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| Q | Significance | CCA | Identified by | Title | Description | |
|---|---|---|---|---|---|---|
| 05000250/FIN-2018003-01 | 2018Q3 | NRC identified | Vital Inverter Alternate AC Supply Cables Were Not Included in the Nuclear Safety Capability Assessment | On 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. | ||
| 05000251/FIN-2018003-02 | 2018Q3 | Green | Self-revealing | Inoperable Auxiliary Feedwater Steam Supply Flow Path | A 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. | |
| 05000250/FIN-2018002-01 | 2018Q2 | NRC identified | Unit 3 Emergency Diesel Generator (EDG) Operability during Fuel Oil Transfer to Unit 4 Fuel Oil Storage Tanks | From 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-2018001-02 | 2018Q1 | Green | Self-revealing | Failure of radiation workers to notify Radiation Protection upon a spill of radioactively contaminated water | A 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-2018001-01 | 2018Q1 | Green | NRC identified | Failure to conduct post maintenance testing in accordance with ASME OM code | A 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. | |
| 05000251/FIN-2017004-01 | 2017Q4 | Green | H.8 | NRC identified | Failure to Perform an Adequate ASME BPVC Section XI Repair/Replacement Plan for a Code Class 1 and 2 Replacement | A NRC-identified NCV of 10 CFR 50.55a, Codes and Standards, was identified for the failure to adequately perform a Boiler and Pressure Vessel Code (BPVC) class 1 and 2 replacement activity in accordance with the Turkey Point Plant American Society of Mechanical Engineers (ASME) Section XI Repair/Replacement Program. Specifically, the licensee did not ensure a system leakage test conducted on October 19, 2017, was appropriately evaluated to meet the requirements of ASME Section XI for pre-service leakage testing of a Unit 4 high head safety injection (HHSI) cold leg injection check valve that was replaced on October 15, 2017. This issue was entered into the licensees Corrective Action Program (CAP) as ARs 2235484 and 2239149. Corrective actions included documenting a formal bases for current operability via a prompt operability determination and updating work order (WO) documentation to fully comply with ASME BPVC Section XI requirements. This performance deficiency was determined to be more than minor because an inadequate inservice inspection repair/replacement plan adversely affected the Reactor Coolant System (RCS) Equipment and Barrier Performance attribute of the Barrier Integrity 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. In accordance with IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, the inspectors determined that the issue had very low safety significance because there was no actual degradation of the RCS boundary. This finding was assigned a cross-cutting aspect in the Procedure Adherence component of the Human Performance cross-cutting area, in that the licensee did not effectively evaluate and appropriately implement the ASME BPVC requirements in the 4-873A Repair/Replacement Plan which were reiterated in licensee administrative procedure 0-ADM-532, ASME Section XI Repair/Replacement Program (H.8). |
| 05000251/FIN-2017004-03 | 2017Q4 | Green | Self-revealing | Inadequate Installation of Outdoor Use Electrical Enclosures Results in Manual Reactor Trip | A self-revealing finding (FIN) was identified for failure to ensure the 4B and 4C main feedwater regulating valve (MFRV) control circuits remained free from the effects of water intrusion or condensation in electrical enclosures. Specifically, a hand selector switch (HSS) enclosure for the 4C MFRV redundant positioners was flooded during wind-driven rain and resulted in the 4C MFRV failing closed, lowering 4C steam generator water level, and a subsequent Unit 4 manual reactor trip initiated by control room operators.Engineering Change (EC) 246879 appropriately selected NEMA-4X rated enclosures for the HSSs but associated SPEC-C-065 did not provide critical configuration details for the enclosure installations. Water collected in the 4B and 4C MFRV positioner HSS enclosures because the penetrations were on top of the enclosures and not properly sealed and the bottom of the enclosure did not have a weep hole.This performance deficiency was determined to be more than minor because it was associated with the design control attribute of the Initiating Events Cornerstone and adversely affected the cornerstones objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown, as well as power operations, because the failure resulted in lowering steam generator water levels and caused control room operators to complete a fast load reduction and manually trip the reactor. In accordance with NRC IMC 0609, Appendix A, The Significance Determination Process for Findings at Power, the inspectors determined that the issue had very low safety significance because it only caused a reactor trip and did not cause the loss of mitigating equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. Since EC 246879 and associated work orders were completed in 2013, the inspectors determined the finding was not indicative of current licensee performance and was not assigned a cross-cutting aspect. | |
| 05000251/FIN-2017004-02 | 2017Q4 | Green | P.1 | NRC identified | Failure to Identify and Correct a Deficient CCW Penetration Seal Configuration that Exacerbates External Piping Corrosion Conditions | A NRC-identified NCV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, was identified for the licensees failure to promptly identify and correct an adverse condition to quality that led to continued corrosion and significant scaling and pitting of the Unit 4 component cooling water (CCW) 18-inch headers at the penetration seals from the CCW heat exchanger room to the 10-foot pipeway. This issue was entered into the licensees CAP as ARs 2217942, 2227877, 2211843, 2236687, and 2239632. Corrective actions included removing protective boots that were inappropriately installed and not in accordance with design drawings and work order instructions, and were collecting hypersaline water that wetted carbon steel piping.The performance deficiency was determined to be more than minor because it was associated with the design control attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the reliability of systems that respond to initiating events to prevent undesirable consequences because corrosion and pipe wastage was ongoing and unmonitored for the Unit 4 CCW headers. In accordance with IMC 0609 Appendix A, The Significance Determination Process for Findings At-Power, the inspectors determined the finding to be of very low safety significance because it did not represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant in accordance with the licensees maintenance rule program for greater than 24 hours. The finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Identification, because the licensee failed to identify the adverse condition that allowed corrosion to continue unmonitored (P.1). |
| 05000250/FIN-2017007-06 | 2017Q3 | Green | NRC identified | Failure to Verify the Adequacy of Design for the ECC and CCW Systems | The NRC identified a non-cited violation of Title 10 Code of Federal Regulations Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to verify the Emergency Containment Cooler (ECC) unit 4A auto start circuitry would not result in exceeding the thermal limits of the CCW system during a design basis accident. Specifically, the licensee failed to verify that a single active failure of the motor starter auxiliary contacts would not result in exceeding the design basis limits for CCW as described in updated final safety analysis report (UFSAR) Section 9.3. For immediate corrective actions, the licensee entered the issue into their corrective action program as AR 2219505, performed a prompt determination of operability, and determined that the CCW system remained operable. The performance deficiency was determined to be more than minor because it was associated with the design control attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, three ECC fans running during a during a design basis accident would result in exceeding the design basis temperature of 158.6 F for the 5 CCW supply and a significant reduction in margin for the SI pump lube oil cooler. The team determined the finding to be of very low safety significance because the finding was a deficiency affecting the design of a mitigating structure, system, or component (SSC) and the SSC maintained its operability. This finding was not assigned a cross- cutting aspect because the issue did not reflect current licensee performance. | |
| 05000250/FIN-2017003-01 | 2017Q3 | Green | P.1 | NRC identified | Failure to Identify and Correct CCW Pipe Corrosion | An NRC-identified NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, was identified for the licensees failure to promptly identify and correct component cooling water (CCW) external pipe corrosion that led to a through-wall flaw and leak on the Unit 3 CCW surge tank makeup line. FPL performed an immediate operability screening and determined the condition was operable but degraded considering previous prompt operability determinations for more significant CCW system leaks that bounded the leak rate and with similarly characterized structural flaws. Plant operators later isolated the through wall leak and established an alternate makeup path. This issue has been entered into the licensees corrective action program as AR 2223132.The failure to identify and correct the significant external corrosion that occurred on the Unit 3 CCW surge tank makeup line was 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 adversely affected the cornerstone objective of ensuring the reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, through wall corrosion affects the reliability of the CCW system. The inspectors determined the finding to be of very low safety significance because it did not represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant in accordance with the licensees maintenance rule program for greater than 24 hours. The finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Identification, because the licensee failed to identify the significant external corrosion and apparent metal pipe wastage. Prior opportunities for FPL to identify the significant external corrosion and pipe wastage occurred through maintenance activities on the same pipe section and system engineer quarterly systems walkdowns (P.1). |
| 05000250/FIN-2017007-10 | 2017Q3 | NRC identified | Potential failure of 125 Vdc Bus 3B Class 1E components | UFSAR Section 8.2.2.3.1 stated that the emergency power for vital instrumentation and controls is supplied by a station DC power system which contains five safety related 125Vdc batteries and four DC distribution panels. 125 Vdc distribution panel 3B supplies safety related power to several safety-related equipment including sequencers, reactor trip switchgear, inverter 3Y06, and control power to 480Vac load centers 3B and 3D and 4160 Vac switchgears 3AB01 and 4AB20. UFSAR Section 7.2 stated that the reactor protection system was designed in accordance with IEEE 279- 1968. Section 4.5 of IEEE 279-1968, Channel Integrity, requires all protection system channels be designed to maintain necessary functional capability under extremes of conditions relating to malfunctions. During the review of calculation 5177-265-EG-22, Circuit Breaker/Fuse Coordination Study, Rev. 8, the team questioned if there were instances where class 1E cables associated with DC Bus 3B (3D23) would not be adequately protected given a short circuit on the load side of the breakers. The failure to ensure the Class 1E protective devices would not allow the maximum available short circuit to permanently damage cabling to safety-related equipment associated with DC Bus 3B could result in additional loss of Class 1E equipment. Unresolved Item (URI) 05000250/2017007-01 and 05000251/2017007-01, Potential failure of 125 Vdc Bus 3B Class 1E components,) is opened for additional review to determine if the Class 1E cables on DC Bus 3B can withstand the maximum possible short circuit and to determine if a performance deficiency exists. | ||
| 05000250/FIN-2017007-01 | 2017Q3 | Green | NRC identified | Inadequate Verification of Electrical Protective Device Selective Coordination | The NRC identified a non-cited violation of Title 10 Code of Federal Regulations Part 50, Appendix B, Criterion III, Design Control, for failure to verify that coordination exists between the protective devices on safety related switchgear in order to minimize the probability of losing a safety related power bus. For immediate corrective actions, the licensee entered this issue into their corrective action program as Action Request (AR) 2220956 and performed an operability determination, which determined the system was operable, and was performing a reevaluation of the calculation to determine adequate coordination. The performance deficiency was determined to be more than minor because it was associated with the Design Control attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, failing to verify short circuits in non-safety related SSCs downstream of the safety related switchgear would not cause a lockout of the safety related bus affected its availability and reliability. The team determined the finding to be of very low safety significance because the finding was a deficiency affecting the design of a mitigating structure, system, or component (SSC), and the SSC maintained their operability or functionality. This finding was not assigned a cross-cutting aspect because the issue did not reflect current licensee performance. | |
| 05000250/FIN-2017007-02 | 2017Q3 | Green | NRC identified | Failure to Perform Design Verification for Under Frequency Trip of the Main Generator Breakers | The NRC identified a non-cited violation of Title 10 Code of Federal Regulations Part 50, Appendix B, Criterion III, Design Control, for failure to verify or check the adequacy of design of the under frequency trip feature of the main generator circuit breakers with regard to the effect of its operation on plant stability and the maintenance of critical safety functions. The licensee entered this issue into their corrective action program as AR 2220874 and AR 2224998. The performance deficiency was determined to be more than minor because it was associated with the Design Control attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective of limiting the likelihood of events that upset plant stability and challenge critical safety functions. Specifically, opening of the main generator breakers due to an under frequency condition on the offsite power system would cause the generator load to suddenly drop from full power to the level of the plant loads, and there was no verification that plant stability and critical safety functions would be maintained. The team evaluated the finding with Inspection Manual Chapter 0609, Appendix A, and determined the finding met the Support System Initiators screening criteria for requiring a detailed risk evaluation. The team determined that this issue increased the likelihood of the support system initiator loss of offsite power (LOOP). The regional senior risk analyst conducted a detailed risk evaluation with a one year exposure and determined the change in core damage frequency was less than 1E-6, which was of very low safety significance (Green). The team did not assign a cross-cutting aspect because the issue did not reflect current licensee performance. | |
| 05000250/FIN-2017007-03 | 2017Q3 | Green | H.9 | NRC identified | Failure to Verify the Adequacy of CCW isolation from Supplemental Cooling System (SCS) | The NRC identified a non-cited violation of Title 10 Code of Federal Regulations Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to verify the adequacy of design of temperature set points used for isolation of the Component Cooling Water (CCW) from the CCW supplemental cooling system (SCS) during an accident. For immediate corrective actions, the licensee entered this into their corrective action program as AR 2218834, performed an operability determination, which determined the system is operable but non-conforming, and issued engineering change (EC) 289598 to account for uncertainties in the CCW SCS temperature isolation setpoint. The performance deficiency was determined to be more than minor because it was associated with the Design Control attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and 4 capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, by not ensuring prompt isolation or adjusting the isolation setpoint to account for instrument uncertainties and temperature lag, the licensee failed to ensure that the SCS loop would be isolated at onset of an accident, which affected the reliability and capability of the CCW system when called upon. The determined the finding to be of very low safety significance because the findings were a deficiency affecting the design of a mitigating structure, system, or component (SSC), and the SSC maintained their operability or functionality. The finding had a cross-cutting aspect in the area of Human Performance because the licensee failed to ensure knowledge transfer to maintain a knowledgeable, technically competent workforce and instill nuclear safety values (H.9). |
| 05000250/FIN-2017007-04 | 2017Q3 | Green | NRC identified | Failure to Verify the Adequacy of Design for Component Protective Covers | The NRC identified a Green non-cited violation of Title 10 Code of Federal Regulations Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to verify the adequacy of design for the non-safety related component protective covers attached to safety related equipment. For immediate corrective actions, the licensee entered this into their corrective action program as AR 02220993 and removed visibly degraded protective covers. 3 The performance deficiency was determined to be more than minor because it was associated with the Design Control attribute and of the Initiating Events Cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as pow er operations. Specifically, the failure to ensure the quality and qualification of commercial components and assemblies to maintain adequate mounting to Class 1E equipment increased the likelihood of inadvertent component failures, and thus increased the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. The team determined the finding to be 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 (e.g. loss of condenser, loss of feedwater). This finding was not assigned a cross-cutting aspect because the issue did not reflect current licensee performance. | |
| 05000250/FIN-2017007-05 | 2017Q3 | Green | NRC identified | Failure to Adequately Perform Discharge Testing on Battery 3B | The NRC identified a non-cited violation of Title 10 Code of Federal Regulations Part 50, Appendix B, Criterion XI, Test Control, for the licensees failure to perform surveillance testing on station battery 3B in accordance with the requirements of Institute of Electrical and Electronic Engineers (IEEE) 450-1987. For immediate corrective actions, the licensee entered this issue into their corrective action program as AR 2219948 and performed an extent of condition review, which determined that none of the station batteries were currently in a degraded condition, and placed surveillance procedure 0-SME-003.15 on administrative hold until the corrective actions are completed. The performance deficiency was determined to be more than minor because if left uncorrected, the performance deficiency had the potential to lead to a more significant safety concern. Specifically, the performance deficiency could result in masking degradation of the battery on future performance discharge tests and adversely affect the ability to trend when the testing periodicity should be increased to once a year as required by Technical Specifications (TS). The team determined the finding to be of very low safety significance because the finding did not represent an actual loss of function of one or more non-TS trains of equipment designated as high safety-significant in accordance with the licensees maintenance rule program for greater than 24 hrs. This finding was not assigned a cross-cutting aspect because the issue did not reflect current licensee performance. | |
| 05000250/FIN-2017007-07 | 2017Q3 | Green | P.1 | NRC identified | Failure to Identify ICW Pipe Corrosion | The NRC identified a non-cited violation of Title 10 Code of Federal Regulations Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensees failure to inspect Intake Cooling Water (ICW) piping in accordance with license renewal commitments. For immediate corrective actions, the licensee entered the issue into their corrective action program as AR 02218430 and AR 02218437, planned to perform localized corrosion wall thickness measurements to ensure the ICW system remained operable. The performance deficiency was determined to be more-than-minor because it was associated with the Equipment Performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective of ensuring the reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, unmonitored corrosion affects the reliability of the ICW systems. The team determined the finding to be of very low safety significance because it did not represent an actual loss of function of one or more non-Tech Spec trains of equipment designated as high safety-significant in accordance with the licensees maintenance rule program for >24 hrs. The finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Identification, because the licensee failed to implement a corrective action program with a low enough threshold for identifying issues (P.1). Specifically, individuals routinely failed to identify corrosion issues on CCW system area walk downs that exceeded proceduralized acceptance criteria of light surface rust specified in 0-ADM- 564, during the July 5, 2017, August 11, 2016, and April 11, 2016 CCW area walk downs. |
| 05000250/FIN-2017007-08 | 2017Q3 | Green | NRC identified | Failure to Correct a Non-Conforming Condition Impacting Containment | The NRC identified a non-cited violation of Title 10 Code of Federal Regulations Part 50, Appendix B, Criterion XVI, Corrective Action, for the licensees failure to take timely corrective action to maintain the unit 3 and 4 containment cathodic protection systems. These systems have been non-functional on both units since 2009. The cathodic protection systems purpose is to protect the containments interconnected liner, reinforcing bars, and tendon trumplates. For immediate corrective actions, the licensee entered the issue into their corrective action program as AR 2216534 and performed a prompt operability determination. The licensee concluded that the containment structure was operable but non-conforming and established plans to monitor the potentially impacted inaccessible areas through continued performance of the American Society of Mechanical Engineers (ASME) IWL and IWE programs until actions are taken to restore the Cathodic Protection System. The performance deficiency was determined to be more than minor, because it is associated with the Design Control attribute of the Barrier Integrity cornerstone and affected the cornerstone objective of maintaining the containment structural integrity and operational capability to provide reasonable assurance that the containment protects the public from radionuclide releases caused by accident or events. Specifically, the failure 6 to implement timely corrective actions to maintain the protection of the containments interconnected liner, reinforcing bars, and tendon trumplates affected the structural integrity and operational capability of the containment structure. The team determined the finding to be of very low safety significance because the finding was not a pressurized thermal shock issue, did not represent an actual open pathway in the physical integrity of the reactor containment, and did not involve an actual reduction in function of hydrogen igniters in the reactor containment. This finding was not assigned a cross-cutting aspect because the issue did not reflect current licensee performance | |
| 05000250/FIN-2017007-09 | 2017Q3 | Severity level IV | NRC identified | Failure to Update the UFSAR with the Latest Information Developed | The NRC identified a Severity Level-IV non-cited violation of Title 10 Code of Federal Regulations 71(e), Maintenance of Records, Making of Reports, for the failure to assure that the Updated Final Safety Analysis Report (UFSAR) contained the latest information developed, including all changes made in the facility or procedures as described in the UFSAR. The team determined that the licensee failed to update the UFSAR to include the latest information regarding several design features associated with turbine runback. For immediate corrective actions, the licensee entered this issue into their corrective action program as AR 2218695 to update the UFSAR. The NRC determined this violation was associated with a minor performance deficiency in accordance with the screening criteria in IMC 0612, Appendix E. Because the failure to update the UFSAR impacted the NRCs ability to perform its regulatory process, the team evaluated the violation using the traditional enforcement process. The team determined that this met the criteria for a SLIV violation because not accurately describing turbine runback design features in the UFSAR could have a material impact on licensed activities, and met the SLIV violation criteria in 6.1.d.3 of the NRC Enforcement Policy. The violation represented a failure to update the UFSAR as required by Title 10 Code of Federal Regulations Part 50.71(e), but the lack of up-to- date information has not resulted in any unacceptable change to the facility or procedures. Cross-cutting aspects are not assigned to traditional enforcement violations | |
| 05000250/FIN-2017003-02 | 2017Q3 | Green | H.12 | NRC identified | Inadequate Operator Fundamentals during Diesel Driven Fire Pump Surveillance Testing | An NRC-identified finding was identified for the failure to adequately implement OP-AA-100-1000, Conduct of Operations procedure. Specifically, non-licensed operators (NLOs) failed to identify that the diesel driven fire pump (DDFP) was operating in a degraded condition. The outboard shaft gland was at elevated temperature because there was no packing leakoff established. Plant operators initiated an action request (AR) 2220785 to repair the stuffing box packing and the DDFP was declared non-functional. The electric driven fire pump (EDFP) remained functional and available to supply 100% of the fire water capacity while the DDFP was non-functional. This issue has been entered into the licensees corrective action program as ARs 2220785 and 2226305.The failure to identify that the DDFP was operating in a degraded condition was a performance deficiency. The performance deficiency was more than minor because it was associated with the protection against external hazards (fire) attribute of the initiating events cornerstone and adversely affected the cornerstones objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown, as well as power operations. Specifically, NLOs did not identify a degrading and unreliable DDFP condition. The inspectors determined that the issue had very low safety significance (Green) because the EDFP remained available to provide 100 percent of the required fire water capacity. The finding had a cross-cutting aspect in the area of Human Performance, Avoid Complacency, because NLOs did not recognize and consider that the DDFP was operating without adequate packing gland leakoff after a significant idle period (H.12) |
| 05000250/FIN-2017003-03 | 2017Q3 | Green | H.12 | NRC identified | Inadequate Maintenance Rule (a)(4) Risk Assessment for the High Head Safety Injection Pumps | An NRC-identified NCV of 10 CFR 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, paragraph (a)(4), was identified for the licensees failure to adequately assess and manage the Unit 3 and Unit 4 online risk associated with taking both Unit 4 high head safety injection (HHSI) pumps out of service. This issue was entered in the licensees corrective action program as AR 2193584. Corrective actions completed included providing additional training to senior reactor operators (SROs) on the maintenance rule (a)(4) implementation procedure and the definition of unavailability as used in maintenance rule (a)(4) risk assessments. The licensees failure to adequately assess and manage the Unit 3 and Unit 4 online risk associated with taking both Unit 4 HHSI pumps out of service, as required by 0-ADM-225, On Line Risk Assessment and Management, was a performance deficiency. The performance deficiency was more than minor because it adversely affected the equipment performance attribute of the Mitigating Systems Cornerstone. The significance of the finding was determined using IMC 0609, Appendix K, Maintenance Risk Assessment and Risk Management Significant Determination Process. The finding was determined to be of very low safety significance (Green) because the incremental core damage probability deficit for the timeframe the HHSI pumps were unavailable was less than 1E-6 for each unit, prior to, and after, the failure of the Unit 3A 4kV switchgear bus. The finding had a cross-cutting aspect in the area of Human Performance, Training, because the control room SROs did not have an adequate understanding regarding crediting operator actions and the definition of unavailability. The SROs incorrectly considered the Unit 4 HHSI pumps as available to perform their safety functions under the maintenance rule (a)(4) risk assessments (H.9). |
| 05000250/FIN-2017002-02 | 2017Q2 | Green | H.1 | Self-revealing | Inadequate Foreign Materials Exclusion Controls for Thermo-Lag Activities Renders Electrical Equipment Inoperable and Results in a High Energy Arc Flash | Green: A self-revealing Green (NCV) of Technical Specification (TS) 6.8.1.a., Procedures and Programs, was identified for the failure to appropriately implement foreign material exclusion (FME) controls during Thermo-Lag fire barrier modifications. Specifically, maintenance procedure 0-GMP-102.21, Installation, Modification and Maintenance of Thermo-Lag Fire Barrier System, Rev. 0C, did not include instructions in sufficient detail to prevent foreign material used in the installation of Thermo-Lag fire barriers from entering nearby electrical equipment and was a performance deficiency (PD) which affected the operation of two redundant safety-related battery chargers and caused a high energy arc fault (HEAF) that damaged the 3A 4kV switchgear bus. After the HEAF, the licensee promptly ceased all Thermo-Lag installation activities. The licensee completed a root cause evaluation in Action Request (AR) 2192198 and revised the installation procedure to prevent foreign material from entering nearby electrical equipment. The PD was more than minor because it caused both a reactor trip and resulted in the unavailability of the 3A 4kV switchgear bus. The inspectors evaluated the significance of this finding by utilizing IMC 0609 Attachment 4, Initial Characterization of Findings, and IMC 0609 Appendix A, The Significance Determination Process for Findings At-Power, and determined the findings significance could not be screened to Green because it caused both a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. Therefore a detailed risk evaluation was required to complete the significance determination. Based upon the results of the evaluation the finding was considered to be Green, or equivalent to low safety significance. The cross-cutting aspect (CCA) that best corresponds to the root cause as described in IMC 0310, Aspects Within the Cross-Cutting Areas, was Resources; leaders ensure that personnel, equipment, procedures, and other resources are available and adequate to support nuclear safety (H.1). |
| 05000250/FIN-2017002-01 | 2017Q2 | Green | P.5 | NRC identified | Failure to Perform 100 Percent General Visual Examinations of Containment Moisture Barriers Associated with Containment Liner Leak Chase Test Connections | Green: A NRC-identified Green NCV of 10 CFR 50.55a, Codes and Standards, was identified for the failure to perform general visual examinations of moisture barrier materials in the reactor containment leak-chase channel test connections in accordance with the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel (BPV) Code, Section XI, Subsection IWE. The licensee performed the required examinations in Unit 3 during the April 2017, refueling outage and initiated corrective actions to revise the physical configuration of leak chase areas and review the In-service Inspection (ISI) Plan. This issue has been entered into the licensees corrective action program as AR 02196637. The failure to conduct the required visual examination of all moisture barriers in accordance with the ASME BPV Code requirements was a PD. The PD was more than minor significance per IMC 0612, Appendix B, Issue Screening, because the current Containment ISI Plan did not adequately implement the ASME BPV Code inspection requirements for the examination of moisture barriers, and if left uncorrected, had the potential to lead to a more significant concern. The finding was of very low safety significance, or Green, per IMC 0609 because it did not, based on inspections performed following discovery, represent an actual open pathway in the physical integrity of the reactor containment. Because the licensee did not effectively evaluate and appropriately implement the ASME BPV Code requirements in the Containment ISI Plan when a reasonable opportunity was available through the licensees review of NRC Information Notice (IN) 2014-07 and Regulatory Issue Summary (RIS) 2016-07, the inspectors determined the finding had a CCA in the operating experience component of the problem identification and resolution cross-cutting area, in that the organization systematically and effectively collects, evaluates, and implements relevant internal and external operating experience in a timely manner (P.5). |
| 05000250/FIN-2017002-03 | 2017Q2 | Green | H.9 | NRC identified | Failure to Implement Fire Detection | Green: A NRC-identified Green finding was identified for the licensees failure to follow plant procedure O-ADM-016, Fire Protection Program, Rev. 19. Specifically, the licensee failed to properly implement fire watches following a HEAF on the 3A 4kV switchgear bus. 3 The inspectors determined that the licensees failure to implement fire detection was a PD. This PD was more than minor because it was associated with the reactor safety mitigating systems cornerstone, and if a fire was not detected in the 3B 4kV switchgear room there was a potential for the B train of equipment to lose function which could have resulted in the unavailability of both the A and B trains of equipment post incident. The finding is not greater than Green because a risk analysis of the PD was performed and determined the risk increase in core damage frequency due to the PD was equivalent to a Green finding of very low safety significance due to the short exposure period. Because site personnel failed to reset fire detectors and implement fire watches in appropriate areas following the incident; and during interviews, inspectors identified that fire drills did not emphasize post incident activities, the inspectors concluded the finding had a CCA in the area of Human Performance associated with the Training; the organization provides training and ensures knowledge transfer to maintain a knowledgeable, technically competent workforce and instill nuclear safety values (H.9). |
| 05000250/FIN-2017008-03 | 2017Q1 | Green | H.1 | NRC identified | Potential Failure to Implement Adequate Foreign Material Exclusion Control | Inspection Scope The team reviewed licensee documents, performed walk downs associated with the safety -related 3A 4kV switchgear located inside room 071, and interviewed licensee personnel to determine the conditions leading up to the internal bus fault event on the morning of March 18, 2017. The documents reviewed included procedures, work orders, drawings of floor plans, one line diagrams, specifications, correspondence, photographs, licensees NRC Inspection Team Briefing document, and Root Cause Charter description AR 02192198. b. Findings and Observations The team initiated the review by performing a walk down of the 3A 4kV switchgear room to establish an understanding of the conditions inside the room that may have affected the 3A 4kV switchgear. The room , which was significantly smaller than the 3B 4kV switchgear room, provided minimally adequate access around the equipment, such as the switchgear , motor control center s (MCC s), a sequencer panel, a sump pump, and floor mounted air handling units. The current limiting reactor (CLR) , or reactor coil, associated with the event was located in section 3AA06 of the 3A 4kV switchgear. The front of this section is across from a room air handler unit, which directs its air towards the ventilation louvers in the CLR section. The team interviewed members of the licensees failure investigation process team and determined their evaluation of the potential causes for the failure of the reactor coil included: Bus fault in reactor coil cubicle 3AA06 Failed insulator in cubicle 3AA06 19 Fault in reactor coil Bus fault external to the 3AA06 cubicle Load fault with failure to isolate Magnetic properties of the reactor coil interacting with erected scaffold. 3AA06 side panels pushed in from outside reducing air gap Foreign material from internal and/or external sources Bolts installed with nuts facing towards grounded surfaces. Large quantities of conductive dust suspended in air from sweeping prior to fault Each of the potential causes were dismissed for lack of any evidence with the exception of those issues that would have contributed to a reduction in the air gap between uninsulated busses and ground surfaces. The installation of the Thermo-Lag was in progress just prior to the bus fault and according to statements from the installing contractor personnel, they had just exited the room to prepare to go to lunch and had been cleaning up the space before leaving. One of the workers had gone back into the room to check on one last item when the bus fault occurred and suffered injuries as a result of the explosion. Based on interviews and photographs provided, it was determined that the mesh, used to make up the joining pieces of insulation, was conductive. That mesh material was also light weight and made out of carbon fiber. The protective relays operated as expected for almost all components , including the 174/TDO relay in the trip circuit that operated the lockout relay, which in turn opened all the breakers in the 3A 4kV switchgear bus. The lockout relay operation prevented the 3A EDG from closing in on the 3A 4kV switchgear bus. The loss of the bus initiated a loss of steam flow on the turbine. The Unit 3 turbine and generator were motoring for approximately 30 seconds with the transmission system experiencing power swings associated with the loss of the main generator. After 30 seconds, the Unit 3 generator 286/G3 lockout tripped followed by the switchyard breakers opening and isolating the generator in 1.8 cycles. The reactor coil separates the high and low sides of the 3A 4kV switchgear bus. The high side, which was upstream of the reactor coil, had a higher withstand capability for short circuits that the low side of the switchgear bus. There is a slight difference between the overcurrent relays for phases A and B compared to phase C. Tracings provided with the details of current and voltage conditions prior to, during , and after the bus fault reveal an increase in the fault current of phase C preceding the increase in phase A. Photographs of the effects of the bus fault indicated an initial arc located next to what appeared to be phase C bus. However, the target flags in the overcurrent relay s failed to indicate a phase C trip. The entire overcurrent protection system worked as expected except for the delay on the phase C components. The team reviewed procedures and methods prescribed by the licensee to control foreign material contamination. A number of the methods indicated included cutting the Thermo-Lag material outside the switchgear room approximately 15ft from the east door to the room. Some of the final cutting and trimming of the carbon fiber mesh was done inside the switchgear room on top of the scaffolding, which had been fitted with Grifflon net to protect from foreign material particles. In addition, a Pearl Weave material was 20 used to protect against falling objects to the space below. The team was able to confirm a number of these methods used by the conditions of the space during the walk down of the room and the interview transcripts provided by the licensee of the Thermo- Lag installation personnel. However, these methods appear to cover larger pieces of material that would be appropriately captured by the Pearl Weave or the Grifflon but not the smaller pieces of carbon fiber mesh that could become airborne and migrate around the room. The only apparent control provided for airborne particulate would be the air filter in the air handling unit. This would require the material to be at an elevation low enough to get sucked in by the air return at the bottom of the air handler. Any material suspended in air would be blown out from the air handler and potentially be blown through the louvers in the reactor coil cabinet. Overall, the team concluded that the licensee was taking appropriate actions to evaluate the potential causes for the failure of the 3A 4kV bus. The most likely potential causes of the event involve the introduction of foreign material into the switchgear as well as the configuration and design of the switchgear. Additional review of information related to these potential causes will be required following the conclusion of the licensees root cause evaluation, which had not yet been completed at the time of the inspection. Therefore the team opened two URI s as documented below. i. URI 05000250, 251/2017008- 03, Potential Failure to Implement Adequate Foreign Material Exclusion Controls Introduction: The team identified an URI associated with the licensees potential failure to properly control the spread of airborne particulates generated from the installation of the Thermo-Lag insulation material on cable trays and conduits inside the 3A switchgear room. Description : The documentation provided to install the Thermo-Lag insulation was prescribed in work order 40464284- 03, EC 283459 Install T -Lag of MCC -3B Power Cables in 3A SWGR , dated the 10th of March 2017. This work order refer red to procedure MA -AA- 101- 1000, Foreign Material Exclusion Procedure, for job supervisor to review and approve the foreign material exclusion ( FME ) controls under item 2.3. The supervisor signature was provided on the 17 th of October 2016 for this particular task. However, the signature date was prior to this work order issue date. Section 4.3 of the FME procedure in paragraph 10 stated that , Special precautions need to be taken when work activities (spray painting, sand blasting, grinding, cutting, welding, insulating, chemical cleaning etc.) may generate airborne dust, debris or chemical fumes that could be introduced into operating plant equipment such as motors, switchgear, control panels and electrical cabinets . In addition, section 4.5.1 , Electrical Cabinets , paragraph 1 , directed personnel to visually inspect the surrounding area, particularly overhead, for potential sources of foreign material and to note any nearby ventilation system that may introduce foreign material into the cabinet. In paragraph 2, it indicated that , Where practical, covers should be installed on open electrical enclosures, cabinets, and boxes required to be left open by procedure, plant operations, or maintenance . Section 4.5.2, Switchgear , directed the personnel to follow the measures identified above. In addition, the conductivity of this mesh may have played a significant factor in the resulting bus fault when it migrated into the reactor coil cabinet through the open louvers and formed a low impedance path from the exposed phase C bus to the metal enclosure of the cabinet. Pieces of the black mesh were discovered inside the reactor 21 coil insulated windings, which indicated an absence of screening material or a means to block foreign material migration into the inside of the reactor coil cabinet with its exposed busses. Procedure 0- GMP -102.21, Installation, Modification and Maintenance of Thermo-Lag Fire Barrier Systems , did not contain an engineering evaluation of the carbon fiber mesh used with the system installed inside the 3A 4kV switchgear room. Material safety data sheet (MSDS -0012821) from Cytec Engineered Materials with product name Thornel Pan Based Standard Modulus Carbon Fiber provided a hazard identification of Electrically Conductive Fibers Airborne fibers can short circuit electrical equipment . This URI was initiated to further review the environment created during the installation of the Thermo-Lag in 3A 4kV switchgear room. This environment may have contributed to a degraded isolation of exposed medium voltage bus bars inside the reactor coil cabinet . Following the completion of the licensees root cause evaluation, inspectors will determine whether performance deficiencies exist ed related to the licensees evaluation of the carbon fiber mesh and the foreign material exclusion controls in effect at the time of the event. (URI 05000250, 251/2017008- 03, Potential Failure to Implement Adequate Foreign Material Exclusion Controls) |
| 05000250/FIN-2017008-02 | 2017Q1 | NRC identified | Potential Failure to Complete an Adequate Risk Assessmen | Inspection Scope The team reviewed the licensees Maintenance Rule 10 CFR 50.65 (a)(4 ) risk management program actions associated with the emergent issue on the Unit 4 leak on the recirculation line of the high head safety injection (HHSI) pumps. The team reviewed the Unit 3 and Unit 4 risk management actions following the failure of the Unit 3 3A 4kV switchgear bus. The team also interviewed the control room shift manager, and the Unit 3 and Unit 4 control room unit supervisors that had the shift responsibilities the day of the Unit 3 4kV switchgear failure to assess their understanding of the risk management actions associated with declaring the 4A and 4B HHSI pump s available to perform their safety function. The team reviewed the software program used by the licensee to assess on -line risk and used the program to run several independent specific scenarios to obtain the core damage frequency (CDF) on- line risk for those scenarios. The team reviewed the clearance tag out that was used to place the 4A and 4B HHSI pumps out of service for making the repairs to the pump recirculation line. The team reviewed the emergency operating procedures for the operator actions the licensee credited for starting the HHSI pumps, versus an automatic start , and assessed whether the actions were adequate to maintain the HHSI pumps available in the on- line risk monitor (OLRM) . The team reviewed the training provided to licensed operators with respect to crediting operator actions to maintain safety systems as available in the OLRM . The team reviewed the licensees procedures that described guarding and protection of safety - related equipment during periods when other systems were undergoing maintenance or being tested. b. Findings and Observations Overall, the team identified several weaknesses with the licensees Risk Management Program actions, both prior to, and after the event. Specifically, 10 CFR 50.65(a)(4) actions associated with the emergent issue for the Unit 4 HHSI system were based on the incorrect assumption that the 4A and 4B HHSI pumps were available. This led to risk management actions that did not include the protection of the 3A and 3B 4kV switchgear which allowed work in the 3A switchgear room to proceed . The team s review of the licensees procedures and practices for accounting for risk on the opposite unit with equipment removed from service identified issues for further follow -up by the regional senior risk analyst and, therefore , an URI was opened, as documented below . URI 05 000250, 251/2017008- 02, Potential Failure to Complete an Adequate Risk Assessment Introduction: The team identified an URI associated with the licensees assessment and management of risk under 10 CFR 50.65(a)(4) prior to and following the event, including their conclusions regarding availability of the Unit 4 HHSI pumps . Description : On Friday March 17, 2017, Unit 3 was operating at 100 percent rated thermal power (RTP) and the operational core damage frequency ( CDF ) of the OLRM was in the low end of the Green band , indicating power operations in the low risk band. Unit 4 was operating at 100 percent RTP and the CDF was also Green in the OLRM . A down- power on Unit 3 was planned to start the next day in preparation for entering a refueling outage. A work crew was inside the 3A 4kV safety -related switchgear room 16 installing Thermo-Lag insulation on cable trays. The licensee needed to complete this insulation work by the end of the Unit 3 outage in order to meet NFPA 805 commitments. The Thermo-Lag work had been ongoing for several months. In the afternoon of March 17, 2017, Engineering identified a leak on a 34 -inch diameter test line pipe down- stream of the common line that joins the 4A and 4B HHSI pump recirculation lines. Based on the identified leakage and engineering inspection, the licensees immediate operability assessment concluded that Unit 4 HHSI system was operable and Operations requested a two- day prompt operability determination. The tag- out clearance to repair the test line required isolating the pump recirculation line to complete a welding code repair, resulting in the Unit 4 HHSI pumps becoming TS Inoperable and also unavailable to perform their safety function. It was estimated the work would take approximately 18 hours. On Saturday, March 18, 2017, the licensee took the 4A and 4B pumps out of service to start the repair. At 6 :24 a.m. EDT, both Units entered TS 3.5.2.a Action d, and started a 72- hour LCO for two of the four HHSI pumps TS Inoperable. During the day -shift turnover, the shift manager, both u nit control room supervisors, and the reactor board operators were updated and informed of the plan to repair the HHSI test line. The crews reviewed the Unit 4 HHSI pumps status of pull -to-lock and the risk assessment that was completed which required operator actions to maintain the HHSI pumps available. None of the SROs challenged the licensees decision to use the EOP network to credit operator action or timeliness to start the pumps to declare the pumps available on the OLRM. The 4A and 4B HHSI return line was isolated at approximately 7: 36 a.m. EDT , which prevented HHSI pump recirculation flow. The 4A and 4B HHSI pump breakers remained available and were not tagged out, and both pump control switches had been placed in pull -to-lock which prevented the pumps from automatically starting on either a Unit 3 or a Unit 4 safety injection (SI) actuation signal . The licensee did not enter the 4A and 4B HHSI pumps into the OLRM as unavailable, instead the pumps were declared available to perform their safety function based on crediting operator action to start the pumps . The licensee protected the 3A and 3B pump rooms, as well as the 3A and 3B pump supply breaker cubicles on their associated 4kV switchgear; however, with the 4A and 4B pumps considered available, the licensee did not protect the 3A and 3B 4kV switchgear, and the Thermo-Lag work continued in the 3A 4kV switchgear. Both u nits OLRM remained in the Green band, based , in part , on having four available HHSI pumps as determined by the licensees risk assessment actions and OLRM results . The Turkey Point Unit 3 and Unit 4 HHSI systems are shared systems. Although each unit has two HHSI pumps, the OLRM credits four available HHSI pumps for Unit 3 and Unit 4. If either unit receives an SI actuation signal, all four pumps receive a start signal and inject into a common HHSI header. The Unit 3 and Unit 4 control rooms are co- located in one large room. There are four HHSI pump control switches in each control room, (i.e., each control room has switches for the 3A, 3B, 4A and 4B pumps ). Each control room has the capability to start or stop any pump. However, if any pump switch is in the pull -to-lock position in either control room, then that pump will not automatically start , nor will it have manual start capability . The licensees risk assessment, credit ed control room operator action to start the 4A and 4B HHSI pumps, in place of an automatic start on a SI actuation, and did not enter the pumps as unavailable into the OLRM. Specifically, operator action was credited by the control room operator taking steps to manually start the HHSI pumps when entering the EOP network during a SI actuation. After entering EOP -E-0, Reactor Trip OR Safety Injection, step 4 had the operator check if SI was actuated, SI Annunciators ANY ON, OR, Safeguards 17 equipment AUTO STARTED. In the response not obtained column of the EOP , if SI was required , the procedure had operators manually actuate SI and proceed to step 5. That step required operators to complete Attachment 3 of EOP -E-0, Prompt Action Verifications, which required verification of pump operation of At least two High- Head SI pumps RUNNING. The response not obtained column requested the operator to manually start High- Head Pump(s). It was determined that it would take approximately 8.5 minutes to advance to that point in EOPs for the control room operator to manually start the tagged out Unit 4 HHSI pumps, in place of the immediate automatic pump start on an SI actuation. Additionally, the team found that on the Unit 3 control room switches , the 4A and 4B HHSI pumps had also been tagged and placed in pull -to-lock. Additional time and coordination would have been needed between the two unit control room supervisors to take the 4A and 4B HHSI pumps out of pull to lock on the Unit 3 side, and this was not addressed in the EOP. During the interview s of the control room supervisors, they did not recall if this sequence of removing the pull -to-lock on both unit control rooms switches had been discussed and the licensee had not provided any written instructions or procedures to the board operators to address this portion of the switch sequencing for taking credit for operator action to start the 4A and 4B HHSI pumps. The team found the licensee did not have a validated timeline to show that all operator action steps would be completed to make the HHSI pumps available prior to the time the HHSI pump safety functions were required. Specifically, the licensee had not validated that any accident scenario required a HHSI pump to start in less than 8.5 minutes . Additionally , it was identified during the inspection that during a specific type of small break LOCA, the HHSI pumps could be started and left dead headed for more than 3 minutes. In this scenario , because the HHSI pump recirculation lines were tagged out, the pumps would have overheated and been damaged , causing the control room operator s to have to address additional issues during accident mitigation, (i.e., loss of refueling water storage tank inventory due to potential leakage from pump s) . In determining the risk assessment of the HHSI pump for availability, the licensee had not addressed this issue and no procedures were provided to control room operators to prevent running the pumps dead headed for longer than 3 minutes. At 11 :07 a.m. EDT , the Unit 3, 3A 4kV switchgear failed and the unit automatically tripped. The licensee determined the 3A HHSI pump was inoperable and at 11 :13 a.m. EDT both units entered T.S. 3.0.3 due to having three of four HHSI pumps inoperable on two units. The repair work on the Unit 4 HHSI test line had not progressed to the point of cutting the pipe and the licensee took actions to restore the 4A and 4B HHSI pumps. At 1 :36 p.m. EDT , the Unit 4 recirculation return line was restored and the HHSI pumps were returned to available and operable status. The team found that the licensee had not assessed the OLRM after the failure of the 3A 4kV switchgear and Unit 4 remained in Mode 1 at 100 percent RTP without an updated risk assessment. During the inspection, the team obtained Unit 3 and Unit 4 OLRM print outs for the equipment that was unavailable prior to, and after, the Unit 3 4kV switchgear failure. The results showed that with two HHSI pumps unavailable, (4A and 4B ), Units 3 and 4 remained in the Green risk band. After the Unit 3 A 4kV switchgear failure, with three HHSI pumps unavailable, Unit 3 increased to the Red band and Unit 4 risk increased to the upper limit of the Green band. 18 The team questioned the adequacy of the licensees decision to credit operator actions to maintain the Unit 4 HHSI pumps available while : (1) performing the code repair on the Unit 4 common HHSI pump test line, (2) potential existed for the HHSI pumps being operated without a recirculation flow line , and (3) the adequacy of instructions or procedures to control room operators when starting the HHSI pumps in certain accident scenarios which would cause pumps to run dead headed. Additionally, the team questioned the licensees risk manage men decisions which included allowing work to continue in the 3A 4kV switchgear room, and, after the failed Unit 3A 4kV switchgear and Unit 3 reactor trip, failure to complete a risk assessment to account for additional unavailable safety -related equipment. The NRC required additional inspect ion to determine whether a performance deficiency exist . Specifically , further review is needed to: (1) determine the adequacy of risk management actions taken to protect Unit 3 equipment while the 4A and 4B HHSI pumps were removed from service, (2) review the OLRM tool to determine whether the CDF results are consistent with the unavailability of the HHSI pumps and the 3A 4kV switchgear, and (3) review the licensees procedures to determine why instructions were provided to start the HHSI pumps while the recirculation lines were tagged out, without evaluating the potential consequences for damaging the pumps during a small break LOCA . (URI 05000250, 251/2017008- 02, Potential Failure to Complete an Adequate Risk Assessment | ||
| 05000250/FIN-2017008-04 | 2017Q1 | NRC identified | Potential Inadequate Design Control of Current Limiting Reactor | Introduction: The team identified an URI associated with potential discrepancies between the licensees design documentation and the installed configuration of busses inside the reactor coil cabinet. Description : The team reviewed the reactor coil layout drawing, showing the location of the reactor coil and bus configuration within the switchgear cabinet and compared the drawing with the photographs available of conditions inside the cabinet, including phase designation marking s provided on the busses, which appeared to indicate a discrepancy between drawings and bus markings. The drawing indicated an incoming bus configuration from front to rear as phase B , phase C , and phase A . However, the photographs indicated markings on the busses themselves as phase A , phase B , and phase C . The trip flags on the overcurrent relays indicate an initial fault starting on phase A . This discrepancy should be reviewed and appropriate corrective actions taken . The team also evaluated the available fault current on the 3A 4kV switchgear to assess the impact of the current limiting reactor ( CLR) on the switchgear and its capacity to withstand short circuit currents imposed on the bus during faults. The vendor indicated that the 3A 4kV switchgear bus high side could withstand 78,000 amperes (A) but the low side could only withstand 60,000 A . The available fault currents in the low side configuration for restoration was determined to be 55,720 A asymmetrical or 35,171 A symmetrical. The team s review of calculation PTN -3FSE -07- 001, Unit 3 - Safety Related AC Electrical Distribution PSB -1, Short Circuit, Voltage Drop and Bus Loading Analysis, indicated an assumed 3A 4kV switchgear bracing for 78,000 A symmetrical to be consistent with a 350 MVA , 4kV breaker. However, other documents indicate a 78,777 A to be an asymmetrical fault current and a 350MVA capability corresponds more 22 closely to 49,000 A symmetrical than the 78,000 A symmetrical. This issue needs further review in order to be fully understood and determine if there are any issues that need to be addressed. The megger test result s provided for the low side of the 3A 4kV switchgear established a 500 megohms (M) resistance measurement between the phase busses as satisfactory. The inspectors noted that other national standards such as the International Testing Association Inc. , Maintenance Testing Specifications , 1997 edition determined that the insulation resistance tests on electrical apparatus and systems recommends a minimum of 1,000 M for an equipment similar to the 3A 4kV switchgear rated for 5,000 V . Finally, t he team identified a potential concern with the design and installation of the CLR unit inside the 3A 4kV switchgear provided with exposed incoming and outgoing 4kV bussing. The 3A 4kV switchgear had thermoplastic insulated bussing throughout the gear except at the CLR coil. There was no industry standard for a required spacing between the bare individual phase busses and grounded surfaces. Information provided indicated a spacing that conformed to accepted industry technical publications. However, other aspects associated with the cabinet construction and room layout of ventilation equipment in this particular case may have contributed to the bus fault. In particular, the louvers in the front and rear of the cabinet allow unimpeded access to the inside of the cabinet and the exposed energized busses. No guidance was provided to maintain the orientation of the bus connection bolts to provide as wide a gap as possible to grounded surfaces. In the case of the 3A 4kV switchgear , photographs showed evidence that the bolts had been installed backwards for the connection to the C phase bus at the rear bottom of the cabinet . This was the flash- over spot where the bus faulted to the metal cabinet. Specifications and drawings associated with this equipment did not provide any guidance on spacing or insulation to be applied to the busses. An URI was opened in order to review the design and configuration of the reactor coil located inside the 3A 4kV switchgear following the completion of the licensees root cause evaluation. This review will be accomplished to determine whether any performance deficiencies exist in the area of design control. (URI 05000250, 251/2017008- 04, Potential Inadequate Design Control of Current Limiting Reactor) | ||
| 05000250/FIN-2017001-01 | 2017Q1 | Green | H.1 | Self-revealing | Inadequate Operational Decision-Making Procedure Implementation Results in Feedwater Heater Water Hammer | Green: A self-revealing finding was identified for the failure to adequately implement OP-AA-105-1000, Operational Decision Making (ODM) procedure that was used to establish plant conditions for the repair of the Unit 3 condensate tube leak in the 3B feedwater heater (FWH). The failure to implement all the steps of OP-AA-105-1000, Operational Decision Making, to establish plant conditions for the repair of the Unit 3 condensate tube leak in the 3B FWH was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the configuration control and procedure quality attributes of the initiating events cornerstone and adversely affected the cornerstones objective to limit the likelihood of events that upset plant stability. Specifically, not implementing the ODM procedure steps 2.3, Rigorous Evaluation, and Steps 2.5, Effective Implementation, of Attachment 3, resulted in an incorrect revision to procedure 3-ONOP-081.02 which led field operators to close the extraction steam to the 5B FWH too quickly and without due-precaution to prevent a rapid decrease in the 5B FWH shell pressure and caused significant water hammer and resulted in a fast load reduction and reactor trip. Using Inspection Manual Chapter (IMC) 0609, Appendix A, The Significance Determination Process (SDP) for Findings at Power, the inspectors determined that the issue had very low safety significance (Green) because the event did not cause both a reactor trip and a loss of mitigating equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. The finding was assigned a cross-cutting aspect of resources in the area of human performance, in that, leaders ensure that personnel, equipment, procedures, and other resources were available and adequate to support nuclear safety. Specifically, the ODM team did not ensure that the revised procedure was adequate to preclude water hammer. (H.1). |
| 05000250/FIN-2017008-01 | 2017Q1 | Green | H.9 | NRC identified | Potential Failure of Fire Detection Capability on Credited Train of Equipment Following High Energy Arc Flash Event | Inspection Scope The team reviewed the fire brigade response after an explosion and smoke was reported coming from the Unit 3 safety -related 3A 4kV switchgear to determine and assess whether : (1) the brigade response was adequately staffed ; (2) there was timely arrival of the required amount of dressed- out fire brigade members ; (3) the required firefighting equipment and communication equipment and procedures were taken to and or available at the scene to adequately plan and execute a fire fighting strategy; and (4) that the brigades fire -fighting actions and communications were appropriate in accordance with the established procedures and the licensees fire brigade program requirements. The team also reviewed whether the licensees fire brigade had requested assistance from the Miami -Dade Fire and Rescue Department , the basis for assistance and if Miami -Dade Fire and Rescue provided any firefighting assistance. The team interviewed the responsible fire brigade team leader and the SRO that responded to the switchgear room to obtain the details regarding the as found conditions and actions taken by the brigade to address the smoke and potential fire in the switchgear room . The team reviewed the licensees fire pre -plan to assess whether the licensee adequately ventilated the smoke from the Unit 3A switchgear given the circumstances. Specifically , the Unit 3 EDG had automatically started and was blowing high velocity air from the radiator exhaust into the direction of the 3A and 3B switchgear room door entrances. The team walked down the Unit 3 4kV switchgear rooms with the responsible SRO that had assisted in decision making to direct smoke ventilation during the incident, to understand the circumstances regarding the strategy used for ventilation. The team reviewed the licensees fire risk management actions implemented after the licensee identified the fire door had been damaged, including the establishment of a fire watch in the 3A 4kV switchgear room. The team reviewed the licensees fire brigade response report and CAP database to determine if the licensee was adequately addressing any unresolved issues identified during the fire brigade response. 12 b. Findings and Observations On March 18, 2017 , at approximately 11: 07 a.m. EDT , as a result of an arc f lash in switchgear room 3A, eleven out of eleven spot detectors and two out of two very early warning detectors activated in switchgear room 3B. The spot detectors activated spatially from the first detector closest to Fire Door D070- 3, which separates switchgear Room 3A and 3B , to the last spot detector activating closest to the exit door on the east side of the room. The licensee acknowledged the alarms at Fire Alarm Control Panel 3C286 after the incident; however, the licensee did not reactivate the smoke detectors until sixty two hours later on March 21, 2017 , at 12:51 a.m. EDT. The team confirmed with the licensee that the detectors would not have activated between the times they were acknowledged and reactivated. The 3B 4kV switchgear was the protected train after the arc f lash in the 3A 4kV switchgear. Procedure 0 -ADM -016, Fire Protection Program , Rev . 19, Table 5.6.3 -1, denotes Fire Zone 70 ( 3B 4kV switchgear) to include fire detection instruments in the maintenance rule (a)(4) monitored fire zone and specified required risk -informed interim compensatory actions for degraded equipment. Section 5.6.3.3. d outlined these compensatory actions as the following: ...all detection instruments must be in service when required to be functional. If any single detector instrument is declared out of service, within one hour, a continuous fire watch shall be established and maintained until the detection instrument is returned to service... Smoke removal activities immediately after the inc ident credits personnel in the switchgear room 3B for nearly four hours. Thereafter, based on the security access logs, at 2 :43 p.m. EDT, two maintenance personnel were placed on fire watch duty until 5:22 p.m. EDT . However, these individuals monitored switchgear room 3A and were not placed inside the room with the credited train, 3B. The following fire watch shift arrived at approximately 6:00 p.m. EDT and maintained presence outside of both switchgear rooms 3A and 3B with the entry doors closed. The licensee informed the team that the crew was fearful of the persistent odor that was emanating after the incident in switchgear 3A. Since this crew did not maintain logs nor access the doors, the licensee confirmed to the team they were present outside. AR 2194579 was generated to document fire watches located outside the room do not meet the intent of 0 -ADM -016.4, Fire Watch Program. The first documented log of a continuous fire watch occurred at 1:15 p.m. EDT on March 19, 2017. This log continues until the smoke detectors were reactivated at 12:51 a.m. EDT on March 21 , 2017 ; however these individuals were located in switchgear room 3A. The team interviewed fire watch personnel and determined that the individuals , which did not maintain fire watch logs and stationed themselves outside the switchgear rooms , were Florida Power and Light (FP&L) employees who recently started fire watch activities; whereas, the individuals that maintained logs and placed themselves inside switchgear room 3A were experienced contractors. The team did not have an opportunity to interview FP&L fire watch employees; the contractors that were interviewed were trained and experienced to sufficiently perform the duties. In addition, the single smoke detector in the 480V Load Center 3A, 3B room (Fire Zone 95) located directly above the switchgear rooms did activate during the incident and was not reactivated until 12: 51 a.m. EDT on March 21, 2017 . The detector is assumed to have activated by smoke travelling from switchgear room 3A to switchgear room 3B to 13 the fire door located on the second level of switchgear room 3B. According to 0- ADM - 016.4, Fire Watch Program, for a deactivated detector in the 480V Load Center 3A, 3B room, the following requirement applies: ...restore the non- functional instruments to functional status within 14 days or within the next 1 hour establish a fire watch patrol to inspect the zones with the non- functional instruments at least once per hour. The licensee maintained an hourly roving fire watch in switchgear rooms 3A, 3B and 3 A/B/C/D 480V Load Centers rooms before the incident that was temporarily suspended for the 11:00 a.m., 12:00 p.m., 1:00 p.m. & 2:00 p.m. hours on March 18, 2017, due to scene safety and subsequent investigation. The hourly rove was reinstated in switchgear rooms 3A, 3B and 3 A/B/C/D 480V Load Center rooms for the 3:00 p.m. hour. The team interviewed licensee fire managers regarding the fire response activities after the incident. The managers were cognizant of the issues and attributed them partly to the false fire alarms in other areas of the plant that occurred shortly after the event . AR 2194706 was generated to enhance fire procedures that would address functionality of suppression, detection and barriers; and consideration of compensatory measures post incident. Overall, the team concluded that the licensees fire brigade response and communications were adequate following the event. However, the team identified issues with regards to the establishment of a fire watch for the 4kV switchgear rooms following the event and therefore opened an Unresolved Item (URI) as documented below . URI 05000250, 251/ 2017008- 01, Potential Fai lure of Fire Detection Capability on Credited Train of Equipment Following High Energy Arc Flash Event Introduction: The team identified an URI associated with the licensees actions to implement fire watches following the 3A 4kV switchgear high energy arc flash . These actions potentially resulted in inadequate fire detection capability in the 3B 4kV switchgear room for a period of up to 58 hours following the event on March 18, 2017. Description : The arc flash in the 3A 4kV switchgear room activated all spot type and early warning smoke detectors in the 3A 4kV switchgear, 3B 4kV switchgear and 3/A/B 480V Load Center rooms. These detectors were not reactivated until 62 hours later on March 21, 2017, (58 hours following completion of smoke removal activities) . After the event , the 3B 4kV switchgear was the protected train of equipment. Due to the risk significance of switchgear room 3B, Procedure 0 -ADM -016.4, Fire Watch Program, require d a continuous fire watch with one smoke detector out of service. For the 3/A/B 480V Load Center, Procedure 0 -ADM -016.4 required an hourly fire rove for detectors out of service. The licensee had established an hourly fire rove before the incident for all the affected rooms that was temporarily suspended for scene safety and subsequent investigation. The licensee was unable to document a continuous fire watch for 58 hours following the smoke removal activities in switchgear room 3B until the detectors were reactivated. Fire watches were posted after the incident to cover switchgear room 3A , which was the non- credited train of equipment. In addition, for approximately 22 hours following smoke removal activities, the individuals covering switchgear room 3A did not keep fi re watch 14 logs and for a period of time the individuals stayed outside the room with the entry door closed. The team noted the cause of this deficiency was primarily due to lack of training and guidance for individuals performing the fire watches. As a result of inactive smoke detectors and no fire watches in switchgear room 3B, the credited train was without smoke detection for approximately 58 hours following smoke removal activities. Due to the risk significance of the room, licensee procedures required a continuous fire watch with one detector out of service. An URI has been opened for additional review to identify whether a performance deficiency existed related to the licensees fire watch actions following the arc flash event on March 18 . (URI 05000250, 251/2017008- 01, Potential Failure of Fire Detection Capability on Credited Train of Equipment Following High Energy Arc Flash Even |
| 05000250/FIN-2017001-02 | 2017Q1 | Green | H.1 | NRC identified | Failure of Vital Battery Chargers Due to Conductive Dust / Particulate Foreign Material Exclusion | Annual Sample: (Opened) Unresolved Item (URI): Failure of Battery Chargers Due To Conductive Dust / Particulate Foreign Material Exclusion 18 a. Inspection Scope: The inspectors performed an in-depth review of AR 2183537 that documented an equipment apparent cause evaluation (EACE) associated with three Unit 3 battery chargers that tripped while in service. Thermo-Lag was being installed in support of fire protection modifications for Turkey Points transition to a risk-informed fire protection program, i.e. NFPA 805. The inspectors reviewed the associated corrective actions to verify they were completed as prescribed and that open actions were scheduled to complete commensurate with the safety significance of the activity. The inspectors walked down the battery chargers to verify selected corrective actions were completed and walked down the modification to HVAC unit V78 that was installed to prevent air from blowing directly into the battery charger ventilation louvers. The inspectors reviewed ARs that were generated during the EACE and evaluated the licensees disposition of these ARs to verify the licensees actions were in accordance with licensee procedure, PI-AA-104-1000, Corrective Action. During this inspection, on March 18, 2017, in a separate location of the plant, the 3A 4kV switchgear bus arc flashed in the reactor coil cubicle causing the 3A 4kV switchgear bus protective relay circuits to automatically deenergize the bus. The inspectors attended the licensees RCE failure investigation team meetings on this issue to obtain updates and gather facts on the arc flash and failed switchgear. The licensees RCE related to the 3A 4kV switchgear failure was in process at the end of this inspection period. The 3A 4kV switchgear room was undergoing Thermo-Lag passive fire barrier installation which was similar to the work in the new electrical equipment room (NEER) that housed the battery chargers. Documents reviewed are listed in the Attachment. This inspection constitutes one sample. b. Findings: Introduction: A URI was opened to determine if there is a performance deficiency related to the battery charger trips in the NEER and failure of the 3A 4kV switchgear bus. Description: On February 2, 2017, the 3A2 vital battery charger input breaker and motor control center (MCC) supply breaker tripped. Four minutes later, the D51 battery charger input breaker tripped. Subsequently, on February 8, 2017, the 3B2 vital battery charger input breaker and MCC supply breaker tripped, and a loud bang and possible flash were reported to have occurred in the lower level near the 4D MCC which supplies 480 Vac to the 3B2 charger. On February 13, the 4A2 and 4B2 battery chargers had difficulty load sharing with redundant battery chargers operating on their associated battery busses. The ARs associated with these separate issues include: AR 2184506, AR 2183540, AR 2183773, and AR 2185218. The licensee initiated an EACE on these issues, AR 2183537. For the battery charger trips that occurred on February 2, the licensee noted that Thermo-Lag work was in progress near the chargers in the NEER. At the time of the breaker trips, several employees were in the NEER performing cleanup from the Thermo-Lag activities. The licensee discovered a notable level of dust on horizontal surfaces in the NEER as well as inside the 3A2 and D51 battery charger cabinets. The licensee concluded the dust was conductive. The 3A2, D51 and 3B2 chargers, which were all located near each other and in the same room elevation, were cleaned and returned to service. The 4A2 and 4B2 battery chargers were also cleaned but it was noted those 19 chargers were in the same room but at a lower elevation. On February 8, the 3B2 charger tripped, despite it having been previously cleaned. It was noted at the time of the 3B2 charger trip that there were several employees installing Thermo-Lag in the NEER. The licensee concluded that the apparent cause of the breaker trips was conductive dust/particulate that may have been created by Thermo-Lag passive fire barrier installation in the vicinity of the battery chargers. The dust/particulate became airborne and settled on charger components. Corrective actions included cleaning all the chargers in the room and installing a modification which provided a sheet metal barrier on top of the D51, 3A2 and 3B2 battery chargers to deflect air from HVAC Unit V78 being blown directly into the louvered charger electrical cabinets. On March 18, 2017, in a separate location of the plant, the Unit 3A 4kV switchgear room, the 3A 4kV switchgear bus arc flashed in the reactor coil cubicle. The arc flash resulted in an explosion and the 3A 4kV switchgear bus was automatically deenergized by protective relay circuits. Similar to the NEER that housed the battery chargers, the 3A 4kV switchgear room was undergoing Thermo-Lag passive fire barrier installation. The deenergized 3A 4kV switchgear bus resulted in a Unit 3 automatic reactor trip. This event and NRC follow-up is described in section 4OA3 of this report. The licensee promptly chartered an RCE team to investigate the failure of the 4kV bus. The licensee noted that prior to the arc flash there were several employees in the 3A 4kV switchgear room performing similar Thermo-Lag installation. As an immediate corrective action, the licensee stopped all Thermo-Lag installation work in the entire fleet. The licensees RCE plan included determining if there were any common causes with the battery charger trips and the 4KV switchgear failure due to Thermo-Lag installations. A URI was identified because additional review is needed to determine if there were any common causes between the battery charger trips and anomalies and the 3A 4kV switchgear bus arc flash and to determine if this issue of concern constitutes a violation. Specifically, the inspectors will review the licensees RCE of the failed 4kV switchgear to determine if there are causes and corrective actions which were not identified during the investigation of the battery charger trip EACE, and if corrective actions could have prevented the 3A 4kV switchgear bus arc flash. (URI 05000250/2017001-02, Failure of Vital Battery Chargers Due to Conductive Dust / Particulate Foreign Material) |
| 05000250/FIN-2016004-01 | 2016Q4 | Green | H.1 | Self-revealing | Unrecognized Inoperable Reactor Protection System Instrument Channel | A self-revealing NCV of Technical Specification (TS) Limiting Condition for Operation (LCO) 3.3.1 was identified for the licensees failure to input the correct Eagle 21 resistance temperature detector (RTD) coefficients into the Eagle 21 reactor protection system (RPS) which resulted in channels being inoperable for longer than their allowed outage times. Immediate corrective actions to restore compliance included inputting the correct RTD coefficients into the Eagle 21 RPS. Planned corrective actions to prevent recurrence included revising engineering procedures to include validation that the RTD coefficients were derived via the correct methodology. This issue was entered into the licensees corrective action program as action request (AR) 02129632. The licensees failure to input the correct RTD coefficients into the Eagle 21 RPS was 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 adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage) because the specified safety function of each functional unit was not met. The inspectors evaluated the significance of this finding and determined the finding was of very low safety significance (Green) because the finding did not affect the function of other redundant or diverse methods of reactor shutdown. The NRC assigned a cross cutting aspect associated with the Resources element of the Human Performance area because the licensee failed to ensure that procedures related to RTD replacement contained adequate information for verifying and inputting correct RTD coefficients (H.1). |
| 05000250/FIN-2016008-01 | 2016Q4 | Green | Licensee-identified | Licensee-Identified Violation | Turkey Point Nuclear Generating Station, Unit 4, Renewed Facility Operating License 3.D, Fire Protection, stated that Florida Power and Light (FPL) 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. NFPA 805, Section 2.4.2.2.2 (b), Common Enclosure Circuits, required circuits that share a common enclosure with circuits required to achieve nuclear safety performance criteria shall be identified for their impact on the ability to achieve nuclear safety performance criteria. Contrary to the above, since 2014, the licensee failed to identify circuits that impact the ability to achieve nuclear safety performance criteria as a result of the effects of fire on circuits that share a common enclosure with the Unit 4 4kV switchgear. The violation was determined to be of very low safety significance based on risk evaluation provided by the licensee and reviewed by NRC senior reactor analyst. The licensee entered this issue into their corrective action program as action request 2134673. | |
| 05000251/FIN-2016003-01 | 2016Q3 | Green | H.5 | NRC identified | Failure to provide adequate flood protection for the 4A RHR train | The NRC inspectors identified a non-cited violation (NCV) of Technical Specification (TS) 6.8.1, for the licensees failure to implement required housekeeping controls in the 4A residual heat removal (RHR) pump room to ensure flood protection devices would not be damaged or otherwised clogged. Specifically, the licensees failure to adequately implement station housekeeping procedure MA-AA-100-1008 to ensure flood protection devices in the 4A RHR pump room were not challenged was a performance deficiency. Immediate corrective actions included removing the debris, entering this issue into the corrective action program (CAP), and initiating a past-operability review. The inspectors determined the performance deficiency to be more than minor because it was associated with the protection against external factors attribute of the mitigating systems cornerstone and there was reasonable doubt of operability which if left uncorrected could have adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Using Manual Chapter 0609, Appendix A, The Significance Determination Process for Findings-At-Power, the inspectors screened the finding as Green because it did not involve the total loss of any safety function. The inspectors assigned a cross cutting aspect in the area of human performance associated with the work management element because the organization failed to adequately implement a process to control work activities in a high-risk flood area, and did not adequately identify and manage risk associated with the flood-sensitive area (H.5) (Section 1R06). |
| 05000250/FIN-2016003-03 | 2016Q3 | Green | H.12 | Self-revealing | Improper ECC Fuse Installation | A self-revealed Green finding and associated Non-cited Violation (NCV) of Technical Specification (TS) Limiting Condition for Operation (LCO) 3.6.2.2 was identified for the failure to properly insert the control power fuse for the 3B Emergency Containment Cooler (ECC) fan. The ECC unit was determined to be inoperable for greater than the allowed outage time of 72 hours and the actions required by TS LCO 3.6.2.2, Action A, were not taken. An immediate corrective action was taken to adjust the fuse holder clips on the 3B ECC breaker to provide a tight fit. Additional corrective actions initiated by the licensee in AR 2108256 included a review of recently replaced similar breakers on Units 3 and 4 to identify and schedule inspection of fuse tightness. The inspectors determined that the finding was more than minor because it was associated with the Mitigating Systems cornerstone attribute of Equipment Performance and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the 3B ECC was not available to automatically start upon receipt of a safety injection signal, and during periods with two ECCs concurrently inoperable, the ECC system would not have been able to perform its specified safety function. To determine the significance of the finding, a Senior Reactor Analyst performed a bounding risk assessment by failing all three containment coolers in the Turkey Point Standardized Plant Analysis Risk (SPAR) model for the entire exposure time of 72 days. The dominant accident sequence was a very small loss of coolant accident (LOCA) where high head safety injection fails for independent reasons. The delta-core damage frequency (CDF) due to the performance deficiency was 1E-8. The low risk result was driven by the low frequency of LOCAs, the limited exposure time, and the low risk value of the containment coolers themselves. The finding was determined to be of very low safety significance (Green). This finding was assigned a cross cutting aspect associated with the avoid complacency element of the human performance area because the licensee failed to confirm fuse holder tightness following implementation of breaker maintenance. The licenee failed to recognize and plan for the possibility of mistakes, latent issues, and inherent risk, even while executing successful outcomes. |
| 05000250/FIN-2016007-01 | 2016Q3 | Green | NRC identified | Failure to Provide Adequate Guidance to Prevent LCSWGR Heat-up | The NRC identified a non-cited violation of Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, for the licensees failure to provide adequate procedural guidance to ensure that the temperature in the Load Center Switchgear Room (LCSWGR) remains below the design temperature of 104 F. The licensee entered the issue into the corrective action program and updated the procedure to include a specific guidance to the operator during a loss of air conditioning. This performance deficiency was determined to be more than minor because it was associated with the Procedure Quality attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, failure to provide adequate procedural guidance to prevent operators from opening the east door (el. 18) in the 3A Switchgear Room (SWGR) when the Emergency Diesel Generator (EDG) 3A is operating (i.e., under Loss of Offsite Power conditions) would cause temperatures to rise above the room design temperature of 104 F. The team determined the finding to be of very low safety significance (Green) because the finding was a deficiency affecting the design of a mitigating structure, system, or component (SSC), and the SSC maintained its operability or functionality. This finding was not assigned a cross-cutting aspect because the issue did not reflect present licensee performance. | |
| 05000250/FIN-2016007-02 | 2016Q3 | Green | NRC identified | Failure to Correct Reactor Coolant Loop Check Valve 312-As Failure to Fully Seat | The NRC identified a non-cited violation of Title 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Actions, for the licensees failure to correct an identified condition adverse to quality involving a failure of charging system check valve 3-312A to fully seat due to internal component wear. The licensee entered the issue into the corrective action program and took corrective actions to replace the valves internal components. This performance deficiency was determined to be more than minor because it was associated with the Equipment Performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to take appropriate corrective actions to address internal component degradation of check valve 3-312A adversely impacts the capability of charging system to isolate and provide back leakage protection to the Chemical Volume and Control System (CVCS) from the Reactor Coolant System (RCS). The team determined the finding to be of very low safety significance (Green) because the valves safety related function of opening to provide a boration flowpath to the RCS was maintained. This finding was not assigned a cross-cutting aspect because the issue did not reflect present licensee performance. | |
| 05000250/FIN-2016003-02 | 2016Q3 | Green | NRC identified | Communication of an NRC Inspector Presence by Security Personnel | The NRC identified an NCV of 10 CFR 50.70, Inspections, paragraph (b)(4), for the licensees failure to ensure that the arrival and presence of an NRC inspector is not communicated to persons at the facility. The licensees actions of announcing the presence and location of an NRC inspector during an unannounced inspection in the protected area was a performance deficiency. Interim corrective actions included providing a site-wide communication to all employess and providing training briefs during shift turnovers informing employees of the regulation. The licensee entered this issue into the CAP as AR 2155881. The NRC evaluated this issue under the traditional enforcement process because the act of announcing NRC presence could impact NRC ability to perform its regulatory function. Specifically, the NRC relies on its ability to perform unannounced inspections to evaluate licensee performance, and communicating the presence and location of NRC inspectors affects their ability to perform these inspections, and as such the regulatory function is impacted. Because the violation was determined to be of very low safety significance, was not repetitive or willful, and was entered into the CAP, this violation is being treated as a Severity Level IV non-cited violation consistent with the NRC Enforcement Policy. This violation was evaluated under the traditional enforcement process and thus does not have a cross cutting aspect (Section 4OA2). | |
| 05000250/FIN-2016009-02 | 2016Q2 | NRC identified | Failure to Comply with Fire Watch Audit Procedure Requirements | NRC Licenses DPR-31 (Turkey Point Unit 3) and DPR-41 (Turkey Point Unit 4), License Condition D, Fire Protection, states, in part, that FP&L shall implement and maintain in effect all provisions of the approved Fire Protection Program as described in the Updated Final Safety Analysis Report (UFSAR) for Turkey Point Units 3 and 4. . . . Section 7.1 of Appendix 9.6A of the UFSAR for Turkey Point Units 3 and 4 states that (t)he Fire Protection Program was established by procedures (citing Procedure 0-ADM- 016). These procedures identify the various positions responsible for the fire protection program implementation, and outline requirements for fire prevention, detection, and suppression. Section 3.2 of FP&L Administrative Directive FPAD-032, Hourly Fire Watch Rove Audit, states that the NPT performing this directive is responsible for . . . (e)nsuring directive is performed and completed as described. Section 5.1 of FPAD-032 states that the audit is to be performed on the 2nd and 4th Tuesday of each month, by selecting a random 24-hour period within the prior 7 or 3 days. Contrary to the above, on multiple occasions between November 2014 and April 2015, hourly fire watch audits were not performed in accordance with Section 5.1 of FPAD- 032. Specifically, the Fire Watch Shift Supervisor (FWSS) responsible for conducting hourly fire watch rove audits (FWSS auditor) did not select random 24-hour periods within the previous 7 or 3 days to perform the audits. Instead, the FWSS auditor selected audit dates in advance and notified other FWSS of the days the audits were going to be performed. | ||
| 05000250/FIN-2016002-01 | 2016Q2 | Green | H.14 | NRC identified | Failure to Update the Final Safety Analysis Report with Applicable Safety System Criteria | NRC inspectors identified a SL IV, NCV of 10 CFR 50.71(e), Maintenance of Records, Making of Reports. The licensee failed to include Eagle 21 licensing basis information into the Updated Final Safety Analysis Report (UFSAR). The Eagle 21 licensing basis information was specified in License Amendment (LA) numbers 135 (Unit 3) and 140 (Unit 4). The licensee entered the issue into their corrective action program (CAP) as action request (AR) 2048916 to update the UFSAR with the design and licensing basis for the Eagle 21. The failure to update the UFSAR was a performance deficiency that was determined to be minor because it did not meet the more than minor screening criteria. Because the issue impacted the NRCs ability to perform its regulatory process, the inspectors evaluated the violation using the traditional enforcement process. The inspectors determined the issue was a SL IV violation because it met violation example 6.1.d.3. The violation represented a failure to update the Final Safety Analysis Report (FSAR) as required by 10 CFR 50.71(e), but the lack of up-to-date information has not resulted in any unacceptable change to the facility or procedures. Cross-cutting aspects are not assigned to traditional enforcement violations. |
| 05000250/FIN-2016002-03 | 2016Q2 | Green | H.7 | Self-revealing | Failure to Post a High Radiation Area | A self-revealing, Green, NCV of Technical Specification (TS) 6.12.1, was identified by health physics inspector(s) for the failure to post a high radiation area (HRA). Specifically, on April 6, 2016, the licensee failed to post the area by the exterior wall of the Unit 4 spent fuel pool (SFP) on the Auxiliary Building roof as a HRA. This performance deficiency was determined to be more than minor because it was associated with the Occupational Radiation Safety Cornerstone attribute of Human Performance, and adversely affected the cornerstone objective of ensuring adequate protection of worker health and safety from exposure to radiation from radioactive material during routine civilian nuclear reactor operation. Specifically, the failure to post and control HRAs can allow workers to enter HRAs without knowledge of the radiological conditions in the area and result in the receipt of unintended occupational exposure. The finding was evaluated using the Occupational Radiation Safety SDP. The finding was not related to the As Low As Reasonably Achievable (ALARA) planning, did not involve an overexposure or substantial potential for overexposure, and the ability to assess dose was not compromised. Therefore, the inspectors determined the finding to be of very low safety significance (Green). This finding involved the cross-cutting aspect of Human Performance, Work Management (H.7) because the organization failed to implement its process for planning and controlling access to HRAs on the Auxiliary Building roof when fuel bundle movement were still ongoing. The violation was entered into the licensees CAP as AR 02123851. |
| 05000250/FIN-2016002-02 | 2016Q2 | Green | H.14 | NRC identified | Failure to Correct Conditions Adverse to Quality Associated with the Eagle 21 System | NRC inspectors identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, for a failure to correct a condition adverse to quality. The licensee identified that the ability to test the Eagle 21 was degraded but failed to take adequate corrective actions to correct the condition. The licensee entered the issue into their CAP as ARs 2023314 and 02145155. The performance deficiency was determined to be more than minor because it was associated with the Equipment Performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, not using core operating limits report (COLR) specified time-constants in surveillance requirement (SR) tests to demonstrate operability of the Eagle 21 system adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of the Thermal Over-Power (OPT) and Thermal Over-Temperature (OTT) reactor trip algorithms. The finding was determined to be of very low safety significance (Green) because defense in depth of the reactor protection system (RPS) existed to trip the unit via alternate and diverse means. The inspectors determined the finding was indicative of present licensee performance and was associated with the cross-cutting aspect of human performance, in the area of conservative bias, because individuals failed to evaluate a proposed action to determine if it was safe in order to proceed, rather than unsafe in order to stop (H.14). |
| 05000250/FIN-2016009-01 | 2016Q2 | Severity level III | NRC identified | Inaccurate Fire Watch Logs | 10 CFR 50.9(a), Completeness and accuracy of information, states, in part, that information required by statute or by the Commissions regulations, orders, or license conditions to be maintained by...the licensee shall be complete and accurate in all material respects. NRC Licenses DPR-31 (Turkey Point Unit 3) and DPR-41 (Turkey Point Unit 4), License Condition D, Fire Protection, states, in part, that FP&L shall implement and maintain in effect all provisions of the approved Fire Protection Program as described in the Updated Final Safety Analysis Report (UFSAR) for Turkey Point Units 3 and 4. . . . Section 7.1 of Appendix 9.6A of the UFSAR for Turkey Point Units 3 and 4 states that (t)he Fire Protection Program was established by procedures (citing Procedure 0-ADM- 016). These procedures identify the various positions responsible for the fire protection program implementation, and outline requirements for fire prevention, detection, and suppression. Section 7.2 of Appendix 9.6A of the UFSAR states that Fire protection specifications are presented in the Fire Protection Program (Procedure 0-ADM-016). Section 3.13.1 of FP&L Procedure 0-ADM-016 states that The Fire Watch is responsible for being constantly alert and watchful for flames, smoke, the odor of burning materials, any safety hazards and/or poor housekeeping practices. Additional duties and responsibilities are described in 0-ADM-016.4, Fire Watch Program. Section 2.2.2 of Procedure 0-ADM-016.4 states that hourly fire watch logs and badge transaction reports are to be kept for one year following the origination date. Contrary to the above, on multiple occasions between November 2014 and April 2015, the licensee maintained records of hourly fire watch logs required by FP&L Procedure 0- ADM-016.4 that were not complete and accurate in all material respects. Specifically, Fire Watch Shift Supervisors (FWSS) initialed and signed hourly fire watch logs indicating that hourly fire watches had been completed, with all required areas checked, when on multiple occasions some areas had not been checked or hourly fire watches had not been performed at all. The hourly fire watch patrol records are material to the NRC because they provide evidence of compliance with regulatory requirements. | |
| 05000250/FIN-2016001-01 | 2016Q1 | Green | Self-revealing | Failure to Fully Implement Procedure QI3-PTN-1, Design Control | A self-revealing finding was identified for the licensees failure to provide complete instructions in Maintenance Support Package (MSP) 06-053 for the Isophase Bus Enclosure Collar replacement modification in the Turkey Point switchyard. Specifically, the control power circuitry termination points in the 8W43 switchyard breaker were not identified and documented in the associated MSP for removal as required by procedure QI 3-PTN-1, Design Control. As a result, a direct current (DC) ground was introduced to the back-up protection relay by a b contact when the 8W43 breaker was opened during a planned bus switching sequence. The DC ground on the back-up protection circuitry actuated the protection relay and caused both the supply breakers for the Unit 3 startup transformer (SUT) to open resulting in a loss of off-site power (LOOP) for Unit 3. The licensee entered this performance deficiency in their corrective action program (CAP) as action request (AR) 02092653 The performance deficiency was more than minor because it was associated with the procedure quality attribute of the initiating events cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during power operations. Specifically, the failure to apply procedure QI 3-PTN-1 in its entirety allowed for a DC ground to be introduced to the DC back-up protection relay circuit resulting in a LOOP. Because this finding caused a LOOP and a resultant loss of residual heat removal (RHR), a detailed risk evaluation was required per IMC-0609, Appendix G, Shutdown Operations Significance Determination Process. A Senior Reactor Analyst assessed the risk significance and concluded it was of very low safety significance (Green). The risk of the event was mitigated by the multiple means that the licensee had available to them to either: 1) restore electrical power to the safety related buses, or; 2) establish alternate means of heat removal either via the steam generators or via primary feed and bleed. The inspectors did not identify a cross-cutting aspect associated with this finding because it was not indicative of current performance since the modification package was implemented greater than three years ago. | |
| 05000250/FIN-2015004-02 | 2015Q4 | Green | Licensee-identified | Licensee-Identified Violation | 10 CFR 50.48 states that each operating nuclear power plant must have a fire protection plan that satisfies Criterion 3 of Appendix A of this part. Turkey Point Renewed Operating License condition D, for Units 3 and 4, states that the licensee shall implement and maintain in effect all provisions of the approved FPP as described in the UFSAR Appendix 9.6A. The approved FPP is implemented, in part, by 0-ADM-016, Fire Protection Program, as referenced in Section 7.2 of UFSAR Appendix 9.6A. Section 5.6 of 0-ADM-016 requires that, for non-functional post-fire safe shutdown components, engineering evaluations should identify appropriate compensatory actions, including hourly fire roves. Contrary to the above, between May 1st, 2014, and April 23rd, 2015, hourly fire watch patrols were not conducted on numerous occasions in fire zones that required regular hourly tours due to fire protection equipment impairment. The failure to perform the fire watch tours did not cause the inoperability of any equipment but resulted in the loss of a defense-in-depth feature for fire detection in fire zones affected by an impaired or non-functional fire safety component or feature. This violation was associated with the Mitigating Systems Cornerstone and affected the cornerstone objective of ensuring the availability, reliability and capability of the systems that respond to initiating events to prevent undesirable consequences. The inspectors determined the finding to be of very low safety significance (Green) after performing a detailed risk evaluation in accordance with Manual Chapter 0609, Appendix A, because the missed fire watch tours reflected a low degradation of the Fire Prevention and Administrative Controls FPP element in that other area fire protection defense-in-depth features such as automatic fire detection (smoke detectors), automatic fire suppression capability (sprinklers), manual suppression capability (fire brigade), and safe shutdown capability from the main control room were still available. The licensee entered this violation into their CAP as AR 02056905. | |
| 05000251/FIN-2015004-01 | 2015Q4 | Green | H.8 | Self-revealing | Failure to correctly follow procedure 3-PMI-072.6, Steam Dump to Atmosphere Control Loop Calibration | A self-revealing NCV of Technical Specification (TS) 6.8.1, Procedures and Programs, was identified when the licensee failed to properly implement procedure 3-PMI-072.6, Steam Dump to Atmosphere Control Loop Calibration. Specifically, the licensee incorrectly installed a temporary electrical jumper in reactor operator console 3C02 instead of 3C04, in contrast to Step 6.3.2 of 3-PMI-072.6. This action resulted in actuation of a 3B 4160 volt (V) vital bus lockout circuit causing loss of power to the B train of Unit 3 (U3) spent fuel pool (SFP) cooling. Immediate corrective actions were taken to remove the jumper and restore the B train of SFP cooling. The licensee entered the condition in its corrective action program (CAP) as action request (AR) 02088911 and 02088914. The performance deficiency was determined to be more than minor because it was associated with the human performance attribute of the barrier integrity cornerstone and adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers (fuel cladding, reactor coolant system (RCS), and containment) protect the public from radionuclide releases. In addition, the performance deficiency, if left uncorrected, had the potential to lead to a more significant safety concern. The finding was screened using IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, Tables 2 and 3, dated July 1, 2012, and Appendix G Attachment 1, Shutdown Operations Significance Determination Process Phase 1 Initial Screening and Characterization of Findings, Exhibit 4 for Barrier Integrity, dated May 9, 2014. The inspectors determined the finding was of very low safety significance (Green) because it was not associated with low temperature over pressurization, freeze seals, steam generator nozzle dams, criticality, drain down or leakage paths, or the containment barrier. Furthermore, one train of SFP cooling remained in operation, the rate of SFP temperature rise was low (~ 2 F/hour), and additional methods remained available to limit SFP temperature rise. This finding was assigned a cross cutting aspect associated with the procedure adherence element of the human performance area because the licensee failed to correctly execute step 6.3.2 of procedure 3-PMI-072.6. |
| 05000251/FIN-2015003-01 | 2015Q3 | Green | H.1 | Self-revealing | Inadequate Work Instructions for Replacing Main Generator Current Transformers | A self-revealing finding was identified for the licensees failure to provide adequate instructions for performing work on the Unit 4 main generator protection control circuitry. As a result, the lugged connections on an installed current transformer lacked the appropriate tightness causing increased electrical resistance and ultimately catastrophic failure of a lug connection. The lug failure produced an open circuit condition on the current transformer causing the generator protection circuit to actuate. This resulted in a turbine trip and reactor trip. Corrective actions included replacing the damaged lug and torqueing all the current transformer lug connections to the vendor recommended value. A root cause evaluation was performed and a revision made to maintenance procedure 0-PME-090.03, Maintenance of Isophase Neutral Bus and Grounding Transformer Connection Assemblies, to include additional instructions on torqueing the lug assemblies. The licensee entered this performance deficiency in their corrective action program (CAP) as action request 02047137. The performance deficiency was more than minor because it was associated with the procedure quality attribute of the initiating events cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during power operations. Specifically, the work package associated with engineering modification package EC 246904 and work order 40063905 directed the technician to connect the current transformer (CT) lugs hand tight and did not require torqueing per the vendor specified torque value. The inspectors screened the significance of the finding using Manual Chapter 0609, Appendix A, Exhibit 1, Transient Initiators. The inspectors determined the finding was of very low safety significance (Green) because the finding did not result in a reactor trip and a loss of mitigation equipment relied upon to transition the plant to a stable shutdown condition. The finding was associated with a cross-cutting aspect in the resources component of the human performance area because the licensee failed to ensure an adequate work instruction document was available to support nuclear safety (H.1) (Section 4OA3). |
| 05000250/FIN-2015404-01 | 2015Q3 | Green | NRC identified | Security | ||
| 05000250/FIN-2015003-02 | 2015Q3 | Green | Licensee-identified | Licensee-Identified Violation | 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, required, in part, that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and nonconformances are promptly identified and corrected. Contrary to the above, after the licensee determined that the site had an inadequate relay PM program (AR 02053778), they failed to identify that the FMR for the 3B EDG needed a 10 year replacement PM. As a result, during the monthly surveillance run of the 3B EDG, the 3B EDG was rendered inoperable when the 3B EDG output breaker failed to close due to the failure of the 3B EDG FMR. The FMR for the 3B EDG had been installed since 1991. A detailed risk evaluation was performed on this licensee identified violation and was determined to be of very low risk significance, i.e., < 1E-6 (Green). The dominant risk result was a grid-related Loss of Offsite Power where multiple EDGs fail and neither offsite power nor the EDGs are recovered. This violation was associated with the Mitigating Systems Cornerstone and determined to be of very low safety significance (Green) after performing a detailed risk evaluation in accordance with Manual Chapter 0609, Appendix A. The licensee entered this violation into their CAP as AR 02024373. | |
| 05000250/FIN-2015201-01 | 2015Q2 | Green | NRC identified | Security | ||
| 05000251/FIN-2015002-01 | 2015Q2 | Green | H.1 | Self-revealing | Inadequate General Operating Procedure to Prevent Inadvertent AFAS While Performing a Reactor Plant Planned Shutdown | A self-revealing non-cited violation (NCV) of Technical Specification (TS) 6.8.1, Procedures, was identified for the licensees failure to maintain adequate guidance in procedure 4-GOP-103, Power Operation to Hot Standby. Specifically, 4-GOP-103 did not contain adequate instructions to control reactor power prior to opening the reactor trip breakers in order to minimize steam generator inventory loss to prevent an auxiliary feed water (AFW) system actuation. As a result, the AFW actuation system (AFAS) actuated unexpectedly during a planned unit shutdown resulting in an excessive reactor coolant system cool down and the operators closing the main steam isolation valves. Corrective actions included entering this issue into their corrective action program (CAP) and revising the procedure to reduce reactor power to at least 20 percent to prevent steam generator inventory loss due to shrinkage following a manual reactor trip during a planned reactor plant shutdown from power operations to hot standby. The performance deficiency was more than minor because it is associated with the procedure quality attribute of the initiating events cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the failure to have specific guidance in procedure 4-GOP-103 to ensure reactor power is lowered to at least 20 percent prior to initiating a manual reactor trip during a planned shutdown resulted in an inadvertent AFAS actuation, reactor coolant system cool down, closing of the main steam isolation valves, and a reduced safe shutdown margin. The inspectors screened the finding using IMC 0609, Appendix A, The Significance Determination Process for Findings at Power, Exhibit 1, Initiating Events Screening Questions. The inspectors determined that this finding was of very low safety significance (Green) 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 was associated with a cross-cutting aspect in the resources component of the human performance area because the licensee failed to ensure an adequate general operating procedure was available to support nuclear safety. |