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On September 21, 2017 at 0800 PDT, Columbia Generating Station declared number 2 Diesel Generator inoperable for maintenance and entered Technical Specification Action Statement (TSAS) 3.8.1, Condition B for One Required Diesel Generator inoperable. At 0821 PDT and again at 1537 PDT Surveillance Requirement 3.8.1.1 was performed per action statement B.1. At 2315 PDT it was noted by operations that a page was missing from the surveillance procedure for both occurrences and determined that the action statement was not met within the required action time. Operations entered TSAS 3.8.1, Condition F for Required Action and associated Completion Time of Condition B not being met. AT 2321 PDT SR 3.8.1.1 was performed satisfactorily and Condition F was exited.

The apparent cause was a failure to page check the surveillance procedure prior to use. Initiatives have been developed to reinforce existing standards and improve human performance.

This event is reportable in accordance with 10 CFR 50.73(a)(2)(i)(B) Operation or Condition Prohibited by Technical Specifications.

On August 20, 2017 at 1605 PDT, Columbia Generating Station was manually scrammed due to a rise in Main Condenser back pressure. The rise in back pressure was due to the spurious closure of the Main Condenser Air Removal Suction Valve (AR-V-1) as a result of the failure of it's associated solenoid pilot valve. Following the reactor scram and depressurization of the reactor a Level 3 actuation occurred. In addition a startup flow control valve failed which necessitated throttling of the Feedwater start-up level control isolation valve to control Reactor Pressure Vessel level. All other safety systems functioned as expected and all control rods were fully inserted. Reactor decay heat was removed via bypass valves to the main condenser.

The apparent cause was the plant modification to address the single point vulnerability of the closure of AR-V-1 was not implemented in time to prevent a plant shutdown. A temporary modification has been installed to maintain AR-V-1 open for the remainder of the operating cycle.

These events are reportable in accordance with 10 CFR 50.73(a)(2)(iv)(A).

The condition reported by this Licensee Event Report (LER) was an expected condition as a result of planned activities in support of a routine refueling outage. As described in the LER, the Nuclear Regulatory Commission (NRC) has provided enforcement guidance, applicable to boiling water reactors, that allows the reported condition. Although this allowance is provided by the NRC's enforcement guidance, this condition is considered reportable in accordance with 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by Technical Specifications.

Between May 16, 2017 and June 15, 2017, Energy Northwest performed operations with the potential for draining the reactor vessel (OPDRV) activities while in Mode 5 without an operable secondary containment. Although this was an expected condition, and is allowed by Enforcement Guidance Memorandum 11-003, Revision 3, these activities resulted in a condition prohibited by Technical Specification 3.6.4.1. The OPDRV activities were planned and completed under the guidance of plant procedures and work instructions, and are considered to have low safety significance based on the interim actions taken. Since this condition was an expected result of these actions, cause determination is not necessary. Energy Northwest will submit a license amendment request to adopt Technical Specification Task Force Traveler 542 associated with generic resolution of this issue.

On December 18, 2016, during a forced plant outage reported under Licensee Event Report (LER)-2016-004, a leak was identified on the minimum flow line of the High Pressure Core Spray (HPCS) system downstream of the Primary Containment Isolation Valve.

HPCS system had been running on minimum flow after being used to maintain Reactor Pressure Vessel water level. The HPCS line leak was identified during a walk down by Operations personnel after the HPCS pump had been secured. Due to the location of the leak downstream of the Primary Containment Isolation Valve, this leak constituted a breach of Primary Containment. Both HPCS and Primary Containment were declared inoperable.

The cause of the leak was determined to be from a gasketed flange in the HPCS minimum flow piping. Corrective actions included replacing the gasket. Further evaluation is ongoing and this report will be supplemented once complete.

On November 20, 2016 at 1402 PST, Secondary Containment (NH) (Reactor Building) became inoperable due to pressure increasing above the Technical Specification limit of -0.25 inches of water gauge (inwg). While the plant was ascending in power, the Reactor Building exhaust air fan unexpectedly failed to start in manual during post-maintenance testing. Prior to this event, Reactor Building Heating, Ventilation and Air Conditioning (VA) (HVAC) System A was running. Per station procedures, System A was stopped and System B was to start. The fan's failure to start resulted in no Reactor Building fans running, and increased Reactor Building pressure.

For a time period of less than one minute, Secondary Containment pressure was not maintained less than or equal to -0.25 inwg.

Immediate recovery actions by Operations personnel included manually starting Reactor Building HVAC System A, which quickly restored Secondary Containment pressure to less than or equal to -0.25 inwg at 1403 PST. While TS limits were exceeded for this short time period, the resulting pressure excursion was bounded by analytical results; and thus, there were no safety consequences for this condition. This event was reported under reporting criteria 10 CFR 50.72(b)(3)(v)(C) and 10 CFR 50.72(b)(3)(v)(D) as Event Notification #52382.

The cause of the exhaust fan's failure to start was a faulty control switch for the fan. Corrective actions for this event include replacement of the control switch. There were no other event-related equipment malfunctions.

At 1322 PDT on March 28, 2016, a manual reactor scram was initiated in response to a loss of Reactor Closed Cooling (RCC). The loss of RCC was due to the opening of a Service Water (SW) valve at the inlet side of the Fuel Pool Cooling heat exchanger during performance of a partial surveillance without proper isolation of the RCC system piping from the heat exchanger. The cross-connection of the two systems caused depressurization and loss of flow from the RCC system into the non-pressurized SW piping. The SW valve was closed and the reactor was scrammed. Safety system responses to the scram signal were normal, with all control rods being fully inserted. Reactor decay heat was removed via bypass valves to the Main Condenser. No safety relief valves lifted and no emergency core cooling systems injected following the reactor scram.

The root cause was determined to be that plant Operators did not properly evaluate plant configuration when performing a partial surveillance including the marking as "N/A" (not applicable) of procedural steps, in accordance with plant procedures. Human performance aspects of the event were quickly addressed and additional corrective actions include reinforcing and monitoring procedure standards, and updating work control procedures at the station.

26158 R6 NRC Form 366 (01-2014)

On July 6, 2015, a review of the Fire Protection and Post Fire Safe Shutdown programs found the original assessment of Multiple Spurious Operation (MSO) Scenario 2x incorrectly concluded that the number of circuit failures was above and beyond the technical requirements. This error resulted in no analysis of MSO Scenario 2x, an unanalyzed PFSS condition, and is being reported in conformance with the reporting requirements of 10CFR 50.73(a)(2)(ii)(B).

In addition this was reported to the NRC man 8-hour report (Event Notification No. 51201) in accordance with'10 CFR 50.72(b)(3)(ii)(B).

Corrective actions include a revision to the calculation to include a re-evaluation of :MSO Scenario 2x, maintaining the affected line isolated until a permanent solution for MSO Scenario 2x is developed; and procedure changes to provide more technical guidance for evaluation of PFSS MSO scenarios:

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This event is being reported as an unplanned actuation of an emergency diesel generator, in conformance with reporting requirements in 10 CFR 50.73(a)(2)(iv)(A). Refer to Columbia Generating Station's Event Notification No.

51086.

On May 22, 2015, during a refueling outage with the plant in Mode 5, electricians in support of testing on the Division 1 Emergency Diesel Generator installed 3 test meters to monitor the under voltage relay in the Division 1 4.16KV Bus 7 Switchgear (E-SM-7) cabinet. Prior to commencing the testing one of the test leads connecting the test meters to the Bus 7 Switchgear cabinet became detached from the test instrument. When one of the electricians reconnected the test lead, it was inserted into the wrong port on the test instrument, causing a phase-to-phase short which resulted in a momentary loss of Bus E-SM-7. The Bus was being powered from the Startup Transformer. The Backup Transformer sensed the loss and re-powered Bus E-SM-7. In addition, the Division 1 Emergency Diesel auto-started on bus under voltage and was subsequently removed from service when the Standby Service Water pump failed to start as a result of a blown fuse caused by the short.

The Division 2 electrical distribution was providing the electrical power and supporting components required for decay heat removal and inventory control at the time of the event and was not impacted by the event.

26158 R6 NRC Form 366 (01-2014)

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)

Description::== FACILITY NAME ==

M. Hedges

• TELEPHONE NUMBER (Include Anon Cod.) 509-377-8277

13. COMPUTE ONE LINE FOR EACH COMPONENT FAILURE DESCRIBED IN THIS REPORT

CAUSE SYSTEM COMPONENT MANU- FACTURER

REPORTABLE

TO EPIX CAUSE SYSTEM COMPONENT

MANU-

FACTURER

REPORTABLE

TO EFIX

14. SUPPLEMENTAL REPORT EXPECTED

0 YES (ft yes, complete 15. EXPECTED SUBMISSION DATE) .:. NO 14. EXPEL MONTH DAY r YEAR

SUBMISSION

DAT3 ., .. . 4.

ABSTRACT (Limit to I it spaces, i.e., approximately 15 single-spaced typewritten On March 12, 2014, it was identified that thr: manhole covers (E10, El 1, and E 15) for vaults containing 4160 volt electric cables were missing the hold down bolts. The hold down bolts are required as part of the tornado missile barrier for the manhole cover for the underground electric vault. It was later determined that the hold down bolts for manhole cover E 1 / (Division 2 Service Water) had been identified as missing since September 6, 2013.

When the bolts were identified as missing on September 6, 2013, the manhole cover and bolts were not recognized as a tornado missile barrier; because this information was not available in routinely used databases and procedures. No compensatory action was taken until March 12, 2014, when large concrete blocks were placed on top of the manholes to prevent the covers from potential removal in the event of a tornado. The degraded missile barrier is considered to have rendered the Division 2 Service Water system inoperable from September 6, 2013, to March 12, 2014. This is reportable as a condition prohibited by Technical Specifications.

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NRC FO

U.S. NUCLEAR REGULATORY COMMISSION UCENSEE EVENT REPORT (LER)

CONTINUATION SHEET

Columbia Generating Station 05000 397 & LER NUMBER 3 P AG E 2 OF 2014 - 0

PLANT CONDITIONS

Columbia was operating at 100% power. There were no inoperable plant systems at the time of discovery that contributed to this event.

EVENT DESCRIPTION

On March 12, 2014, it was identified that three manhole covers (E10, El 1, and E 15) for vaults containing 4160 volt electric cables (CBI.) were missing the hold down bolts. The electric cables in vaults El0 and Eli support the Division 2 Service Water (BI) system. The electric cables in vaults EIS s the Division 3 Service Water system. The hold down bolts are required as part of the tornado missile barrier for the manhole cover for the underground electric vault. It was later determined that the hold down bolts for manhole cover Ell (Division 2 Service Water) had been identified as missing in two condition reports on September 8, 2013, and again on December 3, 2013. When Operations performed an immediate operability determination for the September and December 2013 condition reports, the manhole cover and bolts were not recognized as a tornado missile barrier; therefore, no compensatory action was taken until March 12, 2014.

The degraded missile barrier is considered to have rendered the Division 2 Service Water system inoperable from September 6, 2013, to March 12, 2014. This is reportable as a condition prohibited by Technical Specifications.

IMMEDIATE CORRECTIVE ACTION

It was verified through the Weather Service that no tornados were predicted for our area in the next 24 hours. Large concrete blocks were placed over the manhole covers on March 12, 2014, to prevent the cover from lifting in the event of a tornado.

The information fields in the master equipment list for the applicable manhole covers were completed identifying them as a tornado missile barrier.

CAUSE

The information in this section is based on the preliminary results of a root cause evaluation. If any significant changes in the cause or corrective actions are made in the final evaluation, a supplement will be submitted for this report.

The direct cause for the missing hold down bolts was not determined.

The root cause of the failure to recognize the manhole cover as a tornado barrier was that station procedures that implement the process to establish quality classifications for safety-related systems, structures, and components (SSCs) did not ensure accurate information was available in a timely manner for these components.

There are multiple methods available for determining the safety significance of a degraded component; however., the computerized master equipment list is typically the preferred method. The equipment plant numbers (EPNs) for the manhole covers had been entered into master equipment list in 2012, but no action was taken to complete the remaining data fields for the components to kientify that the manhole covers fulfilled a tornado barrier function, and have the information verified and approved. The master equipment list that station personnel used identified these manhole covers as nonsafety-related.

26158A A3 NA'; FORM 366A 01-"eC14) IL LER NUMENEPI 5 PAGE 2. DOCKET 1. FACILITY NAME Columbia Generating Station YEAR OF 3 A 0014 - 003 -0

NRC FORM

014014) LICENSEE EVENT REPORT (LER) U.S. NUCLEAR REGULATORY COMMISSION

CONTINUATION SHEET

In the immediate rability determination process for the two Condition Reports in 2013, Operations personnel did not have information readily available to them to determine that the manhole cover was a tornado missile barrier. Most plant personnel, including Operations, did not recognize that the information in the computer master equipment list for the manhole covers was not at an approved status and should not be used. The manhole covers did not have any label indicating that it was a tornado missile barrier. Plant drawings did not identify the manhole covers as tornado missile barriers. Additionally, the station barrier impairment procedure did not list the manhole covers as a tornado missile barrier.

FURTHER CORRECTIVE ACTION

Work requests were initiated to repair/replace the missing bolts for the manhole covers.

Revise Engineering procedures to provide clear direction to establish Quality Classifications for safety-related SSCs within the Master Equipment List within a specific time frame. Ensure that procedures include timeliness requirements for establishing and upgrading/downgrading EPNs for installed plant equipment.

Apply a marking on the manhole covers that identify these covers as a tornado missile barrier.

Revise the station barrier impairment procedure to identify manhole covers as a tornado missile barrier.

ASSESSMENT OF SAFETY CONSEQUENCES

No actual tornados occurred during the time of interest. The Division 2 Service Water system remained capable of fulfilling its safety function during this time period. Additionally, at least one other division of Service Water was available during this time period (September 6, 2013 to March 12, 2014) to be able to fulfill the safety function; therefore, the actual safety consequence of this issue was minimal.

SIMILAR EVENTS

There have been no similar events at Columbia Generating Station in the last three years.

ENERGY INDUSTRY IDENTIFICATION SYSTEM (ENS) INFORMATION CODES EIIS s a are bracketed 'Mere applicable in the narrative.

NERGY

.!‘‘ORT1:1--"T er 914)

On January 9, 2014 at 1743 and 1834 hours secondary containment was declared inoperable during repositioning of the dampers. These two events had durations of 3 and 2 minutes respectively. Control Room operators took manual control of the Reactor Building Exhaust Air flow system to restore secondary containment in the first event, and the controller restored pressure automatically in the second.

On January 15, 2014 at 0907 hours and February 17, 2014 at 0304 hours secondary containment was declared inoperable during repositioning of the dampers and during high winds respectively. These two events had durations of 6 and 2 minutes respectively. The system controller automatically restored secondary containment differential pressure in both events.

In each of these events secondary containment vacuum was not maintained greater than or equal to 0.25 inches of vacuum water gauge as required by Technical Specification 3.6.4.1, due to less than optimal control system tuning for the system. Corrective actions include determining, implementing, and documenting the optimum control system tuning for the system, increasing margin by lowering differential pressure set point, and alerting operations before the Technical Specification limit for secondary containment pressure is reached.

26158 R6 NRC Form 366 (01-2014) Columbia Generating Station APPROVED BY OMB: NO. 3150.0104 EXPIRES: 01131/2017 Reported lessons learned are incorporated into the licensing process and fed beck to industry.

Send comments repenting burden estimate to the FOIA, Privacy and Wanton Collections Branch (T.5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by kttemet 0411811 to inixollectsResource@nrc.gov, and to the Desk Met, Office of Information and Regulatory Make, NEOB-10202, (3150-0104), Office of Management and Budget Washington, DC 20503. If a means used to Noose an Infortnation collectbn does not display a currently valid OMB control nunter, the NRC may not conduct or sponsor, and a person Is not required to respond to, the information collection.

Plant Conditions

Event 1: January 9, 2014 at 1743 hours Event 2: January 9, 2014 at 1834 hours Event 3: January 15, 2014 at 0907 hours Event 4: February 17, 2014 at 0304 hours At the time of all events, the plant was operating in Mode 1 at 100% power. There were no structures, systems, or components that were inoperable at the start of any of the events that contributed to the events.

Event Description

Events 1 & 2 - On January 9, 2014 at 1743 and 1834 hours secondary containment vacuum was not maintained while Reactor Building Outside Air (ROA) heating coil face and bypass dampers were repositioning due to outside ambient temperature fluctuation past the set point. These dampers and heating coil allow for outside air to be heated as it enters the system.

These two events had durations of 3 and 2 minutes respectively. In Event 1 control room operators took manual control of the Reactor Building Exhaust Air (REA) flow In-service differential pressure controller (DPIC) (REA-DPIC-1A) to restore secondary containment vacuum to greater than 0.25 inches of vacuum water gauge. In Event 2 the REA in-service controller (REA-DPIC-1A) automatically restored secondary containment vacuum to greater than 0.25 Inches water gauge (inwg).

Event 3 - On January 15, 2014 at 0907 hours secondary containment vacuum was not maintained while the ROA heating coil face and bypass dampers were repositioning due to outside ambient temperature fluctuation past the set point. This event had duration of 6 minutes. In this event the REA in-service controller (REA-DPIC-1A) automatically restored secondary containment vacuum to greater than 0.25 inwg.

Event 4 - On February 17, 2014 at 0304 hours secondary containment vacuum was not maintained during a period of high winds.

This event had duration of 2 minutes. In this event the REA in-service controller (REA-DPIC-1B) automatically restored secondary containment vacuum to greater than 0.25 inwg.

In each event described above, because Reactor Building (NG) vacuum decreased below 0.25 inches of water gauge, secondary containment was logged as inoperable in the surveillance log and Technical Specification 3.6.4.1 Action A was entered.

Extent of Condition This condition of Reactor Building vacuum momentarily dropping below the prescribed limit is specific to the Reactor Building Heating Ventilation and Air Cooling (HVAC) (VA) and Standby Gas Treatment (SGT) (BH) systems, and their capability to establish and maintain secondary containment vacuum. No other systems were affected as a result of this condition.

2$158A R3 NRC FORM 386A (01.2014) During an extent of condition review performed to determine past operability, it was determined that there were multiple instances where secondary containment vacuum was less than the TS required value of 0.25 inwg. In these instances secondary containment vacuum went below the TS required value of 0.25 inwg and went unnoticed by operators as the annunciator alarm comes in at 0.0 inwg. This alarm value has been identified as Incorrect to alert operators to secondary containment vacuum below the TS required value af 0.25 inwg and the condition has been documented in the corrective action process to be aligned with the TS value of 0.25 inwg. In each of these events the REA in-service controller automatically restored secondary containment vacuum to greater than 0.25 inwg.

Immediate Corrective Action In Event 1 Operators took manual control of the REA differential pressure (dP) controller (PDC) and quickly adjusted REA flow to restore secondary containment vacuum to greater than 0.25 inwg.

In Events 2, 3, and 4 the REA flow in-service controller automatically restored secondary containment vacuum to greater than 0.25 inwg.

Cause

In accordance with NUREG-1022 Revision 3 Section 2.3 these four events are being reported together as these have all occurred in the 60 day LER reporting period and appear to have similar cause(s) for each event. Events 1 & 2 were reported together as they were related and occurred within an hour of each other. Events 3 and 4 were reported under individual ENS notifications.

Secondary vacuum dropping below the TS required value of 0.25 inwg happened in four separate events in this LER reporting period. All four of these events were similar in that an external weather related event, three temperature related transients and one wind related transient, occurred that required the exhaust ventilation fan to adjust its flow to maintain a vacuum above the TS required value of 0.25 inwg. The cause of secondary containment vacuum not being maintained greater than or equal to 0.25 inwg was due to improper tuning of the Reactor Building Outside Air (ROA) differential pressure controllers. The transient response of the controllers were not properly tuned to compensate for sudden pressure changes that are expected during operation of the pressure control system.

Operating Experience & Previous Occurrences A loss of the ability to maintain secondary containment vacuum greater than required has occurred and was reported at Columbia Generating Station (Columbia) three times in the past two years.

On August 25, 2013, reported under LER 2013-007-00, secondary containment was declared inoperable during a sudden thunderstorm when secondary containment vacuum was not maintained greater than or equal to 0.25 inwg.

On July 24, 2012, reported under LER 2012-003-00, secondary containment vacuum was not maintained due to an inadvertent trip of one set of the redundant Reactor Building HVAC fans FAN), during ongoing maintenance on the SGT system.

On December 10, 2011, reported under LER 2011-004-00, secondary containment vacuum was not maintained and the cause was determined to be ice buildup and subsequent release on exterior equipment supplying the Reactor Building HVAC system.

The first Operating Experience (OE) event is similar in cause as the four events reported in this LER. Due to the single occurrence and the extreme weather conditions at the time, multiple causal factors were not considered. A corrective action which could have prevented recurrence of this event, to alert operations to a potential issue with secondary containment before the Technical Specification, LCO 3.6.4.1A for secondary containment vacuum is reached, was in 26158A R3 NRC FORM 366A (01-2014) 8. LER NUMBER 3. PAGE 2. DOCKET Columbia Generating Station 05000 397 aft. NRC FORM 3118A (014814) LICENSEE EVENT REPORT (LER) U.S. NUCLEAR REGULATORY COMMISSION

CONTINUATION SHEET

NARRATNE

progress at the time of the four events reported in this LER.

The last two OE events have associated corrective actions, and the causes are not applicable to the current cause of weather related secondary containment vacuum changes, nor would corrective actions from these past two events prevented occurrence of these four events reported in this LER.

As discussed in the Reactor Oversight Process working group public meeting held on January 15, 2014 the Industry has experienced an increase in reports of safety system functional failures (SSFF) in where there is not a true loss of safety function, but momentary conditions in which Technical Specification operability criteria are not satisfied. Specifically temporary losses of secondary containment vacuum have increased In the industry. The four events described In this LER fall into this increase in number of reports.

Further Corrective Actions The potential for these momentary pressure excursions will continue to occur as there has been no change in the design of the equipment To minimize recurrence actions are being taken to update the current calibration procedures to reflect the optimum control system tuning for the REA/ROA system, and increasing margin in secondary containment by lowering the differential pressure set point on the REA controllers. Columbia is also investigating methods to alert operations to a potential issue with secondary containment before the Technical Specification secondary containment pressure is reached.

Assessment of Safety Consequences

This event resulted in an unplanned entry into LCO 3.6.4.1.A. Secondary containment vacuum was less than 0.25 inwg for between 2 and 6 minutes. While the actual vacuum was beyond the range allowed by Technical Specifications, the Reactor Building HVAC system is designed to, among other things; maintain the reactor building during normal operating at a negative pressure with respect to atmosphere to minimize the release of airborne radioactive material. During emergency operation, the SGT system maintains the reactor building at a negative pressure. During each of the events described in this LER at least one train of SGT was In standby condition and available to restore the reactor building to a vacuum above the TS required value of 0.25 inwg.

An engineering safety function analysis was performed which demonstrated that the ability for SGT to achieve secondary containment vacuum to above 0.25 inwg, credited in the accident response analysis, could have been attained using either of the two available trains of the SGT system at the time of each of the events, thus there were no potential safety consequences. There was no actual safety consequence associated with this event since no event involving radiological hazards were experienced during the event.

NEI 99-02 allows the licensee to perform an engineering analysis to determine if the event is reportable as a SSFF performance indicator occurrence. The engineering analysis has shown that these events did not result in a SSFF; therefore this event does not affect the NRC Regulatory Oversight Process Indicators.

Energy Industry Identification System (EIIS) Information Energy Industry Identification System (EIIS) Information codes from IEEE Standards 805-1984 and 803-1983 are represented in brackets as (XXI and pooq throughout the body of the narrative.

26158A R3 NRC FORM 388A (01-2014)

On June 27, 2013 at 17:58 hours a laborer was exiting the Diesel Generator (DO) 3 Room when he inadvertently brushed against the control switch (JS) for the Diesel Mixed Air fan (FAN) causing it to turn to the OFF position. In response to an annunciator alarm In the main control room, an operations supervisor proceeded to the Diesel Generator 3 Room. After ascertaining what had happened by questioning the laborer, the operator turned the fan control switch back to ON and the switch operated smoothly. The Diesel Mixed Air fan was back in service at 18:19 hours, so the fan was inoperable for approximately 21 minutes.

With the Diesel Mixed Air fan switch in the OFF position, the following supported equipment were declared inoperable and the appropriate Technical Specifications were entered: Diesel Generator 3, High Pressure Core Spray (HPCS) (BJ), Division 3 125 VDC battery charger (BYC), Division 3 battery (BTRY), and the Division 3 AC electrical power distribution system (ix).

The loss of the HPCS system resulted In the temporary loss of safety function for a single train system. There was no radiological release associated with this event. No safety system actuations or isolations occurred. The licensee notified the NRC Resident Inspector and Event Notification No. 49152 was submitted.

26158 R5

• Columbia Generating Station 05000397

When performing a logic system functional test (LSFT) of the Remote Shutdown Panel transfer switch during refueling outage R21 on June 4, 2013, the procedure for testing the remote transfer switch for the suppression pool spray valve failed because a jumper had been left installed following a new bucket (breaker) installation at the Motor Control Center during the previous refueling outage R20. A satisfactory LSFT was performed prior to the Installation of the new bucket into the MCC but this LSFT was not re-performed to verify the operability of the new bucket after installation. The problem went undetected until the R21 LSFT test failed. The remote transfer switch was inoperable from May 16, 2011 until June 4, 2013 when the condition was discovered. This resulted in failure to meet Surveillance Requirement (SR) 3.3.3.2.4 and non-compliance with Technical Specifications (TS) Limiting Condition for Operation (LCO) 3.3.3.2.

The preliminary apparent causes have been identified as: (1) a lack of a standard for Work Order instructions involving the removal and installation of Jumpers, resulting in personnel having to rely on experience and skill of the craft for the proper way of executing and documenting required modifications; and (2) inadequate decision making resulting in the use of a post maintenance testing procedure after the installation of the Spectrum bucket in May 2011 that did not adequately prove operability.

.28158 R5

On January 7, 2013, Columbia was operating at 100% power. At 1427 PST both doors of the 501 elevation airlock entrance of the Reactor Building were simultaneously opened for a short period of time. This was the result of the failure of the interlock between the outer door (R304), and the inner door (R305).

Maintenance personnel were moving scaffolding through the Reactor Building outer security door when an equipment operator opened the inner door to exit the Reactor Building. This equipment operator immediately closed the inner door and contacted the Main Control Room. The outer door was key locked closed until corrective actions could be implemented.

Having a condition where both doors in a Reactor Building airlock were opened simultaneously while not undergoing a planned evolution for maintenance or surveillance testing, results in an unintended entry into Technical Specification (TS) 3.6.4.1 Secondary Containment due to a failure to satisfy Surveillance Requirement (SR) 3.6.4.1.3.

It was determined that this condition resulted in a loss of safety function (Secondary Containment) and was reported to the NRC (Event Notification 48656) at 1629 PST on January 7, 2013.

2615B R5 Ur.

• 4-';

On June 28, 2011, while the plant was in Mode 5 for refueling outage R20, Columbia Generating Station (Columbia) failed to enter a required Technical Specifications (TS) Action Statement while performing control rod exercises. During stroke time testing, control rod 34-47 displayed an erroneous indication. Upon initial withdrawal, the four rod display showed an alternating indication of "XX" (meaning the reed switch was not open during movement) and "00" (full in indication) requiring the position indication to be declared inoperable per TS 3.9.4. Control rod 34-47 was subsequently fully inserted and testing resumed on other rods contrary to the required action statement of TS 3.9.4. Upon discovery of the noncompliance, the TS required actions were subsequently performed and the failed reed switch replaced. The Control Room Supervisor and Shift Manager did not verify the required action statements specified in the TS and Bases as required. This was determined to be the apparent cause. A contributing cause included not performing all of the required steps in the procedure for control rod stroke time testing. Columbia has had no previous occurrences of a failure to enter the required action statement of TS 3.9.4.

This condition is reportable under 50.73(a)(2)(i)(B) as a condition prohibited by TS.

26158 R5

65% power due to the Digital Electrohydraulic Control (DEH) trip header momentarily depressurizing during post maintenance testing (PMT). All safety systems were available during the event and operated as designed. Plant operators effectively managed the transient. This event did not pose a threat to the health and safety of the public.

The direct cause of the reactor scram was instantaneous recompression of an air bubble trapped in the intervalve cavity between the A and B Quadvoter valves during post-maintenance testing (PMT).

This allowed backflow of DEH fluid from the emergency trip header into the intervalve cavity during PMT, causing a momentary depressurization of the DEH trip header that resulted in the reactor scram. The root cause of the scram was determined to be a design deficiency in the on-line serviceable Quadvoter assembly which allowed an air bubble to remain in the intervalve cavity following performance of on-line maintenance activities.

26158 R4 Columbia Generating Station 05000397

At approximately 1205 on October 18, 2005, with Columbia Generating Station (Colurnbia)-Jn rrintie 1„..an_Energy__Northwest nuclear...security officer who was operating an x-ray machine detected an unloaded handgun and 20 rounds cif"---- ammunition in the backpack of an Energy Northwest employee at Columbia's Protected Area (PA) access control point (ref: Event Notification #42060).

In response to this event, the handgun was immediately controlled and the individual's unescorted access to the PA was suspended. Following fitness for duty testing, the individual left the owner controlled area. Local law enforcement (Benton County Sheriffs Deputy) responded to the event. This event meets the criteria specified in 10 CFR 10 CFR 73, Appendix G, paragraph 1(d), as this was an attempted introduction of contraband into Columbia's PA. This report is made pursuant to the requirement of 10 CFR 10 CFR 73.71(a)(4) for a 60-day folloW-up written report.

26158 R2

On August 17, 2004, with a plant startup in progress and with the plant in Mode 1 at approximately 20% power, a licensed control room operator improperly filled a feedwater heater with condensate following maintenance. This improper filling evolution tripped the only running reactor feedwater pump initiating a loss of feedwater transient. The reactor was scrammed manually prior to level reaching the automatic trip set point and water level stabilized using the Reactor Core Isolation Cooling (RCIC) system and the recovered reactor feedwater pump.

Failure of the Reactor Operator to follow written instructions resulted in uncontrolled filling of the feedwater heater and a momentary drop in condensate system pressure. The momentary drop in condensate system pressure directly resulted in a trip of the running feedwater pump on low suction pressure.

This event posed no threat to the health and safety of the public or plant personnel. All safety equipment was available during this transient and performed as expected. Following the plant scram, the plant was stabilized in Mode 3 without further event.

26158 R2 I �

On July 30, 2004, Columbia Generating Station (Columbia) was in Mode 1 with the reactor operating at -100 percent power. At 09:23 PDT, the reactor automatically scrammed when the reactor protection system (RPS) received trip signals from three out of four reactor steam dome pressure - high instrument channels.

The high reactor steam dome high-pressure condition was a result of a turbine governor valve (MS-V GV/1) drifting closed. The turbine governor valve drifted closed due to a failure of a bypass capacitor on a NUCANA Servo Driver (NSD) circuit board associated with the governor valve electro-hydraulic control system. The failed capacitor was a monolithic ceramic capacitor. This capacitor provides high frequency bypass filtering for the onboard power supply at one of the operational amplifiers. The capacitor failed with low resistance which caused a high current load that eventually caused the circuit board protective fuse to clear and the closure of MS-V-GV/1.

This event posed no threat to the health and safety of the public. The NSD circuit board was replaced and a detailed failure analysis will be performed on the failed circuit board.

26158 R2