|Report date||Site||Event description|
|05000296/LER-2017-001||31 October 2017||Browns Ferry|
On September 1, 2017, at approximately 1006 Central Daylight Time (CDT), Browns Ferry Nuclear Plant (BFN) Unit 3 3A Residual Heat Removal (RHR) system pump failed to start during performance of Surveillance 3-SR-184.108.40.206 (RHR I), Quarterly RHR System Rated Flow Test Loop I. The apparent cause was the Electrical Preventive Maintenance Instruction for 4kV Wyle/Siemens Horizontal Vacuum Circuit Breaker (Type-3AF) and Compartment Maintenance was revised to include steps to secure the breaker's mounting hardware which caused internal binding of the indication flag. Binding of the indication flag prevented the closing spring of the breaker from charging and the breaker from closing on demand. As a result, automatic start of the 3A RHR pump was prevented. On September 1, 2017, at approximately 1633 CDT, the 3A RHR Pump was declared operable following lubrication and testing of the breaker's indication flag mounting bolt.
A Past Operability Evaluation concluded that the 3A RHR Pump was inoperable from July 26, 2017 to September 1, 2017, which exceeded the Technical Specification allowed outage time. During this time, the 3B, 3C, and 3D RHR pumps would have started automatically upon receipt of an Emergency Core Cooling System (ECCS) initiation signal or from an Operator manual start demand from the Control Room. Based on results from the Probability Risk Assessment and Engineering inspections, there was no significant risk to the health and safety of the public or plant personnel for this event. The Corrective Action to reduce the probability of similar events occurring in the future will be addressed by revising the Electrical Preventive Maintenance Instruction for 4kV Wyle/Siemens breakers to ensure freedom of movement of the indication flag is present during the breaker inspection.
|05000260/LER-2017-004||7 July 2017||Browns Ferry|
On May 8, 2017, the Tennessee Valley Authority was presented with as-found testing results indicating that four of the thirteen Main Steam Relief Valves (MSRVs) from Browns Ferry Nuclear Plant, Unit 2, were outside the +/- 3 percent setpoint band required for their operability. Troubleshooting determined that three MSRVs exceeded their setpoints when their valve discs failed by corrosion bonding to their valve seats. The valve discs were previously platinum coated to prevent this, but the valve seat's rough Stellite surface caused the coating to delaminate. This was the first Unit 2 MSRV service interval to implement the improved surface treatment since a resolution to the delamination issue was identified in 2015. The valve which failed below its setpoint band was determined to have a faulty pilot spring.
These four MSRVs were found to have been inoperable for an indeterminate period of time between April 9, 2015, and February 25, 2017, and longer than permitted by Technical Specifications. The affected valves remained capable of maintaining reactor pressure within American Society of Mechanical Engineers code limits. Additionally, the valves' ability to open under remote-manual operation, activation through the Automatic Depressurization System, or MSRV Automatic Actuation Logics were not affected. The valves remained capable of performing their required safety function.
Corrective Actions were to replace all thirteen Unit 2 MSRV pilot valves with pilot valves which had the platinum coating applied in accordance with the revised procedure, and to analyze the pilot valves of the inoperable MSRVs.
The pilot spring was replaced inside the valve which failed below its specification.
|05000260/LER-2017-003||30 May 2017||Browns Ferry|
On March 29, 2017, at 1842 Central Daylight Time (CDT), during Unit 2 start-up, Operations personnel received annunciators for an Intermediate Range Monitor (IRM) Downscale and a Control Rod Withdrawal Block.
Operations personnel noticed that IRM `G' was reading downscale and adjusted the range down one position with no immediate reaction. At 1844 CDT, an upscale spike on IRM `G' caused a half scram on Reactor Protection System (RPS) 'A' trip system. After verifying that the IRM `G' High-High trip signal was cleared, Operations personnel reset the half scram on RPS 'A'. An immediate, concurrent trip signal from IRM 'F' was then received on the RPS '13' trip system, resulting in multiple rods inserting into the core. When Operations personnel identified multiple rods inserting, a manual reactor scram was inserted at 1844 CDT.
The root cause was determined to be a lack of performing electromagnetic and radio-frequency interference noise testing to detect nuclear instrumentation abnormalities.
Corrective Action to Prevent Recurrence is to perform routine pre-outage and outage-related preventive maintenance tasks for noise-induced cable tests to verify the noise has been removed.
|05000260/LER-2017-001||14 April 2017||Browns Ferry|
On February 16, 2017, the spurious failure of a fuse protecting a High Pressure Coolant Injection (HPCI) system flow controller rendered the HPCI system inoperable. Operators replaced both the line and neutral fuses, and restored HPCI availability. Following a period of monitoring the current flow through the fuse and HPCI system operation tests, Operations declared the Unit 2 HPCI system to be Operable on February 17, 2017.
Since HPCI is a single-train safety system, any period of unplanned inoperability constitutes a safety-system functional failure affecting accident mitigation, and is reportable. However, in the event of an emergency, the Reactor Core Isolation Cooling (RCIC) system remained operable, and all other Emergency Core Cooling Systems and the Automatic Depressurization System were available throughout this event to facilitate core cooling.
Failure analysis indicates that the fuse failed when its internal resistor lead and its tension/retraction spring became uncoupled at their soldered junction, as a result of age-induced solder creep. Corrective Actions include the prompt replacement of the failed fuses, determining the population of fuses on the HPCI system and RCIC system that should be replaced on a one-time basis, and to initiate work orders to replace these fuses.
|05000259/LER-2017-001||21 February 2017||Browns Ferry|
On December 21, 2016, at 1228 Central Standard Time (CST), during a performance of the 4KV Shutdown Board (SDBD) C Undervoltage and Time Delay Relay Calibration and Functional Test, personnel discovered a detached restraining strap on a 4kV SDBD C Degraded Voltage Relay Timer. At 1835 CST, Operations personnel declared the relay inoperable. The timer retaining strap was replaced, and the relay was declared operable on December 22, 2016, at 1251 CST.
A Past Operability Evaluation determined that the timer was inoperable from October 5, 2016, until December 22, 2016, exceeding the Technical Specification allowed outage time.
The most likely cause of this event was human error. Rounding of the screw attaching the retaining strap to the backplane of the electrical cabinet in which the timer was housed allowed the retaining strap to become detached. This deficiency was not corrected despite testing and Quality Control verification. Corrective Actions include replacing the retaining strap using a longer screw, identifying relays previously installed under similar plant modifications, and ensuring that work packages for future installation of relays with seismic retaining straps contain steps to obtain adequate screw engagement during strap installation.
|05000259/LER-2016-002||19 September 2016||Browns Ferry|
On July 18, 2016, the Unit 1 High Pressure Coolant Injection (HPCI) System was removed from service for a scheduled maintenance outage. In support of maintenance activities, the HPCI steam line inboard primary containment isolation valve (PCIV) was placed in the closed position. Following the maintenance outage, warmup of the HPCI System commenced on July 20. During this evolution, unexpected system pressure conditions and responses were encountered that indicated the PCIV was not open. Failure to open the valve resulted in the inability to restore HPCI System operability and a reportable safety system functional failure. Because the valve is a PCIV located inside primary containment, the station planned and manually shutdown the reactor on July 26 for troubleshooting and corrective maintenance. A local leak rate test determined the PCIV function was ineffective, and disassembly of the valve found the valve stem severed. Following repair, the PCIV functions and HPCI System were declared operable on July 31 and August 1, respectively. Unit 1 was returned to full power on August 4.
The cause of this event was a tensile failure of the valve stem. The cause analysis concluded that the failure occurred on April 20, 2016, when the valve was stroked for in-service testing. Based on this the PCIV was inoperable longer than allowed by Technical Specifications. Corrective actions include valve repair, procedure revisions to provide additional margin to prevent back-seating, revision of guidance for high speed valve open limit switch settings, and evaluation of the extent of condition population. The safety significance of this event was determined to be low.
|05000260/LER-2016-002||13 September 2016||Browns Ferry|
On March 19, 2016, at approximately 1024 Central Daylight Time (CDT), the Unit 2 High Pressure Coolant Injection System (HPCI) Steam Admission Valve failed to stroke due to a stuck contactor in the valve motor breaker. This rendered the Unit 2 HPCI inoperable, resulting in a Safety System Functional Failure; however the system had previously been declared inoperable for maintenance and the Unit 2 Reactor Core Isolation Cooling System had been verified as operable in accordance with Technical Specifications Limiting Conditions for Operation 3.5.1. On March 20, 2016, at approximately 1103 CDT, Maintenance personnel commenced work to repair the Unit 2 HPCI steam admission valve motor breaker. On March 21, 2016, at approximately 0245 CDT, Unit 2 HPCI was declared operable following completion of all required PMTS.
The cause of the stuck contactor was accelerated cyclic fatigue due to overheating of the motor starter during packing consolidation and MOVATS testing. Corrective actions were to replace the stuck contactor, to clean contactors in similar HPCI valve motor breakers for Units 1 and 3, to determine an allowable maximum number of valve cycles within a given time period , and to revise plant procedures based on the determined cycle limit in order to prevent contactors from sticking due to accelerated cyclic fatigue.
Subsequent review determined the identified condition to be reportable.
|05000296/LER-2016-006||5 August 2016||Browns Ferry|
During a surveillance test on June 8, 2016, the BFN, Unit 3, High Pressure Coolant Injection (HPCI) Turbine Stop Valve Mechanical Trip Valve behaved erratically upon turbine start. Troubleshooting and maintenance on the valve led to discovery of a condition that could have resulted in the HPCI system being unable to perform its required safety function in a Mode where HPCI Operability was required.
The inoperability was caused by the HPCI Turbine Stop Valve Mechanical Trip Valve's Reset Spring, which was deformed and weakened from years of continuous compression. The spring was replaced and the system was returned to service on June 10, 2016.
Corrective actions to prevent recurrence include revising preventive maintenance procedures to specify replacement of the Trip Tappet, Piston, and Reset Spring on a defined periodicity. Additionally, procedures will be revised to require testing the as-left breakaway force a minimum of three times to ensure repeatability.
Preventative maintenance procedures will also be revised to clarify that lift force checks after spring compression adjustments shall be conducted with the auxiliary oil pump running.
|05000296/LER-2016-002||28 July 2016||Browns Ferry|
On February 22, 2016, during routine maintenance of the Browns Ferry Nuclear, Unit 3 Core Spray (CS) system, relays on the 3ED 4kV Shutdown Board were found de-energized. This resulted in loss of the automatic start function of the 3B and 3D CS Pumps, the 3D Residual Heat Removal (RHR) pump, and the D1 Residual Heat Removal Service Water (RHRSW) pump, with normal power to the 3ED 4kV Shutdown Board.
Troubleshooting determined the relay was de-energized due to a failure of the 6-6C contacts on the MJ(52STA) switch associated with the 3ED 4kV Shutdown Board, and a binding of the 52STA Cam Linkage. This was caused by a misalignment of the switch to linkage interface, due to improper installation. The switch was subsequently replaced. Alignment verification instructions will be added to switch replacement procedures.
The duration of inoperability the 3B and 3D CS pumps, 3D RHR pump, and D1 RHRSW pump, was determined was placed in Mode 4. Manual start of these pumps remained available. Automatic start capability of the other Unit 3 CS, RHR, and RHRSW pumps was unaffected by this condition, and the required safety functions of the impacted systems continued to be met.
|05000259/LER-2016-001||21 June 2016||Browns Ferry|
On April 22, 2016, at 1358 Central Daylight Time (CDT), during transfer of the 4160 V (4kV) Shutdown Bus from Alternate to Normal, the Normal Feeder Breaker (BKR 1722) failed to close when the Alternate Feeder Breaker was manually tripped. 4kV SD Bus 2 de-energized, resulting in the loss of 1B and 2B Reactor Protection System (RPS) as well as Steam Jet Air Ejector 1B. Emergency Diesel Generators (EDG) C and D started, but did not tie to the 4kV Shutdown Boards due to Operations personnel immediately re-closing the Alternate breaker and re-energizing 4kV Shutdown Bus 2. Invalid actuations of several Containment Isolation Valves also occurred during this event due to the loss of RPS. At 1530 CDT, EDG C and D were shut down. BFN, Unit 1, was returned to normal operating conditions.
The cause of this event was loose wires in the closing control circuit for BKR 1722 due to work in the vicinity of the control circuit termination points. Corrective actions were to terminate loose wires, using a ring type lug instead of a forked spade type lug, in the closing control circuit for BKR 1722; and to verify Shutdown Bus 2 transferred successfully to BKR 1722. A briefing was provided to Electrical personnel who perform modifications to discuss the potential consequences of installing tie wraps and performing other activities that could adversely affect existing wiring.
|05000296/LER-2016-005||17 June 2016||Browns Ferry|
On April 18, 2016, during a scheduled surveillance, the power to the Main Steam Line (MSL) B Relief Valve failed to transfer to its alternate feeder breaker when the normal feeder breaker was opened. The Automatic Depressurization System (ADS) function of the MSL B Relief Valve was declared inoperable. It was determined that the ADS valve was inoperable from March 26, 2016 to April 19, 2016. The valve's ability to open under normal power was not affected. Five of the six ADS valves remained operable. Only four ADS valves are required to meet the ADS function in the Loss of Coolant Analysis described in the Final Safety Accident Report.
The unavailability of the ADS alternate power source was directly caused by a bus stab on the back of the Molded Case Circuit (MCC) breaker not fully engaging with the bus. This was apparently caused by improper performance of previous post-maintenance testing. The stab was adjusted, the MCC breaker was returned to service, and the MSL B Relief Valve's ADS function was declared operable upon verification of its alternate power supply.
Corrective actions were to determine which load-feeding MCC breakers have a normal and alternate power source, and revise their preventative maintenance procedures to verify that post-maintenance testing includes power source isolation prior to closing the breaker under load. Breaker bus stabs will be replaced.
|05000296/LER-2016-004||6 June 2016||Browns Ferry|
On April 6, 2016, the Tennessee Valley Authority was presented with as-found testing results indicating that three of the thirteen Main Steam Relief Valves (MSRVs) from Browns Ferry Nuclear, Unit 3, exceeded the +1- 3 percent setpoint required for their operability. Troubleshooting determined that the MSRV discs failed by corrosion bonding to their valve seats. The valve discs were previously platinum coated to prevent this, but the valve seat's rough Stellite surface caused the coating to flake off.
It was determined that the MSRVs were inoperable from March 19, 2014 to February 20, 2016. The affected valves remained capable of maintaining reactor pressure within American Society of Mechanical Engineers code limits. Additionally, the valves' ability to open under remote-manual operation, or activation through the Automatic Depressurization System or MSRV Automatic Actuation Logics was not affected. The valves remained capable of performing their required safety function.
Corrective Actions were to replace all Unit 3 MSRVs, to analyze the pilot valves of the inoperable MSRVs, and to revise procedures to verify the pilot disc finish meets its requirements prior to valve assembly.
|05000296/LER-2016-003||25 April 2016||Browns Ferry|
On February 23, 2016, at approximately 0405 Central Standard Time, during performance of Primary Containment Local Leak Rate Testing (LLRT) of the Main Steam lines, the 3B Outboard Main Steam Isolation Valve (MSIV) failed its as-found LLRT. Because the MSIV failed to meet the leak rate limit, Browns Ferry Nuclear Plant, Unit 3, operated longer than allowed by Technical Specification (TS) Limiting Condition for Operation (LCO) 220.127.116.11. In addition, TS LCO 3.0.4 was not met for each applicable Mode change since the last recorded as-found MSIV leak rate test on March 16, 2014, when the leak rates were below the leak rate limit.
The cause of the event was wear on the seating surface of the pilot poppet seat. Corrective action included replacing the valve stem containing a new pilot poppet, resurfacing the seat and restoration of the valve actuator.
The safety significance of this condition was minimal since the 3B Inboard MSIV was available to perform the safety function.
|05000296/LER-2016-001||21 March 2016||Browns Ferry|
On January 19, 2016, at approximately 1100 Central Standard Time (CST), during troubleshooting of the Main Control Room (MCR) green light indication on the 3A Residual Heat Removal (RHR) Pump Motor Breaker Transfer Switch (MBTS), it was discovered that the 3A RHR Pump MBTS had malfunctioned, potentially preventing the pump from starting from the MCR. The 3A RHR Pump was declared inoperable.
On January 20, 2016, at approximately 0030 CST, the 3A RHR Pump was declared operable following replacement of the 3A RHR Pump MBTS.
A Past Operability Evaluation concluded that the 3A RHR Pump was inoperable from January 9 to January 20, 2016, exceeding the Technical Specification allowed outage time. During this time, the 3B and 3D RHR Pumps were also inoperable on January 14, 2016, from 0127 to 0215 CST, resulting in a Safety System Function Failure. A Probabilistic Risk Assessment determined there was a negligible increase in risk.
The cause of this event was failure of the transfer switch to fully latch due to binding resulting from the MBTS being installed greater than its twenty-one year service life with no Preventative Maintenance (PM) performed. Corrective actions include verifying similar transfer switches are latched in the NORMAL positon on BFN, Units 1, 2, and 3, and creating a PM activity with a replacement schedule for these switches.
|05000260/LER-2015-002||17 March 2016||Browns Ferry|
On September 16, 2015, at approximately 0156 Central Daylight Time (CDT), a large steam leak occurred in Unit 2 High Pressure Coolant Injection (HPCI) Room. Operators manually closed 2-FCV-73-3 (HPCI Outboard Isolation Valve) to isolate steam and declared the single train HPCI system inoperable. During the time period that the HPCI system was inoperable, other systems were available to provide the required safety functions. Following repairs, HPCI was declared operable at approximately 1045 CDT on September 19, 2015. Subsequent evaluation determined that HPCI would have met its 8-hour mission time with the identified condition.
The cause of the steam leak was degradation of the valve packing on 2-FCV-73-16 (HPCI Turbine Steam Supply Valve) due to installation of improper packing material in April 2013. The steam leak initiators were mechanical extrusion of packing material and high temperature acid corrosion of the valve stem. Following steam leak initiation, catastrophic packing failure occurred due to steam induced high temperature degradatioi of the PTFE (Teflon) graphite braided packing. The two root causes were conflicting guidance in the Valve Packing Program procedure and the lack of necessary procedural guidance for the station to appropriately address invisible, superheated steam packing leaks. Corrective actions include revising the applicable procedures.
|05000259/LER-2015-005||28 December 2015||Browns Ferry|
On October 29, 2015 at 1149 Central Daylight Time, it was discovered upon receipt of a vendor report that the Main Steam Isolation Valve (MSIV) accumulators on all BFN inboard MSIVs are of insufficient size to provide the MSIV actuators adequate air volume, at the required pressure, to close the MSIV during a Loss of Coolant Accident (LOCA). Therefore, availability of Drywell Control Air (DWCA) nitrogen from the Containment Inerting system or from the Containment Atmospheric Dilution system was determined to be necessary for operability of inboard MSIVs. From December 1, 2012, to the time of discovery, there were multiple occasions where BFN Unit 1, 2, or 3 DWCA systems were aligned to receive nitrogen from the Plant Control Air system, resulting in the inoperability of multiple MSIVs for longer than allowed by BFN Technical Specification Limiting Conditions for Operation 18.104.22.168, Condition A.
The causes of this event were the failure of the original design of the MSIV actuators and accumulators to account for elevated drywell pressure during the time that the MSIVs are required to stroke for a Design Basis LOCA, and the failure to incorporate internal and external operating experience into the BFN Air Operated Valve (AOV) program.
Corrective actions are to issue and implement design changes to resolve negative margin issue with Units 1, 2, and 3 inboard MSIVs, to review calculations for accumulators associated with the Automatic Depressurization System relief valves to ensure they address LOCA conditions, and to ensure design basis calculations are developed for all Category 2 AOVs at BFN in addition to the Category 1 calculation reviews already in progress.
|05000259/LER-2015-004||30 November 2015||Browns Ferry|
On September 29, 2015, during excavation for a potable water leak approximately 46 feet downstream of the Containment Atmospheric Dilution (CAD) B train, a hole was discovered in the 2-inch stainless steel underground CAD supply piping. CAD B train was declared inoperable and Technical Specification Limiting Condition for Operation 22.214.171.124 Condition A was entered. A past operability evaluation determined that the CAD B train would not have been able to provide its specified safety function in Modes 1 and 2 with the identified condition. On October 10, 2015, the CAD B train was declared Operable following repairs. A review of the past three years of operating history determined that both CAD A and B trains were concurrently inoperable/unavailable for a period of nine days. Therefore, this event is also considered a Safety System Functional Failure. Based on a probabilistic risk assessment, the safety significance of this event was low for all three operating units.
The cause for the hole in the CAD B train supply piping is unknown and the time of occurrence was indeterminate. This is considered to be a legacy issue. Corrective actions include developing and performing a piping integrity test to identify any other potential holes in the supply piping for the CAD A and B trains.
|05000296/LER-2015-005||19 October 2015||Browns Ferry|
On August 20, 2015, at 1032 Central Daylight Time (CDT), while installing test equipment on the 3ED 4kV Shutdown Board (SD BD), for an online dynamic motor test of the 3D Residual Heat Removal pump motor, the Unit 3 Control Room received degraded voltage alarms and under voltage alarms for the 3ED SD BD. The 3ED 4kV SD BD normal feeder breaker opened, and the 3D Emergency Diesel Generator (DG) fast started and tied onto the board.
Troubleshooting was performed on the 3ED SD BD and on the 3D DG. The failure mode for this event was the clearing of primary and secondary 3ED SD BD metering fuses. The normal feeder breaker was closed, and offsite power to the SD BD was declared operable on August 21, 2015, at 1945 CDT.
A definitive cause could not be identified for the clearing of the fuses. However, corrective actions will be implemented that will address all of the most probable causes, and will minimize the likelihood of recurrence. These actions include performing inspections on circuits used for online dynamic motor testing of motors, removing the potentially faulty test equipment from service, and removing online dynamic motor testing from 4kV motor preventative maintenance.
|05000259/LER-2015-002||21 September 2015||Browns Ferry|
On July 22, 2015, during the performance of a quarterly surveillance, the Unit 1 High Pressure Coolant Injection (HPCI) inboard steam isolation valve closing times were in the high alert range. Due to the inability to analyze the stroke time deviation within the required Technical Specification (TS) limit of four hours, the valve was subsequently declared inoperable in accordance with TS Limiting Condition for Operation (LCO) 126.96.36.199, Primary Containment Isolation Valves, and the HPCI system declared inoperable. As a result of the steam line isolation, the Unit 1 HPCI system was unable to perform its safety function. However, in an emergency, other systems were available to provide the required safety functions. On July 25, 2015, the inboard steam isolation valve and the Unit 1 HPCI system were declared operable.
The apparent cause of this event was the closing stroke time of the HPCI inboard steam isolation valve increased due to the valve coasting further open after motor cutoff resulting in a greater total distance of travel during valve closure, which is likely due to decrease in stem factor in packing loads. Corrective actions include performing diagnostic tests and limit switch timing determinations for the valves on Units 1, 2, and 3, including online testing the Motor Operated Valves on Units 2 and 3 to determine if they are experiencing a similar condition, and if the packing friction for the HPCI inboard steam isolation valve has changed.
|05000260/LER-2015-001||17 August 2015||Browns Ferry|
On June 17, 2015, at approximately 1015 Central Daylight Time (CDT), Browns Ferry Nuclear Plant (BFN) Operations personnel attempted to place BFN, Unit 2, Residual Heat Removal (RHR) Loop 1 into Suppression Pool Cooling (SPC). Upon actuating Hand Switch 2-HS-74-5A from the Control Room, Operations personnel observed that 2A RHR pump failed to start, and declared RHR Loop I inoperable.
On June 18, 2015, at 1710 CDT, the pump was started and stopped after completion of troubleshooting, and the RHR Loop I was declared operable.
Troubleshooting discovered a loose terminal wire which intermittently prevented 2A RHR from being manually started from the Control Room. An investigation determined the cause to be human performance errors. RHR Loop 1 was inoperable from March 20, 2015, to June 18, 2015, longer than allowed by BFN, Unit 2, Technical Specifications. This loose terminal wire made the pump vulnerable to failure during a seismic event and, therefore, not in compliance with the design basis for the RHR system. This event did not prevent the 2A RHR Pump from manually starting, from the pump breaker, for SPC in the event of an emergency. Both the SPC manual start and the automatic start response to an Emergency Core Cooling System initiation signal were unaffected by this condition.
Corrective Actions for this event were to discipline the individuals responsible, to tighten the loose fastener, and to revise maintenance instructions to reduce the probability of recurrence.
|05000296/LER-2015-003||1 June 2015||Browns Ferry|
On January 7, 2015, Browns Ferry Nuclear Plant (BFN), Unit 3, 3D and 3E Traversing Incore Probes (TIPs) stopped responding to automatic controls. The TIPs were left outside of their in-shield positions to decay for 24 hours, and the 3D and 3E TIP Primary Containment Isolation ball valves were left open. On January 8, 2015, the 3D and 3E TIPs were returned to their in-shield positions and their ball valves were closed.
On April 2, 2015, it was determined that, with the identified condition the 3D and 3E TIPs were incapable of automatically retracting in the event of an accident. The impact to the Primary Containment Isolation Valves (PCIVs) function was not recognized on January 7, 2015, and the required PCIV actions were not taken. Therefore, BFN, Unit 3, operated with two inoperable PCIVs, in violation of Technical Specifications (TS).
The apparent cause of this event was operations procedure 3-OI-94, Traversing Incore Probe System, lacked the appropriate guidance and relevant information to address TIP problems and associated TS applicability. Corrective actions include revising the procedure to provide additional guidance on responding to TIP probe malfunctions, and conducting briefings with operations.
|05000259/LER-2015-001||22 April 2015||Browns Ferry|
On February 21, 2015, at approximately 2300 Central Standard Time, Browns Ferry Nuclear Plant, Units 1 and 2, declared "D" Emergency Diesel Generator (DG) system inoperable due to the control switch being found by Operations personnel in the "pulled out" stop position, which made the "D" DG incapable of automatically starting. It was determined that the "D" DG was inoperable since the last operation of the control switch, approximately eight days earlier. Although this condition caused the "D" DG to be inoperable longer than allowed by the Technical Specifications, the three other Unit 1 and 2 DGs and all four Unit 3 DGs remained available to fulfill the DG safety functions.
Contrary to the original design of the DG control switches, this control switch was replaced in 2004 with one that did not contain a spring return to normal. The cause of the error was an incorrectly filled out Procurement Data Sheet (PDS). Contributing causes included inadequate procedure revision to address the difference in operation, ineffective use of human performance tools and operator fundamentals, and the switch difference had been identified several times previously but not corrected. Corrective actions included correcting the PDS, briefing Operations procedure writers on the details of this event and lessons learned, coaching Operations personnel on the proper use of operator fundamentals and human performance tools when manipulating plant equipment, and replacing the "D" DG control switch with the correct switch.
|05000296/LER-2015-002||20 April 2015||Browns Ferry|
On January 22, 2015, the Browns Ferry Nuclear Plant (BFN), Unit 3, the 3D Core Spray Pump normal power relay (3-RLY-075-14A-K31B) was found de-energized when it should have been energized during performance of a surveillance. Troubleshooting determined the cause of the relay being de-energized was failure of the MJ(52STA) switch in the associated breaker. The relay is an emergency start permissive for the 3B and 3D Core Spray pumps, the 3D Residual Heat Removal pump, and the D1 Residual Heat Removal Service Water pump. This condition prevented those systems from automatically performing their safety functions under normal power, rendering them inoperable for longer than allowed by Technical Specifications. However, these systems were available and the affected pumps could be manually started to perform their safety functions in the event of an accident. The failed switch only serviced the normal power feed, and automatic starting function was unaffected under emergency power. On February 18, 2015, an engineering evaluation determined the switch had apparently failed on September 17, 2014. On January 24, 2015, the relay and switch were replaced, and the automatic startup function was restored.
Apparent causes of the event are failure to implement all appropriate preventive maintenance or pre-emptive replacement allowing MJ(52STA) switches to fail, and the BFN Breaker Program excluding the associated switchgear components allowing support components to be overlooked with respect to reliability.
Corrective actions include replacing MJ switches in non-spare breakers and revising associated preventive maintenance, and revising the Breaker Program to include essential switchgear components.
|05000296/LER-2015-001||13 April 2015||Browns Ferry|
On February 11, 2015, at 0820 Central Standard Time, Brown's Ferry Nuclear Plant (BFN), Unit 3, declared the High Pressure Coolant Injection (HPCI) and Reactor Core Isolation Cooling (RCIC) systems inoperable due to no suction source aligned. During surveillance testing, the Condensate Storage Tank (CST) emergency discharge isolation valve energized and closed when the breaker was closed, isolating both systems from their suction source. It was subsequently determined that contacts on the local hand switch were stuck closed following performance of a previous maintenance task. Operations personnel re-opened the isolation valve using the hand switch in the Control Room, restoring operability to the HPCI and RCIC systems.
The apparent cause of this event was inadequate design review of a 2010 plant modification which allowed latent design vulnerabilities to be introduced into the plant.
The corrective actions to reduce the probability of a similar event occurring in the future were to remove thermal overload heaters from the affected breakers, preventing valve closure when these breakers are closed; to review a sample of recent engineering change packages for quality of Design Review; to repair a faulty hand switch; and to implement a design change for the CST isolation valves for all three BFN units to prevent spurious operation of the isolation valve when the associated breaker is closed.
|05000296/LER-2015-001, High Pressure Coolant Injection and Reactor Core Isolation Cooling Inoperable Due To No Suction Source Aligned||13 April 2015||Browns Ferry|
On February 11, 2015, at 0820 Central Standard Time, Brown's Ferry Nuclear Plant (BFN), Unit 3, declared the High Pressure Coolant Injection (HPCI) and Reactor Core Isolation Cooling (RCIC) systems inoperable due to no suction source aligned. During surveillance testing, the Condensate Storage Tank (CST) emergency discharge isolation valve energized and closed when the breaker was closed, isolating both systems from their suction source. It was subsequently determined that maintenance task. Operations personnel re-opened the isolation valve using the hand switch in the Control Room, restoring operability to the HPCI and RCIC systems.
The apparent cause of this event was inadequate design review of a 2010 plant modification which allowed latent design vulnerabilities to be introduced into the plant.
The corrective actions to reduce the probability of a similar event occurring in the future were to remove thermal overload heaters from the affected breakers, preventing valve closure when these breakers are closed; to review a sample of recent engineering change packages for quality of Design Review; to repair a faulty hand switch; and to implement a design change for the CST isolation valves for all three BFN units to prevent spurious operation of the isolation valve when the associated breaker is closed.
|05000260/LER-2014-001||23 December 2014||Browns Ferry|
On March 27, 2014, it was determined that the Browns Ferry Nuclear Plant (BFN) Required Actions of Technical Requirements Manual (TRM) 3.7.6, Electric Board Room Air Conditioning (AC) System, Condition B, would allow both BFN, Unit 2, Electric Board Room (EBR) AC subsystems to be inoperable for up to 7 days before declaring the Technical Specifications (TS) supported equipment in the EBRs inoperable. This allowance is contrary with the TS definition of "Operable-Operability" with respect to support systems. On two separate occasions in the past three years BFN, Unit 2, EBR AC System and its TS supported systems, were inoperable longer than allowed by TS. After further review of the condition, the causal analysis was revised and it was determined that BFN, Units 1 and 2, did not experience a Safety System Functional Failure (SSFF). This event is being reported in accordance with Title 10 of the Code of Federal Regulations (10 CFR) 50.73(a)(2)(i)(B).
The root cause determined that BFN personnel failed to fully understand the difference between the Technical Requirements Manual (TRM) and Technical Specifications (TS) with respect to operability.
When the TS and TRM were implemented, BFN personnel failed to realize the intent of the TRM and believed it was at the same level of the TS.
The corrective actions to prevent recurrence include revising the TRM to clearly delineate the intent and use with respect to operability and revising the procedure for Technical Specifications, Licenses and Amendments to clearly delineate the role of the TRM and TS.
|05000296/LER-2014-003||31 July 2014||Browns Ferry|
On June 2, 2014, during performance of the Reactor High Pressure Calibration surveillance, the Residual Heat Removal (RHR) Shutdown Cooling (SDC) Inboard Suction Valve Isolation relay failed to energize preventing automatic closure of the RHR SDC Inboard Suction Valve. On three occasions, the inability of this valve to close automatically upon receipt of the Primary Containment Isolation System signal resulted in a violation of the Browns Ferry Nuclear Plant, Unit 3, Technical Specifications. The Shutdown Cooling Mode of the Residual Heat Removal System was unaffected by this condition.
The cause of the event was relay wires had been lifted and incorrectly landed due to a human performance error at an indeterminate time between a successful post maintenance test (PMT) on March 07, 2014, and the time the condition was corrected by re-landing the wires according to plant drawings on June 6, 2014.
The corrective action to reduce likelihood of recurrence is to develop and deliver a case study to the Maintenance, Modifications, and Operations departments based on the details of this event.
|05000296/LER-2014-002||7 July 2014||Browns Ferry|
On May 6, 2014, at approximately 0830 Central Daylight Time (CDT), the Browns Ferry Nuclear Plant (BFN) Unit 3 reactor automatically scrammed as a result of an Anticipated Transient Without Scram/Alternate Rod Insertion (ATWS/ARI) signal generated during functional testing of reactor water level instrumentation. The scram air header was depressurized through the ATWS/ARI valves causing all rods to insert into the core. The ATWS/ARI signal also simultaneously opened the Recirculation Pump Trip (RPT) breakers, tripping both Recirculation pumps. The loss of both pumps along with reduced core flow caused a reactor water level transient that lowered level below the Reactor Protection System (RPS) trip setpoint (+2 inches), resulting in a full reactor scram signal.
Prior to this event, reactor power was 2.1 percent as all control rods were inserted by the ATWS/ARI initiation ten seconds earlier. Following receipt of the ATWS/ARI signal, all plant systems performed as required.
The root cause of the event was that the ATWS low reactor water level Automatic Trip Unit (ATU) cards initiated a voltage transient that actuated the ATWS high reactor pressure trip due to a design anomaly.
The corrective action to prevent recurrence includes installing time delay relays in association with the Unit 3 reactor pressure ATWS circuit.
|05000296/LER-2014-001||19 May 2014||Browns Ferry|
On March 18, 2014, the Browns Ferry Nuclear Plant (BFN) Unit 3 reactor automatically scrammed due to a turbine trip from a high main turbine moisture separator level. Initial indications show the level controller for 3B2 Moisture Separator failed to maintain level in automatic. Additionally, local manual control attempts failed to restore moisture separator level. Following the turbine trip Main Steam Isolation Valves remained open with main turbine bypass valves controlling reactor pressure.
At approximately 2232, Central Daylight Time (CDT) the 3B2 Moisture Separator Level High Alarm was received and an operator was dispatched to investigate. In accordance with the alarm response procedure the 3B2 Moisture Separator Water Level Controller was placed in manual. Attempts to control the Moisture Separator Reservoir 3B2 High Level Dump Valve manually were ineffective. At approximately 2252 CDT, the Unit 3 reactor automatically scrammed due to a turbine trip from a high moisture separator level.
The root cause was a failure to prevent the introduction of foreign material during the manufacturing process of the Moisture Separator Level Controller. The manufacturing defect was a legacy issue dating back to 1971 when the controller body was originally machined. The corrective actions to prevent recurrence requires the removal, cleaning of air passages, replacement of control relays, for similar controllers and upgrading the calibration procedure to include cleaning guidance.
|05000296/LER-2013-003||18 December 2013||Browns Ferry|
On February 25, 2013, at approximately 1313 hours Central Standard Time, the Browns Ferry Nuclear Plant (BFN), Unit 3, reactor automatically scrammed due to an actuation of the Reactor Protection System from a turbine trip. The turbine tripped on low condenser vacuum due to a reactor feedwater piping separation. The Main Steam Isolation Valves were manually closed. There was one Safety Relief Valve that was manually operated to maintain reactor pressure due to the unavailability of the Main Turbine Bypass Valves upon loss of condenser vacuum. All systems responded as expected to the turbine trip. No Emergency Core Cooling System or Reactor Core Isolation Cooling (RCIC) system reactor water level initiation set points were reached. Reactor water level was controlled with the RCIC system and reactor pressure was controlled with the High Pressure Coolant Injection system.
The root cause for this event is that the system design for BFN, Unit 3, Feedwater Long Cycle line does not account for flashing of water to steam due to isolation valve leakage.
The corrective action to prevent recurrence is to redesign Feed Water Long Cycle lines downstream of each Feed Water Long Cycle isolation valve and upstream of the Miscellaneous Drain Header with a valve and piping configuration appropriately designed for the specified application.
|05000260/LER-2013-002||25 November 2013||Browns Ferry|
On September 24, 2013, during an Environmental Qualification (EQ) review of a work order, it was discovered that the motor leads for the valve actuator on the High Pressure Coolant Injection (HPCI) main pump minimum flow valve had an unqualified electrical splice; and as a result, Operations personnel declared the valve inoperable and entered Technical Specification (TS) 188.8.131.52 Condition C. At 1530 hours Central Daylight Time, as a result of the inoperability of the HPCI main pump minimum flow valve, Operations personnel declared the HPCI System inoperable, and Browns Ferry Nuclear Plant, Unit 2, made an unplanned entry into TS 3.5.1 Condition C.
The root cause of this event was determined to be a lack of clear and specific procedural guidance related to: (1) overt direction on locating and determining the component classification relative to 10 CFR 50.49 requirements, and (2) guidance on changes to EQ components and associated work orders.
Corrective actions to prevent recurrence are to revise the work control planning procedure to include: (1) the requirement that changes to EQ work orders are considered major changes, (2) the requirement that revisions to EQ work orders are reviewed and concurred with by the EQ program manager or designee, and (3) the location of the EQ classification information.
|05000259/LER-2009-002||27 September 2013||Browns Ferry|
On March 20, 2009, in preparation for testing, Operations declared Residual Heat Removal (RHR) pumps 1A and 1C inoperable, entering Technical Specification (TS) Limiting Condition for Operation (LCO) 3.5.1 Condition A and Required Action A.1.
On March 21, 2009, while placing a jumper in accordance with the surveillance, Unit 1 received an RHR Pump Initiate Lockout signal for Loop II RHR Pumps 1B and 1D. With the lockout signal in place, the automatic start function of RHR Pumps 1B and 1D is inhibited. Unit 1 entered TS LCO 3.5.1 Condition H, Action H.1, with two or more low pressure ECCS injection/spray subsystems inoperable for reasons other than Condition A, and entered TS LCO 3.0.3. Operations restored the automatic start function of RHR Pumps 1 B and 1D, and exited TS LCO 3.5.1 Condition H and TS LCO 3.0.3. However, because the concurrent condition of RHR Loop II and Loop 1 RHR pump 1C were unknown at the time, Unit 1 was not placed in LCO 3.0.3 as required by TS 3.5.1, Required Action H.1.
A walkdown recognized that the jumper was being installed in one panel and removed from another. However, when the revision was made, the wrong surveillance step was revised. The action to place and remove a jumper took place in the incorrect cabinet. Corrective actions included a technical review of procedures and re-indoctrinated on adequate independent qualified review techniques.
|05000259/LER-2013-001||12 June 2013||Browns Ferry|
On July 28, 2009, the Tennessee Valley Authority (TVA) identified latent design input inconsistencies in hydrological computer modeling used for probable maximum flood (PMF) calculations.
The root causes of the condition were an organizational behavior which allowed the latent input inconsistencies to go undetected and management failure to provide oversight of the impact of river system changes on the calculated value of the PMF. The corrective actions to prevent recurrence are to procedurally require a Flood Protection Program, develop formal Flood Protection Program Management Implementing Procedure(s) and Design Standards/Guides, create a formal documented risk management process for all engineering products, formalize the elements of engineering technical rigor, and implement an upper tier integrated risk management process.
Upon discovery, TVA implemented both immediate and interim corrective actions to ensure the Fort Loudoun, Cherokee, Tellico and Watts Bar Dams would not overtop during an assumed PMF event.
On May 30, 2013, a new analysis regarding PMF elevations at Browns Ferry Nuclear Plant (BFN), Units 1, 2, and 3 was completed. Although this condition was considered to be unanalyzed, the analysis concluded that it did not result in BFN being in a condition that significantly degraded plant safety with respect to the PMF elevation prior to the HESCO modular flood barriers being placed on top of the dams.
|05000296/LER-2013-002||7 June 2013||Browns Ferry|
On February 11, 2013, the Reactor Core Isolation Cooling (RCIC) system was manually started during a planned Browns Ferry Nuclear Plant (BFN), Unit 3, reactor shutdown. A Reactor Feedwater recirculation piping through wall leak resulted in the loss of condenser vacuum and subsequent unavailability of the Main Turbine Bypass Valves. The RCIC system was manually started to control reactor water level in anticipation of loss of Reactor Feedwater Pumps tripping on low vacuum. Safety Relief Valves were manually operated to maintain reactor pressure. No Emergency Core Cooling System or RCIC system reactor water level initiation set points were reached.
The root causes of this condition are the design used for valves 3-FCV-03-0071, -0072, and -0073 in the Feedwater Long Cycle Return Line is incorrect for the specified application, and BFN personnel did not consistently consider risk when making decisions to replace the BFN, Unit 3, Feedwater Long Cycle valves.
Corrective actions to prevent recurrence are to replace valves 1, 2, 3-FCV-03-0071, -0072, and -0073 with valves appropriately designed for the required operating conditions and to establish initial and continuing training for leaders and craft that support their roles and responsibilities.
Also, BFN has implemented a Strategic Performance Management process to reinforce and institutionalize conservative decision making principles.
|05000296/LER-2013-001||10 May 2013||Browns Ferry|
On January 9, 2013, at 0400 Central Standard Time, an Auxiliary Unit Operator (AUO) performing rounds near the 3D Emergency Diesel Generator (EDG) discovered metal residue around the blower shaft. Inspection by Maintenance determined the blower bearing had failed.
Operations declared the 3D EDG inoperable.
The root causes of this condition are the shielded bearings in the EDG blowers were not adequately assessed on a component level to identify potential failure modes and impacts to EDG operability, and standard vibration data was ineffective in identifying the degradation of the lubrication in the shielded bearings of the BFN, Unit 3, EDG blowers due to the masking effect of generator vibrations.
Immediate corrective actions included the inspection and replacement of all diesel blower bearings that had not been replaced since 2012. The corrective actions to prevent recurrence are to determine appropriate Preventive Maintenance strategies for the population of sealed or shielded bearings associated with EDGs and safety or quality related rotating equipment, and to add an additional vibration monitoring point to the EDG blower fan bearings and relocate two existing monitoring points to the drive end bearing housing.
I I I
|05000260/LER-2013-001||1 May 2013||Browns Ferry|
On March 2, 2013, radiography results for the Browns Ferry Nuclear Plant (BFN), Unit 2, Reactor Core Isolation Cooling (RCIC) system stop-check valve, 2-HCV-071-0014, showed the valve to be in the fully open position; therefore, not meeting its function as a primary containment isolation valve. The RCIC Steam Line Outboard Isolation valve, 2-FCV-071-0003, was closed and deactivated to meet Technical Specification (TS) 184.108.40.206 for Primary Containment Isolation.
This caused the RCIC system to become inoperable. The TS 3.5.3 requires the RCIC system to be returned to service within 14 days. Because valve 2-HCV-071-0014 is unisolable to primary containment, a unit shutdown was required to perform repairs. Actions to initiate reactor shutdown began on March 14, 2013, at 0800 Central Daylight Time.
The root cause of this condition is valve 2-HCV-071-0014 was improperly classified as a Run-to-Failure hand valve when it should have been classified as a Critical check valve.
The corrective action to prevent recurrence is to submit preventive maintenance change requests to open, inspect, clean, and replace valve disc, dashpot, and stem, as necessary, for RCIC Turbine Exhaust Hand Control Valves, RCIC Vacuum Pump Discharge Shutoff Valves, and High Pressure Coolant Injection Turbine Exhaust Valves.
|05000296/LER-2012-004||26 November 2012||Browns Ferry|
On May 24, 2012, at approximately 0638 Central Daylight Time, Operations personnel inadvertently ranged 3H intermediate range monitor (IRM) down instead of up resulting in a half scram from the 3B reactor protection system (RPS) trip channel. Subsequently, the IRM was properly ranged and Operations personnel responded in accordance with procedures to reset the half scram. Coincident with Operations personnel placing the scram reset switch in the Group 2/3 position, an electrical spike was received on 3A IRM of the 3A RPS trip channel resulting in control rod insertion for the Groups 1 and 4 control rods. Operations personnel identified the unexpected control rod motion and initiated a manual reactor scram in accordance with Browns Ferry Nuclear Plant (BFN) Abnormal Operating Instructions.
The root cause was determined to be high impedance of the BFN, Unit 3, Main Control Room (MCR) common ground to station ground that exposed the 3A IRM to noise feedback.
The corrective action to prevent recurrence is to verify that BFN, Unit 3, MCR common ground connections to station ground are as shown in the applicable system drawings. If any ground connections are identified that require repair, work orders will be initiated and repairs performed.
Following repairs, the high impedance connection of BFN, Unit 3, MCR common ground to station ground will be confirmed to have been resolved by documenting the results of validation testing.
|05000260/LER-2012-002||13 August 2012||Browns Ferry|
On June 7, 2012, at approximately 1305 hours Central Daylight Time (CDT), during performance of a surveillance procedure, a steam leak was identified on a Browns Ferry Nuclear Plant (BFN), Unit 2, High Pressure Coolant Injection (HPCI) steam line valve. The condition was evaluated and the valve was determined to be Operable. On June 12, 2012, based on advice from Engineering, Operations personnel requested a Prompt Determination of Operability.
On June 13, 2012, at approximately 1700 hours CDT, the HPCI steam line valve was determined to be incapable of performing its primary containment isolation valve (PCIV) function. Due to the steam leak coming from a valve leak sealant injection port, it was estimated that the allowable primary containment leak rate was exceeded. In accordance with Technical Specification (TS) actions for an inoperable PCIV, the associated penetration was isolated, rendering the HPCI System inoperable. The TS actions were entered for the inoperable HPCI System.
The root cause of the event was inadequate work instructions for ensuring the final plant configuration matched the required configuration.
The corrective action to prevent recurrence is to revise the Work Control Planning Procedure to require work orders to include verification that components affected by maintenance or modification are returned to the required configuration.
|05000259/LER-2011-002||21 March 2012||Browns Ferry|
On April 28, 2011, at 2338 hours Central Daylight Time, with all three units in cold shutdown and power supplied to the 4-kV shutdown buses by onsite emergency diesel generators (EDGs), Browns Ferry Nuclear Plant personnel performed a shutdown of the Unit 1/2 C EDG. The Unit 1/2 C EDG was shutdown due to a hydraulic oil leak in piping for the EDG governor that was causing voltage and frequency fluctuations. Following shutdown of the Unit 1/2 C EDG, the 4-kV shutdown board C, which was being powered by the Unit 1/2 C EDG, de-energized. This resulted in a loss of power to the 1B Reactor Protection System causing a Primary Containment Isolation System (PCIS) actuation. The PCIS isolation (Group 2) caused the loss of Shutdown Cooling on Unit 1 for 47 minutes. In addition, the loss of power to the 4-kV shutdown board C also caused the loss of the 2B Residual Heat Removal (RHR) pump leading to a momentary suspension of Shutdown Cooling for Unit 2. Shutdown Cooling for Unit 2 was immediately restored using the 2D RHR pump. The root cause of the oil leak was determined to be a less than adequate design of the Unit 1/2 C EDG governor oil piping to compensate for vibration I loading.
This report also constitutes a 10 CFR 21 notification.
|05000296/LER-2009-003||29 July 2011||Browns Ferry|
On February 13, 2007, and again on August 26, 2009, during post-scram reviews, Browns Ferry Nuclear Plant personnel identified an unexpected level of instability in the Reactor Core Isolation Cooling (RCIC) system flow and turbine response following reactor scrams that occurred on February 9, 2007, and on August 24, 2009. Following each event, site engineering personnel reviewed the RCIC response and concluded the RCIC system was capable of performing its design function and Operations determined that RCIC was operable. On February 12, 2007, and again on August 26, 2009, Unit 3 entered Mode 2, commencing startup operations. Following the second event on August 24, 2009, Unit 3 was returned to service and remained at power until September 12, 2009, when Unit 3 was removed from service for scheduled maintenance activities.
During the September 2009 outage, the RCIC Electric Governor-Remote (EG-R) was replaced and I successfully tested. On March 25, 2010, in response to questions from the Nuclear Regulatory Commission (NRC), the Tennessee Valley Authority notified the NRC via a conference telephone call I that Unit 3 RCIC was inoperable since March 22, 2006, after the EG-R had been installed and when Unit 3 exceeded 150 psig while in Mode 2. This reflected RCIC inoperability longer than allowed by Technical Specification 3.5.3 and mode changes not allowed by LCO 3.0.4. A failure analysis, conducted by Engine Systems Incorporated, determined the oscillations were caused by a missing buffer piston and springs within the EG-R.
|05000259/LER-2011-001||27 June 2011||Browns Ferry|
On April 27, 2011, severe weather in the Tennessee Valley Service Area caused grid instability and loss of all 500-kV offsite power sources that resulted in automatic scrams of all three units.
All three units were in Mode 1 at the time of the event. All scram systems were actuated, all actuations were complete, and required systems started and functioned successfully with the exception of an indeterminate position indication for the Unit 3 B Inboard Main Steam Isolation Valve. All onsite safe shutdown equipment was available with the exception of the 3B Emergency Diesel Generator (EDG), which was inoperable and unavailable due to planned maintenance.
After the event, only one 161-kV line remained available for offsite power - all (seven) 500-kV lines and one (of two) 161-kV line were lost. All three units immediately entered Mode 3 (Hot Shutdown) with their respective 4-kV busses supplied by the onsite EDGs.
On April 27, 2011, at 1701 hours, a Notification of Unusual Event (NOUE) was declared due to the loss of normal and alternate supply voltage to all unit-specific 4-kV shutdown boards for greater than 15 minutes and at least two EDGs supplying power to unit-specific 4-kV shutdown boards. On May 2, 2011, at 2050 hours, the NOUE was terminated following restoration of qualified offsite power sources.
|05000296/LER-2010-003||21 April 2011||Browns Ferry|
Unit 3 Cycle 14 operation failed to meet Technical Specifications (TS) Surveillance Requirement (SR) 220.127.116.11.8, which requires verification that a representative sample of reactor instrumentation line EFCVs actuate to the isolation position on a simulated instrument line break signal. With the discovery of multiple failures during unit shutdown for refueling, multiple EFCVs may have been inoperable during Cycle 14 operation.
TS Limiting Condition for Operation 18.104.22.168 requires that each Primary Containment Isolation Valve be operable in reactor Modes 1, 2, and 3, and when the associated instrumentation is required to be operable.
Given the multiple failures of EFCVs, it is likely that Unit 3 did not comply with the applicable Required Actions and associated Completion Times of TS 22.214.171.124 Action C. Accordingly this situation is being reported as any operation or condition prohibited by the plant's Technical Specifications, i.e., 10 CFR 50.73(a)(2)(i)(B).
The failed EFCVs were replaced. In accordance with the implementation of the Maintenance Rule (10 CFR 50.65) the Browns Ferry Nuclear Plant (BFN), Units 1, 2, and 3 EFCVs have been placed in Maintenance Rule a(1) status. The BFN Corrective Action Program has implemented actions to improve reliability of the EFCVs.
|05000296/LER-2010-004||24 February 2011||Browns Ferry|
On December 26, 2010, at 1615 hours Central Standard Time, an alarm for Main Turbine Vibration High 3-VA-47-15 was received in the Unit 3 control room on annunciator panel 3-XA-55-7B Window 32.
Control room operators responded using Unit 3 Alarm Response Procedure (ARP) 3-ARP-9-7B. Exciter rotor inboard journal bearing vibration level indicated 8.0 mils and rising, and the outboard journal bearing indicated 5.5 mils and rising. At 1617 hours, an Upper Power Runback was initiated per the ARP. It was noted that vibration levels initially lowered then continued rising. At 1620 hours, control room operators initiated a manual reactor scram.
The direct cause of this event was an exciter rotor-deflector rub resulting from a combination of high differential air exit temperatures and existing decreased clearances on the rotor. The root cause was inadequate procedural guidance for monitoring the exciter air cooling system and prescribing mitigation actions to be taken based on differential temperature limits.
The rub was corrected during the forced outage. Corrective actions include installation of cooler vents for use in minimizing air binding, establishment of a cooler venting process, increased controls and documentation of manual "balancing" valve manipulation, increased system monitoring process rigor and oversight, and performance of a training analysis for inclusion of relevant aspects of this root cause into the Operations and Engineering training materials.
|05000260/LER-2009-004||12 February 2010||Browns Ferry|
At 1200 hours Central Daylight Time (CDT) on June 11, 2009, Browns Ferry Nuclear Plant Unit 2 experienced a rise in drywell leakage during reactor startup. The four-hour unidentified leak rate from 0800 to 1200 hours CDT on. June 10, 2009, was 0 gallons per minute (GPM), while the four-hour unidentified leak rate from 0800 to 1200 hours CDT on June 11, 2009 was 3.88 GPM. This increase in leakage exceeded the Technical Specifications (TS) Limiting Condition for Operation (LCO) 3.4.4 limit of a 2 GPM increase in unidentified leakage in a 24 hour period. At 1555 hours CDT on June 11, 2009, Unit 2 initiated a reactor shutdown via a manual reactor SCRAM to comply with TS LCO 3.4.4 Condition C to be in Mode 3 in 12 hours and to be in Mode 4 within 36 hours.
Following verification that the procedure, 2-AOI-100-1, Reactor Scram, actions were completed, the reactor mode switch was placed in Shutdown. The increase in unidentified leakage was due to failure of a Main Steam Line B Safety Relief Valve (SRV) to fully close. As a result of this steam leakage, two main steam SRV tailpipe vacuum breakers, 2.5 inch and 10 inch, were cycling. This SRV failure and vacuum breaker cycling allowed steam to enter the drywell instead of going to the torus.
Additionally, upon reset of the manual reactor scram, Reactor Protection System (RPS) 'B' scram channel did not reset as expected. At 1609 hours CDT on June 11, 2009, RPS Channel 'A' actuated a full reactor scram due to Intermediate Range Monitor 'C' spiking high and the inability to reset RPS 'B'.scram channel. This automatic scram was found to be the result of a loose scram relay/contactor terminal connection.
|05000260/LER-2009-008||24 November 2009||Browns Ferry|
On September 30, 2009, at approximately 0830 hours Central Daylight Time, Browns Ferry Nuclear Plant (BFN) Site Engineering personnel concluded that during a September 29, 2009, manual reactor scram, the Reactor Core Isolation Cooling (RCIC) system pump failed to inject into the reactor vessel in response to decreasing water level. At the time the conclusion was made, Unit 2 was in Mode 3 with reactor pressure less than 150 psig; thus, the RCIC system was not required to be operable in accordance with the Applicability of Technical Specification (TS) 3.5.3, RCIC System. Consequently, no entry into the associated TS actions was required.
Previously, on September 12, 2009, BFN personnel noted that plant data indicated that since August 27, 2009, the output from the Woodward Electric Governor-Magnetic Pickup (EG-M) control box was lower than expected.
On September 29, 2009, the Unit 2 RCIC system failed to properly start and inject into the reactor vessel when the Reactor Vessel Low Low, Level 2 (-45 inches) setpoint was reached following a manual reactor scram.
Because the RCIC system failed to inject when needed and the governor output had been lower than expected for an extended period of time, TVA has concluded that the RCIC system had been inoperable longer than the TS 3.5.3, Required Action A.2 Completion Time of 14 days. The root cause of this event was a failure to enter a condition adverse to quality into the corrective action program. When the HPCI system was inoperable, it remained available for injection into the reactor pressure vessel except for a total of five minutes. During the time periods that the HPCI system was unavailable, the remaining emergency core cooling systems were available to perform the HPCI system function. Therefore, TVA concludes that there was no significant reduction in the protection of the public by this event.
|05000260/LER-2009-007||20 November 2009||Browns Ferry|
At 2321 hours on September 29, 2009, with Unit 2 at 100 percent power, operators were in the process of removing reactor feedwater pump 2B from service for scheduled maintenance. At the time, condensate pump 2B and condensate booster pump 2C had been previously removed from service for maintenance. When feedwater pump 2B speed was lowered to where flow was below the minimum flow setpoint, the pump 2B minimum flow valve automatically opened. This action increased total condensate flow, which lowered feedwater and condensate booster pump suction pressures. Feedwater pump 2A and condensate booster pump 2A subsequently tripped on low pump suction pressure signals. Feedwater pump 2C automatically increased speed to maintain reactor vessel level and tripped on overspeed. Operators manually scrammed the reactor due to decreasing vessel water level. Decreasing vessel level also resulted in the auto-initiation of High Pressure Coolant Injection (HPCI) and Reactor Core Isolation Cooling (RCIC). HPCI successfully started and in combination with feedwater pump 2B restored water level to normal. RCIC started,but failed to achieve sufficient speed to inject. A separate LER is being submitted on the RCIC malfunction.
The event investigation determined that the operating instructions for removing a feedwater pump from service were inadequate for the operating configuration (with less than a full complement of condensate and condensate booster pumps in operation). The subject operating instructions have been revised to require that feedwater flow be below that needed for 85 percent power prior to removing a feedwater pump from service if a condensate/condensate booster pump is not in service. A new tool for assessing the risk of online activities was implemented. The risk review process for performing online feedwater/condensate system maintenance is also being reviewed.
|05000259/LER-2008-001||3 November 2008||Browns Ferry||On September 3, 2008, at 2344 hours Central Daylight Time (CDT) during a scheduled performance of the Unit 1 Surveillance, RPS Circuit Protector Calibration/Functional Test for 1A1 and 1A2, the Unit 1 Reactor Operator noted that secondary containment dampers Reactor Zone Exhaust Inboard Isolation Damper (1-DMP 64-42) and Reactor Zone Exhaust Outboard Isolation Damper (1-DMP-64-43) failed to close on a Group 6 Primary Containment Isolation Signal generated during the surveillance. The root cause of this event is the use of Dow Corning 550 lubricant in a normally energized solenoid. In a March 2002 event, an ASCO solenoid valve failed to close. Silicone based lubricant used by the manufacture during assembly caused the valve to malfunction. The corrective actions included replacement of the Units 2 and 3 solenoid valves. However, the solenoids associated with the Unit 1 secondary containment isolation dampers were not replaced. In response to this event, TVA replaced the solenoid valves for these two dampers.|
|05000296/LER-2008-002||31 July 2008||Browns Ferry||On June 2, 2008, TVA determined that 7 of the 13 Main Steam Relief Valves (MSRVs) (SB), removed from Unit 3 following Cycle 13 operation mechanically actuated at pressures greater than 3 percent above their Technical Specifications (TS) setpoint, thus inoperable. One valve exhibited leakage past the seat, and the lift pressure could not be verified. Unit 3 TS limiting condition for operation (LCO) 3.4.3 requires that twelve (12) MSRVs be operable in reactor modes 1, 2, and 3. If less than twelve MSRVS are operable, the unit is to be placed in Mode 3 hot shutdown within 36 hours. As such, it is probable that Unit 3 operated outside the TSs longer than allowed by the TSs. Therefore, TVA is submitting this report in accordance with 10 CFR 50.73(a)(2)(i)(B), as any operation or condition prohibited by the plant's Technical Specifications.|
|05000296/LER-2008-001||7 July 2008||Browns Ferry||On May 5, 2008, at approximately 0332 hours Central Daylight Time (CDT) Emergency Diesel Generators (EDGs) 3EC and 3ED auto-started and tied to their respective shutdown boards due to an under voltage condition. Operations was in the process of returning the Unit 3 4KV Unit Board 3B to the normal supply in accordance with Operating Instruction 0-01-57A, Switchyard and 4160V AC Electrical System, when the board failed to transfer. The loss of power to Unit Board 3B resulted in a loss of power to 4KV Shutdown Boards 3EC and 3ED, 480V Reactor Motor-Operated Valve (RMOV) Board 3B, and Reactor Protection System 3B (RPS) (JC) power supply. Due to the loss of power on the shutdown boards, EDGs 3EC and 3ED started and tied to their respective shutdown boards. Unit 3 also received Primary Containment Isolation System (PCIS) Groups 3 and 6 isolations and actuations. A coincidental upscale trip of the 3A intermediate range monitor (IRM), which resulted in RPS Channel 3A half scram, in combination with the de-energizing of the RPS Channel 3B resulted in an unexpected full reactor scram. The Standby Gas Treatment (SGT) and Control Room Emergency Ventilation (CREV) systems initiated as expected. By 0352 hours CDT the reactor scram and PCIS logic was reset, the SGT and CREV Systems were returned to standby readiness. By 0944 hours CDT power was restored to 4KV Shutdown Boards 3EC and 3ED; likewise, EDGs 3EC and 3ED were secured. TVA is submitting this report in accordance with 10 CFR 50.73(a)(2)(iv)(A) as any event of condition that resulted in manual or automatic actuation of any system listed in paragraph 10 CFR 50.73 (a)(2)(iv)(B).|
|05000296/LER-2007-005||17 March 2008||Browns Ferry|
On December 31, 2007, at 2140 hours Central Standard Time (CST), Unit 3 reactor received an automatic scram signal following a main generator load reject. The reactor scram from the generator load reject was expected. All systems responded to the scram as expected. All control rods inserted. During the initial pressure transient, which peaked at 1141 psig, six of the main steam system relief valves opened. The reactor pressure was subsequently controlled with the main steam system bypass valves. The reactor water level was controlled by the Feedwater system, the normal heat removal path through the main condenser was maintained during the event. The reactor scram was reset December 31, 2007, by 2146 hours CST.
TVA is submitting this report according to 10 CFR 50.73(a)(2)(iv)(A), as an event that resulted in a manual or automatic actuation of the systems listed in paragraph 10 CFR 50.73(a)(2)(iv)(B) (i.e., reactor protection system including reactor scram of trip, and general containment isolation signals affecting containment isolation valves in more than one system.)