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05000251/FIN-2018003-022018Q3Turkey PointInoperable Auxiliary Feedwater Steam Supply Flow PathA self-revealing Green NCV of 10 CFR 50, Appendix B, Criterion V, Procedures, was identified when FPL failed to ensure that the torque arm of the 4A steam generator (SG) auxiliary feedwater (AFW) steam supply valve, MOV-4-1403, remained engaged with its valve stem key. A disengaged torque arm subsequently caused the geared limit switch settings for the 4-1403 motor operator to become out of sync with the valve travel and rendered the AFW 4A SG supply flow path inoperable.
05000389/FIN-2018003-012018Q3Saint LucieFailure to meet the Transient Combustible Requirements Specified by NFPA 805The inspectors identified a Green non-cited violation (NCV) of 10 CFR 50.48(c), National Fire Protection Standard NFPA 805, requirements. Specifically, the licensee failed to comply with transient combustible control requirements in high risk fire zones as required by NFPA 805 and implemented by licensee procedure ADM-19.03, Transient Combustible Control.
05000395/FIN-2018003-012018Q3SummerLicensee-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 of the Enforcement Policy. V.C. Summer Operating License condition 2.c(18) states in part that the licensee shall implement and maintain in effect all provisions of the approved fire protection program that comply with 10 CFR 50.48(c), National Fire Protection Association (NFPA) 805 of which Chapter 3, Section 3.2.3, Procedures, states, Procedures shall be established for implementation of the fire protection program. Contrary to the above, on January 10, 2017, the licensee failed to implement an established procedure, FPP-025, Fire Containment, Revision 6D, to ensure fire door DRAB/319 closes and latches on its own power.
05000250/FIN-2018003-012018Q3Turkey PointVital Inverter Alternate AC Supply Cables Were Not Included in the Nuclear Safety Capability AssessmentOn June 25, 2018, the inspectors inquired about an open corrective action item documented in AR 2156812. AR 2156812 was originated by FPL on September 20, 2016, and documented that the NFPA 805 Nuclear Safety Capability Assessment (NSCA) circuit analysis failed to include and analyze cables associated with the alternate power supply to all vital inverters on either Turkey Point Unit. The vital inverters power vital plant instruments and controls and are normally powered by the vital DC batteries. The NSCA analysis incorrectly considered that the alternate AC power supply would be always available to power the vital inverters if the DC power supply was damaged by fire. However, the alternate power supply cables may be impacted by fire damage. Not correctly including the fire damage potential for the inverter alternate power supply cables resulted in a non-conservative analysis when the NSCA was performed. The inspectors inquired why compensatory measures in the form of fire watches were not established for the non-conservative NSCA analysis. In response to the inspectors questions, FPL determined that the non-conservative condition still existed and that it was potentially more than a minimal risk impact. FPL considered that if the fire Probabilistic Risk Assessment (PRA) evaluation determines the issue to not result in a risk increase of more than 1E-7/year for core damage frequency and no more than 1E-8/year for large early release frequency, that the change to the fire protection program to correctly analyze the vital inverter power supplies is no more than minimal risk impact. FPL initiated interim compensatory measures in the form of roving fire watches in all the affected Unit 3 and Unit 4 fire areas. FPL initiated AR 2270522 to document the associated interim compensatory measures. AR 2270522 also tracks completion of the necessary NSCA change and an associated fire PRA evaluation to correctly model the vital inverter power supply cables. FPL expects to complete the fire PRA evaluation in December 2018. Units 3 and 4 Operating License Condition 3.D., Transition License Conditions 1. requires, in part, that risk-informed changes to the licensees fire protection program may not be made without prior NRC review and approval unless the change has been demonstrated to have no more than a minimal risk impact, as described in Operation License Condition 3.D., Other Changes that May be Made Without Prior NRC Approval, 2. Fire Protection Program Changes that Have No More than Minimal Risk Impact. The results of FPLs fire PRA evaluation expected to complete in December 2018 are necessary to determine if this issue is a violation of Units 3 and 4 Operating License Condition 3.D., Transition License Conditions 1. This issue remains unresolved pending review of FPLs fire PRA evaluation.
05000395/FIN-2018003-022018Q3SummerMinor ViolationThe inspectors concluded that rotation of the safety-related SW pipe support, SWH-4021, was a condition adverse to quality (CAQ) identified in CR-04-01705. The inspectors also concluded that the failure to correct this CAQ was a minor violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, which states in part that CAQs are promptly identified and corrected. Screening: The inspectors determined that the degradation of SWH-4021 was minor based on the absence of any deformed components on the pipe support, and that the respective train of the SW system remained overall operable. The licensee corrected the CAQ during the quarter using WO 1813577, Return SWH-4021 to design requirements. Enforcement: This failure to comply with 10 CFR 50, Appendix B, Criterion XVI constitutes a minor violation that is not subject to enforcement action in accordance with the NRCs Enforcement Policy.
05000250/FIN-2018002-012018Q2Turkey PointUnit 3 Emergency Diesel Generator (EDG) Operability during Fuel Oil Transfer to Unit 4 Fuel Oil Storage TanksFrom April 2, through April 10, 2018, the 4B emergency diesel generator (EDG) was out of service for maintenance. On April 4, 2018, the licensee transferred diesel fuel oil (fuel) from the Unit 3 common storage tank, using the 3A EDG fuel transfer pump, 3P10A, to the 4B EDG storage tank. To perform the fuel transfer, operators aligned the 3A EDG fuel transfer system by: 1) removing the 3P10A control switch from the automatic position; 2) closed the air-operated fill valve CV-3-2046A, to the 3A EDG day tank, by isolating and venting its instrument air supply line; and, 3) opened normally locked-closed Unit 3 and Unit 4 fuel transfer manual valves. During the fuel transfer from Unit 3 to Unit 4, the automatic fuel transfer operation from the Unit 3 storage tank to the 3A EDG day tank was defeated. The licensee did not consider the 3A EDG inoperable in this alignment and credited operator manual actions (OMAs) to restore its day tank to automatic fill operation. Technical Specification (TS) surveillance requirement 4.8.1.1.2.b, requires in part, that, each diesel generator shall be demonstrated OPERABLE by demonstrating that a fuel transfer pump starts automatically and transfers fuel from the storage system to the day tank. The inspectors questioned if the licensee was in compliance with the surveillance requirement during the fuel transfer and if the 3A EDG was operable by crediting OMAs. The licensees initial assessment was that the 3A EDG remained operable during the fuel transfer. Additionally, the licensee described that this particular issue was previously reviewed and described in a condition report evaluation, 00-14-19, dated September 22, 2000. The evaluation concluded that automatic operation of the fuel transfer pump was required for EDG operability but automatic operation of the day tank fill valve was not required for operability. The 3A and 3B EDG day tank fill valves are pneumatically operated valves and rely on the non-safety grade instrument air system for operation. Additionally, the evaluation stated that since the instrument air system was non-safety related, and the large EDG day tanks provide ample run time for the EDGs, OMAs were considered part of the system design basis. The inspectors noted to the licensee that the Turkey Point TSs do not specifically credit OMAs associated with the EDG fuel transfer system in a limiting condition for operation (LCO). The inspectors also noted to the licensee that TS Surveillance Requirement (SR) 4.0.1 states Surveillance Requirements shall be met during the OPERATIONAL MODES or other conditions specified for individual Limiting Conditions for Operation unless otherwise stated in an individual Surveillance Requirement. TS SR 4.8.1.1.2.b. requires demonstrating that a fuel transfer pump starts automatically and transfers fuel from the storage system to the day tank. If CV-3-2046A fails closed on a loss of instrument air, the licensee has an off-normal operating procedure that uses local OMAs to align a compressed air bottle to open CV-3-2046A to align fuel to the 3A EDG day tank. UFFSAR section 9.15.1.1.2.1.5 stated in part, Air-operated valves in the transfer lines from the diesel oil storage tank to the day tank automatically open in response to signals developed by logic circuitry incorporating tank level and pump control switch positions. The valves can be locally opened using a separate air source in the event normal instrument air is not available. Section 9.15.1.3.1 described in part Sufficient time exists for providing an alternative air source for opening the day tank fill isolation valves should instrument air fail before the day tank is emptied. With respect to the fuel transfer evolution, the licensee stated that the restoration could be completed with OMAs in sufficient time prior to the day tank being depleted of fuel. The license initiated AR 2269269 to complete a design basis and license basis review on the EDGs for operability during cross unit fuel transfers. Interim actions included declaring the EDG out of service anytime a cross unit fuel transfer was performed. At the conclusion of the inspection period the licensee had not completed the design and license basis evaluation. It was indeterminate whether a performance deficiency exists. This issue remains unresolved pending review of the licensees design and license basis evaluation. Planned Closure Action: A review of the licensees design and license basis evaluation documented in AR 2269269 was required for closure and to determine a performance deficiency exists. Licensee Actions: The license entered this issue into the corrective action program as AR 2269269 to complete a design and license basis review of EDG operability during cross unit fuel transfers. Interim actions included declaring the EDG inoperable any time a cross unit fuel transfer was performed. Corrective Actions Reference: AR 2269269
05000250/FIN-2018001-022018Q1Turkey PointFailure of radiation workers to notify Radiation Protection upon a spill of radioactively contaminated waterA self-revealing Green NCV of Technical Specification (TS) 6.8.1, Procedures and Programs, was identified for failure of radiation workers to notify Radiation Protection (RP), in accordance with procedure RP-AA-100-1002, Radiation Worker Instruction and Responsibilities, step 4.13.4, Spills and Observed Leaks, when a spill of radioactively contaminated water occurred. Specifically, on January 22, 2018, during a line-up of the 4D demineralizer resin fill isolation valve on the auxiliary building roof, two radiation workers (non-licensed operators) removed the weather-protective enclosure over the valve to verify its position. Upon removalof the enclosure, approximately half a gallon of highly contaminated water spilled onto the auxiliary building roof. The workers then attempted to clean up and decontaminate the area on their own with a water hose, rather than notify RP. This action spread the contamination into a larger area and into the site storm drain system
05000250/FIN-2018001-012018Q1Turkey PointFailure to conduct post maintenance testing in accordance with ASME OM codeA Green NRC-identified NCV of 10 CFR 50.55a, Codes and Standards, was identified for the failure to adequately perform post maintenance testing on valve CV-4-2906, 4B emergency containment cooler (ECC) air-operated outlet valve, in accordance with the American Society of Mechanical Engineers (ASME) Operation and Maintenance (OM) Code, Subsection ISTC, Inservice Testing of Valves in Light-Water Reactor Nuclear Power Plants.
05000335/FIN-2018001-012018Q1Saint LucieImproper Evaluation of LCV-9005 position setpoints Leads to AFASOn November 19, 2013, during reactor startup activities, feedwater bypass valves, A (LCV-9005) and B (LCV-9006), were found to be operating at different throttle positions while maintaining their respective steam generator water levels. Valves LCV-9005 and 9006 were both originally installed in April 1978. LCV-9005 was replaced in 1994, with an equivalent valve, due to obsolescence. The original valve had a full open stroke length of 1.5 inches (in.), while the new equivalent valve had a full open stroke length of 2 in. to provide the same flow as the original valve. When installed, LCV-9005 was set up to limit its stroke length to 1.5 in., matching the replaced valve, and the associated drawings were never revised to show that the new valve had a full 2 in. open stroke length. In 2009, the distributed control system (DCS) was installed utilizing these drawings and was setup under the assumption that both valves, LCV-9005 and LCV-9006, were the same model valves and stroke lengths.The DCS system was designed to provide a signal to throttle the feedwater bypass valves following a reactor trip to 20 percent open to provide approximately 5 percent feed flow in order to recover steam generator water levels utilizing main feedwater. During Unit 2 startup activities in November 2013, the licensee noted a discrepancy in the valve positions for LCV-9006 and LCV-9005 when they were providing steam generator water level control. The licensee placed the issue in the corrective action program under Action Request (AR) 1921720 and determined that it was necessary to evaluate a revision of the LCV-9005 DCS setpoint, which was accomplished by an engineering condition evaluation under AR 1925428. The engineering condition evaluation was inadequate in that it failed to recognize the differences in the two different model valves, and therefore failed to provide adequate corrective actions to address performance issues associated with these differences.The final recommendation from AR 1925428 was that the current LCV-9005 setting did not impose any risk to the plant operation, as the 2A steam generator level had been within acceptable range with no control room alarm observed. Therefore, no setpoint change was required at that point.On October 26, 2017, following a Unit 2 trip, LCV-9005 was sent a digital DCS demand signal to be 20 percent open. Since the valve was locally set to have a maximum stroke of 1.5 in. instead of 2 in. open, the actual flow through the valve was less than 5 percent. This resulted in flow lower than needed to maintain 2A steam generator level, and caused level to lower, which eventually resulted in an actuation of the A train auxiliary feedwater actuation system (AFAS). Corrective Action(s):The licensee implemented corrective actions to: 1) properly set up LCV-9005 in order for it to have a full stroke length of 2 inches so that it could provide the required feedwater flow and, 2) update associated drawings to include correct stroke lengths.Corrective Action Reference(s): This issue was entered into the licensees CAP as AR 2232869
05000395/FIN-2018001-012018Q1SummerFailure to Perform an Adequate Risk Assessment With Consequent Reactor TripA self-revealed, Green NCV was identified for the licensees failure to adequately assess risk in accordance with 10 CFR 50.65(a)(4), Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, involving repairs to a non-safety related inverter, XIT-5905. This NCV closes LER 05000395/2017-005-00: Automatic Reactor Trip Due to Main Turbine Trip.
05000324/FIN-2013002-022013Q1BrunswickFlood Impacts Due to Degraded Flood Protection MeasuresThe inspectors are opening a URI associated with the potential for flood intrusion into the service water building, reactor building, and emergency diesel generator building due to degraded flood protection measures to determine if a performance deficiency exists. From August through October, 2012, the licensee performed walkdowns of flood protection measures in accordance with Nuclear Energy Institutes 12-07 Walkdown Guidance. The licensee and inspectors identified degraded or missing flood protection measures in the service water building, reactor building, and emergency diesel generator building. The inspectors are opening a URI to review the licensees evaluation of these flood protection deficiencies and determine if a performance deficiency exists. The licensee entered these issues into the CAP as NCR 600850. This issue is being tracked as: URI 05000325/2013002-02 and 05000324/2013002-02, Flood Impacts due to Degraded Flood Protection Measures.
05000400/FIN-2013002-032013Q1HarrisSolid State Protection System Digital ModificationThe inspectors identified an unresolved item (URI) associated with the licensees implementation of a digital modification to the solid state protection system (SSPS) logic and control boards. This item remains unresolved pending NRC staff review of additional information to determine if the change could have been performed under a 10 CFR 50.59 evaluation and whether it should have been submitted to the NRC for prior approval. The SSPS logic and control boards provide the coincidence logic to produce actuation signals for operation of the reactor protection system (RPS) and the engineered safety features actuation systems (ESFAS). Engineering change 78484, Replace SSPS Boards with new Westinghouse Design Boards, Rev. 6, examined a digital modification to the existing SSPS logic and control boards. The original boards used fixed logic devices (transistor-transistor logic devices) whereas the replacement boards use reprogrammable logic devices (complex programmable logic devices (CPLDs)). The licensee performed a 10 CFR 50.59 Screening (AR 537776) using procedure REG-NGGC-0010, 10 CFR 50.59 and Selected Regulatory Reviews, Rev. 18. The procedure used the guidance in NEI 96-07, Guidelines for 10 CFR 50.59 Implementation, Rev. 1, as supplemented by NEI 01-01, Guidelines on Licensing Digital Upgrades, Rev. 1, to evaluate the design and implementation of digital modifications to instrumentation and control systems under 10 CFR 50.59. The licensees screening indicated (in summary) that the new design boards performed the same functions and were functionally tested; therefore, did not adversely affect the SSPS design bases functions previously evaluated in the UFSAR. The screening further determined the modification could be implemented without a more detailed 10 CFR 50.59 evaluation. The inspectors reviewed the screening using the licensees procedural guidance and determined the modification adversely affected the SSPS design functions described in the UFSAR because: (1) The response times of the new design boards were slower. Section 4.3.3 of NEI 01-01, Other Digital Issues in the Screening Process, indicates that performance changes from UFSAR described requirements (i.e. response time) should be screened in and require further evaluation under 10 CFR 50.59. (2) Human System Interface (HIS) features (i.e. dip switches, RS-232 communication ports, and indicating light-emitting diodes or LED) were added. Section 4.3.4 of NEI 01-01, Screening Human System Interface Changes, indicates that changes that create new potentional failure modes in the interaction of operators and maintenance personal with the system should be further evaluated for the potential increase in the likelihood of malfunctions. (3) The new boards were loaded with a data file (which NEI 01-01 defines as a type of base software) that configures the CPLD logic. Section 4.3.2 of NEI 01- 01 Software Considerations, indicates that digital modifications that involve the use of software applications should be conservatively treated as an adverse effect (requiring evaluation under 10 CFR 50.59) due to the potential introduction of new failure modes (software based failures, including Common Cause Failures (CCF)) not previously evaluated in the UFSAR, especially when modifications involve redundant high risk safety systems (i.e. RPS.ESFAS) In response to the inspectors questions, the licensee performed a 10 CFR 50.59 evaluation (AR #588797) and determined the change could be implemented without prior NRC review and approval. The licensee indicated that (1) the new boards still met the response time requirements for the SSPS as described in the UFSAR, (2) the HIS vulnerabilities were mitigated by configuration at the vendor facility, and (3) the CPLDs were not software-based and that the data files were simple logic files that were fully tested, verified, and validated to operated as expected. The licensee asserted that the development and quality assurance processes used, including design, verification & validation, and configuration control mitigated any potential increase in the likelihood of malfunctions due to software (or embedded data file) (10 CFR 50.59 criteria (c)(2)(ii)). The licensee also compared the hardware functional testing performed by the vendor with criteria in Branch Technical Position (BTP) 7-19, Guidance for Evaluation of Diversity and Defense-in-Depth in Digital Computer-Based I&C Systems, Rev. 6, section 1.9, to show that software CCFs required no further evaluation. Specifically, the licensee indicated that the functional testing for the boards was adequate for 100 percent testing for every possible combination of inputs and every possible sequence of device states were tested and all outputs were verified on the boards (and embedded software) to eliminate consideration of software based CCF. Based on this testing, the licensee concluded that the use of software did not create a possibility of malfunctions of the SSPS with a different result than previously evaluated in the UFSAR (10 CFR 50.59 criteria (c)(2)(vi)). After reviewing the 10 CFR 50.59 evaluation, the inspectors found that they did not have sufficient information to determine that NRC review and approval was not required prior to implementation of the modification. Specifically, the inspectors could not verify the licensees conclusions regarding the software reliability and the simplicity and testing of the new boards. Because the licensee claimed that the CPLDs were not softwarebased, the licensee did not address the software development processes described in NEI 01-01, section 5.3.3, Digital System Quality. Specifically, the inspectors noted that second and third party commercial vendors were involved in the manufacturing of the CPLDs and development of the base software data-file without a quality software development process as addressed in NEI 01-01. In addition, because of the licensees claim that the CPLDs were not software-based, the licensee excluded the possibility of software CCF as addressed in NEI 01-01, section 3.2.2, Software Common Cause Failure. The inspectors concluded that software CCF of the SSPS could introduce new failure modes not previously analyzed in the UFSAR. With respect to the simplicity and testing of the SSPS boards, the inspectors questioned the simplicity of the boards and the appropriateness of using testing to rule out consideration of CCFs. In addition, the testing performed by the licensee did not meet the guidance in BTP 7-19. The inspectors also concluded that the HSI features added to the SSPS boards provided additional risk of failures not associated with the original SSPS boards when used by operators and maintenance personnel. In order to determine if the change could have been performed under a 10 CFR 50.59 evaluation and whether it should have been submitted to the NRC for prior approval, this issue remains unresolved pending NRC staff review of additional information to be provided by the licensee to address the issues described above. This issue is being tracked as URI 05000400/2013002-03, Solid State Protection System Digital Modification.
05000400/FIN-2013002-042013Q1HarrisNumber 1 Reactor Coolant Pump Seal Leakoff Line OVER-PRESSURIZATIONThe inspectors identified a URI associated with licensees capability to meet their station blackout (SBO) mitigation strategy. This item remains unresolved pending the inspectors review of the additional information to determine compliance with 10 CFR 50.63, Loss of All Alternating Power. The reactor coolant pumps (RCP) No.1 seal leakoff line was designed to recover leakoff volume, at low pressure and temperature, and return it to the chemical and volume control system (CVCS). The leakoff lines (one per pump) join into a common header before exiting containment to the CVCS. In 1992, Westinghouse Technical Bulletin, NSD-TB-91-07-R1, Over-Pressurization of RCP No.1 Seal Leakoff Line, informed specific licensees (including Harris) of the potential over-pressurization of the No.1 seal leakoff line during high seal leakoff flow conditions as a result of abnormal performance of the No.1 RCP seal. Specifically, the leakoff line pipe segment downstream of the air operated valve (which fails open on loss of instrument air) and upstream of the flow element restriction orifice was designed to 150 psig and could overpressurize and fail under high flow conditions. While Harris had implemented recommendations contained in the bulletin, the licensee did not upgrade the piping for higher pressures nor evaluate the line capability to handle expected seal leakage flow rates associated with loss of seal cooling (LOSC) events documented in Westinghouse Owner Group Report WCAP-10541 Reactor Coolant Pump Seal Performance Following a Loss of All AC Power, Rev 2. The technical bulletin specifically stated that the validity of the information in WCAP-10541 was dependent upon the assumption that the integrity of the leakoff line was maintained. The inspectors reviewed WCAP-10541 and noted that the leakoff line could experience a pressure transient between 800-2000 psig during a LOSC event before seal leakage flow rates stabilize at approximately 21gpm and 800psig. The report also indicated that the backpressure provided by the leakoff line (upstream of the orifice) is what limits seal leagage to 21gpm and reduction of this backpressure would result in higher seal leakage flow rates. In 2003, Information Notice (IN) 2003-19, Unanalyzed Condition of Reactor Coolant Pump Seal Leakoff Line During Postulated Fire Scenarios or Station Blackout, informed licensees of specific LOSC events (SBO and fires coincident with loss of all AC events) that could over-pressurize and fail the leakoff line. The IN reemphasized the pressures that will be experienced by the leakoff line (800-2000 psig) and that the failure of the line would result in RCP leak rates in excess of the 21gpm determined by Westinghouse and the 25 gpm assumed in SBO coping analyses. The inspectors reviewed the licensees evaluation of IN 2003-19 (AR #1069790-09) and determined the licensees actions did not adequately address the potential for over-pressurizing the seal leakoff line. The licensee entered the issue into the CAP as AR #589248 and indicated that the alternate seal injection (ASI) system, installed in December of 2010 to meet the sites new fire protection program requirements (NFPA-805, Performance-Based Standard for Fire Protection for Light Water Reactor Electric Generating Plants), automatically starts on a LOSC event (SBO or fire related) and will maintain seal cooling. By maintaining seal cooling, the RCP seal leakage flow rates are expected to remain at nominal operating values (2-5 gpm) and prevent seal leakage flow rates that would challenge the integrity of the No.1 seal leakoff line. The inspectors questioned the appropriateness of crediting the ASI system for SBO events and the systems capability to prevent overpressurization of the leakoff line. Specifically: The inspectors noted that the ASI system was not credited for meeting the current licensing bases for SBO. The ASI has a delayed start and the inspectors questioned whether seal cooling would be restored before seal leakage increases to the point of challenging the leakoff line. This issue remains unresolved pending the inspectors review of additional information to be provided by the licensee to address the issues described above and determine compliance with 10 CFR 50.63, Loss of All Alternating Power. This issue is being tracked as: URI 05000400/2013002-04, No. 1 Reactor Coolant Pump Seal Leakoff Line Over-Pressurization.
05000400/FIN-2013002-012013Q1HarrisInadequate Correction Actions Involving the Incorrect Determination of OperabilityAn NRC-identified Green NCV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action was identified for the licensees failure to take corrective actions related to incorrect operability determinations which resulted in violation of TS 3.8.1.1 (Electrical Power Sources) associated with the S-2B-SB failure to secure on October 26, 2012. The licensee entered the issue into their CAP as AR #569593. As corrective actions, on October 31, 2012, Operations opened the supply breaker (1B21-SB-4B) for the primary shield fan to remove any impact to the Emergency Diesel Generator (EDG) operability. Additionally, the licensee created AR #584473 to evaluate and correct issues associated with their operability determinations. The licensees failure to take timely, appropriate corrective actions for inadequate operability determinations was a performance deficiency. 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, the failure to take timely, appropriate corrective actions could have resulted in a more safety significant violation of TS than the identified violation of TS 3.8.1.1 (Electrical Power Sources) associated with the S- 2B-SB failure to secure on October 26, 2012. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 2 of IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings at Power, the inspectors determined that this finding is of very low safety significance (Green) because the performance deficiency did not involve a deficiency affecting the design or qualification of a mitigating system and did not represent a loss of system function. The cause of the finding was directly related to the cross-cutting aspect for appropriate corrective actions to address safety issues in a timely manner commensurate with their safety significance and complexity in the CAP component of the cross-cutting area of Problem Identification and Resolution, in that the licensee failed to take appropriate and timely corrective actions to address incorrect determinations of operability
05000324/FIN-2013002-012013Q1BrunswickFailure to Follow Procedure for Variable Frequency Drive Reactor Recirculation Pump Design ModificationAn NRC-identified Green finding was identified for the failure of the licensee to follow Procedure EGR-NGGC-0005, Engineering Change (EC), when performing the variable frequency drive (VFD) modification for the reactor recirculation pumps (RRPs). Specifically, between April 4, 2010 and the present, the licensee inappropriately used a Rapid Field Release (RFR) to revise the power supplies for the relays in the VFD system without re-evaluating the EC, the 10 CFR 50.59 Screen/Evaluation, and the Failure Modes and Effects Analysis (FMEA). This resulted in a new failure mode on a loss of the power supply causing a RRP runback and placing the plant in a flow transient, and a loss of cooling to the RRP seals. The licensee entered this issue into the corrective action program (CAP) as nuclear condition report (NCR) 581202. The performance deficiency associated with this finding was the failure of the licensee to follow Procedure EGR-NGGC-0005, Engineering Change (EC), when performing the VFD modification for the RRPs. The finding was more than minor because it was associated with the design control attribute of the Initiating Events Cornerstone and affects 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 VFD modification inappropriately causes a RRP runback on a loss of 480 VAC and core flow instability, and a loss of cooling to the RRP seals. 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 because as a transient initiator due to the RRP runback, the finding did not cause a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. The inspectors determined the finding was also of very low safety significance because as a loss of coolant accident (LOCA) initiator, after a reasonable assessment of degradation, the finding would not result in exceeding the reactor coolant system leak rate for a small break LOCA or likely affect other systems used to mitigate a LOCA resulting in a total loss of their function. 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 actions to address the impact of changes to the work scope, associated with the VFD modification, on the plant.
05000400/FIN-2013002-022013Q1HarrisFailure to Implement Design Control Measures for the EDG Starting and Control Air SystemThe inspectors identified a non-cited violation of 10 CFR 50, Appendix B, Criterion III, Design Control, involving two examples. In one example, the licensee did not translate instrument uncertainties associated with the EDG low-pressure alarm and pressure indicator into operating and alarm response procedures. In the second example, the licensee failed to verify the design adequacy for blocking the EDG nonemergency generator trips during emergency operation. The licensee entered the first example into their CAP as ARs #586788, #586837, #588517, and #589308 and initiated a standing instruction to verify starting air pressure was maintained above 200 psig while evaluating appropriate corrective actions. The licensee entered the second example into their CAP as ARs #382359 and #412546, and implemented a facility change to correct the design deficiency. The failure to translate instrument uncertainties associated with the EDG low-pressure alarm and pressure indicator into operating and alarm response procedures, and failure to verify the design adequacy for blocking the EDG non-emergency generator trips were performance deficiencies. The performance deficiencies were more than minor because they were associated with the Design Control attribute of the Mitigating System Cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors assessed the finding using IMC 0609 Attachment 4, Initial Characterization of Findings; and IMC 0609 Appendix A, The Significance Determination Process for Findings At-Power, and determined the finding was of very low safety significance (Green) because the design deficiencies were confirmed not to result in loss of operability of the EDGs. The finding was reviewed for cross-cutting aspects and none were identified since the performance deficiencies were not indicative of current licensee performance.
05000324/FIN-2013002-032013Q1BrunswickLicensee-Identified ViolationThe following violation of very low safety significance (Green) was identified by the licensee and is a violation of NRC requirements which meets the criteria of the NRC Enforcement Policy, for being dispositioned as a Non-Cited Violation. Technical Specification 5.7.1, High Radiation Area, requires posting and barricading of HRAs with dose rates not exceeding 1 Rem/hour at 30 centimeters from the radiation source or from any surface penetrated by the radiation. Contrary to this, on April 25, 2012, an unposted and unbarricaded HRA was identified by the licensee in the Unit 1 Reactor Building 80 elevation Reactor Water Clean-Up (RWCU) Precoat Tank area. During the previous shift, following a RWCU Back Wash Receiving Tank (BWRT) resin transfer drop to the Radwaste RWCU phase separators, a survey was performed and the area was downposted from HRA to RA. However, the survey failed to detect dose rates on the piping underneath the Unit 1 RWCU Precoat tank of 2.5 Rem/hour contact and 0.4 Rem/hour at 30 centimeters. The elevated dose rates were not found until a procedurally required follow-up survey was performed approximately 3.5 hours later by another HP technician. The technician took immediate corrective actions including posting and barricading the affected area. This finding was of very low safety significance (Green) because there was no substantial potential for overexposure. This was based on the fact that no workers entered the hotspot area underneath the Precoat tank during the brief period that the area was not properly controlled. In addition, the dose rates involved were not high enough to provide a substantial potential for overexposure. The licensee entered the issue into their CAP as NCR 532588.
05000400/FIN-2013002-052013Q1HarrisReactor Power Transient Due to Inadvertent Isolation of the 4B Feedwater HeaterA self-revealing Green finding (FIN) was identified for the licensees failure to establish and implement an adequate operating procedure (OP-136, Feedwater Heaters, Vents and Drains, Revision 41) to restore the 4B feedwater heater (FWH) alternate level control valve (1HD-323) to automatic operation. The licensee entered this issue into the Corrective Action Program (CAP) as Action Request (AR) #592336. The licensee took corrective action to reduce reactor power immediately and revise OP-136 to include a power reduction prior to restoring 1HD-323 to automatic operation. The licensees failure to establish and implement an adequate operating procedure (OP-136, Feedwater Heaters, Vents and Drains, Revision 41) to restore 1HD-323 to automatic operation was identified as a performance deficiency. The performance deficiency was more than minor because it was associated with the procedure quality attribute of the Initiating Events cornerstone and affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions. Specifically, failure to establish and implement an adequate operating procedure resulted in a steam plant transient that caused an unplanned reactor power increase to 101.1 percent Rated Thermal Power (RTP). In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 1 of IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings at Power, the inspectors determined that this finding is of very low safety significance (Green) because the performance deficiency did not involve the complete or partial loss of a support system that contributes to the likelihood of an initiating event and it did not affect mitigation equipment. The finding has a cross-cutting aspect of Implements and Institutionalizes Operating Experience, as described in the Operating Experience component of the Problem Identification and Resolution cross-cutting area because the licensee failed to institutionalize operating experience from the previous month.
05000400/FIN-2013002-062013Q1HarrisLicensee-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 disposition as a Non-Cited Violation. 10 CFR 50, Appendix B, Criterion XVI, Corrective Action requires, in part, that in the case of significant conditions adverse to quality corrective actions shall be taken to preclude repetition. Contrary to this requirement, corrective actions taken after the Containment Pre-Entry Purge Outside Containment Isolation Valve (1CP-1) failed EST-220, Type C Local Leak Rate Test on February 23, 2004 failed to preclude repetition (AR #119086). Specifically, the licensee failed to incorporate adequate guidance to re-torque the stud bolts on the seat clamping ring into procedure CMM0225. This resulted in 1CP-1 failing EST-220, Type C Local Leak Rate Test due to excessive leakage again on December 3, 2012. This violation was determined to be of very low safety significance (Green) because the finding did not represent an actual open pathway and did not involve an actual reduction in function of hydrogen igniters in the reactor containment. The licensee entered this issue into their CAP as AR #575878. As corrective actions, the licensee revised the seat replacement procedure, properly torqued the stud bolts and satisfactorily tested 1CP-1.
05000324/FIN-2013002-042013Q1BrunswickImplementation of Enforcement Guidance (EGM) 11-003, Revision 1, Enforcement Guidance Memorandum on Dispositioning Boiling Water Reactor Licensee Noncompliance with Technical Specification Containment Requirements During Operations with a Potential for Draining the Reactor VesselA violation of TS 3.6.4.1 was identified. However, because the violation was identified during the discretion period described in EGM 11-003, Revision 1, the NRC is exercising enforcement discretion in accordance with Section 3.5, Violations Involving Special Circumstances, of the NRC Enforcement Policy and, therefore, will not issue enforcement action for this violation, subject to a timely license amendment request being submitted.
05000324/FIN-2012005-042012Q4BrunswickInadequate Design of EDG 2 ASSD Switch A1The inspectors identified a Green NCV of 10 CFR 50 Appendix B, Criterion III, Design Control, for failure to assure that the design basis for EDG 2 Alternate Safe Shutdown (ASSD) Switch A1 was correctly translated into specifications and drawings. Specifically, between original EDG 2 installation and September 1, 2012, a wiring discrepancy existed associated with EDG 2 ASSD Switch A1 which resulted in an induced fault that could have impacted the ability to locally control EDG 2 during certain fire scenarios. The licensees corrective actions included correcting the EDG 2 control circuit wiring to ensure it was in accordance with the existing approved design and returning EDG 2 to operable status. The licensee entered this issue into the CAP as NCR 557897. The performance deficiency associated with this finding was the failure to assure that the design basis for EDG 2 ASSD Switch A1 was correctly translated into specifications and drawings. The finding was more than minor because it was associated with the protection against external factors (i.e. fire) attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective to ensure the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, an induced fault could have impacted the ability to locally control EDG 2 during certain fire scenarios. Using IMC 0609, Attachment 4, issued June 19, 2012, Initial Characterization of Findings, and IMC 0609, Appendix F, Attachment 1, Part 1: Application of Fire Protection SDP Phase 1 Worksheet, the results of this evaluation required further significance evaluation. A phase 3 analysis was performed by a regional SRA in accordance with NRC IMC 0609 Appendix F. The finding affected the capability to achieve alternate safe shutdown for Unit 1. The result of the analysis was an increase in core damage frequency of <1E-6/year a GREEN finding of very low safety significance. The finding does not have a cross-cutting aspect since the performance deficiency is not indicative of current plant performance. The EDG 2 ASSD Switch A1 wiring discrepancy has existed since original EDG installation.
05000324/FIN-2012005-012012Q4BrunswickFloor Drains Not Functioning Due to PluggingThe inspectors are opening an URI to review the licensees evaluation of the potential for adverse impact due to floor drain sock filter plugging in safety-related pump rooms and determine if there is a performance deficiency. On November 24, 2012, during a steam leak in the 2A Feedwater Heater Room, water did not adequately drain from the room through the floor drains due to plugging in the floor drain sock filters. The licensees immediate corrective actions included removing the sock filters so that the water could drain. The sock filters are also installed in safety-related pump rooms in the reactor building. The inspectors are opening an URI to review the licensees evaluation of the potential for adverse impact due to drain plugging in safety-related pump rooms and determine if there is a performance deficiency. The licensee entered this issue in the CAP as NCR 574261. This issue is being tracked as a URI: URI 05000325/2012005-01 and 05000324/2012005-01, Floor Drains Not Functioning Due to Plugging.
05000400/FIN-2012009-012012Q4HarrisTechnical Specification Inoperability of MSIVs Due to Failure to Conduct Diagnostic TestingThe inspectors identified a non-cited violation of Technical Specification (TS) 3.7.1.5, Main Steam Line Isolation Valves, due to one or more MSIVs being inoperable for a time greater than the allowed outage time and a plant shutdown was not completed in accordance with the action statement of TS 3.7.1.5. MSIV diagnostic testing in accordance with EGR-NGGC-0205, Air Operated Valve (AOV) Reliability Program, had not been conducted by the licensee. This contributed to the licensee not identifying long-term corrosion/oxidation of the valve piston rings that resulted in the B and C MSIV failure to initially close during stroke time testing on April 21, 2012. The licensee conducted repairs of all three MSIVs and restored them to an operable condition prior to entering Mode 4 following the completion of an ongoing refueling outage. The licensee entered this condition into their corrective action program (CAP) as Nuclear Condition Report (NCR) 531773. The failure to properly classify the MSIVs as risk significant and implement MSIV diagnostic testing in accordance with the AOV program procedure EGR-NGGC-0205 was a performance deficiency (PD). The PD is more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone and affected the cornerstone objectives of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding is also associated with the containment isolation barrier performance attribute of the Barrier Integrity cornerstone and affected the cornerstone objective of providing reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, the failure to conduct periodic diagnostic testing that would have identified long-term internal valve degradation due to unexpected corrosion/oxidation of the valve piston rings in all three MSIVs resulted in two MSIVs failing to initially close during TS stroke time testing on April 21, 2012, and excessive internal friction in all three MSIVs such that they may not have been capable of performing their safety-related closure function during certain design basis events. Using IMC 0609, Appendix A, The Significance Determination Process for Findings At- Power, the inspectors determined there was an actual loss of safety function greater than the TS allowed outage time associated with the finding which required a more detailed risk evaluation. A detailed risk evaluation was performed by a regional senior reactor analyst. The result of the analysis of the risk of the PD was a delta core damage frequency (CDF) of <1E-6/year and a delta Large Early Release Fraction (LERF) of <1E- 7/year, a GREEN finding. No cross-cutting aspect was assigned to this finding because licensee decisions made in regard to classifying the MSIVs in the AOV program were made more than three years ago and therefore, not reflective of current plant performance.
05000400/FIN-2012005-022012Q4HarrisLicensee-Identified ViolationThe licensee identified during the performance of OST-2044 (Radwaste Daily Operations Surveillance Test) on November 27, 2012, that the Waste Processing Building Stack 5 Accident Monitor (RM-WV-3546-1) was reading lower than expected and declared the monitor inoperable. An investigation revealed that at the conclusion of the maintenance activities performed the previous day, the monitor was returned to operable status while its database had incorrect settings. The inaccurate database was determined to have rendered the monitor inoperable. 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, states in part that activities affecting quality shall be prescribed by documented instructions and procedures. Contrary to the above, on November 26, 2012, the licensees procedure OWP-RM-19 (Operations Work Procedure Radiation Monitor) failed to adequately prescribe the correct instructions to ensure Radioactive Gaseous Effluent Monitoring Instrumentation received the appropriate post maintenance test. The licensee entered this issue into their CAP as AR #574702 and the monitor database was restored and tested. Using IMC 0609, Significance Determination Process, this finding was determined to be of low safety significance because the finding did not represent an actual dose impact in excess of Appendix I to10 CFR Part 50 or 10 CFR 20.1301(e).
05000261/FIN-2012005-012012Q4RobinsonAdequacy of Preventative Maintenance for the Dedicated Shutdown Diesel Generator Cooling SystemOn October 2, 2012, during monthly testing of the DSDG in accordance with OST-910, Dedicated Shutdown Diesel Generator Monthly, the control room received a DSDG Trouble alarm. Shortly after the alarm was received, the DSDG tripped. The licensee determined that the DSDG automatically tripped due to an engine jacket water over temperature condition. After the trip, licensee personnel inspected the engine and discovered that the drive belts for the belt driven radiator fan had come off the pulleys which prevented proper heat removal from the engine cooling system. All three drive belts were found to have varying degrees of wear and degradation. The last visual inspection of the fan belts was performed on September 12, 2011 and the last satisfactory surveillance run was performed on August 28, 2012. The DSDG is required to supply back-up power during a 10 CFR 50.65 Station Blackout condition and Appendix R conditions. Following the discovery of the thrown belts, the licensee replaced all three belts and performed a root cause evaluation. The root cause team determined that the cause of the failure was the lack of a time based replacement of the fan belts. The belts were last replaced in 2003. The inspectors reviewed the licensees root cause and asked additional questions regarding the expected service life of the fan belts. Additional inspection is required to review the licensees response to the inspectors questions and determine if a performance deficiency exists.
05000261/FIN-2012005-032012Q4RobinsonQuestions Regarding Whether GOTHIC is Sufficiently Qualified for Use in Operability DeterminationsInformation Notice 2011-17, issued July 26, 2011, informed addressees of recent instances of gas accumulation in safety-related systems in which the resulting operability determination of the as-found condition relied on computer models (i.e., GOTHIC) that were not demonstrated to be technically appropriate for the intended application. Specifically, the computer models had not been sufficiently qualified by benchmarking against test or plant data. The inspectors reviewed information related to the licensees response to GL 2008-01 and determined that the licensee had found voids in the SI system, RHR system, and CS piping. In most instances, the licensee had used GOTHIC to evaluate the past operability of the subject systems with voids, and then vented the gas prior to returning the subject systems back to service. The licensee had also evaluated the continued operability of the subject systems with a void left in place until corrective actions were implemented. Specifically, in 2008, the licensee evaluated eight gas voids found following filling and venting of the subject systems that could not be successfully removed during RO-25. The inspectors observed that the licensee used the GOTHIC as part of these evaluations to perform analysis of gas movement to predict how a void volume in piping is translated into a transient void fraction at the entrance of the pumps. The evaluations were the basis for the continued operability until corrective actions could be taken to remove the voids during the following RO-26, approximately 19 months later. While acknowledging the NRCs concerns that the GOTHIC models may not be sufficiently qualified by benchmarking against test or plant data for the particular gas transport scenario and piping configuration being analyzed, the licensee prepared engineering change document EC 86423 to document their justifications for continued use of the GOTHIC models to support operability determinations. The inspectors determined that this issue will remain unresolved pending additional inspection and consultation with a GOTHIC subject matter expert at NRC headquarters to evaluate the licensees use of GOTHIC to support operability determinations. This issue will be identified as URI 05000261/2012005-03, Questions Regarding Whether GOTHIC is Sufficiently Qualified for Use in Operability Determinations.
05000261/FIN-2012005-042012Q4RobinsonQuestions Regarding the Adequacy of the Fill and Vent Procedure for the Residual Heat Removal Heat ExchangersProcedure OP-201-1, RHR System Venting directs system venting by a series of static and dynamic venting evolutions. The inspectors noted that the procedure did not specify the minimum flowrates necessary to ensure an adequate dynamic flush of the HXs. Specifically, the inspectors identified that dynamic venting of the system is performed by establishing flow via both the RHR HXs and its bypass line, which reduces the effective flow available to dynamically vent the HXs. The licensee indicated that following the fill and vent procedure, operations performs a post maintenance test (per OST-253, Comprehensive Flow Test for the RHR Pumps ), before returning the system to service, that establishes full flow through the HXs and would completely vent the HXs if the initial fill and vent was not successful. The inspectors was concerned because establishing full flow through the HXs with a large enough void size inside the HXs could potentially result in a water hammer condition that exceeds the structural design limitations of the system. The licensee is performing an evaluation to determine if any voids could be left in the HXs after fill and vent, and what the potential effects on the system could be. The inspectors determined that this issue will remain unresolved pending additional inspection to evaluate the licensees evaluation. This issue will be identified as URI 05000261/2012005-04, Questions Regarding the Adequacy of the Fill and Vent Procedure for the Residual Heat Removal Heat Exchangers
05000261/FIN-2012005-022012Q4RobinsonFailure to Effectively Implement Gas Intrusion ProgramThe inspectors identified a Finding for the licensees failure to perform the 18- month pre-refueling outage (RO) ultrasonic testing (UT) examinations on 47 potential gas accumulation locations required by plant operating manual PLP-085, Emergency Core Cooling Systems Gas Management Program (GL 2008-01). Compliance with PLP-085 ensures the capability of the safety injection (SI), residual heat removal (RHR), and containment spray (CS) systems to perform their safety-related functions, and effectively implements the licensees gas management program as committed to the NRC in response to Generic Letter 2008-01. The licensee entered the issue into the corrective action program (CAP) as nuclear condition report (NCR) 575063, and is evaluating corrective actions. The failure to perform pre-RO UT examinations on 47 potential gas accumulation locations, as required by PLP-085 was a performance deficiency. The performance deficiency was more than minor because if left uncorrected, it had the potential to lead to a more significant safety concern. Specifically, if the licensee continued to miss pre-RO UT examinations, conditions that result in the formation of voids in the SI, RHR, and CS systems could go undetected with the potential to adversely affect the systems capability to perform their functions. The inspectors assessed the finding using IMC 0609 Attachment 4, Initial Characterization of Findings; and IMC 0609 Appendix A, The Significance Determination Process for Findings At-Power, and determined the finding was of very low safety significance (Green) because it was not a design deficiency, it did not represent the loss of a system safety function, did not result in exceeding a Technical Specification allowed outage time, and did not screen as potentially risk-significant due to a seismic, flooding, or severe weather initiating event. The inspectors identified a cross-cutting aspect in the work practices component of the human performance area, because the licensee did not define and effectively communicate expectations regarding procedural compliance and personnel following procedures. Specifically, on two occasions, the licensee did not perform pre-RO UTs in accordance with their gas management program, as described in PLP-085.
05000324/FIN-2012005-052012Q4BrunswickInadequate Maintenance Procedure for Fluorescent Lights over Safety-related EquipmentThe inspectors identified a Green finding for the licensee not having an adequate procedure for maintenance on fluorescent lights over safety-related equipment. Specifically, between plant startup and August 29, 2012, the licensee did not have instructions for closing S-hooks on fluorescent lights over safety-related equipment during maintenance on the fluorescent lights. This resulted in over 40 S-hooks open in safety-related buildings which could result in fluorescent lights falling and impacting safety-related equipment during a seismic event. The licensees corrective actions included closing the open S-hooks and adding instructions for closing S-hooks to work order (WO) 431558. The licensee entered this issue into the CAP as NCR 551646. The performance deficiency associated with this finding was the failure of the licensee to have an adequate procedure for maintenance on fluorescent lights over safety-related equipment. The finding was more than minor because if left uncorrected, the deficiencies could lead to a more significant safety concern. If left uncorrected, the failure to provide procedural guidance to close the S-hooks on fluorescent lights over safety-related equipment could lead to fluorescent lights falling on safety-related instruments during a seismic event resulting in a reactor trip. This finding is also associated with the design control attribute of the Initiating Events Systems Cornerstone. Using IMC 0609, Appendix A, issued June 19, 2012, The Significance Determination Process (SDP) for Findings At-Power, the inspectors determined the finding was of very low safety significance because the finding did not cause a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. The finding has a cross-cutting aspect in the area of problem identification and resolution associated with the CAP attribute because the licensee did not identify the open S-hook issue completely, accurately, and in a timely manner commensurate with their safety significance during the Fukushima walkdowns.
05000324/FIN-2012005-032012Q4BrunswickInadequate Maintenance Procedure for the EDG Jacket Water Pump Wear Ring TolerancesA self-revealing Green NCV of Technical Specification (TS) 5.4.1a, Procedures, was identified because the licensee did not have an adequate maintenance procedure to perform work on the emergency diesel generator (EDG) 3 engine-driven jacket water pump (JWP). Specifically, between July 25, 1992 and November 15, 2012, Procedure 0CM-ENG528, Gould Engine Driven Jacket Water Pump Model 3736, did not provide the correct tolerances for the EDG JWP wear rings, resulting in the JWP seizure. The licensees corrective actions included replacing the casing wear rings with wear rings with the correct tolerance and revising Procedure 0CM-ENG528. The licensee entered this issue into the corrective action program (CAP) as nuclear condition report (NCR) 572546. The performance deficiency associated with this finding was the failure of the licensee to have an adequate procedure for maintenance on the EDG 3 engine-driven JWP. The finding was more than minor because it was associated with the procedure quality attribute of the Mitigating Systems Cornerstone and affects the cornerstone objective of ensuring the availability and reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the inadequate procedure resulted in reduced availability of EDG 3 to repair the engine-driven JWP and reduced reliability of the jacket water system during operation. Using IMC 0609, Appendix A, issued June 19, 2012, The Significance Determination Process (SDP) for Findings At-Power, the inspectors determined the finding was of very low safety significance because the finding did not affect the design or qualification of a mitigating structure, system and component (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. Procedure 0CM-ENG528 included the incorrect tolerances since July 25, 1992.
05000324/FIN-2012005-022012Q4BrunswickEmergency Diesel Generator 3 Slow StartOn October 14, 2012, the licensee was running EDG 3 for a zero oil pressure start test in accordance with Procedure 0PT-12.2.c, No. 3 Diesel Generator Monthly Load Test. The EDG reached rated speed at approximately 38 seconds after the EDG was started and then tripped. Surveillance Requirement 3.8.1.7 requires the EDG reach rated conditions within 10 seconds. Several seconds after reaching rated speed, the EDG began to coast down due to receiving a lockout signal since full rated conditions were not achieved within the nominal time delay of 45 seconds. The licensee replaced the overspeed start emergency boost cylinder and declared the EDG operable on October 17, 2012. The inspectors are opening an URI to review the licensee\'s evaluation of the cause of the EDG failure and determine if there is a performance deficiency. The licensee entered this issue in the CAP as NCR 567016. This issue is being tracked as a URI: URI 05000325/2012005-02 and 05000324/2012005-02, Emergency Diesel Generator 3 Slow Start.
05000324/FIN-2012005-062012Q4BrunswickFire Related Unanalyzed Condition that could Impact Equipment Credited in Safe Shutdown AnalysisTitle 10 of the Code of Federal Regulations, 50.48(b)(1) requires, in part, that all nuclear power plants licensed to operate prior to January 1, 1979, must satisfy the applicable requirements of Appendix R, Section III.G. Appendix R, Section III.G.3 states, in part, that alternative or dedicated shutdown capability be provided where the protection of systems whose function is required for hot shutdown does not satisfy the requirement of 10 CFR 50, Appendix R, Section III.G.2. Contrary to the above, from original plant startup to October 13, 2011, the licensee failed to provide an alternative or dedicated shutdown capability when the requirements of 10 CFR 50, Appendix R, Section III.G.2 were not met. Specifically, the licensees alternative/dedicated post-fire SSD strategy for five FAs failed to ensure alternative shutdown capability because the licensee had not considered the possibility of certain fire-induced spurious actuations of critical components that would potentially result in the loss of equipment required for safe shutdown. Because the licensee committed to adopt NFPA 805 and change their fire protection licensing bases to comply with 10 CFR 50.48(c), and this commitment was documented prior to December 31, 2005, the NRC is exercising enforcement and reactor oversight process discretion for this issue in accordance with the NRC Enforcement Policy, Section 9.1, Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48) and Inspection Manual Chapter 0305. This issue was identified and addressed during the licensees transition to NFPA 805, it was entered into the licensees CAP as NCR 493784, immediate corrective action and compensatory measures were taken, it was not likely to have been previously identified by routine licensee efforts, it was not willful, and it was not associated with a finding of high safety significance.
05000400/FIN-2012005-012012Q4HarrisFailure of the Primary Shield Supply Fan (S-2B-SB) to Remain Secure when StoppedDuring monthly equipment swapping on October 26, 2012, the licensee attempted to secure the S-2B-SB from the main control board. The fan stopped when the switch was turned to the OFF position, but automatically restarted when the switch was released without a valid start signal. The inspectors identified that the failure of the S-2B-SB to remain stopped when secured from the main control board adversely affected compliance with TS Surveillance Requirements (SR) 4.8.1.1.2 F.4 which verifies operability of the B EDG, B Electrical bus and B sequencer. Additional inspection activities are needed to determine the extent of condition, relative to SR compliance, and if a performance deficiency exists. Pending the results of this additional inspection, an URI will be opened and designated as URI 05000400/2012005- 01, Failure of the Primary Shield Supply Fan (S-2B-SB) to Remain Secure when Stopped.
05000261/FIN-2012004-012012Q3RobinsonFailure to Include the Fuel Oil Supply to the Tsc/Eof/Security Diesel in the Maintenance RuleThe inspectors identified a Green non-cited violation (NCV) of 10 CFR 50.65(b)(2), Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, because the licensee failed to include all aspects of the Fuel Oil System in the maintenance rule program. Specifically, the fuel oil supply to the Technical Support Center (TSC) Emergency Operations Facility (EOF) Security Diesel is required to support the diesels emergency operating procedure (EOP) function of providing backup power to security lighting and the plant computer system. The licensee entered the issue into their corrective action program (CAP) as Nuclear Condition Report (NCR) 560424. The licensee corrective actions included revising the scoping document of the fuel oil system to include its function of providing fuel to the diesel. The failure to scope in the fuel oil system function of providing fuel to the TSC/EOF/Security Diesel to the maintenance rule program was a performance deficiency. The finding was more than minor because it impacted the equipment performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to scope in the fuel oil supply to the maintenance rule could affect the TSC/EOF/Security reliability and the accomplishment of EOPs. This finding was considered to have very low safety significance (Green) because the finding did not cause a loss of mitigation equipment functions and 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 more than 24 hours. This finding had a cross cutting aspect in the Corrective Action Program component of the Problem Identification and Resolution area, because the licensee failed to perform a thorough evaluation, such that the necessary support systems for the TSC/EOF/Security diesel were identified and added to the maintenance rule program.
05000261/FIN-2012004-022012Q3RobinsonLicensee-Identified ViolationThe following finding of very low significance was identified by the licensee and is a violation of NRC requirements, and, consistent with the NRC Enforcement Policy, is being dispositioned as an NCV. 10 CFR 50.63 Loss of All Alternating Current Power, requires in part that station batteries and other necessary support systems must provide sufficient capacity and capability to ensure the core is cooled and appropriate containment integrity is maintained in the event of a station blackout. Contrary to the above, on August 28, 2012 during PM-452, Dedicated Shutdown UPS Battery Test, the dedicated shutdown uninterruptible power supply (DS-UPS) batteries failed to meet the acceptance criteria. The licensee documented this condition in NCR 557582 and NCR 558425. The results of previous test indicated a negative trend in battery performance and that the battery should have been replaced before failure. The licensee initiated actions to replace the DS-UPS batteries. The inspectors evaluated this finding using NRC Inspection Manual Chapter 0609 Appendix F, Fire Protection Significance Determination. The finding was screened as having very low safety significance (Green) because the assigned fire degradation rating was low. In addition, based upon licensee procedures and operator actions, it is reasonable to conclude that the dedicated shutdown diesel generator would have been started and available to provide power to the required safe shutdown equipment prior to the battery falling below minimum voltage
05000400/FIN-2012004-022012Q3HarrisB Startup Transformer Lockout Due to Loss of Oil Filled Cable PressureA self-revealing Green NCV of Technical Specification (TS) 6.8.1, Procedures, was identified for the licensees failure to develop an adequate procedure for maintenance on an oil filled cable. Specifically, the licensee failed to provide adequate instructions to prevent causing additional damage to the cable which resulted in the lockout of the B Startup Transformer (SUT) on June 25, 2012. This also resulted in unavailability of the preferred power source for the B safety related equipment for over two days. As corrective actions, the licensee repaired the cable, restored oil pressure and returned the B SUT to its normal standby configuration. Additionally, the licensee performed an investigation which concluded that the cable had been damaged at the site of a previous repair when it was handled during maintenance. The issue was placed into the CAP as AR #545920. The licensees failure to develop an adequate procedure to ensure proper handling of the cable and prevent inadvertently causing damage was a performance deficiency. The performance deficiency was more than minor because it was associated with the Procedure Quality attribute of the Mitigating Systems cornerstone, and it affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, it resulted in the lockout of the B SUT and unavailability of the preferred power source for the B safety related equipment for over two days. Using IMC 0609, Significance Determination Process, this finding was determined to be of very low safety significance because it was not a design or qualification deficiency, did not represent an actual loss of function of at least a single train for greater than the TS AOT or two separate safety systems out-of-service for greater than the AOT, did not result in a loss of safety function of one or more non-TS trains of equipment designated as risk significant for greater than 24 hours, and did not involve the loss or degradation of equipment or function specifically designed to mitigate a seismic, flooding, or severe weather initiating event (e.g., seismic snubbers, flooding barriers, tornado doors). The finding had a crosscutting aspect of complete, accurate and up-to-date procedures, as described in the Resources component of the Human Performance cross-cutting area, because the licensee did not develop adequate procedures to prevent further damage while performing maintenance on the SUT cables
05000324/FIN-2012004-032012Q3BrunswickEDG2 Wiring on ASSD SwitchA wiring discrepancy was identified during inspection of the EDG 2 ASSD switch 2-DG-SS-A1. A contact in the circuit was determined to be bypassed that would have the potential to prevent proper isolation of the EDG2 control circuits from the Main Control Room (MCR) during an Appendix R fire event. The inspectors plan to review the licensees cause evaluation for this event and determine if a performance deficiency existed. This issue is being tracked as URI 05000325; 324/2012004-03, EDG2 wiring on ASSD switch.
05000324/FIN-2012004-012012Q3BrunswickFailure to Maintain Secondary Containment Operable During an OPDRV ActivityThe inspectors identified a Green non-cited violation (NCV) of TS 3.6.4.1, Secondary Containment because the licensee did not maintain secondary containment operable as required during a maintenance activity considered an operation with a potential for draining the reactor vessel (OPDRV). Once questioned by the inspectors, the licensee restored secondary containment, developed an Operation standing instruction (12-052) to treat the activity as an OPDRV and placed this issue into its corrective action program (CAP) as AR 562188. The failure to maintain secondary containment operable while Unit 1 was in Mode 4 with an OPDRV in progress 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 adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers (fuel cladding, reactor coolant system, and containment) protect the public from radionuclide releases caused by accidents or events because the Unit 1 secondary containment boundary was not preserved or maintained. The inspectors evaluated the finding using Inspection Manual Chapter (IMC) 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, which required an analysis using IMC 0609 Appendix G since the reactor was in Mode 4 (cold shutdown). The finding was determined to be of very low safety significance (Green) according to IMC 0609 Appendix G, Attachment 1, Checklist 6, since a quantitative assessment (Phase 2 or Phase 3 evaluation) was not required. Specifically, the inspectors determined that the licensee maintained adequate mitigation capability for reactor vessel water level inventory and an event did not occur that could be characterized as a loss of control. The cause of this finding was directly related to the cross-cutting aspect of Accurate Procedures in the Resources component of the Human Performance area, because the licensee did not consider the recirculation pump seal replacement activity to be OPDRV based on procedural guidance that contains exclusions to what are considered OPDRV activities.
05000324/FIN-2012004-022012Q3BrunswickFailure to Maintain Secondary Containment Operable During an OPDRV ActivityA self-revealing Green NCV of 10 CFR 50.54(q)(2) was identified for the licensees failure to properly evaluate or consider the impact to emergency response facilities of design change ESR98-00436 which was implemented in 1999. This resulted in the loss of Emergency Response Facility Information System (ERFIS), Emergency Response Data System (ERDS), Safety Parameter Display System (SPDS), and all displays including radiation monitors for the emergency response facilities. Specifically, the licensee failed to ensure that adequate emergency response facilities and equipment were available as required by the Brunswick Nuclear Plant Radiological Emergency Plan, Section 1.3.1.3 revision 80 and 10 CFR 50.47(b)(8). This issue was captured in the licensees CAP as AR 542704. The licensees failure to properly evaluate or consider the impact to emergency response facilities of design change ESR98-00436 which was implemented in 1999 was a performance deficiency. Specifically, the licensee introduced a single point failure mode which did not meet the design requirements specified in their Design Basis Document (DBD 60) sections 3.6.7.2 and 3.6.7.3. This resulted in the licensees failure to ensure that adequate emergency response facilities and equipment were available as delineated in the Updated Final Safety Analysis Report (UFSAR) Section 7.7.1.9, and required by the Brunswick Nuclear Plant Radiological Emergency Plan, Section 1.3.1.3, revision 80, and 10 CFR 50.47(b)(8). The finding was more than minor because it adversely affected the Emergency Preparedness Cornerstone objective of ensuring that the licensee was capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. Specifically, the Facilities and Equipment attribute was affected during the time when the ERFIS, ERDS, SPDS, and all displays including radiation monitors for the emergency response facilities were degraded, and as a result did not meet 10 CFR 50.47(b)(8) Planning Standard program element, adequate emergency facilities and equipment to support the emergency response are provided and maintained. The finding was assessed for significance in accordance with NRC IMC 0609, Appendix B Emergency Preparedness Significance Determination Process. Attachment 2 of Appendix B, Failure to Comply Significance Logic is as follows: Failure to comply; Loss of Risk Significant Planning Standard Function (RSPS), No; RSPS Degraded Function, No; Loss of Planning Standard Function, No; the result is a Green finding. The inspectors determined that this resulted in a very low safety significance finding (Green). No cross-cutting aspect was assigned to this finding because the performance deficiency occurred more than three years ago and is not reflective of current plant performance.
05000324/FIN-2012004-042012Q3BrunswickLicensee-Identified ViolationA wiring discrepancy was identified during inspection of the EDG 2 ASSD switch 2-DG-SS-A1. A contact in the circuit was determined to be bypassed that would have the potential to prevent proper isolation of the EDG2 control circuits from the Main Control Room (MCR) during an Appendix R fire event. The inspectors plan to review the licensees cause evaluation for this event and determine if a performance deficiency existed. This issue is being tracked as URI 05000325; 324/2012004-03, EDG2 wiring on ASSD switch.
05000400/FIN-2012004-012012Q3HarrisFailure to Adequately Perform Containment Visual Inspection When Containment Integrity is RequiredThe inspectors identified a Green NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, when the licensee failed to adequately correct a previously identified issue associated with the performance of OST-1081, Containment Visual Inspection when Containment Integrity is Required. Specifically, on June 3, 2012 during an independent containment closeout inspection by the NRC resident inspectors, cables were identified as not having been analyzed for the impact on the operation of the containment sumps. The licensee did not identify or reconcile the unanalyzed cables in containment during the performance of OST-1081. The licensee removed a large portion of the cabling and then completed an operability evaluation, while in mode 3, on June 6, 2012 for the cables that remained. The evaluation concluded that the containment sump was fully operable, but with reduced margin because of the cables. The cables were further analyzed and recorded in Engineering Change 87249, with a similar conclusion. The issue was placed into the corrective action program (CAP) as action request (AR) #566201. The licensees failure to adequately identify and take prompt corrective actions to evaluate temporary cables in containment during OST-1081, which had not been previously analyzed was identified as a performance deficiency. The performance deficiency was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone and it adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, it could potentially cause one or more Residual Heat Removal (RHR), Containment Spray (CT) pumps, and associated Emergency Core Cooling Systems (ECCS) trains to be inoperable in the event that the containment sump became clogged and lost the required Net Positive Suction Head (NPSH) to the pump, during certain accidents. Using IMC 0609, Significance Determination Process, this finding was determined to be of very low safety significance because it was not a design or qualification deficiency, did not represent an actual loss of function of at least a single train for greater than the Allowed Out-of-service Time (AOT) or two separate safety systems out-of-service for greater than the AOT, did not result in a loss of safety function of one or more non-Technical Specification (TS) trains of equipment designated as risk significant for greater than 24 hours, and did not involve the loss or degradation of equipment or function specifically designed to mitigate a seismic, flooding, or severe weather initiating event (e.g., seismic snubbers, flooding barriers, tornado doors). The finding had a cross-cutting aspect of Evaluation of Identified Problems, as described in the Corrective Action component of the Problem Identification and Resolution cross-cutting area, because the licensee did not implement adequate corrective actions to prevent recurrence of unanalyzed material left in containment following the performance of OST-1081
05000324/FIN-2012004-052012Q3BrunswickLicensee-Identified Violation10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. Licensee procedure ADM-NGGC-0107, Equipment Reliability Process Guideline, steps 9.4.9 and 9.4.10 required component experts and preventive maintenance (PM) optimization to determine if there was a cost effective PM to prevent failure and then to develop the PM model. Contrary to the above, the Unit 1 high pressure coolant injection (HPCI) ramp generator signal converter (RGSC) did not have the appropriate preventive maintenance to prevent failure. As a result, the Unit 1 high pressure coolant injection (HPCI) system failed the HPCI System Operability Test performed on April 30, 2012 and was declared inoperable. The licensee entered this issue into the CAP as NCR 534364. Corrective actions included replacing the RGSC and creating a PM task to replace the RGSCs on a specified frequency. Using IMC 0609, Appendix A, Phase 1 Initial Screening and Characterization of Findings, the inspectors determined this finding required a Phase 2 analysis. The Phase 1 screened this Mitigating Systems Cornerstone finding to Phase 2 because the finding represented a loss of HPCI system and/or function. The inspectors, with the assistance of the regional Senior Risk Analyst, performed a Phase 2 analysis using the Saphire 8 Model. 109 hours of unavailability time was used for the analysis since HPCI was not required during the refueling outage from February 23, 2012 through April 29, 2012. Based on the results of the Phase 2 analysis, the inspectors determined the finding was of very low safety significance
05000324/FIN-2012007-012012Q2BrunswickFailure to Properly Assemble Reactor Vessel Head Following Maintenance OutageA self-revealing (Green) non-cited violation (NCV) of 10 CFR 50, Appendix B Criterion V, Instructions, Procedures, and Drawings was identified for failure to properly implement plant procedures for reactor pressure vessel (RPV) reassembly following the Unit 2 maintenance outage in November 2011. This resulted in excessive leakage from the Unit 2 RPV during reactor startup and pressurization on November 15 and November 16, 2011, and the declaration of an Unusual Event for reactor coolant system (RCS) unidentified leakage in excess of 10 gallons per minute on November 16, 2011. The unit was shut down and depressurized on November 16, 2011, and the issue entered into the licensees CAP as NCR 500035. The licensees failure to correctly implement procedure 0SMP-RPV502, Reactor Vessel Reassembly, to ensure that the RPV head was properly reassembled following the November 2011 Unit 2 maintenance outage was a performance deficiency. The finding was more than minor because it was associated with the Initiating Events cornerstone attribute of equipment performance (the reliability of the RCS barrier integrity) and adversely affected the cornerstone objective of limiting the likelihood of events that upset plant stability and challenge critical safety functions during shutdown or power operations. Specifically, the failure to adequately implement this procedure resulted in excessive leakage from the Unit 2 RPV during reactor startup and pressurization. Inspection Manual Chapter 0609, Significance Determination Process (SDP), Attachment 0609.04, Phase 1 Screening Worksheet was used to screen the significance of the finding. The finding required a Phase 2 SDP analysis because it resulted in unidentified RCS leakage exceeding technical specification limits. Evaluation of the finding using the NRC pre-solved SDP table was not appropriate because the table does not contain a suitable target for RPV vessel integrity. Therefore, a Phase 3 SDP analysis was required. A Phase 3 analysis was performed by the regional Senior Reactor Analyst. Since the finding resulted in a shutdown, the SDP was analyzed as an additional transient that had a small potential to result in a Small Loss of Coolant Accident (SLOCA). The actual leak rate was low enough to not be considered to be a SLOCA, but there was potential for larger leakage. The Phase 2 SDP process uses an order of magnitude increase in the initiating event frequency for issues with the potential to increase the frequency of a particular event. This philosophy was used in the Phase 3 SDP process to allow a risk-informed input to the SDP for the SLOCA potential for this finding, due to the difficulty in calculating an exact percentage of time that the condition of the head closure would result in a larger leak. This resulted in an analysis that assumed a transient occurred that would result in a SLOCA about 1 percent of the time. This result represents an upper bound for the finding. The results were a risk in the low E-7 range, and the finding is GREEN. The SLOCA contribution was less than E-7. Dominant sequences involved loss of secondary side cooling and makeup, with either loss of containment heat removal, or loss of high pressure injection and failure to depressurize the reactor to allow the use of the low pressure systems. Because of Brunswicks concrete lined torus, and the low contribution of the high pressure sequences, the Large Early Release Frequency did not result in an increase in the significance. The cause of this finding was directly related to the cross-cutting aspect of supervisory and management oversight in the Work Practices component of the Human Performance area because oversight of the RPV reassembly was inadequate to insure that workers were able to accurately execute the steps of procedure 0SMP-RPV502, Reactor Vessel Reassembly.
05000261/FIN-2012003-022012Q2RobinsonLack of Preventive Maintenance on Feedwater Control Switch Results in an Automatic Reactor TripA self-revealing Green finding was identified when the licensee failed to establish adequate preventative maintenance for equipment associated with the feedwater control systems. Specifically, the licensees inappropriate classification of the feedwater flow loop selector switch as a run-to-failure component permitted the switch to remain in service, without preventative maintenance, until its failure on March 28, 2012, which resulted in a feedwater transient and reactor trip. Corrective actions included the replacement of the failed switch and future replacement of seven additional switches that were deemed to be at risk for a similar failure. This issue has been entered into the corrective action program (CAP) as Nuclear Condition Report (NCR) #527203. The licensees inappropriate classification of plant equipment in accordance with ADMNGGC- 0107 Rev. 1, Equipment Reliability Process Guideline, which permitted feed flow selector switch 1/FM-488B to remain in service, without preventative maintenance, until failure was a performance deficiency. This finding was determined not to be a violation of NRC requirements. The finding was more than minor because it was associated with the initiating events cornerstone attribute of Equipment Performance, and it affected the associated cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the performance deficiency caused an automatic reactor trip from 55 percent power operations on March 28, 2012. The finding was determined to be of very low safety significance (Green) because the finding did not contribute to both the likelihood of a reactor trip and the likelihood that mitigating equipment or functions would not be available. The performance deficiency had a cross-cutting aspect of Evaluation of Identified Problems in the area of Problem Identification and Resolution, because the licensee failed to thoroughly evaluate the events in 2010 and 2008 such that the resolutions addressed the causes and extent of conditions as necessary.
05000261/FIN-2012003-032012Q2RobinsonInoperability of the Refueling Water Storage Tank Not Recognized as a Safety System Functional FailureThe inspectors identified a Green finding for the licensees failure to identify and document Safety System Functional Failures (SSFF) in accordance with REG-NGGC- 0009, NRC Performance Indicators and Monthly Operating Report Data. The licensee did not recognize that rendering the refueling water storage tank inoperable by placing the non-seismically qualified purification system in operation as documented in LER 05000261/2011-001-00, Condition Prohibited by Technical Specifications When Non- Seismic System was Aligned to Refueling Water Storage Tank due to Regulatory Requirements not Adequately Incorporated in Plant Documentation also created a SSFF. The licensee entered the issue into the CAP as NCR 539132. Corrective actions are still being evaluated. The inspectors determined that the licensees failure to identify and document a SSFF was a performance deficiency. Specifically, Attachment 7 of REG-NGGC-009, NRC Performance Indicators and Monthly Operating Report Data, Rev. 11 requires documenting SSFFs. The finding was determined to be more than minor because the minor screening question of whether the performance deficiency would have caused the SSFF PI to exceed a threshold was determined to have occurred. Specifically, had the licensee recognized the SSFFs and documented them during the investigation of LER 05000261/2001-001-00, the SSFF PI would have crossed the green/white threshold in the 4th quarter of 2010. The finding screened as Green because no loss of operability or functionality resulted from the failure to recognize the SSFF and document the event as described in LER 05000261/2011-001-00. The inspectors determined this performance deficiency had a cross-cutting aspect in the Corrective Action Program component of the Problem Identification and Resolution Area, because the licensee did not thoroughly evaluate the condition described in LER 05000261/2011-001-00, to include conditions such as a SSFF.
05000261/FIN-2012003-012012Q2RobinsonAdequacy of PRE-PLANNED Mitigating Actions in Response to Declaring the Control Room Envelope InoperableAn URI is being opened to provide for additional inspection in response to the actions performed by the licensee after declaring the control room envelope (CRE) inoperable due to not performing an adequate surveillance to demonstrate the integrity of the CRE. The inspectors noted on June 12, 2012, that in response to declaring the CRE inoperable on June 6, 2012, the licensee was required to verify mitigating actions to ensure CRE occupancy for design basis conditions in accordance with Technical Specification (TS) 3.7.9 Action G.2 was completed within 24 hours. Those actions are described in PLP-019, Control Room Envelope Habitability Program. An aspect of the mitigating actions included having self-contained breathing apparatus (SCBA) available for the control room occupants. The licensee verified five SCBAs were available in the control room for use by normal shift complement of licensed operators and shift technical advisor. The inspectors questioned whether the emergency communicator should have an SCBA. The licensee responded by adding a sixth SCBA on June 12, 2012. Additional inspection is required to determine if the emergency communicator is required to have an SCBA staged in the control room to support response to design basis conditions.
05000400/FIN-2012007-022012Q2HarrisFailure to Notify the NRC of the EOF Loss of Emergency Assessment CapabilityThe inspectors identified an AV of 10 CFR Part 50.72(b)(3)(xiii), for the failure to report the loss of emergency assessment capability in the EOF. Specifically, the EOF was unavailable to perform its intended function for periods greater than seven days on several occasions from August 2009 to November 2011. This issue was entered into the licensees CAP as NCR 492707. The failure to report the loss of emergency assessment capability in the EOF as required by 10 CFR Part 50.72(b)(3)(xiii) was a performance deficiency. The finding was more than minor because it impacted the regulatory process which depends on plant activities being properly reported. The inspectors evaluated this finding against NRC IMC 0609 Appendix B, Emergency Preparedness Significance Determination Process Section 7.3. The inspectors determined that traditional enforcement is applicable. The licensee failed to report an occurrence of a major loss of emergency assessment capability. Specifically, the licensee failed to maintain a fully functional EOF when portions of the ventilation system were removed from service without compensatory measures, and the licensee failed to report the occurrence as required. 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. In this case, and as discussed above, the NRC concluded that the failure to provide the required report is associated with a preliminarily White finding for the failure to maintain a fully functional EOF. In addition, the licensees failure to report the condition of the EOF from August 2009 to November 2011, as required by 10 CFR 50.72, impeded the NRCs regulatory process. Had the licensee reported the incident as required, NRC review and follow-up inspection likely would have occurred, which may have prompted the licensee to adopt compensatory measures and/or corrective actions, thereby precluding the incidents that followed after August 4, 2009. Based on the above, the NRC determined the severity level of this apparent violation is preliminarily Severity Level III in accordance with the NRC Enforcement Policy.
05000261/FIN-2012003-042012Q2RobinsonInaccurate Safety System Functional Failure Performance Indicator SubmittalThe inspectors identified a Severity Level (SL) IV NCV of 10 CFR 50.9(a), Completeness and Accuracy of Information, when the licensee inaccurately reported Safety System Functional Failure (SSFF) performance indicator data beginning with the 4th quarter of 2010. The licensee entered the issue into the CAP as NCR 539132. Corrective actions are still being evaluated. The inspectors determined the licensees failure to identify and document a SSFF was a performance deficiency. Specifically, Attachment 7 of REG-NGGC-009, NRC Performance Indicators and Monthly Operating Report Data, Rev. 11 requires documenting SSFFs for inclusion in the NRC performance indicator (PI) submittal. This resulted in a failure to submit complete and accurate PI data resulting from the investigation of LER 05000261/2011-001-00, Condition Prohibited by Technical Specifications When Non-Seismic System was Aligned to Refueling Water Storage Tank due to Regulatory Requirements . Due to the inadequate review of LER 05000261/2011-001-00, the licensee submitted inaccurate data for the SSFF PI beginning in the 4th quarter of 2010. If accurate data had been provided the SSFF PI would have transitioned from green to white in the 4th quarter of 2010. The finding was more than minor because it impacted the ability of the NRC to perform its regulatory oversight function. The finding was determined to be a SL IV violation using the examples in the Enforcement Policy, where a licensee submits inaccurate or incomplete PI data to the NRC that would have caused a PI to change from green to white. No cross-cutting aspect was assign due to traditional enforcement violations are not screened for cross-cutting aspects.
05000400/FIN-2012008-012012Q2HarrisB AND C MSIVs FAIL TO CLOSE DURING SURVEILLANCE TESTINGThe inspectors identified an URI associated with issues in the licensees MSIV maintenance and testing. These issues were potential contributing causes to the April 21, 2012, B and C MSIV failure to stroke close. Description: Several issues were identified regarding the licensees MSIV maintenance and testing. Some of the issues identified were: FnIn the last two refueling intervals, maintenance was making minor adjustments to the actuator hydraulic speed control system to decrease the time needed to shut the valves as a result of increasing stroke test closure time results. FnBeginning in 2001, work deficiency documents were initiated due to the MSIVs experiencing difficulty in opening during refueling outage cycling. There had not been any corrective maintenance conducted requiring valve internal disassembly and the licensee had not developed any periodic PMs to visually inspect the condition of valve internals. FnThe valve vendor manual recommended weekly valve partial exercising ten percent of its total stroke in order to assure that the actuator and valve was properly functioning. Prior to 2000, this partial exercising was being performed quarterly. In 2000, the licensee revised their IST program requirements to discontinue quarterly exercising in lieu of the 18-month cold shutdown TS stroke testing that was currently being conducted. FnPrior to the current MSIV failures; the MSIVs had never been tested as part of the licensees AOV program. Summary: The licensees root cause investigation was not completed at the conclusion of the special inspection; the determination as to whether these issues represented performance deficiencies was not completed. Pending completion of the licensees root cause evaluation (RCE) and subsequent NRC review to determine if a performance deficiency exists, disposition of these issues will be tracked via Unresolved Item (URI) 05000400/2012008-01, B and C MSIVs Fail to Close During Surveillance Testing.
05000324/FIN-2012007-032012Q2BrunswickFailure to Perform Adequate Training for Reactor Vessel ReassemblyNRC inspectors identified a Green non-cited violation (NCV) of 10 CFR 50, Appendix B Criterion V, Instructions, Procedures, and Drawings for failure to properly implement plant procedure TRN-NGGC-1000, Conduct of Training for training and qualifications of the reactor pressure vessel (RPV) reassembly team prior to RPV reassembly during the Unit 2 maintenance outage in November 2011. This resulted in inadequate worker knowledge of the tools and procedures associated with RPV reassembly, which contributed to the RPV head studs being inadequately tensioned and excessive leakage from the Unit 2 RPV during reactor startup and pressurization on November 15 and November 16, 2011. The unit was shut down and depressurized on November 16, 2011, and the issue entered into the licensees CAP as NCR 500035. The licensees failure to comply with procedure TRN-NGGC-1000, Conduct of Training, to ensure that the maintenance team performing the RPV reassembly after the November 2011 Unit 2 maintenance outage received adequate training was a performance deficiency. The finding was more than minor because it was associated with the Initiating Events cornerstone attribute of human performance and adversely affected the cornerstone objective of limiting the likelihood of events that upset plant stability and challenge critical safety functions during shutdown or power operations. Specifically, the failure to adequately implement procedure TRN-NGGC-1000 contributed to the failure to adequately tension the RPV head studs during the Unit 2 November, 2011 maintenance outage, which resulted in excessive leakage from the Unit 2 RPV during reactor startup and pressurization. Inspection Manual Chapter 0609, Significance Determination Process (SDP), Attachment 0609.04, Phase 1 Screening Worksheet was used to screen the significance of the finding. The finding required a Phase 2 SDP analysis because it resulted in unidentified RCS leakage exceeding technical specification limits. Evaluation of the finding using the NRC pre-solved SDP table was not appropriate because the table does not contain a suitable target for RPV vessel integrity. Therefore, a Phase 3 SDP analysis was required. The regional Senior Reactor Analyst determined that adequate training of the RPV assembly team would have had the potential to mitigate the failure to adequately torque the RPV head studs, which was analyzed to be a Green finding (see NCV 05000324/2012007-01 above). Since the impact of the mitigation would be less than the impact of the underlying finding, this finding is also Green. The cause of this finding was directly related to the cross-cutting aspect of training in the Resources component of the Human Performance area because the licensee failed to provide sufficiently trained personnel to reassemble the RPV.
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