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At 0110 on 11/17/03, during the performance of a maintenance surveillance, fuse 11321A- F8, the power supply fuse for the High Pressure Core Spray System (HPCS) Low Level Initiation/High Level Trip, was found not fully seated in its fuse clip. Loss of fuse continuity would have prevented automatic actuation of HPCS on reactor vessel low level, and would have prevented automatic closure of the HPCS discharge valve on reactor water high level.

The fuse was pushed back fully into the fuse clip at 0143. Engineering determined that, with the fuse not fully seated, continuity might not have been retained during a seismic event.

The cause of this event could not be determined. The most probable cause was a failure to fully seat the fuse during the last clearance order restoration in March 2002.

Corrective actions included a walk down of other cabinets in the Main Control Room and Auxiliary Electric Equipment Room for similar conditions.

On April 17, 2013, LaSalle Units 1 and 2 were operating in Mode 1 at 100% power, with a severe thunderstorm in progress. At 1457 hours CDT, lightning struck 138KV Line 0112, resulting in a phase-to-ground fault which subsequently cleared. At 1459 hours, a second phase-to-ground fault on Line 0112 occurred and all 345 KV oil circuit breakers (OCBs) in the main switchyard opened, resulting in a loss of offsite power and reactor scrams on both Units. All emergency diesel generators automatically started and loaded onto their respective busses. All control rods fully inserted, and all systems responded as expected.

An Unusual Event was declared due to a loss of offsite power for greater than 15 minutes. Offsite power was restored to all ESF busses by 2301 hours on April 17, 2013, and the Unusual Event was terminated at 0814 hours on April 18, 2013.

The root cause of the event was determined to be degradation of the 138kV switchyard grounding system that allowed a lightning induced fault to flash over onto the DC protective system. The ground system in the 138kV switchyard was repaired, and corrective actions include improving lightning shielding in the 138kV switchyard.

On March 29, 2014, Unit 1 was in Mode 1 at 100% power. At 1620 hours CDT, the Division 3 Core Standby Cooling System (CSCS) Pump Room, Switchgear Room, and Battery Room Ventilation failed in such a manner that heat could not be removed from the rooms. Due to the lack of ventilation in the Division 3 switchgear room the High Pressure Core Spray (HPCS) system was declared inoperable and Condition B of Technical Specification (TS) 3.5.1 was entered.

The cause of the event was a failure of the hydramotor pump bearing for the 1VD19Y, Division 3 CSCS Ventilation Return Fan Outlet Damper. Loss of hydraulic pressure in the hydramotor resulted in 1VD19Y failing in the closed position. The corrective action for the event was replacement of the hydramotor for the 1VD19Y damper.

On September 3, 2001, Unit 2 ESF Bus 241Y lost power due to actuation of the Division 1 undervoltage (UV) protective circuit. This caused the feedwater level control circuits to lose power. At 1728 hours, the operators inserted a manual scram because reactor water level could not be controlled.

Following the scram, reactor level continued to decrease until High Pressure Core Spray and Reactor Core Isolation Cooling automatically initiated and injected to restore level. All systems operated as designed. Safety relief valves were manually actuated to control reactor water level. 3 All control rods fully inserted.

The root cause of this event was that fuses failed in the potential transformer portion of the Division 1 UV protective circuit.

This scram was inserted due to loss of feedwater flow at 100% power. This transient is bounded by loss of feedwater event with a single failure. The loss of a single ESF bus caused the loss of some ESF systems. The redundant systems were available and operated as necessary to remove decay heat and control reactor vessel level and pressure.

On 7/7/03, while at 100 percent power, the LaSalle Station Unit 2 main power

• B" phase disconnect in the switchyard catastrophically failed, resulting in a main generator trip and reactor scram. The electrical transient tripped the three circulating water pumps, which resulted in the loss of normal heat removal. While controlling reactor pressure and level using the safety relief valves (SRv), the resulting shrink and swell transients caused four additional scram signals on low reactor level.

The cause of the disconnect failure could not be established. The cause of the additional scram signals was the lack of an operating strategy for these conditions.

The safety significance of this event was minimal. A reactor scram with a loss of the main condenser in an analyzed event. Reactor level and pressure were maintained using Reactor Core Isolation Cooling and the safety relief valves, and the High Pressure Core Spray System was available throughout the event.

Corrective actions include development of a condition monitoring program to inspect and monitor the condition of the insulators, and evaluating the adequacy of current switchyard inspection and maintenance procedures.

On September 25, 2010, at 0210 hours CDT, the Unit 2 Rounds Equipment Operator reported that the High Pressure Core Spray (HPCS) switchgear room supply fan 2VDO5C and the electrically interlocked exhaust fan 2VDO7C were not running. All Unit 2 Division 3 equipment was declared inoperable and unavailable. Because HPCS is a single train system, this occurrence is reportable under 10 CFR 50.72(b)(3)(v)(D) and 10 CFR 50.73(a)(2)(v)(D) as an event or condition that alone could have prevented the fulfillment of the safety function of structures or systems that are needed to mitigate the consequences of an accident.

Troubleshooting identified that the switchgear cubicle control relay had failed. The relay was replaced, and post maintenance testing was completed satisfactorily. The cause was determined to be age-related failure due to the lack of time-based replacement preventative maintenance, which was due to improper duty cycle classification. Corrective actions include reclassifying the subject relays to high duty cycle and instituting time-based replacements.

On April 18, 2013, Unit 2 was in Mode 3 following a scram and a loss of offsite power that had occurred on both LaSalle Units the previous day. At 1400 hours CDT, three pin hole through-wall leaks in the U2 High Pressure Core Spray (HPCS) minimum flow line piping were discovered. The leaks were on the outside bend of the first elbow downstream of the minimum flow restricting orifice, and appeared to be leaking a total of approximately 0.5 gpm with the HPCS pump not running.

Unit 2 HPCS was declared inoperable and, because the HPCS minimum flow line is in direct communication with the suppression pool, primary containment was also declared inoperable.

The direct cause of the event was a combination of cavitation and mechanical wear/erosion of the piping wall. The apparent cause was procedural inconsistencies that allowed operation of the HPCS system in minimum-flow for extended periods. Corrective actions included replacing the leaking pipe elbow, and performing ultrasonic inspections of susceptible piping on both Units. Also, HPCS operating procedures will be reviewed and revised as required to provide consistent guidance for minimizing operation of HPCS in minimum flow mode.

On August 5, 2014, at approximately 1734 hours CDT, Unit 2 automatically scrammed from 100% power on high neutron flux, followed by a Group I containment isolation. Following the Group I isolation, the control room operators noted that the position indication for valve 2B21-F022C, the inboard 2C Main Steam Isolation Valve (MSIV), showed dual indication rather than full closed.

Troubleshooting of the 2C MSIV determined that the valve stem disk had separated from the stem, which allowed the main disk to drop into the main steam flow path. The resulting reactor pressure transient added positive reactivity, which caused the high neutron flux scram. Increased steam flow in the other three main steam lines resulted in a nearly simultaneous high main steam line flow Group I containment isolation.

The cause of the stem-disk separation on the 2C MSIV was fretting wear attributable to marginal design. The root cause of the event was a legacy decision made in 2008 deferring installation of a manufacturer upgrade that would have prevented the failure. Corrective actions include installing the upgrade on all MSIVs on both units, and reviewing previous deferral decisions made using the same decision-making process.

On January 30, 2017, during routine surveillance testing of the Unit 2 Division 3 Diesel Generator Cooling Water (DGCW) system, the cooling water strainer backwash valve was unable to open. The Division 3 DGCW system was declared inoperable. Upon investigation, operators determined the cause of the valve malfunction was due to stem-disc separation. Division 3 DGCW is a support system for the Division 3 Emergency Diesel Generator and the High Pressure Core Spray (HPCS) system. The required actions of Technical Specifications (TS) 3.7.2 and 3.5.1 were entered on January 30, 2017 when the DGCW and HPCS system, respectively, were determined to be inoperable. TS 3.7.2 Required Action (RA) A.1 requires the supported system to be immediately declared inoperable. TS 3.5.1 RA B.2 requires restoration of the HPCS system to operable within 14 days. TS 3.8.1 was not applicable since a note provides that Division 3 AC electrical power sources are not required to be operable when HPCS is inoperable. The valve was replaced, and the HPCS system was returned to operable on February 2, 2017.

This condition could have prevented the HPCS system, a single train safety system, from performing its design function. This event is reportable in accordance with 10 CFR 50.73(a)(2)(v)(D) as an event or condition that could have prevented fulfillment of the safety function of structures or system that are needed to mitigate the consequences of an accident. There were minimal safety consequences associated with the event since the other emergency safety systems remained operable, and the Division 3 DGCW system remained functional as it retained the ability to provide the required flow through the system. The apparent cause of the stem-disc separation was erosion due to the carbon-steel valve internals in a raw water system environment.

At 1247 on May 21, 2001, Columbia Generating Station was in Mode 3 when the HPCS pump (HPCS-P-I) and the HPCS System were declared inoperable due to low pressure in the HPCS water leg pump discharge piping. Operations was in the process of transferring water from the condensate_storageianksio the_suppression_pool when thesuction_path to HPCS-P-1 was isolated.

HPCS-P-1 was immediately secured. HPCS System discharge pressure subsequently dropped to the low-pressure alarm setpoint, requiring Operations to declare HPCS-P-1 inoperable. After filling and venting the HPCS System, HPCS-P-1 and the HPCS System were declared operable at 1322 on May 21, 2001.

This condition is reportable under 10 CFR 50.73 (a)(2)(v)(D) because HPCS is a single train safety system that was unable to perform its required safety function for approximately 35 minutes.

The plant remained in compliance with technical specifiCations, and was in a condition where both low pressure coolant injection and low pressure core spray were capable of providing flow to the reactor pressure vessel. Although this event occurred over two years ago, Energy Northwest did not discover that the event should have been reported as a single train safety system failure until November 20, 2003.

26158 RI

On August 22, 2003 at 0234 PDT, the Reactor Core Isolation Cooling system (RCIC) was isolated as a result of a battery cell in the Division 1 250 VDC battery (E-B2-1) not meeting Technical.Specification (TS) battery_cell parameter requirements. With E-B2-1 inoperable, TSs require the supported features of E-B2-1 to be immediatey declared inoperable. RCIC-V 19, the RCIC pump minimum flow bypass valve, is a containment isolation valve. RCIC-V-19 is also supported by battery E-B2-1. RCIC-V-19 was declared inoperable, and was closed and deactivated to comply with plant TSs. Because RCIC-V-19 was inoperable, operators isolated the steam inlet valve (RCIC-V-1) to the RCIC turbine to prevent operation of the RCIC system.

The isolation of the RCIC system is reported as an event or condition that could prevent the fulfillment of the safety function of structures or systems that are needed to mitigate the consequences of an accident.

Upon replacement of the battery cell, E-B2-1 was restored to service, and the RCIC system was declared operable at 1700 PDT on August 22, 2003.

26158 R2 .1 -

On February 21, 2004, Columbia Generating Station (Columbia) was in Mode 1 with the reactor operating at approximately 100 percent rated thermal power. At approximately 08:41 the Reactor Core ____ isolation_Cooling.(RCIC) system was declared inoperable due to _a loss of control power to the RCIC reactor pressure vessel injection valve (RCIC-V-13). The cause was a failure of a normally energized under-voltage relay. The function of the relay is to sense a loss of voltage to the valve motor operator, interrupt valve control power and provide annunciation in the control room. The relay failed due to a failed relay coil that was subjected to long-term heating. Previous reviews to identify relays that should be periodically replaced did not capture this relay because it had no equipment part number and was not included in the master equipment list, the database used to conduct these reviews.

This event posed no threat to the health and safety of the public or plant personnel.

The failed relay was replaced and the RCIC system returned to operable status in 12 hours 48 minutes.

Thermography was performed on 43 relays in the DC distribution system and one relay was identified for replacement. Additional actions are planned to identify other relays in the DC distribution and selected portions of the 480 Volt AC systems that need periodic replacement.

26158 R2 26158 R2 -

On November 22, 2004, Columbia Generating Station (Columbia) was in Mode 1 at approximately 100 percent of rated thermal power. At 17:30 PST, the Reactor Core Isolation Cooling (RCIC) system was declared inoperable after one of its steam supply containment isolation valves (RCIC-V-63) was inadvertently closed during the performance of a channel functional test/channel calibration procedure. The procedure was discontinued and plant operators verified that the High Pressure Core Spray System was operable as required by Technical Specifications. The RCIC system was restored to its normal standby lineup and declared operable two hours and three minutes later.

The immediate cause was a personnel error by one of the I&C technicians performing the procedure. The root causes included over-reliance on self-checking and peer-checking, the procedure did not contain adequate precautionary information, no direct field supervision of the evolution, and no integrated risk assessment of the work.

A briefing was conducted to explain the event to Electrical and I&C craft and supervisors. The procedure being used, and other similar procedures, will be revised to add appropriate precautions. Additional expectations for frequency, depth, and quality of supervisory field oversight are being implemented. A new integrated risk management procedure will reduce the potential for similar errors.

26158 R2

On June 23, 2005, Columbia Generating Station was in Mode 1 with the reactor operating at approximately 23 percent power. At 13:46 PDT, an automatic reactor scram occurred due to a low water level condition in the reactor vessel. The low reactor water level condition was caused by an 0 __-inadvertent loss of reactor feedwater pump RFW-P-1B-due to a false low suction'pressure caused by human error during planned maintenance activities. Control room operators entered appropriate Emergency Operating Procedures and stabilized the plant following the reactor scram.

Plant systems responded as designed with the exception of RCIC as discussed below. As long term corrective action, a time delay will be installed or the low suction pressure trip removed to prevent spurious RFW pump trips.

The RCIC system was manually started to restore reactor water level and was later manually tripped.

The system had to be reset locally due to tripped mechanical overspeed trip linkage. During two subsequent attempts to restart RCIC the pump tripped on low suction pressure. Operators were then able to successfully start RCIC with the flow controller in manual. A time delay has been added to the RCIC low suction pressure trip logic to resolve this issue.

26158 R3

On June 28, 2007 at 1717 PDT Columbia Generating Station experienced an unexpected trip of Condensate Booster Pump (CBP) 2B (COND-P-2B). The trip occurred while operators were manually transferring the COND-P-2B duplex oil filter to the standby filter. The trip of COND-P-2B resulted in a low suction pressure trip of the reactor feedwater pumps and a reactor scram on low water level.

The cause of this event was a latent equipment condition involving the incorrect configuration of the COND-P-2B lube oil filter valves combined with the operational decision to transfer filters with COND-P 2B required to be in service.

Corrective actions have been initiated to properly configure the COND-P-2B lube oil transfer valves and enhance plant documentation to ensure the proper configuration is maintained following future maintenance activities. Furthermore, Energy Northwest will enhance the operational directives governing future on-line oil filter transfers.

There are no documented previous instances at Columbia involving the inadvertent removal of CBP lube oil filters from service.

26158 R3

This event is being reported under 10 CFR 50.73(a)(2)(v)(D). On December 20, 2010, the low pressure core spray pump was started and the minimum flow valve lost indication. An annunciator was received indicating that the valve had lost power.

The three line power fuses for the starter for the motor operator were found to be cleared. The cleared fuses were Cooper/Bussman Fusetron dual-element, time-delay, current-limiting, 600 Volt, 1.25 Amp fuses (model FRS-R-1-1/4). The overload element in each fuse was failed (triggered). Troubleshooting did not reveal any binding within the valve, binding within the motor operator, or sticking or dirty contacts within the starter. An examination of the cleared fuses revealed a poor solder joint in the trigger assembly in one fuse. The cause of this event is premature failure of one of the three fuses from momentary inrush current at a current value under the fuse curve which led to overload and failure of the remaining two fuses. Corrective actions consisted of quarantine of fuses from the same lot as that of the cleared fuses and inspection of fuses in all safety-related motor operated valves in support of ECCS to ensure they were not the same brand fuse of the same 1.25 Amp size from the same lot.

On March 2, 2015, it was identified that Columbia Generating Station's (Columbia) barrier impairment procedure which allowed for floor plugs in the room above the Emergency Core Cooling System (ECCS) and Reactor Core Isolation Cooling (RCIC) System pump rooms to be removed was non-conservative and Columbia had been non-compliant with Technical Specifications. Specifically, from December 3, 2014, until December 19, 2014, floor plugs over Residual Heat Removal (RHR) System B pump were removed without an adequate flood barrier resulting in RHR System B being inoperable. The barrier impairment procedure allowed for removal of ECCS or RCIC floor plugs with either a one hour flood tour or installation of a berm as a compensatory measure to maintain operability of the applicable ECCS or RCIC System. A one hour flood tour was initiated per the procedure, and a berm was erected; however both the one hour flood tour and the berm were inadequate. Corrective actions planned to prevent recurrence includes revising the barrier impairment process.

26158 R6 NRC Form 366 (01-2014)

On December 18, 2016 at 11:24 hours, an automatic scram occurred due to a fault on an off-site transmission network. A reactor scram was automatically initiated by the plant response to the transient.

All rods fully inserted, Main Steam Isolation Valves (SB,V) automatically closed due to loss of pow er to both Reactor Protection Sy stem (JC) busses. All safety sy stems operated as designed. Two Safety Relief Valves (SB,V) were initially cycled automatically, then several manually to maintain Reactor Pressure Vessel (AC) pressure. Reactor water level was maintained with Reactor Core Isolation Cooling (BN), Control Rod Drive (AA) flow, and High Pressure Core Spray (BG).

The cause analysis for the loss of off-site power is being performed by the entity responsible for the off-site transmission network, Bonneville Power Administration (BPA). BPA took immediate corrective actions to restore the off-site transmission network. The root cause evaluation addressing the plant response is being performed by plant personnel. A supplemental LER will be issued when the cause analyses are completed.

On January 25, 20:7 at 1836 PST, smoke was detected in the High Pressure Core Spray (HPCS) System diesel room with no indication of a lire. Immediate recovery actions by Operations personnel included opening the disconnect for the affected motor starter, at which point the smoke dissipated, Investigation of the condition found the motor starter for the Diesel Mixed Air Fan had failed, Prior to the start of the event, the HPCS system had been declared inoperable in accordance with plant Technical Specifications for planned maintenance.

The apparent cause of the motor starter failure was overheating of the contactor coil due to elevated system voltages. Corrective actions for this event include replacement of the contactor coil, increased frequency of preventative maintenance, and procedure revision. There were no other event-related equipment malfunctions.

tow Fogm 366 (08-2Q15)

On October 15, 2001 at approximately 0959, Nine Mile Point Unit 2 (NMP2) scrammed from approximately 100 percent power due to closure of the Main Steam Isolation Valves (MSIVs). Post scram the Safety Relief Valves (SRVs) were used for reactor pressure control until the MSIVs were re-opened. The scram occurred while restoring a steam flow transmitter after surveillance testing.

Post scram two high reactor water level conditions occurred that resulted in level 8 conditions. The first level 8 condition caused the "A" and "B" feedwater pumps to trip, as designed. The "A" feedwater pump was later re-started. The second level 8 condition resulted in the operating "A" feedwater pump tripping, as designed. Reactor pressure was then reduced so that the condensate booster pumps could be used for inventory control. While reducing pressure, a low reactor water level condition occurred. A level 2 condition occurred that resulted in actuation of the Reactor Core Isolation Cooling (RCIC) System and the High Pressure Core Spray (HPCS) System and closure signals to Primary Containment Isolation Valve groups 2,3,6,7,8 and 9. Reactor water level was recovered using RCIC and HPCS. Reactor pressure was reduced and the condensate booster pumps were used to provide inventory control. RCIC and HPCS were then returned to standby. Reactor pressure was reduced to approximately 150 pounds per square inch; the MSIVs were re-opened and reactor pressure control was shifted to the Turbine Bypass valves.

The cause of the reactor scram was an inadequate surveillance procedure. The causes of the low reactor water level condition were training issues relative to transient operation of RCIC and selection of a less than optimum event mitigation strategy. Corrective actions include benchmarking methods of restoration of similar transmitters, reviewing activities performed at power that are classified as trip sensitive, reviewing the event with operating crews and developing training on the effect of SRV opening on reactor water level.

RC FORM 366 (1-2001) �

On August 23, 2009, at 0915 hours, the Nine Mile Point Unit 2 (NMP2) control room received a High Pressure Core Spray (HPCS) Inoperable annunciator and a Division 3 Diesel Direct Current Control Power Failure annunciator for one second, after which both annunciators cleared. An operator was immediately dispatched to the Division 3 switchgear room, but did not find any obvious failure.

During troubleshooting, a degraded connection was found between the removable and stationary parts of the HPCS breaker CLOSE fuse block. The contact gap for one of the receiver connections internal to the stationary section of the CLOSE fuse block was wider than the other 3 receiver connections. At that point, HPCS was declared inoperable per Technical Specification 3.5.1. The degraded receiver connection was adjusted and the CLOSE fuse block was reassembled. The HPCS pump was run and subsequently declared operable at 2046 hours.

Throughout the event, NMP2 continued to operate at 100% power. There were no other inoperable components impacting this event.

The apparent cause of this event was failure to incorporate a GE Service Advisory Letter (SAL) 322.1 recommendation for checking the fuse block contact wipe or contact gap settings as part of the 4.16 kV breaker Preventive Maintenance (PM).

To prevent reoccurrence, the procedures for the 4.16kV and 13.8 kV breaker PMs will be revised to include the fuse block contact gap adjustment.