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On November 23, 2017, a routine surveillance on the South Texas Unit 1 Train "C" Control Room Makeup and Cleanup Filtration System failed due to the Train "C" control room makeup filtration system heater de-energizing approximately two minutes after actuation. The makeup filtration system heater de-energized due to an improperly configured jumper on a circuit board associated with the Train "C" control room makeup filtration unit outlet low flow switch. The circuit board had been installed with the improperly configured jumper on September 27, 2017. The circuit board was properly configured and returned to service on November 24, 2017.

This resulted in the Train "C" Control Room Makeup and Cleanup Filtration System being inoperable for 58 days; the associated Technical Specification allowed outage time for this condition is 7 days. The cause of the event is the maintenance work instructions did not include steps to: (1) ensure that the circuit board jumper is in the correct position, and (2) conduct a post-maintenance test to ensure proper operation of the heaters. As a corrective action, the applicable maintenance work instructions will be revised to (1) ensure that the circuit board jumper is in the correct position, and (2) conduct a post-maintenance test to ensure proper operation of the heaters.

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.

On June 9, 2017 at approximately 0509 hours, Secondary Containment Zone 3 differential pressure was lost during a routine restoration due to the failure of the Unit 1 Zone 3 'A' Reactor Building Exhaust Fan.

Technical Specification Surveillance Requirement (SR) 3.6.4.1.1 was not met.

Zone 3 differential pressure was recovered to > 0.25" WG (Water Gage) by placing Unit 1 Zone 3 Filtered Exhaust to STOP and allowing Unit 2 Zone 3 to recover differential pressure. Zones 1 and 2 were not affected. This event is being reported under 10 CFR 50.73(a)(2)(v)(C) as a condition that could have prevented the fulfillment of a safety function.

The cause was determined to be a broken ring terminal on the breaker which prevented the fan from starting. Maintenance replaced the ring terminal and re-terminated the wire.

There were no actual consequences to the health and safety of the public as a result of this event.

On March 8, 2017 at approximately 0239 hours, Secondary Containment Zone III (Unit 1&2 Reactor Bui ding) differential pressure lowered to less than the Technical Specification (TS) limit of 0.25 in w.g. due to due to Load Center Breaker 26240-021 (supply breaker to 2Y246) being returned to service without Motor Control Center (MCC) Breaker 26246-023 (supply breaker to 2Y246) restored. As a result, TS 3.6.4.1 Surveillance Requirement (SR) 3.6.4.1.1 was not met due to the loss of vacuum.

The condition is being reported in accordance with 10 CFR 50.73(a)(2)(v)(C) as an event or condition that could have prevented fulfillment of a safety function.

The cause of the event was less than adequate procedure use and adherence.

Corrective actions included a communication to Operators and a revision to the Procedure and Work Instructions Use and Adherence procedure to perform a second check for non-conditional procedure steps.

There were no actual consequences to the health and safety of the public as a result of this event.

Over a period of approximately one month, the OB Main Control Room (MCR) Heating, Ventilating and Air Conditioning (HVAC) system experienced four failures. Troubleshooting was completed for each of the failures and for three of the failures the cause was determined to be an intermittent dropout or chattering of the Loss of Offsite Power (LOOP) start relay for two fans (0B-V116 MCR Supply and OB-V121 MCR Return Fans). The fourth failure was due to a contactor in the Motor Control Center (MCC) for the OB-V116 MCR Supply Fan. On 11/29/16 the second failure occurred on the LOOP start relay for the OB-V116 MCR Supply fan. The investigation identified a manufacturing defect of the Agastat/Tyco ETR Relays in the lot of relays used for the recent preventative maintenance (PM) relay replacements. The relays were determined to be unreliable since the initial PM replacement on 10/19/16 until 12/5/16, when the quality issue was identified and relays from a different lot were installed. The B train of MCR HVAC was determined to be inoperable due to the relay issue for a period of 47 days, which is greater than the allowable Limiting Condition for Operation (LCO) action window of 7 days (per TS 3.7.2.a.1) for an inoperable Control Room Emergency Fresh Air System (CREFAS) train.

Therefore, this was a condition prohibited by Technical Specifications (TS).

On August 4, 2016, while performing a Fire Protection/Appendix R self-assessment, it was discovered that the floor between the Cable Spreading Room (CSR) and the Plant Administration Building (PAB) basement is not an adequate Appendix R fire barrier. Because the CSR and the PAB are located in the same Fire Area (FA), a fire in the PAB could spread to the CSR requiring evacuation of the control room (CR). When the CR is evacuated, alternate shutdown activities are performed at the Alternate Shutdown System (ASDS) Panel. The travel path used to access the ASDS Panel following control room evacuation traverses the same fire area in the PAB.

This unanalyzed condition resulted from the determination that because of the inadequate fire barrier, a fire in the PAB would now require use of an alternate shutdown strategy to safely shutdown the reactor. However, the alternate shutdown strategy requires that the operators traverse from the control room through the PAB Fire Area to access the alternate shutdown equipment. This path could be impacted by the PAB fire.

In response to this discovery an hourly fire watch was established.

On March 31, 2016 at approximately 06:03, while performing lineups for Local Leak Rate Testing (LLRT), the Control Room received a Division two (2) Primary Containment Isolation System (PCIS) alarm along with a Division two (2) Heating Ventilation Air Conditioning (HVAC) isolation, and Standby Gas Treatment (SBGT) and Control Room Emergency Outside Air Supply System (CREOASS) initiation. This was shortly followed by the Division one (1) Primary Containment Isolation System (PCIS) alarm along with a Division one (1) Heating Ventilation Air Conditioning (HVAC) isolation, and Standby Gas Treatment (SBGT) and Control Room Emergency Outside Air Supply System (CREOASS) initiation.

The valid actuation signal was the result of the performance of four (4) LLRT procedures concurrently for four (4) separate drywell pressure instruments. These instruments are divisional with each powered by a different channel.

Placing each in "TEST" mode, resulted in bringing both the Division one (1) and Division two (2) isolation logic. The cause of the valid actuation signal was less than adequate procedure use and adherence by Operations staff members. Corrective action included coaching and remediation of an individual involved in confirming the position of the test switch, communication to the Operations organization and revision to the LLRT procedures.

There was no operational impact as a result of this this event due to the plant being in Mode 5. This event resulted in a eight (8) hour Emergency Notification System (ENS) communication pursuant to 10 CFR 50.72(b)(3)(iv)(A).

This Licensee Event Report (LER) is being communicated pursuant to 10 CFR 50.73(a)(2)(iv)(A).

On 02/13/2016 at 0206 (CST) the plant was at 99 percent reactor power when Fuel Building Exhaust Fan "A" (1VFO4CA) tripped due to indicated high Secondary Containment (SC) vacuum during routine venting of the drywell per plant procedures. Following the fan trip, SC vacuum degraded, eventually exceeding the Technical Specification (TS) limit of 0.25 inch vacuum water gauge. The TS Limiting Condition for Operation (LCO) 3.6.4.1 Required Action A.1 and an Emergency Operating Procedure were entered. Plant Operations subsequently started the Standby Gas Treatment System (VG) and restored Secondary Containment within TS limits. An investigation determined that ice formed in the sensing line causing an inaccurate Secondary Containment vacuum reading on the indication and control loop for 1VFO4CA. This caused 1VFO4CA to trip which in turn led to a loss of Secondary Containment vacuum. A cause evaluation established that prior instrument sensing line designs did not recognize the potential to trap water in the sensing line to the Secondary Containment pressure instrumentation. Corrective actions will include completing an engineering change to install an alternate Fuel Building Ventilation (VF) system sensing line design to prevent moisture accumulation line to ensure accurate indication and control of Secondary Containment pressure.

This event is reportable under 10 CFR 50.73(a)(2)(v)(C).

On April 21, 2015, at 2258 hours, the Reactor Building ventilation system was unable to maintain a negative pressure in Zone III of Secondary Containment, resulting in entry into Limiting Condition of Operation (LCO) 3.6.4.1, Condition A, for failure to meet Surveillance Requirement (SR) 3.6.4.1.1 on Units 1 and 2. Because the cause analysis was not complete at the time the original LER was submitted, this supplement is being submitted in accordance with NUREG-1022, Rev. 3, Section 5.1.5, Supplemental Information and Revised LERs, to disclose the final cause determination and corrective actions generated.

Per Technical Specification (TS) 3.6.4.1, Secondary Containment must be maintained at 0.25 inches water column (in. w.c.) vacuum. This event was caused by a unique equipment line up coupled with high winds. The apparent cause was determined to be inadequate risk assessment of the test alignment. Corrective actions included reassessing the risk of this alignment and multi-department reviews of test procedures within the Extent of Condition to ensure risk is properly assessed.

There were no actual consequences to the health and safety of the public as a result of this event. An engineering evaluation determined no Safety System Functional Failure actually occurred as a result of this event.

On November 9, 2015 at 20:40 PST, Secondary Containment (Reactor Building) became inoperable due to pressure increasing above the Technical Specifications (TS) limit of -0.25 inches water gauge (inwg).

At the time of the event the Division 2 Reactor Building Heating, Ventilation and Air Conditioning System (HVAC) was controlling Secondary Containment differential pressure. Power supply E-E/S-299 then failed, causing Division 2 Secondary Containment Pressure controller to lose power. This resulted in the Division 2 Reactor Building Exhaust Fan flow being reduced, causing Secondary containment pressure to rise above TS limit of -0.25 inwg.

Operations personnel manually started the Division 2 SGT lead fan to restore negative pressure. The lead fan operated at max flow (due to the failure of E-E/S-299) resulting in the restoration of Secondary Containment pressure to within TS limits.

The Division 1 HVAC was manually started, allowing Operations personnel to manually secure the Division 2 SGT lead fan and maintain Secondary Containment pressure.

The direct cause for the loss of E-E/S-299 was due to an incorrect lug size installed in the fuse block during initial construction.

Current procedures are adequate to prevent a similar error.

26158 R6 NRC Form 366 (01-2014) APPROVED BY OMB: NO. 3150-0104 EXPIRES: 01/31/2017 Reported lessons learned are incorporated into the licensing process and fed back to industry.

Send comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by intemet e-mail to Inf000llects.Resource@nrc.gov, and to the Desk Officer, Office of Information and Regulatory Affairs, NEOB-10202, (3150-0104), Office of Management and Budget, Washington, DC 20503. If a means used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.

alarm. A fire damper inspection was being performed that opened a Control Room HVAC ductwork access hatch that caused the alarm. The hatch was opened and immediately shut, re-establishing the boundary of the Control Room Envelope (CRE). The Control Room Emergency Ventilation (CREV) system was declared inoperable due to opening the ventilation duct hatch without prior administrative controls in place. As a result, Technical Specification 3.7.4, Condition C, was entered and subsequently exited within approximately one minute.

The cause of the inadvertent CRE breach was the design drawing contained in the work package that was reviewed during the Plant Barrier Impairment (PBI) screening did not adequately define the boundaries of the CRE.

Corrective actions included reviewing all open PBI packages. Associated Control Room boundary drawings and procedures will be revised to correctly annotate the proper CRE boundary to include the MCR ventilation ductwork access hatch.

The safety significance of this event was minimal. Given the impact on the MCR envelope, this report is submitted (for Units 1 and 2) in accordance with the requirements of 10 CFR 50.73 (a)(2)(v)(D), which requires the reporting of any 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.

On April 4, 2015, Harris Nuclear Plant was shut down for a scheduled refueling outage in mode 5 and was performing the Remote Shutdown System Operability test. Following transfer back to the Main Control Board, the supply breakers to the normal air intake isolation dampers' motor actuators both independently tripped due to high instantaneous current from the attempted direction reversal of their respective motor actuators.

These trips caused both dampers to be in the partially open position, rendering the Control Room Envelope (CRE) boundary inoperable. The apparent cause of this event is that the HMCP model breaker/starter combination installed by a Design Change is more sensitive to peak current spikes than the original EF3 model breakers. The contributing cause associated with this event was that industry operating experience (OE) was not adequately reviewed to identify existing OE on the need to raise the trip setting on HMCP model breakers. Immediate corrective action was taken to manually close the dampers and restore integrity of the CRE boundary. The corrective action taken to address the breaker sensitivity observed was that the trip settings for the impacted HMCP model breakers installed by the Design Change were revised to add margin to the trip settings.

On April 24, 2014, during a review of previous conditions affecting equipment qualification it was identified that the environmental qualification of Namco EA180 series limit switches were not being properly maintained per vendor requirements. This condition was not verbally reported at the time of discovery as the condition was identified and resolved while the plant was in an extended shutdown.

A cause evaluation was completed and determined that technical requirements from the vendor manual for maintaining environmental qualification of the Namco EA180 series limit switches were not captured in the applicable plant procedure.

The applicable plant procedure has been revised to include vendor information for maintaining environmental qualification of the limit switches. The limit switch top cover gasket and screw assemblies for all environmentally qualified Namco EA180 series limit switches were replaced and torqued in accordance with vendor requirements.

On January 6, 2014, the differential pressure (DP) in the reactor building rose above the requirement of -0.25 inches of water column DP, causing entry into Limiting Condition of Operation (LCO) 3.6.4.1, Condition A.

Secondary containment was declared inoperable at 02:45.

The DP transient occurred when a non-licensed plant operator (NLO) was hanging tags in support of maintenance work. During the process of hanging tags, the NLO inadvertently opened the wrong drain valve.

When the wrong drain valve was open, the reactor recirculation motor generator (RRMG) exhaust fan discharge damper that was operating closed. The NLO felt the change in DP and closed the drain valve, which opened the RRMG exhaust fan discharge damper, restoring ventilation. DP was restored, secondary containment was declared operable at 03:02, and the LCO was exited. During this event, DP remained negative at all times.

The root cause is the organization was not fully aware of the effects of the cross-over leakage between the reactor building envelope and the RRMG exhaust system. To prevent recurrence of this event, procedures will be revised to ensure adequate precautions are taken to avoid exceeding the -0.25 inches of water column DP requirement, information about the effects of cross-over leakage will be incorporated into the appropriate training materials, and a procedure to directly measure air leakage will be developed.

On October 31, 2013, at approximately 1834 Central Daylight Time during review of industry operating experience, South Texas Project (STP) determined an unanalyzed condition exists related to the Control Room (CR) fire analysis. The original design of ammeter circuits which provide CR current indication for the non-Class 48 VDC battery and battery charger circuits and for the non-Class turbine lube oil emergency pump control circuit does not include overcurrent protection features to limit fault current. In the postulated event, a fire in the CR could cause a ground loop through unprotected ammeter wiring or control circuit wiring and potentially result in excessive current flow and heating to the point of causing a secondary fire outside the CR in the cable raceways.

The postulated secondary fire could affect the availability of equipment needed to place the plant in a safe shutdown condition during a CR fire event. This scenario has not been analyzed in accordance with 10 CFR 50 Appendix R. Compensatory fire watch measures have been implemented and remain in place for the affected fire zones in the plant.

The cause was determined to be that the original design of the affected CR circuits did not adequately address fire protection program requirements. A design change is planned to correct the latent design deficiencies by providing circuit protection on affected CR circuits.

On May 8, 2013 at 19:53, a safety-related circuit breaker failed when Operations personnel attempted to start Shutdown Cooling Heat Exchanger Room B air handling unit. In accordance with Operations administrative procedure for Technical Specification and Technical Requirements Compliance, Operations personnel entered the applicable Technical Specification Limiting Condition for Operation for Containment Spray (CS) train B. A replacement breaker was installed and a successful start of the air handling unit was performed. CS Train B was declared operable at 17:30 on May 9, 2013.

An evaluation of the failure determined that the air handling unit had been effectively rendered inoperable since installation of the circuit breaker on April 18, 2013. Containment Spray train B was inoperable from 03:09 on April 17, 2013, when the train was declared inoperable to perform preventative maintenance until 17:30 on May 9, 2013, a total of 22.6 days. This time period exceeds the Technical Specification allowed outage time of 7 days. Technical Specification 3.6.2.1 was not complied with, which requires that with one CS system (train) inoperable, restore the system (train) to operable status within 7 days or be in at least Hot Standby within the next six hours. During this time frame CS 'A' was inoperable for 6.65 hours. Since both trains of Containment Spray were inoperable this is considered a Safety System functional failure due to the system being unable to mitigate the consequences of an accident.

This LER reports the failure of components caused by a defect in ARD66OUR control relays reported by Westinghouse, pursuant to 10 CFR 21, on April 8, 2013. The defect resulted in the failure of five normally energized control relays at PVNGS in two different systems in Unit 1 and two different systems in Unit 2.

The relays were used in normally energized applications which are de-energized to position associated components to support the related safety function. The relays failed to change state when de-energized during testing.

The five failed relays were replaced. The cause was a change in the manufacturing process that occurred in May 2008. The defect was exhibited only on relays that failed in the manner described in the Westinghouse Part 21 report. An extensive testing program was completed to identify and replace ARD66OUR relays installed at PVNGS that exhibited the described failure mode. Westinghouse has modified the ARD66OUR relay plastic molding process to preclude this described failure mode. LER 05000529 / 2009-002-00 reported ARD66OUR relay failures that exhibited a similar failure mode.

On 2/6/2013, with all three Oconee Units at 100 percent power, Oconee Nuclear Station (ONS) personnel concluded that emergency power equipment could be adversely impacted by a licensee identified original design issue involving inadequate analysis of electrical equipment heat loads and weaknesses in the Heating Ventilation & Air Conditioning (HVAC) system design.

The investigation determined that the principle causes were associated with inadequate and incomplete inputs and methods in development of HVAC systems during original plant design and Blockhouse, and the 230kV Switchyard Relay House susceptible to single failures.

Compensatory measures were put into place. Corrective actions include modifications to resolve the inadequacies with the original plant design issues.

This event is reportable under the following criteria: Operations Prohibited by Technical Specifications, Unanalyzed Condition, Event that could have prevented Fulfillment of a Safety Function, and Common Cause.

On 14:35 on 12/17/2012, the A Class lE electrical equipment air conditioning unit (SGKO5A) was declared inoperable due to identification of Freon leakage from the unit's low oil pressure and compressor discharge sensing lines. Following repair to address the leakage, the unit was declared operable at 11:08 on 12/18/2012.

The SGKO5A unit provides a support function for the A train of Class lE electrical equipment. The Class lE electrical equipment is addressed in the plant's Technical Specifications. Since the leakage for SGKO5A had apparently existed prior to the time of discovery, it was concluded that SGKO5A and the supported Class 1E electrical equipment had been inoperable for a period of time longer than the allowed by the plant Technical Specifications.

The leakage was the result of two sensing lines rubbing together. The Root Cause was determined to be an inadequate scope of previously conducted equipment reliability evaluations on the HVAC system. The leaks were repaired. In addition, preventive maintenance and monitoring of vibration-susceptible Class lE electrical equipment air-conditioners will be increased.

On July 24, 2012, secondary containment pressure exceeded technical specification allowable limits for a period of approximately four and a half minutes. The pressure excursion was due to an inadvertent trip of reactor building fans ROA-FN-1B and REA-FN-1B. The trip occurred during ongoing maintenance on the Standby Gas Treatment (SGT) system. While technical specification limits were exceeded, the resulting pressure excursion was bounded by analytical results, and thus there were no safety consequences for this event. The investigation concluded that there was no direct evidence that a human performance error caused this event. The cause for the event was determined to be that operations does not have guidance on swapping to redundant lineups when work is to be performed on the SGT or reactor building HVAC .

Corrective actions will revise standard operating procedures and Instrument Master Data Sheets by adding a note about reactor building fan trip risk.

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On 3/1/2012, at 1353 hours, an issue was identified with the doors for the safety related battery rooms and their normal pOsition. Several doors to the battery rooms are held open via electromagnetic door devices. At the time, it was thought that there was no uninterruptible power to the door mechanisms, and that all the doors are expected to close in the event of a loss of offsite power (LOOP). Inadvertent closure of the doors following a momentary loss of power prevents their design function of venting hydrogen from the battery rooms and providing tornado venting pathways in the building. Compensatory measures were taken to secure the doors open to maintain the hydrogen purging and tornado venting functions. A roving fire watch was implemented to comply with the fire protection function of the doors. As an extent of condition on 3/12/12, the cable spread room (CSR) doors were also identified to utilize the same design and electrical supply configuration as the battery room doors.

The CSR is located above the battery rooms in the Electric and Control (E&C) Building. Contingency actions were put in place to secure the CSR doors open and implement a fire impairment in the event of a tornado risk. On 4/11/12, it was discovered that the battery room and CSR doors have small battery backup units which could sustain the doors with adequate power to maintain their position for 45 seconds sufficient to allow AC power to be restored through the Emergency Diesel Generators (EDG5) during a tornado. However, the backup units were found to be in a state of degradation, challenging the ability of the backup batteries to maintain their power supply to the door hold-open devices during a tornado event. No recent preventive maintenance work orders exist for the inspection or replacement of these units. There were no actual safety consequences impacting the plant or public safety as a result of these events. The cause was a design process legacy issue, and current design processes are significantly different from those in place during early operation of CPNPP. The specific conditions have been addressed in the corrective action program and, along with current programs and practices, are adequate to prevent future occurrences. All times in this report are approximate and Central Time unless noted otherwise.