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On October 4, 2017 at 0155 hours, while in Mode 1 at 100 percent rated thermal power, inoperability of both A and B trains of Motor Control Center, Switchgear, and Miscellaneous Electrical Equipment Areas Heating, Ventilation, and Air Conditioning System and Battery Rooms Exhaust System (M23/24) occurred. Train A was shutdown and declared inoperable based on excessive drive belt noise and belt malfunction. Train B was inoperable due to ongoing maintenance on its associated chilled water system. The combination of inoperability resulted in a loss of safety function. Technical Specification (TS) 3.0.3 was entered per plant procedures, and at 0250 hours a plant shutdown was commenced. At 0620 hours, the A train of M23/24 was declared operable following belt replacement and TS 3.0.3 was exited. The plant was restored to 100 percent rated thermal power at 0804 hours.

The cause was determined to be inadequate procedural guidance in that the "general tensioning" method described in plant maintenance procedure, V-belt and Sheave Maintenance, is insufficient for restoring components to a reliable condition. Corrective action includes revising the procedure for correct tensioning guidance.

The safety significance of this event is considered to be very small. This event is being reported in accordance with 10CFR50.73(a)(2)(v)(B), 10CFR50.73(a)(2)(v)(C), and 10CFR50.73(a)(2)(v)(D) as an event or condition that could have prevented the fulfilment of a safety function.

NRC FORM 386 (06-2016)

On May 15, 2017, an engineering investigation determined that a modification installed in 2014 on two of the four safety-related main control building chillers had a design error. The nature of that error was such that the performance of a regularly scheduled preventative maintenance (PM) task to draw an oil sample from'the chiller gearbox inadvertently caused the chiller to be incapable of responding to an automatic start signal. A review of the history of the PM found that, on three occasions since the modification was installed, the task was performed on the operable chiller that was in the standby condition. The inadvertent inoperability of the standby division of the main control building chillers causes the loss of safety function of the supported electrical distribution systems in the building. The control building chilled water system provides cooling to the equipment rooms housing the battery chargers and inverters for the safety-related onsite electrical distribution systems. The loss of cooling to the various equipment rooms in the control building requires that the supported equipment in those areas be declared inoperable. The Technical Specifications for the Division 3 DC distribution system requires that the high pressure core spray (HPCS) system be immediately declared inoperable. This condition potentially causes the HPCS system to be incapable of performing its safety function, and is, thus, reportable in accordance with 10 CFR 50.73(a)(2)(v)(D). The error in the subject modification is considered a legacy issue since its design was completed and approved in July 2012. The PM task will be revised to preclude its performance on chillers in the standby configuration.

At no time during the three performances of the PM on the operable standby chiller was there an actual demand for its automatic start. This condition was, thus, of minimal significance with respect to the health and safety of the public.

I

On May 26, 2017, while performing the Automatic Depressurization System (ADS) quarterly surveillance, the time delay on the Trip System A (Division 1) ADS initiation timer relay was found outside of its Technical Specification (TS) Allowable Value of 5 115 seconds. Specifically, the ADS timer requirements in TS 3.3.5.1, Emergency Core Cooling System Instrumentation, Table 3.3.5.1-1, Emergency Core Cooling System Instrumentation, Function 4, Sub-function c. ADS Initiation Timer, Allowable Value was not met. The cause was determined to be inadequate preventive maintenance and review of the previous test results. This event is reportable as a license event report (LER) in accordance with 10CFR50.73(a)(2)(i)(B), as a "condition prohibited by Technical Specifications" because the same relay failed its previous test and could not be considered as OPERABLE during the full interval between tests. Corrective actions included replacement of the defective timer relay and planned actions to replace the corresponding timer relays in ADS and the Feedwater Control System. In addition, the applicable preventive maintenance procedures were revised. The event posed no threat to the health and safety of the general public or to nuclear safety as ADS would have performed as designed. No Technical Specification safety limits were challenged or violated.

APPROVED BY OMB: NO. 3150-0104 EXPIRES: 3/31/2020 366A U.S. NUCLEAR REGULATORY COMMISSION NRC FORM (4-2017)

• ..*

• ‘‘ Reported lessons learned are incorporated into the licensing process and fed back to industry. Send comments regarding burden estimate to the Information Services Branch (T-2 F43), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by e-mail to 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.

(See NUREG-1022, R.3 for instruction and guidance for completing this form httplAwm.nrc.00vireadino-rm/doc-collections/nureas/staff/sr1022/r3/) 05000 416

DESCRIPTION

On May 26, 2017, while performing Automatic Depressurization System (ADS) (AD)(C23) quarterly surveillance, the time delay on the Trip System A ADS initiation timer relay (RLY2) was found outside of its Technical Specification (TS) Allowable Value of 115 seconds. Specifically, the ADS timer requirements that are specified in Technical Specifications 3.3.5.1, Emergency Core Cooling System (ECCS) Instrumentation, Table 3.3.5.1-1, Emergency Core Cooling System Instrumentation, Function 4, Sub-function c. ADS Initiation Timer, Allowable Value were not met.

The failure mechanism is degradation of the timing function in the ADS initiation timer relay (Agastat Model TR14D3EC750) that delays initiation of ADS in order to allow time for high pressure injection to restore reactor water level. The TS Allowable Value for this timer is less than or equal to 115 seconds. The as found value was beyond this value. This surveillance is performed on a quarterly basis. This same condition was found during the last surveillance performed on February 23, 2017.

This condition was not found during the surveillance performed prior to that on November 18, 2016.

The Automatic Depressurization System is required in Modes 1, 2, and 3 with the reactor above 150 psig. Between November 18, 2016 and January 30, 2017, the plant was in Mode 4. Therefore this function was not required from November 18, 2016 to January 30, 2017, which is when the reactor reached 150 psig in Mode 2.

The ADS was required to be Operable from January 30, 2017, until May 26, 2017. ADS initiation is accomplished by energization of either the Trip System A (Division 1) or Trip System B (Division 2) solenoids (FSW) associated with each of the ADS valves. The logic for each Trip System is separate and either trip system will cause all the ADS relief valves to open. Therefore, the automatic safety function would still be accomplished within the allowable time provided that the Trip System B was Operable. Trip System B initiation logic was taken out of service on March 10, 2017, to support performance of the quarterly ADS channel calibration surveillance procedure. An additional review was performed to determine if the Trip System A logic would have initiated within the allowable time during the period when the Trip System B logic was out of service. The average rate of change of the setpoint between surveillances was 0.402 seconds/day for the first interval (November 18, 2016 - February 23, 2017) and 0.424 seconds/day for the second interval (February 23, 2017 - May 26, 2017). Use of the larger rate of change is conservative, and therefore a rate of 0.424 seconds/day was assumed for the second interval. Linearly extrapolating from an as left condition of 104 seconds on February 23, 2017, it is concluded that the setpoint would have been approximately 110.4 seconds on March 10, 2017. This value is within the 115 second TS AV. Therefore, it is concluded that no loss of safety function occurred for this condition.

REPORTABILITY

This event is reportable as a license event report (LER) in accordance with NUREG-1022, Section 3.2.2, and 10CFR50.73(a)(2)(i)(B), as a "condition prohibited by Technical Specifications" because the same relay failed its previous test and could not have been considered operable for the full interval between tests. The timer relay would have been considered inoperable for a time period such that the Technical Specification 3.3.5.1 completion time would not have been met.

NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION (6-2016)

CONTINUATION SHEET

(See NUREG-1022, R.3 for instruction and guidance for completing this form + a httplAvwt.v.nrc.covireadinci-rm/doc-collections/nureqs/staff/sr1022/r3I) APPROVED BY OMB: NO. 3150-0104 EXPIRES: 3/31/2020 Reported lessons learned are incorporated into the licensing process and fed back to industry. Send comments regarding burden estimate to the Information Services Branch (T- 2 F43), U.S. Nuclear Regulatory Commission, Washington, DC 20555.0001, or by e-mail to InTocollects.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.

05000 416

CAUSE

The direct cause of the failure is the degradation of timing function for ADS initiation timer relay 1B21-K5A, most likely due to the electrolytic capacitor degradation.

The cause of the failure was an inadequate preventive maintenance task and inadequate procedural guidance.

The procedures did not require periodic replacement of the relay nor did they require an engineering review of the test results.

CORRECTIVE ACTIONS

Immediate:

The defective timer relay in Trip System A was replaced.

Completed:

Preventive maintenance tasks were revised to require periodic replacement of the relays.

Surveillance testing was revised to require timely engineering review of the completed quarterly surveillance tests.

Planned:

The corresponding relays in ADS and the Feedwater Control System will be replaced. This action has been entered in the corrective action program and may be modified in accordance with that program.

SAFETY SIGNIFICANCE

Initiation of the ADS is accomplished by energizing either the Trip System A or Trip System B solenoids associated with each of the ADS valves. Each separate trip system will cause all the ADS relief valves to open. Therefore, the automatic safety function would still be accomplished within the allowable time with Trip System A inoperable provided that Trip System B was Operable. Trip System B initiation logic was taken out of service on March 10, 2017, to support performance of the quarterly ADS Channel B calibration surveillance procedure. An additional review was performed to determine if the Trip System A logic would have initiated within the allowable time during the period when the Trip System B logic was out of service. The conclusion was that the "A" setpoint would have been approximately 110.4 seconds on March 10, 2017. This value is within the 115 second TS AV. Therefore, at least one division of ADS was always available to perform the safety function. In addition, manual actuation was available, and operators are trained on the conditions requiring manual actuation and the associated procedures.

The ADS acts as a backup to High Pressure Core Spray System (BG) for a small break loss of coolant accident. The High Pressure Core Spray System was not impacted by the degraded condition of ADS.

The event posed no threat to the health and safety of the general public or to nuclear safety as ADS would have performed as designed. No Technical Specification safety limits were challenged or violated. Industrial safety was not challenged, and there was no potential or actual radiological release during the event.

PREVIOUS SIMILAR OCCURRENCES

The identified licensee event reports were attributed to inadequate maintenance procedures. The events were reviewed and it has been determined that the causes and corrective actions were sufficiently different that they could not have predicted or prevented the occurrence of this event.

At 1808 hours on 1/27/17, Grand Gulf Nuclear Station entered into LCO 3.5.1.6 when the High Pressure Core Spray (HPCS) Jockey Pump (Component Function Identifier- P) failed and the HPCS System was declared inoperable. The Reactor Core Isolation Cooling (RCIC) System was verified operable and investigation into the cause was initiated. Under those plant conditions the Plant Technical Specifications action to restore the HPCS System to operable status allows a 14 day completion time.

No other safety systems were inoperable at the time of this event.

The decision was made to disassemble the HPCS Jockey Pump and rebuild the pump using parts from the warehouse which was completed on 1/29/17. The pump was tested to demonstrate functionality of the pump on 1/29/17 and the system was returned to service.

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 September 4, 2016 at 02:58, Grand Gulf Nuclear Station entered three TS LCO Action Statements because RHR 'A' pump was declared inoperable.

LCO Actions entered:

1) 3.5.1 for one low pressure ECCS injection/spray subsystem, 2) 3.6.1.7 for one RHR containment spray subsystem, and 3) 3.6.2.3 for one RHR suppression pool cooling subsystem. All have 7 day Completion Times A decision was made to shutdown the plant to repair the RHR 'A' pump because, based on the troubleshooting and testing plan, the pump could not be repaired and returned to service within the LCO Completion Times. At 0300 CDT on 09/08/16, GGNS initiated the transition to Mode 4.

The pump was removed from service and sent to the vendor facility for decontamination, disassembly and failure analysis.

The 'A' pump was then replaced and tested satisfactorily. RHR 'A' was returned to operable.

APPROVED BY OMB: NO. 3150-0104 EXPIRES: 10/31/2018 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 internet e-mail to Intocollects.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 366A U.S. NUCLEAR REGULATORY COMMISSION

CONTINUATION SHEET

2. DOCKET 3. LER NUMBER 05000 416

PLANT CONDITIONS PRIOR TO THE EVENT

At the time of the event, Grand Gulf Nuclear Station (GGNS) Unit 1 was in Mode 1, at 100% rated thermal power.

All systems, structures and components, with the exception of the RHR 'A' pump, that were necessary to mitigate, reduce the consequences of, or limit the safety implications of the event were available. No other safety significant components were out of service.

DESCRIPTION

On September 4, 2016, GGNS was performing a Residual Heat Removal (RHR) 'A' quarterly Technical Specification (TS) Surveillance Requirement (SR). At 02:58, The RHR pump failed to meet its TS SR Acceptance Criteria for flow and differential pressure (d/p) and was therefore declared Inoperable. Action Statements for TS Limiting Conditions for Operation (LCOs) 3.5.1, 3.6.1.7 and 3.6.2.3 were entered, each having Completion Times of 7 days.

LCO Action Statements entered:

1) 3.5.1 for one low pressure ECCS injection/spray subsystem, 2) 3.6.1.7 for one RHR containment spray subsystem, and 3) 3.6.2.3 for one RHR suppression pool cooling subsystem.

Initial troubleshooting verified that the pump was incapable of meeting the flow requirement of 7756 gpm and d/p of 131 psid simultaneously. The observed pump flow and discharge pressures were verified to be correct via a temporarily installed ultrasonic flow meter and pressure gauge. RHR system valves and lines were verified not to be clogged or leaking. The pump motor was confirmed to be operating at the proper speed.

Further troubleshooting and testing lead station management to the conclusion that RHR 'A' would not be returned to operable status within the 7 day Completion Time. A decision was made to commence an orderly shutdown. On September 8, 2016 at 0300, GGNS began the transition to Mode 4. No other systems were out of service that would have complicated an orderly shutdown to Mode 4.

REPORTABILITY

Event Notification No. 52225 was made to the U.S. Nuclear Regulatory Commission (NRC) Operations Center.

This LER is being submitted pursuant to Title 10 Code of Federal Regulations 10 CFR 50.73(a)(2)(i)(A) for the completion of any nuclear plant shutdown required by the plant's Technical Specifications. Telephonic notification was made to the NRC Emergency Notification System on September 8, 2016, at 03:27, pursuant to 10 CFR 50.72(b)(2)(i) for the initiation of any nuclear plant shutdown required by the plant's Technical Specifications.

CAUSE

Direct Cause: The RHR 'A' pump was unable to provide its required flow at the required differential pressure in order to perform its safety function.

APPROVED BY OMB: NO. 3150-0104 EXPIRES: 10/31/2018 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 internet e-mail to Infocollects.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

NRC FORM

366A U.S. NUCLEAR REGULATORY COMMISSION

CONTINUATION SHEET

Grand Gulf Nuclear Station, Unit 1 05000 416 Apparent Cause: Subsequent investigation suggests internal pump degradation but the Apparent Cause is ongoing. A supplemental report to this LER will be provided when the Apparent Cause investigation is complete.

EXTENT OF CONDITION

Quarterly surveillance data of similar Emergency Core Cooling System (ECCS) pumps showed no evidence of degradation. Data was re-examined from the following pumps: Low Pressure Core Spray (LPCS), High Pressure Core Spray (HPCS) and RHR 'B' and 'C.' GGNS also performed a partial quarterly surveillance on the RHR 'B' which was completed satisfactorily.

CORRECTIVE ACTIONS

The RHR 'A' pump was replaced and retested satisfactorily. The pump removed from service has been sent to the vendor facility for failure analysis.

SAFETY SIGNIFICANCE

The event posed no threat to the health and safety of the general public or to nuclear safety as safety- systems performed as designed. No Technical Specification safety limits were violated. Industrial safety was not challenged, and there was no potential or actual radiological release during the event.

PREVIOUS SIMILAR EVENTS

Previous similar events. will be discussed in the supplemental report upon completion of the Apparent Cause investigation.

On November 19, 2015, at 7:24 a.m. CST, with the plant operating at 97 percent power, the high pressure core spray system (HPCS) was declared inoperable following the failure of the operating chiller in the Division 2 control building ventilation system (HVK).

Chiller "D" was in service when the building operator found an oil leak on that machine. The chiller subsequently tripped on low oil pressure. The "A" chiller in the Division 1 subsystem automatically started as designed. The loss of cooling to the various equipment rooms in the control building requires that the supported equipment in those areas be declared inoperable. The Technical Specifications for the Division 3 DC distribution system requires that the HPCS system be immediately declared inoperable. This condition potentially causes the HPCS system to be incapable of performing its safety function. Maintenance technicians identified the source of the oil leak as a failed seal on the compressor drive shaft. The apparent cause of the seal failure was the age-related degradation of a setscrew holding one of the rotating elements of the seal, allowing it to get out of position and disrupt the integrity of the seal face. In this event, the "A" chiller automatically started as designed, and it was confirmed to be operating correctly within 10 minutes. The HVK system continued to support the safety function of Division 3 electrical equipment after chiller trip, since the time required to restore an operable chiller is significantly less than the time limit for restoration of equipment room cooling. This event had no actual adverse effect on the ability of the Division 3 HPCS electrical system to perform its design safety function since there was more than sufficient time to align the other chiller in the same division to provide control building switchgear room cooling. This event, thus, did not constitute an actual loss of the ability of the HPCS system to perform its design safety function.

On June 16, 2015, at 0452 hours, during performance of surveillance testing, a degraded voltage time delay relay was found outside of the Technical Specification allowable value.

The cause of the Division 3 degraded voltage time delay relay being outside the allowable value was setpoint drift and the calibration setpoint not being centered within the allowable value range. The relay was satisfactorily recalibrated in accordance with procedures and successfully passed the as-left performance test during the remainder of the surveillance testing and was made operable on June 16, 2015, at 1117 hours. Planned corrective actions include centering the time delay relay setpoint within the allowable value and relay removal for analysis and evaluation.

The safety significance of this event is considered to be small. The degraded voltage time delay relay initiates load shedding, isolates the Division 3 bus and starts the Division 3 Emergency Diesel Generator (EDG). The Division 3 EDG is the on-site power source for the High Pressure Core Spray System which is a single train system. Therefore, this event is being reported in accordance with 10CFR50.73(a)(2)(v) as an event or condition that could have prevented the fulfillment of a safety function.

Additionally, as discussed in the Event Analysis section, this event is not considered a safety system functional failure because the as found setpoint was within the analytical design limit.

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 December 2, 2013, at 0903, Nine Mile Point Unit 2 (NMP2) was lowering reactor power level to remove the main turbine from service to support maintenance. During the power reduction, the Low Frequency Motor Generators (LFMGs) did not start automatically. Attempts to manually start the recirculation system pumps in slow speed were unsuccessful and a manual reactor scram was inserted due to the sudden reduction in core flow.

This event is reportable in accordance with 10 CFR 50.73(a)(2)(iv)(A) as a condition that resulted in manual or automatic actuation of any of the systems listed in 10 CFR 50.73(a)(2)(iv)(B). The Reactor Protection System is listed in 10 CFR 50.73(a)(2)(iv)(B).

The root cause of this event is a failure to identify that the switches in the auto transfer circuits for the reactor recirculation pumps to shift from high speed to low speed are single point vulnerable (SPV) components because they were exempted from the AP-913 classification process. Since the switches were not classified as SPV components, no mitigation strategies were developed.

Corrective actions include revision of the operating procedures to manually start the LFMG sets and not rely on the auto transfer circuitry.

There are no similar Licensee Event Reports for NMP2.

On April 25, 2013, Unit 2 was in Mode 1 at approximately 56% power. The east condenser waterbox was being dewatered in order to address a condenser tube leak. Waterbox isolation valves 2CW007A and 2CW007C had been closed using their motor operators; however, in order to minimize leak-by, an attempt was made to manually seat the valves. These valves are 144 inch butterfly valves with no internal stops. Outlet isolation valve 2CW007C was seated without incident, but inlet valve 2CW007A was inadvertently moved past its closed position, which allowed flow from the running circulating water pumps to fill the waterbox.

At 2005 hours CDT, the Main Control Room was informed that a large amount of water was coming from the open waterbox upper manways. An attempt was made to close the manways; however, at 2019 hours, the 2A and 2B circulating water pumps tripped on high condenser pit water level, requiring Unit 2 to be manually scrammed.

The root causes of the event were determined to be a lack of strict procedural adherence on the part of the operators performing the waterbox dewatering task, and inadequate procedure quality. Corrective actions include coaching in accordance with company policies, and clarifying revisions to the circulating water dewatering procedure.

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 January 22, 2013, at 0332 hours, the reactor protection system (RPS) automatically actuated due to a loss of feedwater flow to the reactor pressure vessel (RPV). There were no complications during the shutdown as all control rods fully inserted and pressure was maintained by normal means. The High Pressure Core Spray (HPCS) and the Reactor Core Isolation Cooling (RCIC) systems actuated based on a valid reactor water level initiation and injected to restore RPV water level.

The cause of the event was failure of a balance-of-plant inverter/static transfer switch, which provides electrical power to the digital feedwater control system. A circuit card in the static transfer switch degraded, which affected operation of the inverter. The electrical loads serviced by the inverter/static transfer switch were placed on an alternate power source. This alignment will continue until permanent repairs are made which are currently scheduled for the next refueling outage.

The safety significance of this event is considered to be small. This event is being reported in accordance with 10 CFR 50.73(a)(2)(iv)(A) as an event or condition that resulted in an automatic actuation of the RPS, HPCS, and RCIC systems, and Operational Requirements Manual section 7.6.2.1, which requires a Special Report submittal following an Emergency Core Cooling System actuation and injection into the reactor coolant system.

On August 31, 2012, at 09:40 CDT, while blowing down the 2B Diesel Generator (DG) A train Starting Air receiver for preventative maintenance, the receiver pressure decreased below the minimum 165 psig required for DG operability per Technical Specification (TS) 3.8.3, Condition D. The 2B DG provides emergency AC power to Division 3, which supplies the High Pressure Core Spray System (HPCS). The 2B DG was declared inoperable in accordance with TS 3.8.3 Required Action E.1.

At 10:22 CDT, the A air start train was re-pressurized to greater than 165 psig, and the 2B DG was declared operable.

The 2B DG was inoperable for approximately 42 minutes.

The cause of the event was determined to be a degraded drain valve on the A train starting air receiver. The corrective actions included replacement of the drain valve.

On May 8, 2012, plant engineers confirmed that the lubricating oil in the Division 3 diesel generator (DG) was contaminated with fuel at a level that required its replacement. At the time of this discovery, a plant heat-up was in progress in preparation for return to service following a maintenance outage. The oil sample that yielded these 1 results had been drawn on April 25, and shipped off-site for vendor analysis. Plant engineers evaluated the Itrends of prior lubricating oil samples taken prior to May 8, and determined that the DG had become incapable of performing its design safety function on approximately October 28, 2011. It was concluded that this date was the likely starting point of the internal fuel leak that contaminated the oil. That fuel leak likely resulted from gasket damage that occurred during work on the fuel injectors. On May 8, the DG was removed from service in order to change the lubricating oil and repair the fuel leak. It has been determined that, in the as-found condition, the DG remained capable of fulfilling the mission time assumed by the station's probabilistic risk analysis. Enhanced , work instructions for fuel jumper installation have been added to the vendor manual and to model work orders.

This condition is being reported in accordance with 10CFR50.73(a)(2)(i)(B) as operations prohibited by Technical Specifications.t