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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-3.5.1.6 (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.

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.

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.

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.

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.

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.

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.

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.

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 3.6.1.3, 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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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) 3.6.1.3 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.

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.

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.

Unit 3 Cycle 14 operation failed to meet Technical Specifications (TS) Surveillance Requirement (SR) 3.6.1.3.8, 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 3.6.1.3 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 3.6.1.3 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.

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.

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.