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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.

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.

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.

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.

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 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 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.

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.

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.

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.

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.

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 April 15, 2005, at approximately 2200 hours, as part of a pre-planned sequence of events, Unit 1 control room operators manually inserted a Reactor Protection system trip to shut down the reactor from approximately 23 percent of rated thermal power to begin a planned maintenance outage. At 2222 hours, the Reactor Core Isolation Cooling (RCIC) system was manually started to maintain reactor pressure vessel (RPV) coolant level after the 1A and 1B Reactor Feedwater Pumps (RFPs) could not be restarted to maintain level.

The RCIC system started and maintained RPV coolant level until the 1ARFP could be returned to service.

The cause of the event is attributed to coincident failures of the 1A RFP Minimum Flow Valve and the 1B RFP Suction Valve to reposition upon demand and provide start permissives to the associated RFP start logic. The 1A RFP Minimum Flow Valve was repaired by replacing galled internal parts, most likely caused by the presence of foreign material in the system. Replacement of RFP suction flange gaskets will remove the suspected source of the foreign material. The 1B RFP Suction Valve, a motor-operated gate valve, would not open due to the setting of the open torque switch bypass allowing the open torque switch to stop the motor before the gate could unwedge from its seat. Torque switch bypass adjustment and procedure changes will prevent recurrence. The safety significance of this occurrence is considered minimal.

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

On November 22, 2002, GE Nuclear Energy (GE) identified a reportable condition in accordance with 10 CFR 21.21(d) (i.e., SCO2-21, "Stability Option III: OPRM Tmin Specification"). SCO2-21 states that the Stability Option III period based detection algorithm (PBDA) range for minimum period of detection (i.e., Tmin) values specified in Licensing Topical Report NEDO-31960-A, "BWR Owner's Group Long-Term Stability Solutions Licensing Methodology (Supplement 1)," was non-conservative and recommended that the Oscillation Power Range Monitor (OPRM) be considered inoperable if the Tmin value is set greater than 1.2 seconds. Stability Option III is installed on Unit 1 and the Tmin value was set at 1.4 seconds. Therefore, at 1328 Eastern Standard Time (EST) on November 22, 2002, all OPRM channels were declared inoperable in accordance with Technical Specification (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. Subsequently, the Tmin value was changed to 1.2 seconds and all OPRM channels were declared operable at 0917 EST on November 27, 2002. The safety significance of this occurrence is considered minimal.

The apparent cause of the event is an incomplete analysis, performed by GE, when establishing oscillation period ranges to be used for the PBDA.