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 Report dateSiteEvent description
05000324/LER-2017-0033 August 2017Brunswick

On June 5, 2017, BSEP received the results of testing of eleven main steam line safety relief valves (SRVs) removed from Unit 2 during the spring refueling outage. Three of the eleven valves were found to have as-found lift setpoints of their pilot valves outside the +/-3 percent tolerance required by Technical Specification (TS) 3.4.3.

One SRV was 9.1 percent high. One SRV was 8.6 percent high, and one SRV was 5.0 percent high. Evaluation determined that the elevated lift pressures in two valves resulted from corrosion bonding of the SRV pilot valves which raised the breakaway force needed to open the pilot. The third valve experienced steam erosion. This event had no adverse impact on nuclear safety. Although the SRV setpoint limits required by the TS were exceeded, the plant condition was bounded by the Brunswick Unit 2 Cycle 22 Reload Safety Analysis, demonstrating that the SRVs could have performed their safety function of limiting reactor vessel overpressure. TS 3.4.3 requires ten of the eleven installed SRVs to be operable. Since less than ten SRVs were operable, this event is being reported in accordance with 10 CFR 50.73(a)(2)(i)(B) for operation prohibited by the plant's TS. The SRV pilot valves were replaced with certified spares before the startup of Unit 2. A procedure was revised to reduce corrosion bonding by improving surface preparation of SRV pilot valve discs.

05000325/LER-2017-0032 August 2017Brunswick

On June 5, 2017, at 0930 Eastern Daylight Time (EDT), Unit 1 was in Mode 1 at 100 percent power, and Unit 2 was in Mode 1 at 87 percent power and was increasing power after a preplanned control rod improvement evolution. Maintenance personnel were inspecting dampers in the Control Room Air Conditioning (AC) system and Control Room Emergency Ventilation (CREV) system and disconnected an air supply to a damper. This resulted in the CREV system being inoperable due to interruption of the pneumatic supply. The CREV system was restored to operable status by 1009 EDT. At 1352 EDT, a second damper was inspected, and its pneumatic supply was disconnected. During the second occurrence, the Control Room AC system also tripped and was made inoperable. Affected systems were restored by 1407 EDT.

The event is reportable as a loss of safety function per 10 CFR 50.73(a)(2)(v)(D). The event resulted from inadequate use of human performance tools and inadequate work instructions. Corrective actions for this event include restoring the affected pneumatic supply, revising work orders, and taking steps to emphasize proper use of human performance tools.

05000325/LER-2017-00212 June 2017Brunswick

On April 17, 2017, at 0004 Eastern Daylight Time, Unit 1 was in Mode 1 at approximately 100 percent of rated power, and Unit 2 was in Mode 1 at approximately 22 percent of rated power and was starting up from a refueling outage. Operators manually tripped the Unit 2 main turbine to halt increasing bearing vibration.

The power circuit breakers (PCBs) for the Unit 2 main generator did not open as expected on the turbine trip, but subsequently opened when main generator reverse power relays actuated. This resulted in the automatic start of all four emergency diesel generators (EDGs). The EDGs did not tie to emergency busses because offsite power was still available. This event resulted from a component which failed due to foreign material intrusion. A limit switch associated with a main turbine stop valve failed to change states when the turbine was tripped. The limit switch configuration, together with other logic, satisfied the conditions to start the EDGs. The limit switch failure resulted from foreign material in the switch. The failed limit switch was replaced. Planned corrective actions include inspecting similar switches on both units, and sealing the wire entrances of the switch bodies to improve foreign material exclusion.

05000324/LER-2017-0029 June 2017Brunswick

On April 13, 2017, Unit 2 was in Mode 4 preparing to exit a refueling outage. The primary containment was being vented to ensure habitability of the Drywell. The valve alignment for Drywell ventilation makes the primary containment inoperable due to the Drywell and Suppression Chamber airspaces being in communication with each other. At 23:47 Eastern Daylight Time (EDT), the reactor mode was changed from Mode 4 to Mode 2 with ventilation still in progress. In Mode 2, the Primary Containment is required to be operable. Therefore, the plant entered a condition prohibited by the Technical Specifications, and the event is reportable per 10 CFR 50.73(a)(2)(i)(B). It is also reportable per 10 CFR 50.73(a)(2)(v)(D) because the primary containment safety function was lost. The condition was discovered 28 minutes later on April 14, 2017, at 00:15 EDT and was corrected by closing the ventilation flowpaths at 00:30 EDT on April 14, 2017.

This event resulted from Control Room personnel not initiating a tracking document while in Mode 4 with the primary containment inoperable. When preparing to change the plant mode from Mode 4 to Mode 2, the primary containment ventilation status was overlooked. Corrective actions for this event included closing the containment ventilation paths and remediating the Shift Manager and Control Room Supervisor.

05000324/LER-2017-00118 May 2017Brunswick

On March 22, 2017, Unit 2 implemented the guidance of EGM 11-003, Revision 3, "Enforcement Guidance Memorandum 11-003, Revision 3, Dispositioning Boiling Water Reactor Licensee Noncompliance with Technical Specification Containment Requirements during Operations with a Potential for Draining the Reactor Vessel," dated January 15, 2016. Consistent with EGM 11-003, Revision 3, secondary containment operability was not maintained during Operations with a Potential for Draining the Reactor Vessel (OPDRV) activities, and Required Actions C.1 and C.2 of Technical Specifications (TS) 3.6.4.1, "Secondary Containment," were not completed. These conditions are being reported in accordance with 10 CFR 50.73(a)(2)(i)(B) as operations prohibited by the plant's TS.

Implementation of EGM 11-003, Revision 3, during the Unit 2 refueling outage was a planned activity. As such, there was no causal evaluation of the event. Consistent with the guidance provided in EGM 11-003, Revision 3, BSEP will submit a license amendment request to adopt Technical Specification Task Force (TSTF)-542 associated with generic resolution to this issue within 12 months from its approval (i.e., from December 20, 2016).

05000325/LER-2017-00122 March 2017BrunswickOn February 7, 2016, at 1312 Eastern Standard Time (EST), Unit 1 was in Mode 1 (i.e., Run) at 88 percent of rated power in end-of-cycle coastdown. At that time, an event occurred which resulted in a loss of offsite power (LOOP) on Unit 1. Emergency diesel generators EDG-1 and EDG-2 started and tied to their respective Unit 1 emergency buses. During diesel operation, EDG-1 exhibited oscillations in engine speed and bus frequency. These oscillations had no adverse effect on equipment supplied by the bus, and all supplied loads continued to perform their safety functions without interruption and without need for operator intervention. However, due to the speed and frequency oscillations, EDG-1 was deemed after the fact to have been inoperable. Following extensive testing and evaluation, the cause of the oscillations has not been determined. The governor system for EDG-1 was replaced on March 6, 2016, as part of a planned upgrade to EDG-1. Since that time, the oscillations have not recurred. Based on the fact that the governor replacement eliminated the oscillations, it's concluded that the oscillations resulted from a deficiency in the governor system. Since the cause of the inoperability has been eliminated, no further corrective actions are planned.
05000325/LER-2016-00613 February 2017BrunswickOn December 13, 2016, Units 1 and 2 were in Mode 1 (i.e., Run mode) at 98 percent and 97 percent of rated thermal power, respectively. At that time, shift personnel were notified that structural supports for the 2D Control Room air conditioning system condenser were corroded. An operability assessment found the affected air conditioning system inoperable due to the effect on its seismic qualification. Technical Specifications (TS) 3.7.4, Condition A, was entered. On January 30, 2017, the 1D air conditioning system was found with similar conditions. Since the conditions were determined to have existed for longer than the TS allowable out of service time, the plant was in a condition prohibited by the TS. Since more than one air conditioner had been inoperable concurrently, the safety function of maintaining Control Room habitability could have been prevented from being fulfilled during a seismic event. This event resulted from trapped moisture in contact with the steel supports and exposure to the local marine environment which corroded support steel to the point that seismic qualifications were compromised. All affected support steel was replaced by February 2, 2017. The remaining air conditioner was inspected and found acceptable. Guidance for initiating work requests for corroded support members will be enhanced.
05000325/LER-2016-0055 December 2016Brunswick

On October 3, 2016, Units 1 and 2 were in Mode 1 (i.e., Run mode) at 100 percent of rated thermal power.

At that time, Engineering personnel were reviewing the plant response to NRC Information Notice 97-45, Supplement 1, on signal cables for the Drywell High Range Radiation Monitors (DWHRRMs). These cables are susceptible to thermally induced current (TIC), which can degrade the accuracy of DWHRRMs. The review resulted in DWHRRMs being declared inoperable on both units. The DWHRRMs were included in Technical Specifications (TS) Limiting Condition for Operation (LCO) 3.3.3.1 beginning in 1984. As a result of the TIC effect on the DWHRRM cables, BSEP Unit 1 and Unit 2 have operated longer than the TS allowed completion times for inoperable DWHRRMs. This event is reportable per 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by the plant TSs. The event resulted from the inherent characteristics of the cables and DWHRRMs. An existing site procedure directs the use of alternate indications for assessment of drywell or fuel cladding conditions, and this procedure will remain in place as a compensatory action. Corrective actions will include replacing the cables on a schedule to be developed after assessment of available options.

05000324/LER-2016-00229 August 2016Brunswick

On July 5, 2016, at 1640 Eastern Daylight Time (EDT), the Unit 2 High Pressure Coolant Injection (HPCI) system was declared inoperable due to apparent failure of the HPCI Auxiliary Oil Pump. The HPCI Auxiliary Oil Pump provides hydraulic pressure required to open the HPCI Turbine Stop Valve and the HPCI Turbine Control Valve during initial HPCI startup. Failure of the HPCI Auxiliary Oil Pump prevents the HPCI system from performing its safety function.

This condition is being reported in accordance with 10 CFR 50.73(a)(2)(v)(D), as an event or condition that could have prevented the fulfillment of the safety function of a system that is needed to mitigate the consequences of an accident.

The HPCI system inoperability was due to loss of control power for the Auxiliary Oil Pump. The loss of control power was caused by a failed motor overload alarm relay coil; which caused current flow in excess of the control power fuse rating. The HPCI system was restored on July 6, 2016, at 1050 EDT. The alarm relay coil failure was age related.

The corrective actions include creation of preventive maintenance tasks to replace the Unit 1 and 2 HPCI motor overload alarm relay coils on an appropriate frequency.

05000324/LER-2016-0018 August 2016BrunswickOn June 15, 2016, at 05:15 Eastern Daylight Time, Unit 2 was in Mode 1 (i.e., Run mode) at 100 percent of rated thermal power. At that time, Operations personnel were preparing to run the Residual Heat Removal Service Water (RHRSW) system in the spppression pool cooling mode. While performing the valve lineup, an alarm was received on low RHRSW suction pressure. Two instrument valves connected to the "B" and "D" RHRSW pump suctions were found closed. This resulted in the pump start logic being unable to sense RHRSW pump suction pressure, which prevented the pumps from being able to start. With the pumps unable to start, the associated RHRSW division was inoperable. It is most likely that the valves were mispositioned during a previous operation of the "B" RHRSW division. The event resulted from procedures which did not adequately control the position of the instrument valves. Corrective actions for this event included repositioning the valves to their correct configuration and revising applicable procedures.
05000325/LER-2016-0028 August 2016Brunswick

On March 4, 2016, at 1235 Eastern Standard Time (EST), Emergency Diesel Generator (EDG) 3 was declared inoperable. At this time, EDG 1, Emergency bus El, and balance of plant (BOP) bus 1D were inoperable due to planned maintenance. Two inoperable EDGs represents a loss of safety function, for the onsite standby power source.

Therefore, this condition is being reported in accordance with 10 CFR 50.73(a)(2)(v)(D), as an event or condition that could have prevented the fulfillment of the safety function of a system that is needed to mitigate the consequences of an accident. In addition, it was determined that EDG 3 was inoperable for greater than Technical Specifications (TSs) Completion Times. Therefore, this condition is also being reported in accordance with 10 CFR 50.73(a)(2)(i)(B) as operation prohibited by the TSs. Additionally, on March 3, work was ongoing to restore power to BOP bus 1D when an error in the restoration sequence resulted in an invalid auto-start of EDGs 2 and 4. Because the invalid auto-starts of EDGs 2 and 4 are directly related to the events associated with this LER, it is being reported, herein, per 10 CFR

  • 50.73(a)(2)(iv)(A) rather than the optional 60-day telephone notification.

The root cause of the EDG 3 inoperability is a design vulnerability associated with relaxation of the EDG 3 fuse holder fingers which was not properly mitigated. The corrective action to prevent recurrence will be to implement a design change to address the vulnerability.

05000325/LER-2016-0032 May 2016Brunswick

On March 9, 2016, Unit 1 implemented the guidance of EGM 11-003, Revision 3, "Enforcement Guidance Memorandum 11-003, Revision 3, Dispositioning Boiling Water Reactor Licensee Noncompliance with Technical Specification Containment Requirements during Operations with a Potential for Draining the Reactor Vessel," dated January, 15, 2016. Consistent with EGM 11-003, Revision 3, secondary containment operability was not maintained during Operations with a Potential for Draining the Reactor Vessel (OPDRV) activities, and Required Actions C.1 and C.2 of Technical Specification (TS) 3.6.4.1, "Secondary Containment," were not completed. EGM 11-003, Revision 3, was implemented four additional times during the 2016, Unit 1 refueling outage. These conditions are being reported in accordance with 10 CFR 50.73(a)(2)(i)(B) as operations prohibited by the plant's TSs.

Implementation of EGM 11-003, Revision 3, during the Unit 1 refueling outage was a planned activity. As such, there was no root cause evaluation of the event. Consistent with the guidance provided in EGM 11-003, Revision 3, BSEP will submit a license amendment request to adopt a Technical Specification Task Force (TSTF) traveler associated with generic resolution of this issue within 12 months after the issuance of the Notice of Availability of the TSTF traveler.

05000325/LER-2016-0016 April 2016BrunswickOn February 7, 2016, at 1312 Eastern Standard Time (EST), Unit 1 was in Mode 1 (i.e., Run) at 88 percent of rated power in end-of-cycle coastdown. At that time, an electrical fault occurred on a balance of plant 4160-volt bus, resulting in a lockout of the Startup Auxiliary Transformer (SAT) and a loss of both Reactor Recirculation pumps. Licensed personnel inserted a manual scram per procedure. Emergency Diesel Generators supplied emergency electrical busses until offsite power was restored at 1628 EST. The loss of power and reactor water level changes resulted in automatic closures of various Primary Containment Isolation Valves (PCIVs). The electrical fault resulted in an electrical explosion; therefore, an Alert was declared at 1326 EDT. The immediate cause of this event was a fault in a non-segregated electrical bus connected to the SAT. The root causes were insufficient detail in applicable maintenance instructions for inspecting the non-segregated bus housing and inadequate instructions for terminating electrical cables in a circuit breaker cubicle. Corrective actions include repairing equipment damaged by the electrical fault and revising the procedures and work instructions.
05000325/LER-2015-00121 December 2015Brunswick

At 1336 Eastern Standard Time (EST) on February 12, 2015, the Unit 1 High Pressure Coolant Injection (HPCI) System was declared inoperable due to a failure of the HPCI auxiliary oil pump. During performance of a HPCI weekly inspection, the auxiliary oil pump was started and subsequently stopped running unexpectedly.

The HPCI auxiliary oil pump provides hydraulic pressure required to open the HPCI turbine stop valve and the HPCI turbine control valve during initial HPCI startup. Failure of the HPCI auxiliary oil pump prevents the HPCI system from performing its design safety function.

This condition is being reported in accordance with 10 CFR 50.73(a)(2)(v)(D), as an event or condition that could have prevented the fulfillment of the safety function of a system that is needed to mitigate the , consequences of an accident.

The cause of the HPCI inoperability was a faulty magnetic motor contactor coil (i.e., M-coil) within the HPCI turbine auxiliary oil pump motor contactor 1-1XDA-B11-M. The failure of the coil was determined to be most likely long term thermal cycling. The coil was replaced, and the HPCI system was returned to operable status on February 20, 2015.

05000324/LER-2015-0035 August 2015BrunswickOn April 8, 2015, at 1639 Eastern Daylight Time (EDT), licensed personnel were informed that oil leakage on the motor for Residual Heat Removal Service Water (RHRSW) system pump 2C exceeded the amount that would be acceptable in order for the pump to meet its 30-day mission time. Event investigators found that sealant had not been applied to mechanical joints in the bearing housings on the horizontal motor, resulting in oil leaking through the unsealed joints. Based on the historical rate of oil additions, engineering personnel concluded that the bearings would not have been able to operate throughout their full mission time, and licensed personnel declared the 2C RHRSW pump inoperable on that basis. The condition resulted in a failure to comply with Technical Specification (TS) 3.7.1, "Residual Heat Removal Service Water (RHRSW)," and with TS Limiting Condition for Operation (LCO) 3.0.4, and also resulted in a loss of the safety function. The direct cause of this event was lack of sealant in mechanical joints of the bearing housings. The root cause was that the process for identifying and updating maintenance procedures impacted by a safety related engineering change was less than adequate, and a contributing cause was a lack of questioning attitude. Corrective actions for this event included applying sealant to the bearing housings, revising procedures to address safety related engineering changes, and discussing the event with appropriate maintenance personnel.
05000324/LER-2015-00226 June 2015BrunswickOn March 10, 2015, BSEP received the results of testing of eleven main steam line safety relief valves (SRVs) removed from Unit 2 during the spring Unit 2 refueling outage. Three of the eleven valves were found to have as-found lift setpoints of their pilot valves outside the +/-3 percent tolerance required by Technical Specification (TS) 3.4.3. One SRV was 3.2 percent high; one SRV was 3.6 percent high, and one SRV was 4.0 percent low. Elevated lift pressures resulted from micro-cracking remaining on the pilot disc surface which allowed a localized region of the platinum coating to degrade, resulting in slight corrosion bonding which raised the breakaway force needed to open the pilot. No cause was identified for the one SRV having a reduced lift setpoint. This event had no adverse impact on nuclear safety. Although the SRV setpoint limits required by the TS were exceeded, the plant condition was bounded by the Brunswick Unit 2 Cycle 21 Reload Safety Analysis, demonstrating that the SRVs could have performed their safety function of limiting reactor vessel overpressure. TS 3.4.3 requires ten of the eleven installed SRVs to be operable. Since only eight SRVs were operable, this event is being reported in accordance with 10 CFR 50.73(a)(2)(i)(B) for operation prohibited by the plant's TS. The SRV pilot valves were replaced with certified spares before the startup of Unit 2. A maintenance procedure will be revised, and a different base metal for the pilot valve will be assessed.
05000324/LER-2015-00124 April 2015Brunswick

On February 26, 2015, Unit 2 implemented the guidance of EGM 11-003, Revision 2, "Enforcement Guidance Memorandum on Dispositioning Boiling Water Reactor Licensee Noncompliance with Technical Specification Containment Requirements During Operations with a Potential for Draining the Reactor Vessel," dated December 13, 2013. Consistent with EGM 11-003, Revision 2, secondary containment operability was not maintained during Operations with a Potential for Draining the Reactor Vessel (OPDRV) activities, and Required Actions C.1 and C.2 of Technical Specification (TS) 3.6.4.1, "Secondary Containment," were not completed. EGM 11-003, Revision 2, was implemented four additional times during the 2015, Unit 2 refueling outage. These conditions are being reported in accordance with 10 CFR 50.73(a)(2)(i)(B) as operations prohibited by the plant's TSs.

Implementation of EGM 11-003, Revision 2, during the Unit 2 refueling outage was a planned activity. As such, there was no root cause evaluation of the event. Consistent with the guidance provided in EGM 11-003, Revision 2, BSEP will submit a license amendment request to adopt a Technical Specification Task Force (TSTF) traveler associated with generic resolution of this issue within 12 months after the issuance of the Notice of Availability of the TSTF traveler.

05000325/LER-2014-00521 July 2014Brunswick

On May 20, 2014, BSEP received the results of as-found testing on 11 safety/relief valves (SRVs) which had been removed from Unit 1 during the spring 2014 refueling outage. The testing indicated that two of the valves were found to lift outside the Technical Specifications (TS) required tolerance band of +/-3 percent, one having drifted 3.7 percent high and the other 3.4 percent low. Therefore, these two valves were determined to have been inoperable while the unit was in operation. Since TS 3.4.3, "Safety/Relief Valves," requires at least 10 of the 11 valves to be operable, this condition is being reported in accordance with 10 CFR 50.73(a)(2)(i)(B) as operation prohibited by the plant's TS.

Setpoint drift in the increasing direction occurred in one valve because of an inadequate surface finish on its pilot disc which caused a loss of the platinum coating followed by corrosion bonding of the disc and seat. The cause of the setpoint drift in the other valve could not be determined, and the initial lift pressure for the second valve was lower than its setpoint. Corrective actions for this event included replacing all the SRV pilot valves in Unit 1 with certified spares and completing a procedure revision for ensuring proper surface preparation.

05000325/LER-2014-00416 May 2014Brunswick

On March 20, 2014, as a result of the transition process from 10 CFR 50, Appendix R, to NFPA 805, a review of the Brunswick Steam Electric Plant Safe Shutdown Analysis determined that a postulated fire in specific fire areas could disable critical components, potentially resulting in equipment required for safe shutdown being inoperable.

The safety significance of this event is minimal. Deterministic analysis methods used to comply with Appendix R require every possible fire scenario to be addressed; however, the risk posed by these hypothetical events has been determined by analysis to be minimal.

Corrective actions for this event include maintaining fire watches in affected areas and revising fire response procedures to mitigate the consequences of a potential fire in these areas in order to establish compliance with Appendix R and the current licensing basis.

05000325/LER-2014-0039 May 2014Brunswick

At 0937 Eastern Daylight Time (EDT) on March 13, 2014, Operations was informed that both the inner and outer secondary containment airlock doors, on the 50 foot elevation of the reactor building, had been simultaneously opened for approximately one minute. This event occurred while an employee was exiting secondary containment at the same time an employee was entering secondary containment. Upon recognition of the condition, the employees took action to secure both doors.

This condition, as well as one additional similar occurrence, are being reported in accordance with 10 CFR 50.73(a)(2)(v)(C), as an event or condition that could have prevented fulfillment of a safety function needed to control the release of radioactive material. With both doors open, Surveillance Requirement 3.6.4.1.2 of Technical Specification 3.6.4.1, Secondary Containment, was not met, rendering secondary containment inoperable. In each example, Operations with the Potential to Drain the Reactor Vessel (OPDRVs) were in progress and secondary containment was credited as operable.

The root cause of the events is that the design of the secondary containment airlock door interlocks is not robust enough to prevent inoperability of secondary containment. The corrective action to prevent recurrence is to implement a design change to install a new interlock for the secondary containment airlock doors.

05000325/LER-2014-0025 May 2014Brunswick

On March 9, 2014, Unit 1 was in Mode 5 with Operations with Potential to Drain the Reactor Vessel (OPDRVs) in progress. At 1300 Eastern Daylight Time, planned work commenced which removed both the normal and emergency electric power supplies for one train of the secondary containment isolation dampers (SCIDs). As a result, the SCIDs were declared inoperable, despite alignment of temporary control power to the SCIDs, and the Required Actions of Technical Specifications (TS) Limiting Condition for Operation (LCO) 3.6.4.2 were not carried out. Therefore, the plant entered a condition which is prohibited by the TS.

This event resulted from a deficiency in procedure OMMM-054, "Temporary Power Feed Documentation." The procedure did not require a Senior Reactor Operator (SRO) to determine whether a component is required to be operable while being supplied with temporary power. This resulted in SCIDs being supplied with temporary control power, not normal or emergency power, when they were required to be operable.

To prevent recurrence, procedure OMMM-054 will be revised to include an SRO review for temporary power applications.

05000324/LER-2014-0012 May 2014Brunswick

At 1605 Eastern Standard Time (EST) on March 6, 2014, Operations determined that both the inner and outer secondary containment airlock doors, on the 50 foot elevation of the reactor building, had been simultaneously opened for approximately one to two minutes on March 5, 2014. This event occurred while an employee was exiting secondary containment. The inner door failed to latch and opened as the employee was opening the outer door. Upon recognition of the condition, the employee took action to secure both doors.

This condition is being reported in accordance with 10 CFR 50.73(a)(2)(v)(C), as an event or condition that could have prevented fulfillment of a safety function needed to control the release of radioactive material.

With both doors open, Surveillance Requirement 3.6.4.1.2 of Technical Specification 3.6.4.1, Secondary Containment, was not met, rendering secondary containment inoperable.

i The root cause of this event is that the design of the secondary containment airlock c:oor interlocks is not robust enough to prevent inoperability of secondary containment. The corrective action to prevent recurence is to implement a design change to install a new interlock for the secondary containment airlock doors.

05000325/LER-2014-0011 May 2014Brunswick

On March 7, 2014, Unit 1 implemented the guidance of EGM 11-003, Revision 2, "Enforcement Guidance Memorandum on Dispositioning Boiling Water Reactor Licensee Noncompliance with Technical Specification Containment Requirements During Operations with a Potential for Draining the Reactor Vessel," dated December 13, 2013. Consistent with EGM 11-003, Revision 2, secondary containment operability was not maintained during Operations with a Potential for Draining the Reactor Vessel (OPDRV) activities, and Required Actions C.1 and C.2 of Technical Specification (TS) 3.6.4.1, "Secondary Containment," were not completed. EGM 11-003, Revision 2, was implemented four additional times during the 2014, Unit 1 refueling outage. These conditions are being reported in accordance with 10 CFR 50.73(a)(2)(i)(B) as operations prohibited by the plant's TSs.

Implementation of EGM 11-003, Revision 2, during the Unit 1 refueling outage was a planned activity. As such, there was no root cause evaluation of the event. Consistent with the guidance provided in EGM 11-003, Revision 2, BSEP will submit a license amendment request to adopt a Technical Specification Task Force (TSTF) traveler associated with generic resolution of this issue within 12 months after the issuance of the Notice of Availability of the TSTF traveler.

05000324/LER-2013-0016 May 2013Brunswick

On March 7, 2013, Unit 2 implemented the guidance of EGM 11-003, Revision 1, "Enforcement Guidance Memorandum on Dispositioning Boiling Water Reactor Licensee Noncompliance with Technical Specification Containment Requirements During Operations With a Potential for Draining the Reactor Vessel," dated December 20, 2012. Consistent with EGM 11-003, Revision 1, secondary containment operability was not maintained during Operations With a Potential for Draining the Reactor Vessel (OPDRV) activities, and Required Action C.1 of Technical Specification (TS) 3.6.4.1, "Secondary Containment," was not completed. EGM 11-003, Revision 1, was implemented four additional times during the 2013, Unit 2 refueling outage. These conditions are being reported in accordance with 10 CFR 50.73(a)(2)(i)(B) as operations prohibited by the plant's TSs.

Implementation of EGM 11-003, Revision 1, during the Unit 2 refueling outage was a planned activity.

As such, there was no root cause evaluation of the event. Consistent with the guidance provided in EGM 11-003, Revision 1, BSEP will submit a license amendment request to adopt a Technical Specifications Task Force (TSTF) traveler associated with generic resolution of this issue within four months after the issuance of the Notice of Availability of the TSTF traveler.

05000325/LER-2012-00711 April 2013Brunswick

On December 14, 2012, at approximately 1306 hours Eastern Standard Time (EST), inoperability of both subsystems of the Control Room Emergency Ventilation (CREV) system occurred. Because Brunswick has a shared control room, this placed Unit 1 and Unit 2 in Technical Specification (TS) 3.7.3, Required Action C.1, for two CREV subsystems inoperable (i.e., be in Mode 3 within 12 hours).

At the time of the event, a modification to upgrade the Control Building fire detection system was in progress. The 2A CREV subsystem was placed in the radiation/smoke protection mode in compliance with the Technical Requirements Manual. This action prevented an auto-start of the 2B CREV subsystem and, as such, TS 3.7.3 Condition A was entered to restore 2B CREV subsystem to operable status within 7 days.

During work to electrically isolate one of the fire detectors associated with the 2A CREV subsystem, electrical continuity was lost resulting in a charcoal fire signal being sent to the 2A CREV subsystem circuitry and shutting it down. With the 2A CREV subsystem shut down due to the signal, TS 3.7.3 Required Action C.1 applied for both CREV subsystems being inoperable. Actions were taken to re-start the 2A CREV subsystem, and TS 3.7.3 Required Action C.1 was exited within approximately two minutes.

The safety consequences of this event were minimal. The condition existed for approximately two minutes, and plant staff took immediate action to return the equipment to service. The apparent cause of the event was inadequate documentation and communication of the required system alignment to support the ongoing modification.

05000325/LER-2012-00619 November 2012Brunswick

On September 15, 2012, Unit 1 began a forced outage to replace a 1B recirculation pump seal. On September 17, with the unit in Mode 4, a clearance was hung on the 1B recirculation loop and the recirculation pump suction and discharge isolation valves were isolated to provide the reactor coolant system boundary. After the valves were isolated, there was approximately 10 gpm of leakage by the seats.

On September 19, 2012, at approximately 0330 hours Eastern Daylight Time (EDT), secondary containment airlock doors were opened to facilitate additional ventilation flow to the reactor building, thereby improving working conditions. The decision to open the secondary containment airlock doors was based on BSEP established guidance that leakage through mechanical joints (e.g., valve or flange packing leaks, seat leakage through an isolation valve, flange leakage) is not an Operation with a Potential for Draining the Reactor Vessel (OPDRV). The NRC Senior Resident Inspector questioned this position and, ultimately, the NRC concluded that the activity did constitute an OPDRV. Conducting an OPDRV activity coincident with secondary containment being inoperable constituted operation prohibited by Technical Specification (TS) 3.6.4.1 and is reportable in accordance with 10 CFR 50.73(a)(2)(i)(B).

The cause of this event was inappropriate application of guidance in plant procedure 001-01.01, "BNP Conduct of Operations Supplement." The immediate corrective action was to re-establish secondary containment.

05000325/LER-2012-00529 October 2012Brunswick

On August 28, 2012, during planned maintenance on Emergency Diesel Generator No.2 (EDG 2), a post-maintenance continuity test associated with the Alternate Safe Shutdown (ASSD) switch on EDG 2 revealed unexpected results when the switch was taken to the LOCAL position.

Troubleshooting activities determined the switch to be operating properly. However, a current path preventing isolation of the control room circuit remained.

EIt was determined that a wire, not identified in EDG wiring diagrams, created a short between two ASSD switch contacts.

At 2134 hours Eastern Daylight Time (EDT) on August 29, 2012, it was concluded that the condition may impact the ability of EDG 2 to perform its intended ASSD function. In the event of a fire, an induced fault could potentially affect the ability to locally control EDG 2. Local control of EDG 2 is credited in the safe shutdown analysis. This condition did not affect the Technical Specification operability of EDG 2 and it remained fully capable of performing its intended safety function.

The direct cause of this event was a wiring error associated with the local control circuitry for EDG 2.

This was a historical error which was likely introduced during the original installation. Therefore, no root cause was determined. The error was limited to EDG 2 and has been corrected.

05000325/LER-2012-0037 June 2012Brunswick

On April 9, 2012, at 0529 hours Eastern Daylight Time (EDT), electrical power was lost to the 4160 V emergency bus E1. Activities to support performance of procedure OMST-DG11R, "DG-1 Loading Test," were in progress when technicians connected a recorder to the incorrect terminals of an under­ voltage relay on emergency bus El and caused the normal supply breakers for emergency bus El to open. Emergency Diesel Generator (EDG) 1 automatically started and re-energized emergency bus El per plant design.

This condition is being reported in accordance with 10 CFR 50.73(a)(2)(iv)(A) as an event that resulted in automatic actuation of a system specified in 10 CFR 50.73(a)(2)(iv)(B).

The root cause of this event is inadequate use of human performance tools when connecting recorders in preparation for performing OMST-DG11R. Corrective actions include revising the EDG loading test procedures to provide instructions on labeling cables and to incorporate a method to record cable assignments to respective procedural steps.

05000325/LER-2012-0022 May 2012Brunswick

On March 8, 2012, and on March 13, 2012, Unit 1 implemented the guidance of EGM 11-003, "Enforcement Guidance Memorandum on Dispositioning Boiling Water Reactor Licensee Noncompliance with Technical Specification Containment Requirements During Operations With a Potential for Draining the Reactor Vessel," dated October 4, 2011. Consistent with EGM 11-003, secondary containment operability was not maintained during Operations With a Potential for Draining the Reactor Vessel (OPDRV) activities and Required Action C.1 of Technical Specification (TS) 3.6.4.1, "Secondary Containment," was not completed. This condition is being reported in accordance with 10 CFR 50.73(a)(2)(i)(B) as operation prohibited by the plant's TSs.

Implementation of EGM 11-003 during the Unit 1 refueling outage was a planned activity. As such, there was no root cause evaluation of the event. Consistent with the guidance provided in EGM 11-003, BSEP will submit a license amendment request to adopt a Technical Specifications Task Force (TSTF) traveler associated with generic resolution of this issue, within four months after the issuance of the Notice of Availability of the TSTF traveler.

05000325/LER-2011-00330 January 2012Brunswick

On December 1, 2011, at 1344 hours Eastern Standard Time (EST), the Control Building (CB) instrument air dryer failed resulting in loss of control air. As a result, the three Control Room Air Conditioning subsystems required by Technical Specification (TS) 3.7.4, "Control Room Air Conditioning (AC) System," and the two Control Room Emergency Ventilation subsystems required by TS 3.7.3, "Control Room Emergency Ventilation (CREV) System," became inoperable. Because Brunswick has a shared control room, Unit 1 and Unit 2 entered TS 3.7.3 Required Action B.1, for two CREV subsystems inoperable (i.e., be in Mode 3 within 12 hours) and TS 3.7.4, Required Action E.1, for three Control Room (CR) AC subsystems inoperable (i.e., enter LCO 3.0.3 immediately). At 1410 hours, operability of two Control Room AC subsystems and one CREV subsystem was restored, and LCO 3.0.3 was exited, when the CB instrument air dryer was bypassed. No power reduction took place as a result of the LCO 3.0.3 entry.

The failure of the CB instrument air dryer was due to low refrigerant pressure leading to ice blockage of the instrument air supply line. The cause was inadequate monitoring to detect the low refrigerant pressure.

Corrective actions include replacing the instrument air dryer and a procedure revision to bypass the dryer when low refrigerant pressure conditions exist.

05000325/LER-2011-0028 December 2011Brunswick

On October 13, 2011, in preparation for converting from 10 CFR 50, Appendix R, to NFPA 805, a review of the Brunswick Steam Electric Plant (BSEP) Safe Shutdown Analysis identified conditions that may not ensure a protected train of equipment remains available under certain postulated fire scenarios. The analysis determined that a postulated fire in specific fire areas could cause spurious actuation of critical components, potentially resulting in loss of equipment required for safe shutdown. A fire in one of the specified fire areas could potentially adversely affect the following: Suppression Pool level instrument 2-CAC-LT-2602, Residual Heat Removal net positive suction head (i.e., drywell containment overpressure), Reactor Core Isolation Cooling (RCIC), Emergency Bus E-1, and Emergency Bus E-3.

The safety significance of this event is minimal. Fire watches were established for the affected portions of fire areas RB1-1, RB2-1, TB1, CB-2, CB-13, and CB-23. Additionally, fire detection and suppression equipment in the affected areas were fully functional.

This was determined to be a historical condition and no root cause could be identified. Corrective actions include establishing an hourly fire watch in the affected fire areas, revision of alternative safe shutdown procedures, and completion of a new safe shutdown analysis.

05000325/LER-2011-0012 June 2011Brunswick

On April 7, 2011, at approximately 1740 hours Eastern Daylight Time (EDT), a loss of the Control Room Emergency Ventilation (CREV) system occurred. At the time of the event, the plant was performing OMST- DG13R, "DG-3 Loading Test." During performance of this test, the 480 VAC Emergency Bus E-7 main feeder breaker tripped unexpectedly. As a result, the CREV emergency makeup damper 2-VA-2J-D-CB closed on loss of power, resulting in two CREV subsystems required by TS 3.7.3, "CREV System," being inoperable. This condition could have prevented the fulfillment of the safety function for this system. BSEP has a shared Control Room, but only Unit 1 was required to enter TS 3.7.3, Required Action C.1, for two CREV subsystems inoperable (i.e., be in Mode 3 within 12 hours). Unit 2 was operating in Mode 4 for a scheduled refueling outage and did not meet any applicability conditions for TS 3.7.3.

This condition is being reported as an event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to mitigate the consequences of an accident.

The safety consequences of this event were minimal. The condition existed for approximately one hour and 51 minutes, and plant staff took immediate action to return the equipment to service. The direct cause of the E-7 breaker trip was a spurious actuation of the solid state trip unit (i.e., no root cause could be determined).

The corrective actions included replacement of the breaker.

05000325/LER-2010-00411 November 2010Brunswick

On September 12, 2010, at approximately 2100 hours Eastern Daylight Time (EDT), a routine monthly surveillance, OPT-12.2D, "No. 4 Diesel Generator Monthly Load Test," was started on Emergency Diesel Generator No. 4 (EDG4). During the performance of the surveillance test, sparking was observed coming from the diesel generator inner ring brushes. The maximum sparking began approximately 45 minutes after EDG4 started, and remained for the duration of the diesel run. Following performance of the surveillance test, collector ring brush measurements identified abnormal wear on the inner ring brushes. Engineering determined that, due to the brush wear and excessive sparking, EDG4 would not have been able to run for its mission time. At 0430 hours on September 13, 2010, EDG4 was declared inoperable. This condition is being reported as an operation prohibited by Technical Specifications (TS), due to EDG4 inoperable greater than the TS completion time.

The safety consequences of this event were minimal. The three remaining Emergency Diesel Generators were operable and available to provide emergency AC power if needed. The root cause was determined to be untimely implementation of corrective actions to a long-standing concern. The corrective actions include replacing the collector rings with an upgraded design that is not subject to corrosion.

05000325/LER-2010-00223 June 2010Brunswick

On April 25, 2010, at 2100 hours Eastern Daylight Time (EDT), with the unit in Mode 2 at 900 psig, pressure transmitter 1-B21-PT-N023B was declared inoperable due to reading downscale. This transmitter is part of the instrumentation required for operability of Function 3, "Reactor Vessel Steam Dome Pressure - High," of Technical Specification 3.3.1.1, "Reactor Protection System (RPS) Instrumentation." Table 3.3.1.1-1, "Reactor Protection System Instrumentation," which requires two operable channels when in Modes 1 and 2. It was determined that the inoperability of pressure transmitter 1-B21-PT-N023B was due to-valve 1-B21-IV-1384, ."B21-PT-N023B Instrument Isolation Valve," being in the closed position. Unit 1 had previously entered Mode 2 at 0313 hours on April 24, 2010, during startup from the Unit 1, Cycle 18 refueling outage. This condition is being reported in accordance with 10 CFR 50.73(a)(2)(i)(B) as operation prohibited by the plant's Technical Specifications.

The select cause of this event was the failure to effectively use the concurrent verification during the performance of procedure OMST-EFCV18R, "EFCV Rx Inst Pen Sys Isol Vlv Func Test X53, X82, X49B-A.

As a result, valve 1-B21-IV-1384 was left in the closed versus open position. The corrective actions to prevent recurrence will enhance concurrent verification practices through establishing new expectations for Maintenance personnel and procedure improvements.

05000325/LER-2010-00127 April 2010Brunswick

On February 27, 2010, at approximately 0116 hours Eastern Standard Time (EST), Control Room Operators manually inserted a Reactor Protection System (RPS) trip to shutdown the reactor from approximately 21 percent of rated thermal power to begin a planned refuel outage. The 1B Reactor Feedwater Pump (RFP) had been removed from service at approximately 61% rated thermal power and isolated to support scheduled maintenance' activities. Following the insertion of the RPS trip, the lA RFP was shutdown due to high RFP turbine casing drain level. At 0158 hours, Unit 1 Control Room Operators manually started the Reactor Core Isolation Cooling (RCIC) system to maintain reactor pressure vessel (RPV) coolant level following the pre­ planned reactor scram. The RCIC system maintained RPV coolant level until the 1B RFP could be returned to service. The RCIC system was shutdown at 0306 hours. All systems functioned as designed.

The safety consequences of this event were minimal. The RPV level remained in the normal band while RCIC was being used for level control during the transient. All Emergency Core Cooling Systems (ECCS) were operable and available to provide adequate core cooling if needed. The root cause of this event was that Operators made the redundant RFP unavailable while still above the reactor pressure at which a RFP is required to feed the RPV. The corrective actions to prevent recurrence for this event are to revise operating procedures cautioning that a Reactor Feedwater Pump should not be made unavailable before reactor pressure is less than 350 psig.

05000325/LER-2009-0028 September 2009Brunswick

On July 8, 2009, at 1013 hours Eastern Daylight Time (EDT), during planned preventive maintenance activities, electrical power was lost to the 4160V emergency bus E2. Emergency Diesel Generator 2 automatically started and re-energized the E2 bus. The loss of power to E2 resulted in Unit 1 Primary Containment Isolation System Groups 2, 3, 6, and 10 isolations. Per design, no Unit 2 safety system group isolations or actuations occurred. Other Unit 1 actuations included the Reactor Building Ventilation System isolation (i.e., Secondary Containment isolation), automatic start of both trains of the Standby Gas Treatment System and automatic start of both trains of the Control Room Emergency Ventilation System. The affected equipment responded as designed.

This event occurred during activities associated with instrument calibration of an emergency bus E2 voltage transducer. Technicians performing the activity opened the wrong test switch. As a result, arcing occurred when test equipment was connected to an energized circuit. This caused the blown fuse in the C phase of emergency bus E2, which in turn caused a loss of power to the emergency bus and the E2 master/slave breaker to trip. The root cause of this event is inadequacies associated with procedure OPIC-CNV023 and the associated work order used to perform the preventive maintenance task. Corrective actions to prevent recurrence will correct identified problems with these documents.

05000324/LER-2009-00129 March 2009Brunswick

On January 27, 2009, at 2007 hours Eastern Standard Time (EST), the Unit 2 High Pressure Coolant Injection (HPCI) system was declared inoperable due to a sustained high water level in the HPCI exhaust line drain pot. The inability to reduce level in the exhaust line drain pot resulted in backup of water into the HPCI turbine casing which rendered the system unavailable to perform its safety function. This sustained high level was caused by a failure of the HPCI barometric condenser condensate pump and difficulties in establishing an alternate drain path from the barometric condenser. The HPCI system was declared operable, following repair of the HPCI barometric condenser condensate pump, on January 28, 2009, at 2050 hours EST.

There are two root causes associated with this event. The HPCI barometric condenser condensate pump failed because no Preventive Maintenance (PM) activities had been established for the pump and motor.

The difficulties in establishing an alternate drain path were a result of an incorrect annunciator response procedure. Corrective actions to prevent recurrence include establishment of PM activities for the HPCI barometric condenser condensate punip and motor and correction of the annunciator response procedure.

05000325/LER-2008-00311 August 2008Brunswick

On June 11, 2008, as a result of a review of the Reactor Building crane structure by the original Reactor Building cranes did not ensure the crane structural integrity during a design basis seismic event.

Specifically, the allowable design stresses for the design basis seismic event are exceeded in the end connector plates and bolted connections connecting the crane girders. This condition has existed since operation of the plants began.

The direct cause of this event is that the crane girder end connection design was not adequately evaluated during the initial design of the crane by Whiting Corporation (i.e., the OEM). The crane design was performed by Whiting Corporation in the 1970's. Due to the historical nature of this condition, determining a plausible cause is not practical or feasible.

Modifications have been implemented for the Unit 1 and Unit 2 Reactor Building cranes to allow continued restricted use of the cranes for loads of up to 40 tons. Engineering Changes will be developed and implemented to restore the cranes to their original seismic design requirements.

05000325/LER-2008-00130 June 2008Brunswick

On April 29, 2008, at approximately 2313 Eastern Daylight Time (EDT), during performance of the High Pressure Coolant Injection (HPCI) system operability test, the HPCI system was declared inoperable due to a leak on the main pump seal. When the pump seal leak developed, operators secured HPCI and isolated the leak by closing the pump suction isolation valves and the keep fill supply valves.

The safety consequences of this event were minimal. The Emergency Core Cooling Systems (ECCS) and the Reactor Core Isolation Cooling (RCIC) system were operable and would provide appropriate Loss-of-Coolant Accident (LOCA) response.

Investigation of this event found that inadequate post-maintenance venting of piping between the discharge of the HPCI booster pump and the suction of the HPCI main pump led to the seal faces overheating and subsequent failure.

An engineering analysis is in progress to substantiate the ability of the HPCI system to fulfill its safety functions in the degraded condition. This LER will be supplemented, and based on the results of the engineering evaluation, may result in retraction of Event Notification 44179 and withdrawal of this LER.

05000324/LER-2007-00410 December 2007Brunswick
05000325/LER-2006-0037 June 2006Brunswick

At 1630 on April 10, 2006, plant personnel identified a potential detection system. The failure mode has the potential to render the (CREV) system inoperable following power restoration after a (LOOP/LOCA) event. Due to this design deficiency, the CREV Specification (TS) 3.7.3, "Control Room Emergency Ventilation Condition B of TS 3.7.3. This required the units to be in Mode 36 hours. At 2100 on April 10, 2006, the CREV system radiation operable after removal of the chlorine tank car from the exclusion prevent them from operating. This event is being reported in accordance event or condition that could have prevented the fulfillment of are needed to mitigate the consequences of an accident. The safety minimal.

The root cause of this event was determined to be ineffective review modification prior to approval. Corrective actions include revising approval checklist, revision of the modification to eliminate the personnel training.

failure mode of the recently modified chlorine Control Room Emergency Ventilation Loss of Offsite Power/Loss of Coolant Accident system was declared inoperable per Technical System," which placed Units 1 and 2 in 3 within 12 hours and in Mode 4 within and smoke detection mode was restored to area and disabling the chlorine detectors to with 10 CFR 50.73(a)(2)(v)(D), as an the safety function of structures or systems that significance of this event is considered of the chlorine detector replacement an engineering procedure to add a final unanticipated failure mode, and additional

05000325/LER-2004-0014 March 2004Brunswick

On January 4, 2004, while performing the Emergency Diesel Generator (EDG) No. 3 monthly load test, a jacket water system piping leak of sufficient quantity to render EDG No. 3 inoperable was identified. As part of the investigation into this condition a past operability review was performed. The results of this review indicate that (1) a jacket water system pipe coupling was improperly installed during a coupling gasket replacement activity performed on February 3, 2003, and (2) tightening of the improperly installed coupling on December 8, 2003, resulted in excessive further misalignment of the coupling which impacted EDG operability until the misalignment was identified on January 4, 2004. The cause of the condition is attributed to missing pipe supports which resulted in an inadequate pipe coupling alignment. Failure to perform a functional verification following coupling maintenance on December 8, 2003, is considered a contributing cause. This condition is reportable in accordance with the 10 CFR 50.73(a)(2)(i)(B), as operation prohibited by the plant's Technical Specifications (TS), in that the EDG was inoperable for a period of time greater than that allowed by the TS. By January 7, 2004, the EDG No. 3 jacket water piping configuration was restored to the as-designed condition, satisfactorily tested, and the EDG returned to service. Additional corrective actions include .

inspection of the other EDGs for similar jacket water configuration concerns and reinforcement of minor maintenance functional verification requirements with maintenance personnel. Previous reportable occurrences involving either the inoperability of the EDGs or degraded conditions resulting from maintenance activities within the last two years were not identified.

05000325/LER-2003-00226 November 2003Brunswick

On October 5, 2003, Progress Energy Carolinas, Inc. (PEC) received notification from GE Nuclear Energy (GENE) of a reportable condition in accordance with 10 CFR 21.21(d) (i.e., SC03-20, "Stability Option III Period Based Detection Algorithm Allowable Settings," dated October 4, 2003). SC03-20 identified the potential for numerous, unexpected confirmation count resets in the event of an instability condition. These confirmation count resets could result in the inoperability of Technical Specification (TS) Table 3.3.1.1-1, "Reactor Protection System Instrumentation," Function 2.f, "OPRM Upscale?' Therefore, at 1100 Eastern Daylight Time (EDT) on October 5, 2003, the Unit I and Unit 2 Oscillation Power Range Monitor (OPRM) channels were declared inoperable in accordance with TS 3.3.1.1, "Reactor Protection System (RPS) Instrumentation," and an alternate method to detect and suppress thermal hydraulic instability oscillations was placed into effect as directed by Condition I of TS 3.3.1.1. PEC is preparing modifications to implement the recommendations of SC03-20 and return the OPRM Upscale function to operable status for both Units. The safety significance of this occurrence is considered minimal.

The apparent cause of the event is an incomplete analysis, performed by GENE, when establishing the OPRM's period based detection algorithm (PBDA).

NRC FORM 56617.2001)

  • NUMBER NUMBER Brunswick Steam Electric Plant (BSEP), Unit I 05000325 2oR 4