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On November 3, 2017, at 2022 hours, with reactor power at 100 percent, Indian Point Unit 3 experienced an automatic reactor trip on a turbine trip, which was in response to a main generator trip. The main generator trip was initiated by actuation of the Generator Protection System due to a main generator loss of field.

All control rods fully inserted and all required safety systems functioned properly. The plant was stabilized in hot standby with decay heat being removed by the main condenser. The Auxiliary Feedwater System (AFWS) automatically started as expected on steam generator low level to provide feedwater flow to the steam generators. The plant was stabilized in hot standby with decay heat being removed by the main condenser. The direct cause of the loss of main generator field was a failed Thyristor Firing Module drawer which affected proper operation of the redundant Thyristor Firing Module drawer. The root cause was determined to be that the Automatic Voltage Regulator (AVR) Firing Module power supplies have a latent design vulnerability where shared common output nodes are not isolated after a failure. A plant modification is proposed that will eliminate the condition by electrically isolating the AVR Firing Module power supplies upon failure.

This event had no effect on the public health and safety. The event was reported to the Nuclear Regulatory Commission (NRC) on November 3, 2017 under 10 CFR 50.72(b)(2)(iv)(B) and 50.72(b)(3)(iv)(A) as an event that resulted in the automatic actuation of the Reactor Protection System when the reactor is critical and a valid actuation of the AFWS.

On September 6, 2017 at 1157, Nine Mile Point Unit 1 experienced an 'automatic reactor scram due to reactor vessel low water level. The automatic Reactor Protection System (RPS) actuation and reactor scram is reportable per 10 CFR 50.72 (b)(2)(iv)(B) and 10 CFR 50.73(a)(2)(iv)(A) as any event or condition that resulted in a manual or automatic actuation of any of the systems listed in 10 CFR 50.73(a)(2)(iv)(B). Following the automatic scram all plant systems responded per design including High Pressure Coolant Injection (HPCI) System automatic initiation.

HPCI is a flow control mode of the normal feedwater systems, and is not an Emergency Core Cooling System.

The root cause of the scram was a failed power supply within the Proportional Amplifier, PAM-ID23E. This power supply failure resulted in the output from the module dropping out causing the #13 Feedwater Pump Flow Control Valve to close. The corrective action taken was the replacement of the failed Feedwater Level Control module, PAM- ID23E.

On July 3, 2017, at approximately 10:15 AM following a grid disturbance, a manual scram was inserted due to degrading main condenser vacuum because of an improper configuration of the Augmented Off-gas (AOG) System.

The loss of main condenser vacuum resulted when Operations personnel failed to execute procedural requirement to align the AOG system into a shutdown lineup. The loss of vacuum was caused by degraded Steam Jet Air Ejectors (SJAE) performance due to a blocked discharge path.

The AOG system tripped 11 hours earlier following a grid disturbance. During the trip, operations personnel failed to re-align the AOG treatment system to a shutdown lineup resulting in the AOG Flame Arrestor siphoning into the inlet piping which filled the lower section of the off-gas hold up line with water.

On February 17, 2017, at 2353 CST, during Unit 1 power ascension from a previous forced shutdown, operators inserted a manual scram as a result of a high reactor water level condition caused by a rapid change in feedwater flow. The high reactor water level trip occurred due to a failure of the feedwater regulating valve (FRV) 1FW005 positioner arm, which caused the regulating valve to be driven to the full open position. This resulted in a rapid increase of reactor water level that required operators to perform a manual reactor scram. The plant was placed in a stable condition, with no complications in achieving shutdown.

This event is reportable in accordance with 10 CFR 50.73(a)(2)(iv)(A) as an event or condition that resulted in manual or automatic actuation of the reactor protection system (RPS). The safety significance of this condition was minimal, as plant equipment responded as expected for the event. The feedback drive arm and new positioner were installed on the Unit 1 FRV, which allowed the unit to restart following repairs. The FRV positioner feedback assembly had been installed in 2002, during a modification to upgrade of the air-operated valve assembly. This design has proven not to be robust enough for the FRV application.

On September 21, 2016, at 0142 Mountain Standard Time (MST), containment isolation valve SGA-UV-1134 failed to stroke closed from the control room during containment isolation valve testing. The failure resulted in an unplanned entry into Technical Specification Limiting Condition of Operation (LCO) 3.6.3, Containment Isolation Valves. On September 22, 2016, it was concluded the valve was in a configuration that rendered the pneumatic operator incapable of operating the valve, including remote operation and automatic closure in the event of a main steam isolation system signal. The valve had been in this configuration since last operated on June 28, 2016. Therefore, the valve was inoperable longer than the required 4-hour completion time of LCO 3.6.3 Condition C. On September 22, 2016, at 1457 MST, SGA-UV-1134 was properly closed, declared operable, and LCO 3.6.3 was exited.

This event was caused by human error when procedural guidance was not used to return SGA-UV-1134 to its neutral locked configuration following testing on June 28, 2016. Actions have been initiated to ensure proper procedural guidance is used to lock SGA-UV-1134 in the future.

On June, 26, 2015, LER 50-530/2015-002 reported a condition prohibited by LCO 3.0.4 that occurred on May 1, 2015, when Unit 3 entered Modes 4 and 3 while in the applicability of LCO 3.7.4. On May 2, 2015, automatic dump valve, SGB- HV-178, was stroked with steam while in Mode 3 and discovered to be inoperable due to human error incurred during post- maintenance assembly prior to entering Mode 4.

On July 6, 2016, with the Donald C. Cook Nuclear Plant Unit 2 Reactor operating in Mode 1 at 100 percent power, the control room received a report of a steam leak on the Unit 2 B Right Moisture Separator Reheater (MSR)

• crossover piping and damage to the turbine building structure. This information resulted in a decision by the crew to manually trip the Unit 2 Reactor at 0038. The cause of the steam leak was the sudden failure of the balance bellows on the Unit 2 B Right MSR crossover expansion joint, which also resulted in damage to the west wall of the turbine building.

The Root Cause was determined to be an organizational failure to recognize the risk significance of, and to adequately correct or mitigate, previously identified vibration issues with the Unit 2 B Right MSR crossover expansion joint tie rod and bellows in a timely fashion.

This event is being reported in accordance with 10CFR 50.73(a)(2)(iv)(A) as a manual actuation of the Reactor Protection System and an automatic actuation of the Auxiliary Feedwater system.

On 5/16/2016 at approximately 1120 CDT during planned maintenance on Division II of the Low Pressure Coolant Injection (LPCI) system, a through-wall steam leak was observed in the Unit 2 High Pressure Coolant Injection (HPCI) inlet drain pot drain piping. The leak was identified to be on the Inlet Drain Pot line leading to the Main Condenser upstream of the HPCI Inlet Drain Pot 2A Inboard Drain Valve, Air Operated Valve (AOV) 2-2301-29, which is ASME Code Class 2 piping. The cause of the through-wall leak was liquid droplet impingement erosion thinning of chrome moly piping. HPCI was declared inoperable following isolation of the degraded piping per Technical Requirements Manual (TRM) 3.4.a. This event is of low safety significance.

Corrective Actions included replacing the piping with stainless steel, ensuring similar sections of piping are replaced or scheduled for replacement, and reviewing Extent of Condition.

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.

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 February 8, 2016, at 1503 hours, control room operators initiated a manual reactor protection system (RPS) actuation in response to rising temperature in the suppression pool. All control rods full inserted. Prior to the RPS actuation the plant was in mode 1 at approximately 96 percent rated thermal power. At 1500 hours, multiple safety relief valves (SRVs) partially opened due to an invalid reactor pressure vessel (RPV) pressure signal. Control room indications showed two SRVs remained open resulting in a suppression pool temperature rise. Suppression pool cooling was initiated and a plant cooldown to Mode 4 was initiated.

The direct cause of the event was a momentary pressure perturbation limited to the RPV B reference leg that caused the connected transmitters to sense RPV pressure and level changes that resulted in SRV actuation. Corrective actions include revision to plant procedures for operation of the RPV reference legs and associated purge panels, and changes to the time constants for the affected RPV transmitters.

The safety significance of this event is considered to be very 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 a manual actuation of the RPS.

On December 5, 2015, control room operators initiated a manual reactor trip (RT) after observing indications consistent with multiple dropped control rods (CR) following an alarm for the trip of Motor Control Center (MCC)-24/24A. No Control Rod indication was available due to MCC-24 being de-energized. All primary safety systems functioned properly except the primary rod control cabinet power supply (PS1) which was in a degraded condition prior to the event and failed to function as required. The plant was stabilized in hot standby. There was no radiation release. The Auxiliary FW system automatically started as designed. The direct cause of the event was loss of MCC-24 due to an internal fault at the line side leads at cubicle 2H where they connect to the bucket stab assemblies (load side fault). This caused the supply breaker feed to open per design and clear the fault. The de-energization of MCC-24 removed the functioning backup Control Rod (CR) power supply and the remaining degraded primary power supply failed to function as required. The apparent cause was an unanticipated loss of power to the CR system due to the degradation of the primary CR power supply (PS1) which failed to function when the operating power supply (PS2) was lost. MCC-24/24A was lost due to a design error that allowed the positioning of a mounting plate too'close and obstructing the line side wiring resulting in contact. Vibration over time resulted in degraded wiring insulation which eventually shorted. Corrective actions included inspection and testing of the MCC-24 bus and control wiring. The degraded Rod Contrl power supply (PS1) was replaced. Maintenance procedures will be revised to provide more in-depth inspection criteria. The event had no effect on public health and safety.

FACILITY NAME (1) PAGE (3) DOCKET (2) LER NUMBER (6)

On April 23, 2015, at 0210, Donald C. Cook Nuclear Plant Unit 2 Reactor was manually tripped from approximately 2 percent of rated thermal power during plant restart following a refueling outage. Unit 2 Reactor was manually tripped due to the inability to maintain Average Reactor Coolant System Temperature above the Technical Specification (TS) required minimum Temperature for Criticality when two newly installed Steam Dump Valves failed open while being manually valved into service. The valves were subjected to, but not designed for, two phase flow.

The Root Cause has been determined to be that the modification process failed to identify and document all system operational vulnerabilities. The corrective action to preclude repetition is an enhancement of the Engineering Modifications procedure to require development and inclusion of a narrative to describe system operation, including key interfacing system operation.

The manual Reactor Protection System (RPS) actuation was reported via Event Notification 51004 in accordance with 10 CFR 50.72(b)(2)(iv)(B) and 10 CFR 50.72(b)(3)(iv)(A), and 10 CFR 50.72(b)(2)(i). The valid RPS actuation and the completion of the plant shutdown required by TS are reportable as a Licensee Event Report in accordance with (- 10 CFR 50.73(a)(2)(iv)(A) and 10 CFR 50.73(a)(2)(i)(A) respectively.

On July 21, 2015 at 05:05, with Unit 1 at Hot Shutdown and Unit 2 at approximately 6% power, Unit 2 experienced a reactor trip initiated from a turbine trip during performance of the Turbine Overspeed Protection Control system circuitry testing. The turbine trip was caused by governor valves rapidly opening due to a speed error which had accumulated between the turbine speed and reference setpoint resulting in a rapid increase in impulse pressure. The root cause of this event was inadequate instructions in the Overspeed Protection Control testing section of the operating procedure. The testing will be removed from operating procedures and placed in test procedures that are not performed as part of routine turbine startup.

All systems functioned as required. Initiation of auxiliary or emergency systems was not required. Unit 2 was placed in hot shutdown and the health and safety of the public were not affected.

This report is being submitted pursuant to 10CFR50.73(a)(2)(iv)(A) as an event that resulted in the automatic actuation of the Reactor Protection System.

On May 1, 2015, following completion of refueling activities, PVNGS Unit 3 entered Mode 4 and continued to Mode 3 in preparation for plant startup. On May 2, 2015, when plant conditions needed to test atmospheric dump valves (ADV) with steam were achieved, testing of ADVs was initiated. At 1739 on May 2, 2015, testing determined that ADV SGB-HV-178 (ADV-178) would not stroke more than approximately 13 percent open. Operations personnel declared ADV-178 inoperable and entered Technical Specification Limiting Condition of Operation (LCO) 3.7.4, Atmospheric Dump Valves, Condition A. An investigation determined ADV-178 was inoperable when Unit 3 entered Mode 4.

Inspection of ADV-178 determined internal sealing rings were improperly installed during maintenance performed in the refueling outage. The valve was repaired and tested and declared operable at 0853 on May 7, 2015. The causes of the event were human error by maintenance personnel and inadequacies with the procedure used to perform the valve maintenance. Corrective actions will revise work instructions to provide detailed guidance for valve re- assembly and to require verifications of proper re-assembly.

A similar event was reported in LER 50-529/2012-003-00 which resulted when testing in Mode 3 following refueling activities identified an inoperable steam supply valve for the steam driven auxiliary feedwater pump.

On April 10, 2015, at 2100 hours, a planned shutdown for the Susquehanna Unit 2 refueling outage commenced. With shutdown in progress and at approximately 37% power for balance of plant operations, a pre-job brief was conducted in preparation for placing an Auxiliary Boiler in service and placing the Main Turbine Steam Seals on Auxiliary Steam.

At 2129 hours, the 'A' Auxiliary Boiler was placed in service per procedure OP-027-001, "Aux Boiler System," and the Main Turbine Steam Seals were placed on auxiliary steam via valve 221008, "SJAE and Steam Seal Aux Supply !so Vlv." At approximately 2330 hours, the procedure was resumed which directed closure of valve 221008 when Auxiliary Boiler temporary load is no longer needed. At this point, temporary load was no longer needed but auxiliary steam was still flowing through valve 221008, supplying steam to the Unit 2 Main Turbine Steam Seals. The valve was subsquenty closed, which isolated steam to the U2 Main Turbine Steam Seals, allowing air in-leakage into the Main Condenser, causing condenser vacuum to degrade. At 2346 hours, Unit 2 automatically scrammed from approximately 37 percent power due to a the Main Turbine trip on loss of condenser vacuum.

Root Cause: Personnel involved with auxiliary boiler startup did not adhere to Operator Fundamentals and effectively apply appropriate Human Performance error-reduction tools specific to understanding and anticipating the impact of component operation prior to its operation. Completed Action: Procedure OP-027-001, "Auxiliary Boiler System," was revised to caution operators of the potential for isolating auxiliary steam to the Main steam seals and/or Steam Jet Air Ejectors when securing temporary loading of the auxiliary boilers. Key Planned Action: Provide initial licensed and non-licensed operator classroom and job performance measure or dynamic learning activity training with focus on: STAR, Questioning Attitude, Pre job Brief, and understand and anticipate the impact of component operation prior to its operation. Safety Significance: There were no actual consequences to the health and safety of the public as a result of this event.

On February 27, 2015, during the performance of surveillance procedure 3-PT-R006A, three main steam safety valves (MSSV) (MS-46-2, MS-45-4 and MS-47-4) failed their As-Found lift.

set point test. Per the test, these valves must lift at +/- 30 of their required setting.

During the test, 7 other MSSVs tested passed their As-Found test criteria.

Technical Specification (TS) 3.7.1 (Main Steam Safety Valves) requires the MSSVs to be operable in accordance with TS Table 3.7.1-1 and Table 3.7.1-2.

Due to the number of failures, during power ascension the remaining MSSVs were tested and two failed (MS-46-2, MS-46-3).

MSSV MS-46-2 had previously failed and had maintenance performed therefore the failure was considered a post maintenance test failure.

MS-46-3 failed its first lift test by 0.60 but met test lift criteria on the second and third test.

TS Surveillance Requirement (SR) 3.7.1.1 requires each MSSV be verified to lift per Table 3.7.1-2 in accordance with the In-service Testing Program. Operability of the MSSVs includes the ability to open within the set point tolerances. The direct cause of the failure of these valves was severely worn spindle rods.

The apparent cause for the failure of MS-47-4 and MS-46-2 was internal friction due to spindle vibration.

The apparent cause of the failure of.MS-45-4 was reuse of a worn spindle. The apparent cause of the failure of MS-46-3 is foreign material.

Corrective actions included testing all 20 MSSVs and adjusting their set point to be within +/- 1% of design set pressure. Installed new spindles and bronze wear sleeves on valves MS-46-4, MS-46-2, MS-47-4, MS-48-2, MS-49-2, MS-49-1, MS-49-3, and replaced the spindle on valve MS-45-4. The Unit 3 MSSV test frequency will be changed from 4 years to 2 years until all modifications are implemented and IPEC is confident the issue is resolved. The event had no effect on public health and safety.

FACILITY NAME (1) DOCKET (2) LER NUMBER (6) PAGE (3)