding . Deviations from standards and expectations for building scaffolding near fire protection sprinklers were not corrected promptly. (H.2)
05000324/FIN-2017001-022017Q1BrunswickFailure to Control a Temporary Fire Ignition Source Near the Unit 2 Standby Liquid Control Pump Motor and CablesGreen . An NRC- identified Green NCV of License Condition 2.B.(6), Fire Protection Program, was identified for the licensees failure to adequately control fire ignition sources in the Unit 2 standby liquid control (SLC) pump ar ea in accordance with licensee procedure AD -EG -ALL -1523, Temporary Ignition Source Control. Specifically, between January 7, 2017, and January 13, 2017, a temporary electric portable heater was energized 2 feet from an SLC pump motor without continuously attending the temporary ignition source or obtai ning a continuous fire watch. The licensees c orrective actions included turning off the heater and removing it from near the SLC pumps. This issue was entered into the licensees CAP as NCR 2091736. The inspectors determined that the licensees failure to control fire ignition sources in accordance with licensee procedure AD -EG -ALL -1523, was a performance deficiency. The finding was more than minor because it was associated with the Protection Against External Events attribute (i.e. fire) of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the temporary ignition source could have affected a nearby safety -related SLC pump motor and cables, which provide a shutdown mitigation function. The finding was screened using NRC IMC 0609, Appendix F, Fire Protection Significance Determination Proc ess, dated September 20, 2013. Using IMC 0609, Appendix F, Attachment 1, Fire Protection SDP Phase 1 Worksheet, dated September 20, 2013, the findi ng was assigned to the Fire Prevention and Administrative Controls category because the portable heater is part of the plants combustible materials control program. Proceeding to Task 1.3.1 of IMC 0609, Appendix F, Attachment 1, the inspectors determined the finding was of very low safety significance (Green), because even if one train of SLC had been inoperable, the reactor was able to reach and maintain safe shutdown. This finding had a cross cutting aspect in the area of human performance associated wi th the teamwork aspect because individuals failed to effectively communicate and coordinate their activities to ensure that the temporary heaters were energized following prescribed fire protection control measures and written instructions. (H.4)
05000400/FIN-2016004-012016Q4HarrisLicensee-Identified ViolationTS limiting condition for operation (LCO) 3.3.3.6, Action C, Accident Monitoring Instrumentation, states in part that with the number of operable accident monitoring instrumentation channels for the radiation monitor(s), less than the minimum channels operable, initiate the preplanned alternate method of monitoring the appropriate parameter(s), within 72 hours, and either restore the inoperable channel(s) to operable status within 7 days or prepare and submit a Special Report to the Commission, pursuant to Specification 6.9.2, within the next 14 days. TS Table 3.3-10 indicates that a minimum of one channel of the Containment High Range Radiation Monitors (CHRRMs) is required to be operable. Contrary to the above, the licensee identified that they failed to identify the inoperability of the CHRRMs and take the required actions of LCO 3.3.3.6, Action C, from 1998 until an operability determination was completed in September 2016. Using IMC 0609, Appendix B, Emergency Preparedness Significance Determination Process, inspectors determined that this violation was of very low safety significance (Green) because the finding was a failure to comply with a non-risk significant planning standard and no planning standard function failure occurred since other parameters could be used to validate the indications from the CHRRMs. This issue was documented in the licensees CAP as AR 2063783.
05000324/FIN-2016003-012016Q3BrunswickFailure to Implement Risk Management Actions during Elevated RiskAn NRC-identified Green non-cited violation (NCV) of 10 CFR 50.65(a)(4) was identified for the failure of the licensee to implement all necessary prescribed risk management actions (RMAs) during a 2A residual heat removal (RHR) and residual heat removal service water (RHRSW) outage. Specifically, between August 31, 2016, and September 1, 2016, the licensee failed to post protective equipment signs on the 2B RHR/RHRSW motor control centers (MCCs) whose unavailability would have taken Unit 2 into a Yellow risk condition. The licensee took immediate corrective actions to protect the 2B RHR/RHRSW MCCs in the field. The licensee entered this issue into the corrective action program (CAP) as nuclear condition report (NCR) 2059064. The inspectors determined the failure of the licensee to adequately post protected equipment signs for the 2B RHR/RHRSW system, whose unavailability would have taken the unit into a Yellow risk condition, was a performance deficiency. The finding was more than minor because if left uncorrected, the failure to perform RMAs could result in a loss of a safety-related mitigating function, specifically the RHR low pressure coolant injection (LPCI). Using IMC 0609, Appendix K, issued May19, 2005, Maintenance Risk Assessment and Risk Management Significance Determination Process, Flowchart 2, Assessment of RMAs, the inspectors determined the finding screened as very low safety significance (Green) since the incremental core damage probability was less than 1E-6. The finding has a crosscutting aspect in the area of human performance associated with the procedure adherence attribute because the licensee failed to follow plant procedures to fully protect the 2B RHR/RHRSW loop during the 2A RHR/RHRSW loop outage.
05000324/FIN-2016003-062016Q3BrunswickTornado Missile Vulnerability Results in Condition Prohibited by Technical SpecificationsOn July 21, 2016, Units 1 and 2 were in Mode 1 at 100 percent of RTP. At that time, the licensee determined that a conduit in the EDG building was vulnerable to a tornado missile. The tornado missile vulnerability has existed since original plant construction. The conduit contains cables associated with Unit 2 NSW pump B. If the cables were disabled by a tornado missile, 2B NSW pump would be inoperable. TS 3.7.2, Service Water System and Ultimate Heat Sink, requires three of the four NSW pumps to be operable. The licensee determined that during other NSW pump outages, TS 3.7.2 AOT was exceeded. Inspectors verified the immediate compensatory measures were taken and intermediate compensatory measures were taken including updating station abnormal procedures to start the NSW pumps via the alternate safe shutdown switches and providing training to address the vulnerability during tornadoes. Enforcement Guidance Memorandum 15-002, Enforcement Discretion for Tornado-Generated Missile Protection Noncompliance, was implemented, and the licensee declared the 2B NSW pump operable but nonconforming. The licensee entered this issue into the CAP as NCR 2028383. The inspectors reviewed the cause evaluation and the LER. Documents reviewed are listed in the Attachment.
05000400/FIN-2016003-012016Q3HarrisSubsequent Loss of Safety-Related Chilled Water System Results in a Loss of Safety FunctionThe inspectors opened a URI to facilitate prompt tracking, documentation, and closure of inspection, verification, and resolution activities, associated with the A ESCW chiller failures. On July 15, 2016, the A ESCW chiller tripped on low oil pressure. Licensee investigation identified that oil was leaking from the threaded portion of a brass fitting located between a pressure switch and needle valve associated with PDS-01CY-9428ASA-HI. Upon removal, it was observed that significant radial cracking occurred in the threaded portion of the brass fitting. A like-for-like replacement was installed and the A ESCW chiller was returned to service. One week later, on July 22, 2016, the A ESCW chiller tripped again on low oil pressure. The investigation revealed that the same brass fitting had failed and the A ESCW chiller could not meet its mission time of 30 days of continuous operation in the event of a loss of cooling accident. During this 7-day period, the B ESCW chiller was inoperable for a period of time, which means the ESCW system would not have been able to meet its safety function. The licensees investigation into the cause of the subsequent failure is ongoing. A URI is being opened to determine whether the subsequent failure of the brass fitting was reasonably within the licensees ability to predict and therefore a performance deficiency. This issue is being tracked as URI 05000400/2016003-01, Subsequent Loss of Safety-Related Chilled Water System Results in a Loss of Safety Function.
05000324/FIN-2016003-052016Q3BrunswickLicensee-Identified Violation10 CFR 50.9, Completeness and Accuracy of Information, requires, in part, that information required by statute or by the Commission's regulations, orders, or license conditions to be maintained by the licensee shall be complete and accurate in all material respects. WOs associated with safety-related activities are designated as quality-related records that are required to be maintained by the licensees Quality Assurance Program. Contrary to the above, on March 23, 2015, a contract QC inspector deliberately falsified the quality record for WO 2281641-05, resulting in the licensees maintaining of information that was incomplete and inaccurate. The WO is material to the NRC, as it provides documented evidence of compliance with QC inspection requirements. Using traditional enforcement, the SL assigned to this violation was SL IV, because there was a deliberate violation of regulatory requirements, and resulted in no or relatively inappreciable potential safety consequences. This violation also meets the criteria for a NCV because the licensee identified the violation and promptly provided the information concerning the violation, to the NRC. This issue was documented in the licensees CAP as NCR 739864.
05000324/FIN-2016003-022016Q3BrunswickInadequate Procedure to Perform Preventive Maintenance on the HPCI Auxiliary Oil Pump Motor Overload RelayA self-revealing Green NCV of Technical Specification (TS) 5.4.1a, Procedures, was identified for the failure of the licensee to have an adequate procedure for preventive maintenance (PM) on the Unit 2 high pressure coolant injection (HPCI) auxiliary oil pump motor overload relay 2-2XDA-B11-74. Specifically, from May 26, 2015, to July 6, 2016, the licensee failed to incorporate PM task 482688, a 12-year replacement task for the relays, into procedures, resulting in a shorted relay coil, the loss of control power, and the inoperability of the HPCI pump. The licensee replaced the relay and the HPCI pump was returned to operable. The licensee entered this issue into the CAP as NCR 2043067. The inspectors determined that the failure of the licensee to have an adequate PM procedure to replace the Unit 2 HPCI auxiliary oil pump motor overload relay 2-2XDA-B11-74 was a performance deficiency. The finding was more than minor because it was associated with the procedural quality attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to replace the HPCI auxiliary oil pump motor overload relay resulted in the inoperability of the Unit 2 HPCI pump, and the loss of safety function. Using IMC 0609, Appendix A, issued June 19, 2012, the SDP for Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, the inspectors determined the finding screened to a more detailed risk evaluation, since the finding represented a loss of HPCI system and/or function. The inspectors used SAPHIRE to conduct a more detailed risk review of the finding. The inspectors determined that the finding was of very low safety significance (Green), because the core damage frequency (CDF) risk was less than 1.0E-6/year. This finding has a cross-cutting aspect in the area of human performance associated with the work management aspect, for failing to implement a process of planning, controlling, and executing work activities such that nuclear safety is an overriding priority. Specifically the licensee failed to effectively plan and coordinate PM strategies associated with operating experience to prevent the failure of the HPCI pump.
05000324/FIN-2016003-032016Q3BrunswickInadequate Procedure for the 2B RHRSW Subsystem Operability TestA self-revealing Green NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified for the failure of the licensee to have an adequate procedure for the 2B RHRSW pump operability test. Specifically, from July 12, 2001, to August 2, 2016, licensee procedure 0PT-08.1.4A(B), RHR Service Water System Operability Test, did not contain sufficient information to maintain plant status control for the Unit 2 RHRSW subsystem B pressure switch instrument isolation valves, 2-SW-PS-1176B-3 and 2-SW-PS-1176D-3. This resulted in the valves being found mispositioned (closed) and the inoperability of the 2B RHRSW subsystem from June 4 - 15, 2016. This finding resulted in a violation of TS 3.7.1, RHRSW System, since the 2B RHRSW subsystem was inoperable for greater than the TS allowed outage time (AOT). As immediate corrective actions, the licensee opened the 2-SW-PS-1176B(D)-3 valves and ensured the subsystem A pressure switch instrument isolation valves were open. Additionally, the licensee revised procedure 0PT-08.1.4A(B) to maintain plant status control by throttling the drain valves versus the pressure switch instrument isolation valves, and included an independent verification step to ensure the valves are returned to the correct position. The licensee entered this issue into the CAP as NCR 2037920. The inspectors determined the licensees failure to have an adequate procedure for the 2B RHRSW subsystem operability test to ensure configuration control was a performance deficiency. The finding was more than minor because it was associated with the procedural quality attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the inadequate procedure resulted in the inoperability of the 2B RHRSW subsystem. Using IMC 0609, Appendix A, issued June 19, 2012, the SDP for Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, the inspectors determined the finding screened to a more detailed risk evaluation, since the finding represented an actual loss of safety function of a single train for greater than its TS AOT. A regional Senior Risk Analyst (SRA) performed a detailed risk evaluation for the finding by setting the exposure period for 11 days, and assuming recovery actions that could be taken to mitigate the event. In addition, another later recovery was possible for the dominant sequences because service water, in sufficient quantity, could be pushed through the inoperable pumps to provide adequate cooling in non-loss-of-coolant accident (LOCA) sequences. The dominant contributor involved loss of the heat sink through common cause failure. The risk analysis resulted in a finding that is characterized as very low safety significance (Green). The finding had a cross-cutting aspect in the area of human performance associated with the challenge the unknown attribute because the licensee did not stop when faced with uncertain conditions, and risks were not evaluated and managed before proceeding. Specifically, the licensee continued through the April 2016 2B RHRSW system operability test, even when the procedure was not clear on which valve to manipulate to adjust for flow fluctuations.
05000324/FIN-2016003-042016Q3BrunswickLicensee-Identified Violation10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires in part that, activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. Instructions, procedures, or drawings shall include appropriate quantitative or qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished. WO 2281641-05 instructions required in part that, the craft and quality control (QC) hold points, verify the unistrut bolts were torqued to a minimum torque of 72 in/lbs., verify tagging and marking, verify clearances and tolerances, and verify configuration (including dimensions). Contrary to the above, on March 23, 2015, a contract QC inspector deliberately failed to accomplish an activity affecting quality in accordance with a prescribed, documented instruction. Specifically, the QC inspector signed the QC hold points on WO 2281641-05 associated with the removal/installation of a safety-related pipe support for backup nitrogen in the drywell, without verifying and confirming the work had been satisfactorily accomplished according to the WO. Using IMC 0609, Appendix G, Shutdown Operations Significance Determination Process, inspectors determined this finding to be of very low safety significance (Green) since the finding did not involve the total loss of any safety function. This issue was documented in the licensees CAP as NCR 739864.
05000261/FIN-2016002-012016Q2RobinsonLicensee-Identified ViolationSection 50.55a(h)(2) of 10 CFR states in part, for nuclear power plants with construction permits issued before January 1, 1971, protection systems must be consistent with their licensing basis or may meet the requirements of Institute of Electrical and Electronic Engineers (IEEE) Std. 6031991 and the correction sheet dated January 30, 1995. The Robinson FSAR (current licensing basis) Section 3.1.2.20, states in part that, reactor protection is designed to meet all presently defined reactor protection criteria and is in accordance with the proposed Institute of Electrical and Electronic Engineers (IEEE) 279 Standard for Nuclear Plant Protection Systems, August 1968. IEEE-279, Section 4.2, requires that any single failure within the protection system shall not prevent proper protection system action when required. Contrary to this requirement, from initial startup, until April 13, 2016, when using a FRBV (i.e., FRBV in the open position in Modes 1, 2, and 3), and a MSLB occurred, the protection system would not provide the proper system protection action. Specifically, with a single failure of the FRBV to close, the protective system action to isolate feedwater could not be accomplished. This would cause an increase in secondary mass available for release in containment structure, resulting in a higher peak containment pressure that would challenge the containment design pressure. As corrective actions, the licensee implemented a standing instruction and placed caution tags on the FRBVs to ensure the valves remain closed/isolated while operating in Modes 1, 2, and 3. Additionally, the licensee completed an engineering change to update the containment analysis and licensing basis. The licensee entered this issue into the CAP as CRs 2012658, 2020495, and 2018710. The failure to meet the single failure criterion for feedwater isolation following a main steam line break inside containment was a performance deficiency (PD). Significance Determination Process (SDP) screening in accordance with NRC IMC 0609.04 determined that the PD affected the secondary short term heat removal safety function of the mitigating systems cornerstone. The finding was determined to represent a loss of function and a detailed risk assessment was performed per NRC IMC 0609 Appendix A. The bounding analysis assumed a conditional core damage probability of 1.0, a 14 day exposure period estimated from surveillance and outage schedules, and main steam line break inside containment (MSLBIC) initiating event probability and main feedwater regulating valve bypass (MFWRVBV) failure to close probabilities from the NRC SPAR model data. The dominant sequence was an MSLBIC with a failure to close of the MFWRVBV which was assumed to lead to core damage and large early release. The risk was mitigated by short exposure period and the low likelihood of the MSLBIC and the failure to close of the MFWRVBV. The bounding analysis determined that the PD represented a risk increase of < 1.0E-7/year, a GREEN finding of very low safety significance for both core damage frequency and large early release frequency.
05000400/FIN-2015003-022015Q3HarrisWritten NRC Biennial Examinations Did Not Meet Qualitative StandardsThe inspectors identified an URI associated with 10 CFR 55.59, "Requalification," based on a preliminary determination that between 20 and 40 percent of the written examination questions administered to licensed operators during the biennial requalification examination were potentially flawed. This item is unresolved pending further inspection to determine whether a performance deficiency exists. The NRC-required biennial written examinations are designed to ensure that licensed operators maintain safe standards of knowledge and ability in order to take appropriate safety-related actions in response to actual abnormal or emergency conditions. As part of the biennial licensed operator training inspection, the inspectors evaluated the content of two NRC-required biennial written examinations (Set 1 Exam 1 SRO and Set 2 Exam 4 SRO) that the licensee developed and administered to licensed operators in 2014. Between 20 percent and 40 percent of items reviewed were determined to potentially contain flaws such as more than one implausible distracter, direct lookup, or low level of difficulty. The standard for determining a question flaw was located within site-specific procedures and further defined within NUREG-1021, Operator Licensing Examination Standards for Power Reactors. Several questions were determined to potentially not contain an appropriate level of difficulty. In many instances there may not have been an acceptable amount of knowledge tested for where to find the answer in an open book exam. Compounding the impact on level of difficulty, answer choices could be eliminated without using nuclear power plant operating knowledge. The licensee entered the issue into their CAP as AR 01940942. Pending further guidance from the Office of Nuclear Reactor Regulation (NRR) on the evaluation of the level of difficulty in establishing whether a performance deficiency exists, this issue is identified as URI 05000400/2015003-02, NRC Biennial Written Examinations May Not Have Met Qualitative Standards.
05000400/FIN-2015003-012015Q3HarrisFailure to Adequately Implement the Clearance and Tagging ProcedureA self-revealing Green NCV of Technical Specification (TS) 6.8.1, Procedures and Programs, for the licensees inadequate implementation of procedure AD-OP-ALL-0200, Clearance and Tagging, when the licensee failed to establish an appropriate clearance boundary to support filling the cooling tower basin. This resulted in excess of 45,000 gallons of water being spilled in the RAB. The licensee initiated corrective actions to address potential equipment degradation and personnel hazards as a result of the spill. The licensees failure to adequately implement procedure, AD-OP-ALL-0200, Clearance and Tagging, Section 5.5, Step 1 was a performance deficiency. Specifically, CO 310942 did not establish isolation between the cooling tower basin and ISW-276, which was not completely assembled. The performance deficiency was more than minor because if left uncorrected, it would have the potential to lead to a more significant safety concern. Specifically, if operator action had not stopped the leakage, it potentially would have challenged the operability of safety related equipment on multiple levels of the RAB. Using MC 0609, SDP, Appendix G, Exhibit 3 Mitigating Systems Screening Questions, the finding is a deficiency affecting the qualification of a mitigating SSC, however, the SSC function was restored with operator action, resulting in a GREEN finding of very low safety significance. The finding had a crosscutting aspect of procedure adherence, as described in the area of human performance because the licensee allowed the CO to be lifted in the plant without properly establishing an isolation boundary and isolating the cooling tower basin from ISW-276 while not fully assembled. (H.8).
05000400/FIN-2015003-032015Q3HarrisFailure to Implement Adequate Corrective ActionsA self-revealing green finding was identified for failure to implement adequate corrective actions for the repeated failure of PS-4175, low pressure steam inlet crossover pressure switch in accordance with licensee procedure AD-PI-ALL-0100, Corrective Action Program. Specifically, on multiple occasions the licensee failed to install a pressure switch rated for design conditions on the Main Turbine which led to an unplanned reactivity addition, when PS-4175 failed open. The licensee entered this into their corrective action program (CAP) as action request (AR) 755621 and took immediate actions to reduce power to less than 100 percent. Reactor power reached a maximum value of 100.5 percent. Failure to implement adequate corrective action for the repeated failure of pressure switch PS- 4175 in accordance with licensee procedure AD-PI-ALL-0100 was a performance deficiency. The performance deficiency was determined to be more than minor because if left uncorrected the performance deficiency had the potential to lead to a more significant safety concern. Specifically, if not for the manual actions taken by the operators to insert control rods, the reactivity addition would have continued and would have ultimately resulted in a reactor trip on high neutron flux. Using IMC 0609, Significance Determination Process Attachment 4, Initial Characterization of Findings, and Appendix A, The SDP for Findings At-Power, (June 19, 2012), the inspectors determined the finding was a contributor as a Transient Initiator to the Initiating Events cornerstone. The inspectors determined the finding was of very low safety significance (Green) because it did not result in a reactor trip and it did not cause the loss of any mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. The inspectors concluded the finding was associated with the design margins aspect (H.6) of the human performance cross-cutting area since the licensee repeatedly failed to install a pressure switch adequate for the operating conditions.
05000400/FIN-2015003-042015Q3HarrisLoss of A ESW TrainA self-revealing green NCV of 10 CFR 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants, Criterion III, Design Control, was identified for failure to implement design control measures that verify adequacy of design. Specifically, EC 83681 involved the installation of a new pump bearing with different wear characteristics but the EC failed to evaluate the impact of the bearing replacement on alignment sensitivity of the pump shaft. The licensee took immediate action to align the Normal Service Water system to provide cooling to the heat loads affected by the loss of the A ESW pump. Failure to incorporate alignment requirements for the pump shaft in the work instructions associated with EC 83681 was a performance deficiency. The performance deficiency was related to the equipment performance attribute of the initiating events cornerstone. The performance deficiency was determined to be more than minor because the performance deficiency adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the failure of the ESW pump shaft resulted in a loss of service water which ultimately led to the loss of the A train of shutdown cooling for a period of twelve minutes. Inspectors evaluated the finding using IMC 0609, Significance Determination Process, Attachment 4 and Appendix G (June 19, 2012), Shutdown Operations Significance Determination Process. The inspectors determined the finding was associated with the Initiating Event cornerstone and required a detailed risk evaluation because the finding involved a loss of safety function. A detailed risk evaluation was completed by a regional Senior Reactor Analyst (SRA). The regional SRA performed a detailed risk review of the finding. The SRA performed the analysis by increasing the maintenance unavailability for the pump, and evaluating it versus the base case. This method was chosen because the pump was in standby service, and the dominant method of determining there was a failure would have been during testing, or operation under non accident conditions. The additional time for the unnecessary repair was used to adjust the base case maintenance unavailability. Online and shutdown risk were evaluated. The total impact was determined to be low enough for the finding to be GREEN for SDP purposes The finding had a cross-cutting aspect in the Human Performance area of Design Margin (H.6).
05000400/FIN-2015003-052015Q3HarrisFailure to implement EQ Program RequirementsThe inspectors identified a Green NCV of 10 CFR Part 50, Appendix B, Criterion XVI, for the licensees failure to identify and correct a condition adverse to quality affecting the Environmental Qualification (EQ) Program. Specifically, the licensee failed to enter into the CAP the results of the vendor audit of the EQ program which resulted in the licensee blocking open D10 and D11 on June 16, 2015 while the unit was at 100 percent power. The resident inspectors questioned the main control room (MCR) about the doors being open and the licensee immediately closed D10 and D11. The licensee has entered the violation into their CAP as AR 754721, implemented interim guidance as an operations standing instruction (2015-024) not to open D10 or D11 while in mode 1-4. The opening of the tornado door between the main steam tunnel (MST) and the reactor auxiliary building (RAB) was a performance deficiency. The finding was screened in accordance with NRC IMC 0609.04, Initial Characterization of Findings, dated July 7, 2012. The finding was determined to affect the Initiating Events Cornerstone as the MST to RAB tornado door represented a barrier which left RAB systems and components vulnerable to harsh environment conditions should a high energy line break (HELB) occur during the time the doors were open. SDP screening determined that the finding could have affected equipment used to mitigate a LOCA, could have caused a reactor trip, could have resulted in internal flooding conditions, and could have affected equipment relied upon to transition the plant to a stable shutdown condition and required a detailed risk evaluation. A detailed risk evaluation was performed by a regional SRA in accordance with NRC IMC 0609 Appendix A. The major analysis assumptions included: a twenty hour exposure interval, HELBs postulated in all steam and feedwater piping in the MST, pipe break frequency from EPRI Report 1021086, no recovery credit for door closure, and a bounding CCDP value utilized. The CCDP was estimated using the NRC Shearon Harris SPAR model assuming a reactor trip initiator and bounding assumptions that the postulated RAB harsh environmental and flooding conditions would cause failure of the following equipment: auxiliary feedwater system, alternate seal injection system, RAB essential services chillers, component cooling water pumps, charging and safety injection pumps, and the residual heat removal pumps. The dominant sequence was a reactor trip, success of the reactor protection system, and failure of the reactor coolant pump (RCP) seals leading to an unmitigated RCP seal LOCA. The risk was mitigated by the short exposure period and the probability of steam and feedwater HELBs. The analysis determined that the finding represented an increase in core damage frequency of < 1.0 E-6/year, a GREEN finding of very low safety significance. This finding has a cross-cutting aspect in the area of Problem Identification and Resolution in the Corrective Action component because the licensee did not take appropriate corrective actions to address safety issues in a timely manner.
05000400/FIN-2015003-062015Q3HarrisFailure to Report the Loss of Emergency Assessment CapabilityThe inspectors identified a severity level (SL) IV NCV of 10 CFR 50.72(b)(3)(xiii) for the failure to report to the NRC within 8 hours the major loss of emergency assessment capability of the Technical Support Center (TSC). Specifically, on multiple occasions between January 2015 and July 2015, there were unplanned losses of emergency response facility (ERF) function, which resulted in the loss of emergency assessment capability, which the licensee failed to report the condition within the 8-hour time requirement. Subsequently, the licensee notified the NRC once it was realized a report was required and entered the issue in the CAP as AR 757885. The failure to report the loss of emergency assessment capability in the TSC as required by 10 CFR Part 50.72(b)(3)(xiii) was a performance deficiency. The licensees failure to notify the NRC was determined to impact the regulatory process, which requires evaluation through the traditional enforcement process. Based on the examples provided in Section 6.9 of the Enforcement Policy, dated February 4, 2015, Inaccurate and Incomplete Information or Failure to Make a Required Report, the performance deficiency was determined to be a SL IV violation. Specifically, example d.9 states that a SL IV violation involves a failure to make a report required by 10 CFR 50.72 or 10 CFR 50.73. Because the violation was processed as a traditional enforcement violation, no cross-cutting aspect is assigned.
05000400/FIN-2015001-012015Q1HarrisLicensee-Identified ViolationTS 6.8, Procedures and Programs, Section 6.8.1.a requires, in part, that written procedures be established, implemented, and maintained covering the activities recommended in Appendix A of Regulatory Guide (RG) 1.33, Revision 2, February 1978. RG 1.33, Appendix A, Section 8.b.(1).(dd) requires, in part, that procedures be established for safety valve surveillance tests. Contrary to the above, on March 12, 2015, engineers used an inadequate procedure to test main steam safety valves. Specifically, engineering procedure EST-224, Insitu Main Steam Safety Valve Test using Assist Device, did not adequately direct personnel to compensate for the head differential between the pressure gauge and the seat of the main steam safety valves. This resulted in the licensee incorrectly adjusting the setpoint of MSSV MS-46 below TS 3.7.1 limits while operating in Mode 1. The licensee identified this issue after incorrectly declaring the valve operable. However, the licensee was able to restore the setpoint and operability of MS-46 within the TS 3.7.1 Limiting Condition for Operation action time. This violation was determined to be of very low safety significance (Green) because the finding did not cause a reactor trip or the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. The licensee entered this issue into their CAP as AR #737961. As corrective actions, the licensee revised the procedure and restored the setpoint to within TS 3.7.1 limits and retested MS-46.
05000261/FIN-2014005-012014Q4RobinsonFailure to Protect Diesel Driven Equipment from Effects of Extreme Cold TemperaturesThe inspectors identified a Green non-cited violation (NCV) of Technical Specification (TS) 5.4.1, for failure to establish procedural guidance to protect diesel driven equipment important to safety from the effects of extreme cold temperatures. Specifically, the licensees cold weather procedures failed to include actions to maintain fuel oil temperatures above the diesel fuel oil cloud point for the dedicated shutdown diesel generator (DSDG) and/or the engine driven fire pump (EDFP). The licensee entered this into the corrective action program (CAP) as AR 715032 and took immediate corrective actions to revise station procedures to protect the diesel driven equipment during periods of extreme low temperatures. The failure to establish procedural guidance to protect diesel-driven equipment important to safety from the effects of extreme cold temperatures was a performance deficiency. This issue was more than minor because if left uncorrected this finding would have the potential to lead to a more significant safety concern. Specifically, failure to maintain the fuel oil temperatures for the DSDG and/or the EDFP greater than the measured cloud point, may impact the operation of the equipment during extreme low temperature conditions, due to the associated fuel oil transfer system becoming non-functional. A detailed risk assessment was performed by a regional Senior Reactor Analyst in accordance with NRC IMC 0609 Appendices A and F. The latest NRC Robinson SPAR risk model was used to quantify the internal events risk and a calculation was performed to estimate the fire risk. The major analysis assumptions included: both the EDFP and the DSDG were simultaneously considered unavailable without recovery for a 1-day exposure interval, DSDG fire scenarios were considered for the emergency switchgear room (ESWGR), the cable spreading room, and the main control room, where fire could cause a loss of offsite power and the emergency diesel generators (EDGs), compartment total ignition frequency data from the Robinson NFPA 805 project was used and a bounding Conditional Core Damage Probability for the fire scenarios of 1.0. The dominant sequence was a fire in the ESWGR which remained unsuppressed long enough to cause a loss of offsite power and the EDGs requiring use of alternate shutdown which failed due to the performance deficiency impact on the DSDG resulting in station blackout, and core damage due to an unmitigated reactor coolant pump seal loss of cooling accident. The risk was mitigated by the low likelihood of the initiators occurring during the specific cold weather vulnerability periods. The risk due to the performance deficiency was determined to be an increase in core damage frequency of <1E-6/year, a GREEN finding of very low safety significance. The performance deficiency had a cross-cutting aspect of Evaluation in the area of Problem Identification and Resolution because the licensee failed to thoroughly evaluate the effects of cold weather on the fuel system for diesel driven equipment to ensure that resolutions address the extent of conditions commensurate with their safety significance (P.2).
05000400/FIN-2014004-012014Q3HarrisPotential Impact of Sump Pumps out of ServiceThe inspectors identified an URI associated with an equipment clearance that inadvertently resulted in all sump pumps in the EDG and DFOST buildings being nonfunctional. This item is unresolved pending review and evaluation of the licensees evaluation to determine the impact of a potential internal flood and if a performance deficiency exists. On June 26, 2014, the licensee placed equipment under clearance to support installation associated with an Engineering Change (EC). This clearance removed all sump pumps in the EDG and DFOST buildings from service. Inspectors identified this issue and informed the licensee, who restored the sump pumps to service. Additional inspection activities are needed to determine the impact of a potential internal flood and if a performance deficiency exists. Pending the results of this additional inspection, an URI will be opened and designated as URI 05000400/2014004-01, Potential Impact of Sump Pumps out of Service.
05000400/FIN-2014004-032014Q3HarrisLicensee-Identified ViolationTechnical Specification 6.8.1 requires the procedures recommended in RG 1.33 to be established, implemented, and maintained. Regulatory Guide 1.33 requires implementation of an RWP system. Specifically, RWP #1014, Task 4, Valve Maintenance RCB (No HRA Access), required HP to be notified prior to the start of work and for HP to be present and perform surveys when breaching a contaminated system. Contrary to these RWP requirements, on November 22, 2013, two workers entered the containment building and cut out two primary CS valves (CS-761 and 762) without having HP present to perform surveys when breaching a contaminated system. After they exited containment, HP discovered the valves on the ground with removable beta-gamma contamination levels up to 200,000 dpm/100 cm2. This finding was of very low safety significance (Green) because there was no substantial potential for overexposure. This was due to the fact that the external dose rates were low and the contamination levels were not high enough to constitute a substantial potential for overexposure. The inspectors noted that no personnel were contaminated as a result of this event. The licensee entered the event into their corrective action program as AR #648061.
05000400/FIN-2014004-022014Q3HarrisLoss of Emergency Planning SirensThe NRC identified a Green NCV associated with emergency preparedness planning standard 10 CFR 50.47(b)(5), which requires in part, that the means to provide alert and notification and clear instruction to the populace within the plume exposure pathway Emergency Planning Zone (EPZ) have been established. Specifically, on April 3, 2014, the licensee unintentionally initiated a complete loss of sirens while responding to a siren system alarm. The licensee entered this issue into the corrective action program (CAP) as Action Request (AR) #679984. As corrective action, the licensee replaced a failed circuit card and restored functionality of the siren system. The licensees failure to comply with WCP-NGGC-0300, Work Request Initiation, Screening, Prioritization and Classification, was a performance deficiency. Specifically, this failure combined with the circuit card failure caused a complete loss of siren functionality for approximately two hours. This finding was more than minor because if left uncorrected, loss of Alert Notification System function has the potential to lead to a more significant safety concern and is associated with the emergency preparedness cornerstone attribute of Facilities and Equipment (Availability of ANS). This ANS unavailability affected the cornerstone objective of ensuring 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. Using Manual Chapter 0609 Appendix B, Emergency Preparedness Significance Determination Process (Section 5.5) Failure to Comply with 10 CFR 50.47(b)(5), the inspectors determined this finding to be of very low safety significance (Green) because the loss of siren function was of short duration and did not reach the Degraded Risk Significant Planning Standard (RSPS) threshold. The finding had a crosscutting aspect of Procedure Adherence, as described in the Human Performance crosscutting area because the EPTs failed to comply with the procedural guidance of WCPNGGC- 0300 (H.8).
05000324/FIN-2014003-012014Q2BrunswickFailure to Maintain a Standard Emergency Action Level Scheme for FloodingAn NRC-identified Green NCV of 10 CFR 50.54(q)(2), 10 CFR 50.47(b)(4), and the requirements of Appendix E to 10 CFR Part 50, was identified for the failure of the licensee to maintain the effectiveness of the emergency plan. Specifically, from November 6, 2009, to July 21, 2014, the licensee failed to maintain in effect, a standard emergency action level (EAL) scheme by failing to provide effective means for determining flooding water levels which is required to properly classify an ALERT during a probable maximum hurricane (PMH). The licensees corrective actions include painting level indication on the service water building visible to the operator stationed at the service water building to determine when the ALERT flood level is reached. The licensee entered this issue into the CAP as NCRs 688613 and 693590. The inspectors determined that the failure to provide reliable and timely indication for operators to adequately implement the ALERT flooding EAL HA 1.5 was a performance deficiency. The finding is more than minor because it is associated with the Facilities and Equipment attribute of the Emergency Preparedness (EP) cornerstone and affected the cornerstone objective to ensure the licensee is capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. Specifically, the licensees ability to classify an ALERT for a flooding event was adversely affected because flood levels could not be adequately determined. In accordance with the IMC 0609, Appendix B, Emergency Preparedness Significance Determination, issued February 24, 2012, and Figure 5.4-1, the inspectors determined that this finding is of very low safety significance (Green) because the performance deficiency was a condition where an EAL has been rendered ineffective such that an ALERT would not be declared for a flooding event. The finding has a cross-cutting aspect in the area of human performance associated with the resources attribute because leaders failed to ensure that personnel, equipment, procedures, and other resources are available and adequate to support nuclear safety and declare an ALERT for a PMH. (H.1)
05000261/FIN-2014008-012014Q2RobinsonFailure to Take Adequate Corrective Action to Preclude Repetition of a Significant Condition Adverse to Quality Associated with the Steam Generator Tube LeakThe team identified a Green NCV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Actions, for the licensees failure to take adequate corrective action to prevent repetition of a significant condition adverse to quality regarding steam generator tube leakage due to poor maintenance practices. Specifically, on February 27, 2014, the C steam generator showed indications of a primary to secondary tube leak due to foreign material that was introduced during the fall 2013 refueling outage. As immediate corrective actions, on March 7, 2014, the licensee shutdown the plant and repaired the leak. This violation was entered into the licensees CAP as nuclear condition reports (NCRs) 683695, 683593, and 683591. The licensees failure to implement appropriate corrective actions to address poor worker practices to prevent recurrence of a steam generator tube leak was a performance deficiency. The finding was more than minor because it was associated with the initiating events cornerstone equipment performance attribute and it adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, foreign material entered the steam generator and damaged a steam generator tube, which increased the likelihood of a steam generator tube rupture. The inspectors screened this finding using IMC 0609, Appendix A, The Significant Determination Process (SDP) For Findings At-Power, dated June 19, 2012. The finding screened as Green per Section D of Exhibit 1, Initiating Events Screening Questions, because testing showed that the affected steam generator tube could sustain three times the differential pressure across the tube during normal full power and that the steam generator did not violate the accident leakage performance criterion. The performance deficiency does not have a cross cutting aspect because the last revision of the root cause evaluation was completed in 2011 and it is not indicative of current licensee performance.
05000324/FIN-2014003-042014Q2BrunswickLicensee-Identified Violation10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, states, in part, activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. Licensee Procedure OPS-NGGC-1305, Operability Determinations, states, in part, a structure, system, or component is Operable if the TS definition of OPERABLE is satisfied. Technical Specification 3.6.4.1, Secondary Containment, and TS 3.6.4.2, Secondary Containment Isolation Dampers, require secondary containment and SCIDs to be operable. Contrary to the above, on March 9, 2014, Procedure 0MMM-054, Temporary Power Feed Documentation, was not appropriate to the circumstances and did not require an operability determination when SCIDs was powered from a nonsafety-related power supply. The licensee failed to declare the SCIDs inoperable while powered from temporary nonsafety-related electrical power and OPDRVs were in progress. The SCIDs system was inoperable because the normal or emergency electrical power was not capable of performing its related support function. The finding is more than minor because it is associated with the configuration control attribute of the Barrier Integrity Cornerstone and adversely affects the cornerstone objective to provide reasonable assurance that physical design barriers (standby gas treatment) protect the public from radionuclide releases caused by accidents or events. Specifically, the finding is more than minor since the SCIDs system was inoperable. Using IMC 0609, Appendix A, issued June 9, 2012, The SDP for Findings At-Power, the inspectors determined the finding screened to very low safety significance (Green) since the finding only represented a degradation in the radiological barrier function of secondary containment standby gas treatment. The licensee entered this issue into the CAP as NCR 673858. The NRC issued EGM 11-003, Revision 2, to exercise enforcement discretion and not cite licensees for TS violations related to the conduct of OPDRVs with secondary containment inoperable provided that certain criteria were met. One of the criteria was that the licensee must follow all other TS applicability and action requirements. Since the licensee was conducting OPDRVs during the time of the inoperability, the licensee did not meet the criteria in EGM 11-003 for the staff to consider exercising discretion on March 9, 2014. For the inoperability, TS 3.6.4.2 required initiation of action to suspend OPDRVs immediately, as did TS 3.6.4.1, Secondary Containment, for inoperable secondary containment. Therefore, Unit 1 was in a condition prohibited by TS 3.6.4.1, and TS 3.6.4.2.
05000261/FIN-2014003-022014Q2RobinsonLicensee-Identified ViolationSection 50.49 of 10 CFR, Environmental Qualification of electric equipment important to safety for nuclear power plants, states that each licensee shall establish a program for qualifying specified electric equipment. Section (a)(3) of 10 CFR 50.49 specifies the environmental qualification requirements for post-accident monitoring equipment. Section (f) of 10 CFR 50.49 requires, in part, that each item of electric equipment important to safety must be qualified by testing an identical item of equipment under identical conditions. Contrary to the above, since May 1992, the licensee failed to maintain the qualification of the limit switches for CVC-204B, letdown line isolation, in accordance with the tested configuration of the equipment which rendered the Post Accident Monitoring Instrumentation function inoperable. The licensee documented this condition in AR 640902 and AR 633207. The cause was determined to be associated with a human performance event in which the licensee failed to use the proper heat shrink insulators per procedure CM-309, Sealing Low Voltage Electrical Splices for Environmentally Qualified or Safety Related Splices. Following discovery of this condition, the licensee replaced the non-environmental qualified splice and returned the equipment to the test configuration. Using IMC 0609, Appendix A, issued June 19, 2012, The SDP for Findings At-Power, the inspectors determined that this finding is of very low safety significance (Green) because the finding did not represent an actual loss of function of one or more non-Technical Specification Trains of equipment designated as high safety-significant in accordance with the licensees maintenance rule program for greater than 24 hours.
05000261/FIN-2014003-012014Q2RobinsonFailure to Identify and Correct Degraded Wire Labels in the Reactor Protection Relay CabinetsA self-revealing Green non-cited violation (NCV) was identified for the licensees failure to promptly identify and correct degraded wire labels in the reactor protection cabinets, which were a condition adverse to quality, as required by 10 CFR Part 50, Criterion XVI, Corrective Action. This resulted in an automatic reactor trip. Immediate corrective actions included inspection of both trains of relay racks to identify and remove any potential foreign material. The licensee also tested both trains of reactor protection relays to verify no foreign material was present. Additionally, the licensee plans to replace the wire labels in the reactor protection and safeguards relay racks during refueling outages 29 and 30. The licensee documented the issue in the corrective action program as CR 654789. The performance deficiency was more than minor because it was associated with the equipment performance attribute of the initiating events cornerstone and adversely affected the cornerstone objective of limiting the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the degraded wire labels became lodged between contact 2-6 on relay LC-496A1-X(B), which set up the half-trip condition to cause a reactor trip, during the surveillance testing. Using IMC 0609, Appendix A, issued June 19, 2012, The Significance Determination Process (SDP) for Findings At-Power, the inspectors determined that this finding is of very low safety significance (Green) because although the finding caused a reactor trip, it did not cause the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. This finding had a crosscutting aspect of identification in the area of problem identification and resolution because the licensee failed to implement a corrective action program with a low enough threshold for identifying issues in that the licensee process did not recognize, during review of the work requests for the degraded wire labels, that this issue should have been entered into the corrective action program as a nuclear condition report.
05000324/FIN-2014003-022014Q2BrunswickFailure to Include Flood Protection Features in the Maintenance Rule ProgramAn NRC-identified Green non-cited violation (NCV) of 10 CFR 50.65(b)(2)(ii) was identified for the failure of the licensee to scope flood protection features in the maintenance rule (MR) program. Specifically, from July 10, 1996, to May 8, 2014, the licensee failed to include floor drain flood protection features in the MR program that are nonsafety-related but whose failure could prevent safety-related structures, systems, and components (SSCs) from fulfilling their safety-related function. The licensees corrective actions included scoping the floor drains into the MR program. The licensee entered this issue into the corrective action program (CAP) as nuclear condition report (NCR) 677850. The inspectors determined that the failure of the licensee to monitor flood protection features in the MR program, as required by 10 CFR 50.65(b)(2)(ii), was a performance deficiency. The finding is more than minor because it is associated with the protection against external factors (i.e. flood hazard) attribute of the Mitigating Systems Cornerstone and adversely affects the cornerstone objective of ensuring the availability, reliability, and capability of the safety related systems to respond to initiating events to prevent undesirable consequences. Specifically, the finding is more than minor because failing to monitor flood protection features resulted in degradation of various flood protection features which could have impacted safety-related equipment. Using IMC 0609, Appendix A, issued June 9, 2012, The SDP for Findings At-Power, Exhibit 2, the inspectors determined the finding is of very low safety significance (Green) because it did not represent an actual loss of function of one or more non-TS trains of equipment designated as high safety-significant in accordance with the licensees maintenance rule program for greater than 24 hours. The finding has a cross-cutting aspect in the area of problem identification and resolution associated with the resolution attribute because the organization failed to take effective corrective actions to address issues in a timely manner commensurate with their safety significance. Specifically, the licensee failed to scope the credited flood protection floor drains into the MR program. (P.3)
05000324/FIN-2014003-032014Q2BrunswickLicensee-Identified ViolationTechnical Specification Section 5.4.1.a, Administrative Control (Procedures), states, in part, that written procedures shall be established, implemented, and maintained, covering applicable procedures recommended in Regulatory Guide 1.33, Appendix A, November 1972 (Safety Guide 33, November 1972). Section l.1 of Regulatory Guide 1.33, Appendix A, November 1972, (Safety Guide 33, November 1972) states, in part, that maintenance that can affect the performance of safety-related equipment should be properly planned and performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances. Contrary to the above, from March 11, 2014, to April 3, 2014, the licensee failed to follow procedure OMA-NGGC-0201, Contingency Planning and Discovery Management, to properly plan for the replacement of the reactor water cleanup (RWCU) inlet line isolation valve 1-G31-F001. Specifically, a written contingency plan was not developed. As a result, significant items were missed in the planning and preparation. This contributed to the licensee exceeding the As Low as Reasonably Achievable (ALARA) dose goal for this job by 11 rem. This finding was more than minor because it was associated with the Program and Process ALARA planning attribute of the Occupational Radiation Safety Cornerstone and adversely affected the objective to ensure the adequate protection of worker health and safety from exposure of radiation from radioactive material during routine civilian nuclear reactor operations. The inspectors determined the finding to be of very low safety significance (Green) because Brunswicks three-year rolling average (2011-2013) is 185 person-rem, which is below the SDP criteria of 240 person-rem for boiling water reactors. The licensee entered this issue into the CAP as NCR 678510.
05000324/FIN-2014003-052014Q2BrunswickLicensee-Identified Violation10 CFR 26.29(a), Training content, requires, in part, that in the licensee and other entities shall ensure that the individuals who are subject to this subpart have the following: (1) knowledge of the policy and procedures that apply to the individual, the methods used to implement them, and the consequences of violating the policies and procedures. Contrary to this requirement, the licensee only provided informal training to some contractor supervisors and managers when it initially implemented the fatigue rule requirements in 2009. Specifically, no additional training was given prior to the Unit 1 spring 2012 outage, related to licensee procedure ADM-NGGC-0206, Managing Fatigue and Work Hour Limits, Revision 7. This finding was more than minor because the lack of procedural knowledge allowed the licensee to routinely fail to perform appropriate management of work hour limits and waivers, and if left uncorrected, this could lead to a more significant safety concern. This violation was determined to be of very low safety significance (Green) because no significant events or human performance issues were directly linked to personnel fatigue as a result of the hours worked. The licensee entered this issue into their CAP as CRs 546446, 546483 and 551121.
05000324/FIN-2014003-062014Q2BrunswickLicensee-Identified Violation10 CFR 26.205(b)(1), Shift turnover, requires, in part, that the licensee calculate the work hours of individuals who are subject to this section as the amount of time the individuals perform duties for the licensee. Contrary to this requirement, numerous violations of the work hour limits of individuals were identified. Specifically, during the Unit 1 spring 2012 refueling outage, the licensee misinterpreted the turnover rules to include the time necessary for critical path employees to participate in safety, health physics, and pre-job briefings, dress out, retrieve equipment and arrive at their turnover locations, which, in some cases, was three to four hours of turnover time, which did not meet the definition of shift turnover. This finding was more than minor because if left uncorrected, the continued inappropriate use of work hour calculations would permit workers to exceed work hour limits, and could lead to a more significant safety concern. This violation was determined to be of very low safety significance (Green) because no significant events or human performance issues were directly linked to personnel fatigue as a result of the hours worked. The licensee entered this issue into their CAP as CRs 546446, 546483, 550642, and 564726.
05000261/FIN-2014002-052014Q1RobinsonDefective Motor Operated Potentiometer causes failure of the DSDG during surveillance testingAn URI was identified regarding the trip of the DSDG, on December 31, 2013, during monthly surveillance testing. The URI is being opened to provide for additional inspection of the equipment issues that led to the failure and to review the results of the vendors analysis of a defective motor operated potentiometer to determine if a performance deficiency exists. On December 31, 2013, during monthly testing of the DSDG in accordance with licensee procedure OST-910, Dedicated Shutdown Diesel Generator (Monthly), the output breaker tripped open on overcurrent while the operators were attempting to adjust DSDG output voltage. Operators in the field noted erratic voltage indication prior to the failure. Engineering identified that the likely cause was a failure of the motor operated potentiometer (MOP). The licensee replaced the MOP with a new part from stock and performed post maintenance testing. The MOP that was removed was sent offsite for forensic analysis. During examination, the licensee identified a manufacturing defect for the MOP. The licensees extent of condition investigation found the same manufacturing defect on the MOP installed in the DSDG and in a MOP in storage. The licensee replaced the MOP in the DSDG with a MOP that was verified to be acceptable. Engineering has sent the defective components back to the vendor for additional analysis. This issue will be identified as URI 05000261/2014002-05; Defective Motor Operated Potentiometer causes failure of the DSDG during surveillance testing.
05000325/FIN-2013005-012013Q4BrunswickFailure of Transformer Common C and Loss of Emergency Core Cooling System KeepfillThe inspectors opened an unresolved item (URI) to determine if a performance deficiency exists with the loss of Transformer Common C and the emergency core cooling system (ECCS) keepfill system. On February 22, 2012, the Common C 4160/480V transformer failed. This resulted in a loss of power to the circulating water intake pump (CWIP) traveling screen motors, which lead to high delta-pressure across the traveling screens. The CWIP 1B tripped due to high delta-pressure across its associated traveling screen. In anticipation of a loss of condenser vacuum, the licensee inserted a manual reactor SCRAM on Unit 1. As a result of the SCRAM, reactor water level reached the Reactor Water Level - Low Level 1 actuation set point and the Primary Containment Isolation System (PCIS) Groups 2 and 6 isolations occurred. Additionally, the Main Steam Isolation Valves (MSIVs) (PCIS Group 1) were manually closed prior to reaching the Condenser Vacuum Low actuation set point. Also, a loss of the Common C Transformer resulted in the loss of the demineralized water transfer pumps, which is the source of keepfill for the ECCS piping. With the loss of keepfill, ECCS systems started to depressurize, with Unit 1 ECCS depressurizing in 17 minutes and Unit 2 ECCS depressurizing in 2 hours and 29 minutes. With depressurized ECCS, both units entered TS 3.0.3. The licensee provided temporary power to a single demineralized water pump and successfully filled and vented the ECCS within 4 hours and 16 minutes of the event. The inspectors opened an URI to determine if a performance deficiency exists with the loss of Transformer Common C and the ECCS keepfill. The licensee entered this issue in the CAP as NCR 519193. This issue is being tracked as URI 05000325/2013005-01, Failure of Transformer Common C and Loss of Emergency Core Cooling System Keepfill.
05000324/FIN-2013005-022013Q4BrunswickInadequate Design Control for Required Service Water Flow to the Emergency Diesel GeneratorsAn NRC-identified Green NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, was identified for the failure of the licensee to verify the adequacy of design of the emergency diesel generator (EDG) service water flow. Specifically, from May 1, 1989, until October 28, 2013, Calculation M-89-0008, contained non-conservative values for EDG maximum loading, service water inlet temperatures, and heat exchanger fouling factor, resulting in a non-conservative calculation for required service water flow to the EDG jacket water heat exchanger, which called into question the operability of EDG 3. The licensee re-performed Calculation M-89-0008 and determined EDG 3 was operable. The licensee entered this issue into the corrective action program (CAP) as nuclear condition report (NCR) 592035. The inspectors determined that the failure of the licensee to have an accurate calculation for required service water flow to the EDG jacket water heat exchanger was a performance deficiency. The finding was more than minor because it was associated with the design control attribute of the Mitigating Systems Cornerstone and adversely affects the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the non-conservative calculation called into question the operability of EDG 3. Using IMC 0609, Appendix A, issued June 19, 2012, the SDP for Findings At-Power, the inspectors determined the finding was of very low safety significance (Green) because the finding did not affect the design or qualification of a mitigating structures, systems, and components (SSC), the finding did not represent a loss of system and/or function, the finding did not represent an actual loss of a function of a single train for greater than the technical specification (TS) allowed outage time, the finding did not represent an actual loss of a function of one or more non-TS trains of equipment, and did not screen as potentially risk-significant due to a seismic, flooding, or severe weather initiating event. The finding has a cross-cutting aspect in the area of human performance associated with the resources attribute because the licensee did not have complete, accurate and up-to-date design documentation for EDG service water flow. Specifically, due to the inspector?s questions, Calculation M-89-0008 required revision due to non-conservatisms in August 2013 and in November 2013.
05000325/FIN-2013005-032013Q4BrunswickInadequate Procedure to Perform Preventative Maintenance on the Residual Heat Removal Room CoolersA self-revealing Green NCV of TS 5.4.1a, Procedures, was identified for the failure of the licensee to have an adequate procedure for preventative maintenance on the 1B residual heat removal (RHR) room cooler damper limit switch. Specifically, between May 1990 and September 26, 2013, the licensee did not have an adequate preventative maintenance procedure to replace the 1B RHR room cooler damper limit switch and to tighten the paddle arm on the limit switch. This resulted in the failure of the 1B RHR room cooler to start and the inoperability of the 1B RHR train. The licensee replaced the limit switch on the damper, tightened the paddle arm on the limit switch, returned the room cooler to operable, and entered this issue into the CAP as NCR 607986. The inspectors determined that the failure of the licensee to have an adequate procedure to replace the 1B RHR room cooler limit switch and tighten the limit switch paddle arm was a performance deficiency. The finding was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone and adversely affects the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to replace the limit switch and tighten the limit switch paddle arm resulted in a failure of the cooler fan and damper, and the inoperability of the 1B RHR train. Using IMC 0609, Appendix A, issued June 19, 2012, the SDP for Findings At-Power, the inspectors determined the finding was of very low safety significance (Green) because the finding did not affect the design or qualification of a mitigating SSC, the finding did not represent a loss of system and/or function, the finding did not represent an actual loss of a function of a single train for greater than the TS allowed outage time, the finding did not represent an actual loss of a function of one or more non-TS trains of equipment, and did not screen as potentially risk-significant due to a seismic, flooding, or severe weather initiating event. The finding does not have a cross-cutting aspect since the performance deficiency is not indicative of current plant performance. Vendor Manual QTR155, NAMCO Controls, which required periodic replacement of the limit switch and checking the limit switch for tightness, was provided to the licensee in May 1990.
05000324/FIN-2013005-042013Q4BrunswickLicensee-Identified ViolationThe following finding of very low significance (Green) was identified by the licensee and is a violation of NRC requirements which meets the criteria of the NRC Enforcement Policy, for being dispositioned as a NCV. 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, states, in part, that activities affecting quality shall be prescribed by documented procedures and shall be accomplished in accordance with these procedures. Contrary to the above, from August 2010 until August 2013, when SRV pilot valve conical seating surface finish requirements were incorporated into licensee Procedure OCM-VSR509, Main Steam Relief Valves Target Rock Model 7567 Air Operators and Pilot Assembly, Disassembly, Inspection, and Reassembly, the licensee failed to prescribe procedural requirements for the SRV pilot valve conical seating surface finishes. This resulted in four of the eleven SRVs being out of tolerance, which was a violation of plant TS 3.4.3., Safety Relief Valves. The licensee took action to replace all of the pilot valves with valves that had the correct surface finish. This violation was determined to be of very low safety significance (Green) because the finding was a deficiency affecting the design or qualification of a mitigating SSC that maintained functionality. The licensee entered this issue into their CAP as NCR 607846. The licensee revised procedure OCM-VSR509 as a corrective action to prevent recurrence.
05000324/FIN-2013010-012013Q4BrunswickFailure to Identify and Correct Flood Protection Degradation in Safety-Related BuildingsThe NRC identified an AV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, with two examples. The first example involved the failure of the licensee to promptly identify and correct conditions adverse to quality associated with flood protection of multiple safety-related buildings. Specifically, the licensee failed to promptly identify or correct safety-related buildings that contained openings that would have adversely impacted their ability to mitigate external flooding of these buildings in the event of a design basis probable maximum hurricane (PMH). The second example involved the failure of the licensee to correct a significant condition adverse to quality. Specifically, the licensee failed to implement a corrective action to preclude repetition by not adequately developing an engineering program to mitigate the consequences of external events (flooding, high winds, and seismic) that ensured appropriate equipment classifications, with interfacing programs of maintenance rule (MR) and zero tolerance for equipment failures. This resulted in a violation of technical specification (TS) 3.7.2, Service Water (SW) System and Ultimate Heat Sink, and TS 3.5.2, Emergency Core Cooling System (ECCS) Shutdown, since the inoperability of the required number of service water pumps (SWPs) would violate TS 3.7.2, and TS 3.5.2 since SW cools the residual heat removal (RHR) system heat exchangers. The inspectors determined the failure to identify and correct the missing and degraded flood barriers in multiple safety-related buildings, and the failure to implement a corrective action to preclude repetition by not developing an engineering program to mitigate the consequences of external events that ensured appropriate equipment classifications, with interfacing programs of MR and zero tolerance for equipment failures, was a performance deficiency. The finding was more than minor because it was associated with the protection against external factors attribute (flood hazard) of the Mitigating Systems Cornerstone and adversely affects the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, nine of the ten Unit 1 and Unit 2 SWPs would be potentially inoperable and unavailable during specified PMH events. Because the finding involved reactor shutdown operations and conditions, IMC 0609, Appendix G, Shutdown Operations Significance Determination Process (SDP), Attachment 1, issued May 25, 2004, Phase 1 Operational Checklists for Both pressurized water reactors (PWRs) and boiling water reactors (BWRs), was used. The inspectors used Checklist 5, BWR Hot Shutdown: Time to Boil < 2 Hours, and determined the finding increased the likelihood that a loss of decay heat removal (DHR) will occur due to failure of the system itself or support systems, degraded the licensees ability to cope with a loss of offsite power (LOOP), degraded the licensees ability to add reactor coolant system (RCS) inventory when needed, and degraded the licensees ability to establish an alternate core cooling path if DHR could not be re-established for 24 hours. Further, the performance deficiency involved external events. Consequently a Phase 2 analysis could not be performed and the issue screened directly to a Phase 3 analysis. The significance of this issue is To Be Determined (TBD) and its final significance will be dispositioned in separate transmittal. The issue is not an immediate safety concern because the licensee has taken appropriate corrective actions. The finding has a cross-cutting aspect in the area of human performance associated with the field presence attribute because deviations from standards and expectations were not corrected promptly, and the licensee did not ensure supervisory and management oversight of work activities, including contractors. Specifically, licensee management failed to ensure degradation associated with flood protection of the safety-related buildings was identified and corrected.
05000324/FIN-2013010-042013Q4BrunswickFailure to Submit a Timely LER for Service Water System InoperabilityAn NRC-identified AV of 10 CFR 50.73(a)(2)(i)(B) and 10 CFR 50.73(a)(2)(v)(B), was identified for failure of the licensee to provide a written Licensee Event Report (LER) to the NRC within 60 days of identifying a condition which was prohibited by plant TS 3.7.2, SW System and Ultimate Heat Sink, and an event that could have prevented the fulfillment of a safety function of RHR. The licensees corrective actions included submitting LER 50-325 and 50-324/2013-003-00 on November 14, 2013. The licensee entered this issue into the CAP as NCR 629064. The inspectors determined the failure of the licensee to provide a written LER to the NRC within 60 days as required by 10 CFR 50.73(a)(2)(i)(B) and 10 CFR 50.73(a)(2)(v)(B) was a performance deficiency. This violation involved a failure to make a required report to the NRC and is considered to impact the regulatory process. Such violations are dispositioned using the traditional enforcement process instead of the SDP. As discussed in the Enforcement Policy, the severity level of a violation involving the failure to make a required report to the NRC will be based upon the significance of and the circumstances surrounding the matter that should have been reported. This issue is being characterized as an AV in accordance with the NRC's Enforcement Policy, and its final significance will be dispositioned in separate future correspondence. Because this violation involves the traditional enforcement process, a cross-cutting aspect is not assigned to this violation.
05000324/FIN-2013003-062013Q2BrunswickNon-Conservative Calculation for Service Water Flow Rate to the Emergency Diesel GeneratorsThe inspectors are opening an URI to review the revision to Calculation M-89-0008, Heat Balance on DG 2 Jacket Water Service Heat Exchanger, for service water flow rate required for EDG operability during a design basis event, to determine if the performance deficiency associated with this issue is more than minor. On January 14, 2013, the licensee was performing Procedure 0ENP-2705, Service Water Heat Exchanger Thermal Performance Testing, to measure the service water flow rate to the EDG 3 jacket water heat exchanger, and found flow to be in the range of 351 to 358 gpm. The expected flow rate is 900 gpm to 1100 gpm. After visual inspection, it was determined the EDG 3 service water outlet valve 2-SW-V208 was throttled to 1-1.25 turns instead of the required 2.25 turns specified in 0OP-39, Diesel Generator Operating Procedure. Diesel 3 was determined to be operable based on Calculation M-89-0008, which required the measured service water flow rate to be above 350 gpm at an ultimate heat sink temperature of 90F. The licensee performed a past operability evaluation and determined the service water outlet valve 2-SW-V208 was out of position since April 2010. The licensee determined the maximum service water inlet temperature experienced between April 2010 and January 2013 was 89.2F on August 2, 2011 and August 6, 2012. The licensee concluded that since the inlet temperature was below 90F in 2011 and 2012, and the service water flow rate was above 350 gpm, that EDG 3 had always been operable. The inspectors reviewed Calculation M-89-0008 and determined that the calculation assumed an EDG loading of 3500 kW instead of the EDG loading of 3850 kW allowed by TS 3.8.1, AC Sources Operating, Surveillance Requirement 3.8.1.11. The inspectors determined that the failure to have an adequate calculation for service water flow rate required for EDG operability was a performance deficiency. The inspectors are opening an URI to review the revision to Calculation M-89-0008 and determine if the performance deficiency is more than minor. The licensee entered this issue in the CAP as NCR 592035. This issue is being tracked as a URI: URI 05000325/2013003-06 and 05000324/2013003-06, Non-Conservative Calculation for Service Water Flow Rate to the Emergency Diesel Generators.
05000324/FIN-2013003-102013Q2BrunswickNotice of Enforcement Discretion for Replacement of the E8 TransformerIn accordance with the NRCs NOED process, the inspectors are opening a URI to facilitate prompt tracking, documentation, and closure of inspection, verification, and resolution activities, including enforcement action determinations, associated with the NOED. The inspectors are opening the URI to determine if a performance deficiency exists. On April 15, 2013, due to the inoperability of Division II emergency buses E4/E8, the licensee requested the NRC not enforce compliance with TS 3.7.3, Required Action A.1; TS 3.8.1, Required Action B.3; TS 3.8.4, Required Action A.1; and TS 3.8.7, Required Action A1 until April 17, 2013 at 3:15 am. The licensee requested and was granted the NOED on April 15, 2013 at 2:05 pm. The LCO extension allowed the site time to complete the replacement of and test the E8 transformer to restore operability. The inspectors are opening an URI to determine if a performance deficiency exists. The licensee entered this issue in the CAP as NCR 601376. This issue is being tracked as a URI: (URI) 5000325/2013003-10; Notice of Enforcement Discretion for Replacement of the E8 Transformer.
05000324/FIN-2013003-092013Q2BrunswickResidual Heat Removal A Heat Exchanger Bypass Valve 2-E11-F048A Stud FailureThe inspectors are opening an URI to review the licensees evaluation of the operability of A RHR heat exchanger bypass valve 2-E11-F048A and determine if the performance deficiency associated with this issue is more than minor. On March 29, 2012, during Unit 2 refueling outage B221R1, maintenance personnel were going to repack A RHR heat exchanger bypass valve 2-E11-F048A. A member of maintenance hit one of the four valve yoke to bonnet hold down 134 studs with his foot and the stud sheared off at the nut. A second yoke hold down stud sheared off at the nut when maintenance personnel tried to remove the nut. The licensees corrective actions included replacing the four studs. The licensee determined the failure mechanism of the two studs was low stress, high cycle fatigue caused by vibration of the valve during throttling operations. The inspectors determined that the performance deficiency associated with this issue was the failure of the licensee to evaluate the effects of vibration on valve 2-E11-F048A when the valve was used for throttling, which resulted in the two studs sheering. The inspectors are opening an URI to review the licensees evaluation of the operability of valve F048A and determine if the performance deficiency is more than minor. The licensee entered this issue in the CAP as NCR 598294. This issue is being tracked as a URI: URI 05000324/2013003-09, Residual Heat Removal A Heat Exchanger Bypass Valve 2-E11-F048A Stud Failure.
05000324/FIN-2013003-032013Q2BrunswickInadequate Work Order to Perform a Modification to the Control Room Emergency Ventilation SystemAn NRC-identified Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified, for the licensees failure to have an adequate instruction or procedure to perform a modification to the control room emergency ventilation system (CREV). The licensee took immediate action to return CREV to service and entered this issue into the CAP as NCR 578363. The inspectors determined that the failure of the licensee to have an adequate procedure for installing a jumper on the 2A CREV system was a performance deficiency. The finding was more than minor because it was associated with the configuration control attribute of the Barrier Integrity Cornerstone and affects the cornerstone objective to provide reasonable assurance that physical design barriers (fuel cladding, reactor coolant system, and containment) protect the public from radionuclide releases caused by accidents or events. Specifically, the failure to have an adequate procedure to install a jumper on the 2A CREV system resulted in the safety system functional failure of CREV. Using IMC 0609, Appendix A, issued June 19, 2012, the SDP for Findings At- Power, the inspectors determined the finding screened to a detailed risk evaluation because the finding represented a degradation of the radiological barrier function and smoke or toxic atmosphere function of the control room barrier. The regional SRA performed a Phase 3 analysis on the finding. A screening calculation was performed to estimate the impact the finding would have on the facility for conditions that would lead to plant shutdown, or failure of the filtering function of the ventilation system. The low likelihood of failure to recover the system, combined with the short time the deficiency existed, resulted in a finding of very low safety significance (Green). The finding has a cross-cutting aspect in the area of human performance associated with the work control attribute because the licensee did not appropriately coordinate work activities by incorporating the impact of changes to the work scope or activity on the plant when installing a ring lug jumper on the 2A CREV subsystem.
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