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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.

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.

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).

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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

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