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At approximately 0918 hours on Tuesday, December 12, 2017, while operating in MODE 1 at approximately 18 percent power, the Grand Gulf Nuclear Station (GGNS) experienced a loss of the Engineered Safety Features (ESF) Transformer 11 which was powering the Division 1 ESF bus. Subsequently, the station experienced an automatic start of the Division 1 Emergency Diesel Generator and the partial isolation of the primary and secondary containment buildings. Both of these events were expectedand as designed. The direct cause of ESF actuations was the loss of ESF Transformer 11. The cause of the transformer loss is under investigation at this time and this licensee event , report will supplemented upon completion of GGNS's causal analysis.

Additionally, GGNS experiented an unrelated isolation of the Reactor Core Isolation Cooling System upon restoration of power. The isolation of the Reactor Core Isolatigh Cooling System did not result in a loss of safety function. The cause of this isolation is under investigation and will be documented in accordance with the.GGNS corrective action program.

This event is reportable to the NRC in accordanCe with 10 CFR 50.72(b)(3)(iv) and 10 CFR 50.73(a)(2)(iv)(A) as an event or condition resulting in a valid actuation of a ESF system.

Grand Gulf Nuclear Station, Unit 1 05000 416 .

NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION APPROVED BY OMB: NO. 3150-0104 EXPIRES: 3/3112020 (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 so RkG,„ LICENSEE EVENT REPORT (LER)

• r F43), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by e-mail to y n4 CONTINUATION SHEET Infocollects.Resource@nrc.gov: and to the Desk Officer: Office of Information and .i: Regulatory Affairs, NEOB-10202. (3150-0104). Office of Management and Budoet, Washington, DC 20503: If a means used to impose an information collection does not c's, T

• (See NUREG-1022, R.3 for instruction and guidance for completing this form display a currently valid OMB control number, the NRC may not conduct or sponsor. and a N*,......0, htto://vAmnrc.00virP-adiriq-rmidoc-collectionsinureosistaff/sr1022/r3A . person is not required to respond to, the information collection.

DESCRIPTION

At approximately 0918 hours on Tuesday, December 12, 2017, while operating in MODE 1 at approximately 18 percent power, the Grand Gulf Nuclear Station (GGNS) experienced a loss of the Engineered Safety Features (ESF) Transformer 11 (EB) which was powering the Division 1 ESF bus (EA): The transformer experienced an instantaneous ground resulting in a transformer lockout and loss of power to the ESF bus. Subsequently, the station experienced an automatic start of the Division 1 Emergency Diesel Generator (EK) and the partial isolation of the primary and secondary containment buildings. Both of the system actuations were expected responses to a loss of ESF bus and both systems responded as designed. The direct cause of ESF actuations was the loss of ESF Transformer 11.

Additionally, GGNS experienced an unrelated isolation of the Reactor Core Isolation Cooling System (BN) upon restoration of power. The' isolation of the. Reactor Core Isolation Cooling System did not result in a loss of safety function. The cause of this isolation is under investigation and will be documented in accordance with the GGNS corrective action program.

REPORTABI LITY

This event is reportable to the NRC in accordance with 10 CFR 50.72(b)(3)(iv)(A) and 10 CFR 50.73(a)(2)(iv)(A) as an event or condition resulting in a valid actuation of a ESF system.

The 10 CFR 50.72 reporting requirements were met with the completion of Emergency Notification System (ENS) Notificatibn 53115, at 1740 hpurs eastern standard time on December 12, 2017.

CAUSE

Direct Cause:

The direct cause of the ESF actuation was the loss of ESF Transformer 11 and the opening of the transformer feeder breaker due to an instantaneous ground.

Apparent Cause:

The most probable cause is a ground on one of the feeder cables to ESF Transformer 11.

However, the investigation and causal analysis is ongoing at this time and this licensee event report will be supplemented upon completion of the GGNS causal analysis.

NRC FORM

(6-2016) 366A U.S. NUCLEAR. REGULATORY COMMISSION LICENSEE. EVENT REPORT (LER)

• CONTINUATION 'SHEET (See NUREG-1022, R.3 for instruction and guidance for completing this form htto://www.nrc.coWreadino-rm/doc-collectionsinureos/staff/sr1022/r3/) APPROVED BY OMB: NO. 3150-0104 EXPIRES: 3/3112020 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 Infoccillects.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.

2. DOCKET 3. LER NUMBER 05000.416

CORRECTIVE ACTIONS

Spare Essential Transformer 21 was placed into service and normal power was restored.

The investigation and causal analysis is ongoing and this licensee event report will be supplemented upon completion of GGNS's causal analysis. The planned corrective actions will be included in the corrective action program and may be changed in accordance with the program.

• .":

SAFETY SIGNIFICANCE

There were no nuclear safety consequences or radiological consequences as a result of this event.

No Technical Specification Safety Limits were violated. Upon the loss of Engineered Safety Feature Transformer 11 all required accident mitigation ESF components responded as designed.

The isolation of the Reactor Core Isolation Cooling System, although unexpected, did not adversely impact the plant's ability to respond to the event.

PREVIOUSLY SIMILAR EVENTS

Protective Relaying Circuitry on the "B" Main Transformer Transformer Wiring Entergy has reviewed the events listed in the licensee event reports (LER) documented above to determine if the corrective actions should have prevented the event documented in this LER.

Based on a preliminary evaluation it has been concluded the established corrective actions would not have prevent this event.

Entergy's investigation into the cause of this event and the development of corrective actions to preclude recurrence are ongoing. This section will be supplemented at the conclusion of this effort.

At 1000 EDT on September 9, 2017, the Division 2 Mechanical Draft Cooling Tower (MDCT) fans were declared inoperable due to loss of output from the over speed fan brake inverter. The MDCT fans are required to support operability of the Ultimate Heat Sink (UHS) and the Emergency Equipment Cooling Water (EECW) system. The Division 2 EECW system cools the High Pressure Coolant Injection (HPCI) system room cooler. As a result, the non-functionality of the fan brakes lead to an unplanned HPCI inoperability.

Since HPCI is a single train system designed to mitigate the consequences of a loss of coolant accident (LOCA), this event could have prevented the fulfillment of a safety function. The cause of the event was the failure of the Division 2 fan brake inverter.

Corrective Actions were taken to replace the inverter and returning the MDCT fans, the UHS, EECW and HPCI to service on September 9, 2017 at 2351 EDT. A failure modes evaluation was performed by the vendor with no direct cause of the failed output determined. The fan brake system is only required for a design basis tornado and there was no credible tornado threat during this event.

The HPCI system is not required to mitigate a design basis tornado. The safety significance of this event is very low and there were no radiological releases associated with this event.

On June 8, 2017 at 1527 hours, the reactor automatically scrammed due to a loss of Main Turbine- Electro-Hydraulic Control (EHC) logic power causing a high neutron flux, Reactor Protection System (RPS) trip. The safety systems operated as expected. Secondary Containment differential pressure lowered to 0" WG due to a trip of the normal operation of the Reactor Building Ventilation system. The differential pressure was restored by the initiation of Standby Gas Treatment System.

The scram was caused directly by a DC+ (direct current, positive) test lead (Maxi Grabber) that inadvertently contacted with the grounding screw, causing a short and momentary loss of EHC logic power.

Immediate action was taken to validate that there was no damage to the +30 VDC (volts DC) EHC logic.

The root cause for this event is an insufficient focus on the High Risk Activity of adjusting the EHC power supply, and inadequate risk mitigating actions for that activity.

The condition is being reported in accordance with 10 CFR 50.73(a)(2)(iv)(A) as an event that resulted in an automatic actuation of the RPS, including reactor scram. Although no safety system functional failure occurred, this event is also reportable pursuant to 10CFR 50.73(a)(2)(v)(C) as a condition that could have prevented fulfillment of a safety function. There were no actual, or potential consequences to the health and safety of the public as a result of this event.

I

On June 19, 2017 following a planned High Pressure Coolant Injection (HPCI) system maintenance, a HPCI start attempt was performed per the quarterly test procedure. HPCI failed to start during the test due to the steam stop valve HO-7 not opening caused by HO-7 oil relay not functioning properly.

Since the component was not the subject of the maintenance activity, the HPCI failure was reported to the NRC under Emergency Notification System, Event Number 52814.

The HO-7 oil relay was repaired and the HPCI system was returned to operable status at 13:30 on June 23, 2017.

On February 11, 2017, Unit 2 was in Mode 5 for a planned refueling outage. While attempting to fill and vent the Unit 2 High Pressure Core Spray (HPCS) system, no flow was observed from the drywell vent valves or downstream of the HPCS injection valve. The HPCS system was already inoperable to support scheduled surveillances performed on February 8, 2017 in which the HPCS injection isolation valve had been cycled five times satisfactorily. Troubleshooting determined the cause of the valve malfunction was due to stem-disc separation. The valve internal components were replaced prior to restart of the unit from the refueling outage. The root cause of the valve failure was insufficient capacity of the shrink-fit stem collar, combined with multiple high-load cycles, which resulted in loosening and eventual shear failure of the wedge pin and threads.

This component failure is reported in accordance with 10 CFR 50.73(a)(2)(v)(D) as an event or condition that could have prevented fulfillment of the safety function of structures or system that are needed to mitigate the consequences of an accident. This condition could have prevented the HPCS system, a single train safety system, from performing its design function if the valve failure occurred during an actual demand. This component failure is also reported in accordance with 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by Technical Specifications (TS) 3.5.1 "ECCS - Operating," since the HPCS system could have been 1 inoperable for greater than the TS 3.5.1, Required Action B.2, Completion Time of 14 days to restore HPCS system to operable status. There were minimal safety consequences associated with the condition since HPCS was not required to be operable at the time of the failure, and other required emergency safety systems remained operable. There were no actual demands for Unit 2 LHPCS, other ECCS systems, or the reactor core isolation cooling (RCIC) system during this period.

- --- ------- - NRC FORM 366 (04-2017) - 01 003 2017

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

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

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

On March 27, 2017, at 1825 (EDT), with the reactor at 100 percent core thermal power and steady state conditions, plant personnel caused a High Pressure Coolant Injection (HPCI) System isolation. Pilgrim Nuclear Power Station was performing planned testing on the Reactor Core Isolation Cooling (RCIC) when the HPCI System isolated. Accordingly, the HPCI System was declared inoperable.

The Technical Specifications Limiting Condition for Operation 'Action Statement 3.5.C.2 was entered and planned troubleshooting into the cause of the HPCI isolation was started. This event is reportable under 10 CFR 50.73(a)(2)(v)(D), 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.

There was no impact to public health and safety from this condition.

On February 23, 2017, radiography results for the Browns Ferry Nuclear Plant (BFN), Unit 2, Reactor Core Isolation Cooling (RCIC) system stop check valve, 2-HCV-071-0014 (71-14 valve), showed the valve to be in the fully open position.

In this position, the valve was incapable of performing its design function as a Primary Containment Isolation Valve (PCIV).

In order to isolate the affected primary containment penetration flowpath, the RCIC Steam Line Outboard Isolation Valve was closed and deactivated to secure flow through the adjacent PCIV check valve in the exhaust line in accordance with plant Technical Specifications (TS) Limiting Conditions for Operation (LCO) for Primary Containment Isolation.

It is assumed in the Past Operability Evaluation (POE) that the 71-14 valve had been inoperable from April 2015 to February 2017, in violation of TS LCO 3.6.1.3. During this time period, another check valve (upstream of the 71-14 valve) remained capable of isolating the affected penetration. The 71-14 valve was repaired during the BFN, Unit 2, Cycle 19 Refueling Outage which began on February 25, 2017.

The cause of this condition was determined to be inadequate minimum allowable internal clearances for the 71-14 valve.

The 71-14 valve internals were machined to minimum allowable material as an interim action to mitigate risks. The corrective action to prevent recurrence is to replace the 71-14 valve with a new valve design that is not susceptible to the same internal binding potential.

On February 8, 2017, at 1151 EST with Unit 1 at approximately 100 percent rated thermal power, the High Pressure Coolant Injection (HPCI) suction and discharge pressure indicators were noted to be downscale during a main control room panel walk down. Upon further investigation, it was discovered that the output voltage of the DC to AC inverter was degraded. The HPCI DC to AC inverter supplies power to the HPCI flow controller and power supply. HPCI was therefore declared inoperable due to the degraded voltage condition.

The inoperable as found condition of the HPCI pressure indicators was due to degraded output voltage from the DC to AC HPCI inverter. The degraded inverter was removed and replaced and HPCI was returned to operable status. As part of an extent of condition review, the internals of the degraded inverter were inspected to determine what caused premature failure of the inverter. Based on the findings of this inspection, the preventative maintenance frequency for inverter replacement and calibration will be adjusted as necessary.

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 November 8, 2016 at 11:27 hours, Cooper Nuclear Station (CNS) declared Reactor Core Isolation Cooling (RCIC) inoperable for surveillance testing and entered Technical Specification (TS) Limiting Condition for Operation (LCO) 3.5.3, Condition A. Subsequently at 11:41 hours, RCIC was declared inoperable due to a water leak from the lube oiler cooler lower flange.

During investigation it was determined that valve RCIC-AOV-PCV23, which was replaced during Refueling Outage 29, was full open causing excessive cooling water pressure to the lube oil cooler. This valve regulates cooling water to the lube oil cooler. Initial examination revealed that the actuator was purchased with a closed travel stop instead of the required open travel stop. The work order was revised to fabricate and install an open travel stop. On November 10, 2016, following valve modification, RCIC passed surveillance testing, was declared operable, and TS LCO 3.5.3, Condition A, exited.

The root cause evaluation determined that the correct air operated valve was not purchased because the material master purchase order text and associated drawing didn't detail the requirement of an open travel stop.

To prevent recurrence, CNS will revise the material master purchase order text to state that the valve includes a travel stop in the open direction to limit valve travel. In addition, the drawing will be modified to show the correct travel stop with a note emphasizing the design function of the travel stop.

On September 24, 2016, at 20:40 hours, during reactor cooldown for Refueling Outage 29, Cooper Nuclear Station control room operators closed the inboard Main Steam Isolation Valves (MSIV) to minimize steam flow to control the reactor cooldown rate. Reactor pressure was controlled using the Main Steam Line Drains; and the condensate/feed system was available for reactor water level control.

On September 25, 2016, at 01:03 hours, while equalizing pressure across the MSIVs to below 200 psid, a differential pressure of 190 psid was established. Upon opening MS-AO-80A, a Group 1 isolation was immediately received due to a Main Steam Line high flow signal. The control room operators subsequently equalized pressure and successfully opened MS-AO-80A, as well as the remaining MSIVs, at 18:52 hours.

The cause of the event was insufficient procedure guidance exists regarding limitations on opening the MSIVs. To correct this, the applicable procedure has been revised to change the differential pressure limitations for opening MSIVs from 200 psid to 80 psid.

The safety significance of the event is low and did not pose a threat to the health and safety of the public.

On March 19, 2016, at approximately 1024 Central Daylight Time (CDT), the Unit 2 High Pressure Coolant Injection System (HPCI) Steam Admission Valve failed to stroke due to a stuck contactor in the valve motor breaker. This rendered the Unit 2 HPCI inoperable, resulting in a Safety System Functional Failure; however the system had previously been declared inoperable for maintenance and the Unit 2 Reactor Core Isolation Cooling System had been verified as operable in accordance with Technical Specifications Limiting Conditions for Operation 3.5.1. On March 20, 2016, at approximately 1103 CDT, Maintenance personnel commenced work to repair the Unit 2 HPCI steam admission valve motor breaker. On March 21, 2016, at approximately 0245 CDT, Unit 2 HPCI was declared operable following completion of all required PMTS.

The cause of the stuck contactor was accelerated cyclic fatigue due to overheating of the motor starter during packing consolidation and MOVATS testing. Corrective actions were to replace the stuck contactor, to clean contactors in similar HPCI valve motor breakers for Units 1 and 3, to determine an allowable maximum number of valve cycles within a given time period , and to revise plant procedures based on the determined cycle limit in order to prevent contactors from sticking due to accelerated cyclic fatigue.

Subsequent review determined the identified condition to be reportable.

During a surveillance test on June 8, 2016, the BFN, Unit 3, High Pressure Coolant Injection (HPCI) Turbine Stop Valve Mechanical Trip Valve behaved erratically upon turbine start. Troubleshooting and maintenance on the valve led to discovery of a condition that could have resulted in the HPCI system being unable to perform its required safety function in a Mode where HPCI Operability was required.

The inoperability was caused by the HPCI Turbine Stop Valve Mechanical Trip Valve's Reset Spring, which was deformed and weakened from years of continuous compression. The spring was replaced and the system was returned to service on June 10, 2016.

Corrective actions to prevent recurrence include revising preventive maintenance procedures to specify replacement of the Trip Tappet, Piston, and Reset Spring on a defined periodicity. Additionally, procedures will be revised to require testing the as-left breakaway force a minimum of three times to ensure repeatability.

Preventative maintenance procedures will also be revised to clarify that lift force checks after spring compression adjustments shall be conducted with the auxiliary oil pump running.

On April 26, 2016, it was noted that the green off light for High Pressure Coolant Injection (HPCI) auxiliary lube oil pump (ALOP) in the Control Room, was not illuminated. A non-licensed operator was dispatched to the HPCI ALOP starter and reported the green bulb appeared to have shattered in the socket. HPCI was declared inoperable at 1754 Central Daylight Time (CDT) resulting in entry into Technical Specifications Limiting Condition of Operation 3.5.1, Condition C, HPCI System Inoperable.

Investigation found the 125 volts direct current fuse open circuited and the local indication green light and socket were damaged. The cause of the failure was determined to be a lack of engineering knowledge which led to a design change in 1984 in the HPCI ALOP starter circuitry that diminished the robustness of the circuit with respect to a specific failure modality; direct short circuiting within the indication bulb itself. The HPCI system was restored to operable status on April 28, 2016, at 1245 CDT.

This event is being reported as a loss of safety function due to HPCI being a single-train safety system.

The potential safety consequences of this event were minimal due to the limited duration the condition existed and the redundant/diverse core cooling systems which remained operable.

3. LER NUMBER 2. DOCKET NUMBER 05000- 298 Cooper Nuclear Station 2016 - 002 - 00