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On June 23, 2015, Nine Mile Point Unit 2 identified two separate instances where the isolation capability for the Reactor Vessel Low Water Level (Level 2) primary containment isolation valves on both divisions was not maintained during performance of surveillance testing. The events occurred on April 22, 2015, and May 5, 2015.

This event is reportable under 10 CFR 50.73 (a)(2)(v)(C) as an event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to control the release of radioactive material. The Surveillance testing on both dates was for valves powered by one division. To prevent an inadvertent full isolation signal from occurring, during the testing on the division, the power supply breakers for the division valves were opened while they were being tested.

The event described in this LER is documented in the station's corrective action program as 182518177. There are no similar event reports.

On January 12, 2015 at 1939, Nine Mile Point Unit 2 declared secondary containment inoperable due to secondary containment vacuum decreasing below the technical specification limit. The condition is reportable under 10 CFR 50.72 (b)(3)(v)(C) and 10 CFR 50.73(a)(2)(v)(C) as any event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to control the release of radioactive material. The change in secondary containment vacuum was the result of sustained high winds.

Secondary containment was declared operable at 1956 when secondary containment vacuum was restored to greater than 0.25 inches of vacuum water gauge. The apparent cause evaluation identified inadequate system balancing and failure to adjust the inlet damper after filter bag removal for seasonal readiness which allowed a volume increase that was beyond the control capability of the pressure control dampers during a high wind event.

Corrective actions taken include adjusting Reactor Building intake dampers to lower supply fan flow to bring recirculation motor operated dampers into their control range and to adjust other system lineups until the dampers begin to modulate.

The event described in this LER is documented in the plant's corrective action program as IR# 2436393. NMP2

(NMP2) Reactor Building was breached when workers opened both inner and outer airlock doors, R261-1 and R261-2, simultaneously while passing through. The integrity of the airlock was re-established within 4 to 5 seconds when one of the doors was closed and latched. A second opening of both airlock doors occurred at 1140 that same day. Secondary containment differential pressure never exceeded the minimum Technical Specification limit of 0.25 inch of vacuum water gauge. These events are significant in that the secondary containment was momentarily breached during replacement of the Reactor Recirculation Pump "B" seal, an activity which had the potential for draining the reactor vessel (OPDRV).

The causal analysis identified that workers did not use their human performance verification tools to ensure the opposing outer door of the airlock was closed prior to opening the inner door. Corrective actions taken include coaching and counseling for workers involved in the event on the importance of applying their human performance tools of self-checking and peer-checking when passing through secondary containment doors. A previous LER submitted on a similar event could not be identified.

On March 12, 2014, at 1422 Nine Mile Point Unit 2, declared the secondary containment inoperable due to the secondary containment experiencing a positive differential pressure (dP) condition. This condition is reportable under 10 CFR 50.72 (b)(3)(v)(C) and 10 CFR 50.73(a)(2)(v)(C) as any event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to control the release of radioactive material. The positive dP was the result of sustained high winds from the northeast associated with Winter Storm Vulcan. The reactor building was isolated at 1630 and secondary containment declared operable at 1700 when secondary containment vacuum was restored to greater than 0.25 inches of vacuum water gauge.

The causal evaluation identified that procedural guidance does not provide operators the direction to place the Standby Gas Treatment System in service and/or isolate the Reactor Building to maintain a negative pressure in the secondary containment prior to exceeding the Technical Specification (TS) limit for secondary containment dP. Corrective actions taken or planned include revising a plant procedure to provide direction to initiate the Standby Gas Treatment System and isolate the Reactor Building during high wind conditions prior to exceeding the TS limit for secondary containment dP. The event described in this LER is documented in the plant's corrective action program as CR-2014-002028. NMP2 LER 2013-005 reported similar events.

On February 16, 2014 at 1216, Nine Mile Point Unit 2 (NMP2) was operating at 100 percent power when an automatic actuation of the Division I and III Emergency Diesel Generators (EDG) occurred due to a loss of a 345 kV bus owned by National Grid. The bus outage resulted in the loss of off-site power source (Line 5) owned by Exelon. Automatic actuation of the EDGs is reportable under 10 CFR 50.72(b)(3)(iv)(A) and 10 CFR 50.73(a)(2)(iv)(A). The cause of the loss of Line 5 is due to a faulted current transformer associated with 345kV Breaker R210 owned by National Grid, the transmission owner. The faulted transformer caused a voltage transient for both station service and offsite power loads. This resulted in the loss of: 1) the service water radiation monitor and radwaste/reactor building vent gaseous effluent monitoring systems 2) the 'C' and 'D' Reactor Water Cleanup (WCS) filter strings, and 3) spent fuel pool cooling. The voltage transient also caused Feed Water level control valve actuator controls to lock up and go to manual operation. The causal analysis identified the failure mechanism of the CT as an insulation breakdown internal to the CT.

The corrective actions include purchasing spare CTs and performing follow up tests and repairs on damaged equipment. NMP1 LER 2008-001 and NMP2 LER 2012-004 are similar LERs submitted previously which involve the actuation of the EDGs due to a loss of Power Line 5.

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 February 28, 2013 at 1319, Nine Mile Point Unit 2 was operating at 100 percent power when the High Pressure Core Spray (HPCS) system pressure pump failed. At the time of the failure, the HPCS system was inoperable for planned maintenance. The HPCS system pressure pump failure was due to an electrical short caused by a turn-to-turn failure in the motor.

The cause of this event was determined to be a turn-to-turn short in the motor winding, attributed to poor manufacturer quality of the original motor.

Corrective actions include replacement of the failed motor with a rewound motor and development of a new replacement strategy for these types of motors.

This event is reportable in accordance with 10 CFR 50.73(a)(2)(v)(D), as any event or condition that at the time of discovery could have prevented the fulfillment of the safety function of structures or systems that are needed to mitigate the consequences of an accident. This report constitutes a 10 CFR 21 (Part 21) notification because the motor failure that initiated the event is attributed to a manufacturing deficiency.

There are no previous LERs similar to this event.

On October 23, 2011, at 09:15, Nine Mile Point Unit 2 (NMP2) was operating at 100 percent of rated thermal power when the Division I reactor water cleanup system (RWCU) differential flow - high channel was declared inoperable due to failing its channel check. A troubleshooting plan was developed to determine the cause for the failed channel check.

While performing the troubleshooting plan, at three separate times (October 24, 2011 at 01:52, 02:58, and 05:19), both the Division I and Division II RWCU differential flow timers were placed in bypass, and Technical Specification (TS) 3.3.6.1, Condition B was entered for one or more automatic functions with isolation capability not maintained. In each of the three instances, one channel of the RWCU differential flow - high function was restored to operable status within 1 hour as required by TS 3.3.6.1 Required Action B.1. In the morning of October 24, 2012 the oncoming crew recognized that bypassing both RWCU differential flow timers in this manner could have prevented the fulfillment of a safety function.

The cause of this event was human performance error. The operating crew became focused on the completion time associated with the LCO condition and never fully evaluated the Technical Specification Bases.

The crew involved in this event has been coached. An Operations department communication has been sent as a result of this event which reinforced the requirements of TS 3.0.2 Bases and the importance of an operating crew to use all available information with the Shift Manager as the single point of accountability. The RWCU system operating procedure has been revised to clarify the reportability requirements when removing both divisions of the RWCU high differential flow isolation from service. A training needs assessment has been initiated to determine if additional training is needed on TS Bases.

At 0152 on August 6, 2011, the containment gaseous radiation monitors went into alarm and it was identified that Reactor Coolant System (RCS) unidentified leakage was increasing. At 0205, a Technical Specifications Condition was entered for RCS unidentified leakage increase above the specified limit. The RCS unidentified leakage peaked at 11.35 gpm, which resulted in an Unusual Event being declared due to reaching an Emergency Action Level (unidentified leakage greater than 10 gpm). At 0227, commenced lowering reactor power. Reactor power was reduced to 20% and, at 0941, the Reactor Protection System was manually actuated by placing the reactor mode switch in the Shutdown position. The unidentified leakage was due to a packing leak from the "A" RCS pump discharge blocking valve. The cause of the packing leak was determined to be vibration/turbulent flow that caused packing relaxation and failure. The valve packing was replaced, torqued and the gland follower nuts were secured in place. The packing for other similar valves was re- torqued and the gland follower nuts were secured in place.

A Preventive Maintenance Surveillance Test (PMST) activity will be created to re-torque the packing for RCS pump blocking valves every two years. Additionally, a modification will be implemented to install a live loading design on the RCS pump blocking valves in an upcoming outage.

There have been two other similar LERs involving RCS valve packing leakage: Nine Mile Point Unit 1 LER-2006-001 and Nine Mile Point Unit 2 LER-2001-007.

On May 26, 2006, Nine Mile Point Nuclear Station (NMPNS) determined that an unanalyzed condition had existed on February 8, 2006, due to potential water hammer impacts in the Nine Mile Point Unit 2 (NMP2) Reactor Core Isolation Cooling (RCIC) system. During planned maintenance, the RCIC system was declared inoperable but available for automatic and manual start with the RCIC turbine steam exhaust piping vacuum breakers isolated.

Under worst case conditions, if RCIC was manually or automatically started with the exhaust piping vacuum breakers isolated, the configuration may result in water hammer related stresses significantly above allowables. Under such conditions, there is an increased likelihood that primary containment boundary piping could be breached and other systems affected.

The root cause of this condition has been attributed to the failure of original design change process to provide cautions in procedures and adequate training regarding the RCIC vacuum breaker function when the vacuum breakers were installed prior to NMP2 initial start-up.

To prevent recurrence, key plant procedures have been revised to ensure the RCIC system will not be placed in the same or similar configurations as described in this report. Additional actions to prevent recurrence include implementing staff training with regard to potential water hammer events and improvements in evaluating and applying industry operating experience.

On March 20, 2017 at 02:27, Nine Mile Point Unit 1 performed a manual scram of the reactor due to pressure oscillations.

This event is reportable under 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).

The Unit was offline and reactor shutdown was in-progress at the time of the scram. The cause of the scram was manual scram. The scram was required at approximately 4% reactor power when pressure oscillations occurred exceeding the procedurally required limit. The apparent cause of this event was Mechanical Pressure Regulator (MPR) oscillations caused by a combination of the fouling of the MPR's pressure sensing bellows line and a bypass relay linkage passing through a worn bushing which created a friction induced sticktion of the linkage.

The event described in this LER is documented in the plant's corrective action program.

On Thursday July 28, 2016, at approximately 2357 hours with power level at approximately 100 percent, Nine Mile Point Unit 1 (NMP1) experienced a loss of Uninterruptible Power Supply (UPS), UPS 162B which resulted in loss of Reactor Protection System (RPS) Bus 11. Numerous half scram and half isolation signals were generated in addition to the isolation of both # 11 and # 12 Emergency Condensers (ECs).

EC # 12 was returned to standby on 7/29/2016 at 0041 hours and EC # 11 was returned to standby on 7/29/2016 at 0045 hours. The causes of this event were the failure of a UPS capacitor and the bypass power transfer set point being set too low for the type of transient. Corrective actions include immediate replacement of the failed capacitor, installation of new higher temperature rated capacitors and adjusting the low voltage bypass power transfer set point.

This event is reportable under 10CFR50.73(a)(2)(v)(B).

On Friday September 4th, 2015 at 09:16:04, Nine Mile Point Unit 1 automatically scrammed from approximately 100% rated power due to an inadvertent Main Steam Isolation Valve (MSIV) isolation. This event is reportable under 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). During quarterly surveillance testing, the MSIV failed to stop its close stroke and reopen automatically per design, due to a failed MSIV pilot test valve. The root cause of the event was an inadequate application of the designed pilot test valve for MSIV control, resulting in the pilot test valve internals binding during the surveillance test. The failed pilot valve spool and cage assembly were replaced.

The corrective action to prevent recurrence is to replace the MSIV pilot valveS with an industry proven design.

The event described in this LER is documented in the plant's corrective action program.

On May 8, 2014, at 1645, the results of an industry operating experience (OE) extent of condition review identified that an un-fused control circuit associated with the Unit 1 Reactor Water Cleanup Isolation Valve 12 could short circuit due to a fire in the circuit cable routing. This short circuit could cause the cable to self- heat and cause secondary fires along the associated cable route. The unanalyzed secondary fires could adversely affect safe shutdown equipment and potentially cause the loss of ability to safely shutdown as required by 10 CFR 50 Appendix R. The original plant wiring design and configuration for the containment isolation valve did not include separate overcurrent protection for motive power and control wiring. The only protection for control circuit wiring is by motive circuit fuses which are not sized appropriately to protect the control wiring. As a compensatory measure, Operations has initiated a fire inspection each shift to monitor the associated Fire Areas (1 and 10) until separate fuses are installed within the control circuitry of the motor operated valve (MOV). A similar event was reported in LER 2013-002.

This condition was entered into the Nine Mile Point (NMP) corrective action program as Condition Report (CR) 2014-004630.

On October 22, 2013 it was discovered that unfused ammeter indication circuits associated with the Nine Mile Point Unit 1 (NMP1) safety-related Direct Current (DC) buses could short circuit due to a fire in the circuit cable routing. This ground fault equivalent hot short could cause the cable to self-heat and lead to secondary fires. The unanalyzed secondary fires could adversely affect safe shutdown equipment and potentially cause the loss of the ability to safely shutdown as required by 10 CFR 50 Appendix R.

This event is reportable in accordance with 10 CFR 50.73(a)(2)(ii)(B) as a condition that resulted in the nuclear plant being in an unanalyzed condition that significantly degraded plant safety, and 10 CFR 50.73(a)(2)(ix)(A) as a condition that as a result of a single cause could have prevented the fulfillment of a safety function for two or more trains or channels in different systems.

The cause of this event is that the equipment design issue was not recognized as an unacceptable configuration. The design issue is associated with an evolving industry understanding of the 10 CFR 50 Appendix R common enclosure scope.

Corrective actions include the isolation of the affected circuits at the DC bus in order to prevent the condition from occurring, and the development, issuance and installation of a plant modification to install fuses on the safety-related DC ammeters at NMP I to ensure adequate circuit protection to prevent the propagation of fires in additional areas due to overcurrent conditions.

On December 13, 2012 at 16:30:10 hours, the primary containment was declared inoperable due to a primary containment leakage rate that was in excess of the Technical Specification (TS) 3.3.3.a limit. TS 3.0.1 requires that in the event Limiting Condition for Operation (LCO) requirements cannot be satisfied because of circumstances in excess of those addressed in the Specification, the unit shall be placed in a condition in which the LCO is not applicable. A normal orderly plant shutdown commenced at 16:45:00 hours and at 19:12:46 hours, a manual reactor scram was initiated from 18 percent power, in order to reduce the reactor coolant temperature to a value less than 215 degrees F within 10 hours of declaring the containment inoperable. At 23:33:00 hours, the reactor coolant temperature was below 215 degrees F.

This event is reportable in accordance with 10 CFR 50.73(a)(2)(i)(A) as a plant shutdown required by Technical Specifications, with 10 CFR 50.73(a)(2)(iv)(A) as an actuation of the high pressure coolant injection system, and with 10 CFR 50.73(a)(2)(v)(C) as a condition that could have prevented the fulfillment of a safety function of a system needed to control the release of radioactive material.

Corrective actions include cleaning the inside surfaces of drywell purge isolation valves IV-201-31 and 1V-201-32 and associated piping to remove corrosion and testing the valves to restore containment integrity and containment isolation valve operability.

On October 29, 2012 at 21:00:57 hours, Nine Mile Point Unit 1 (NMP1) experienced an unplanned, automatic, reactor scram due to a Turbine Trip from 100 percent power caused by activation of a generator lockout relay. The generator trip was an unexpected consequence and was initiated by a high fault current condition in the Scriba switchyard detected by both NMP I instantaneous ground directional overcurrent relays. A polarity wiring error within the generator step up transformer neutral ground current transformers (CTs) caused the relay protection circuits to actuate on the fault in the Scriba switchyard. This was not expected because the relay protection circuits were designed to detect a fault condition between the main generator and the station output breakers. The error was caused by less than adequate oversight by CENG personnel of transformer XF-TB01 testing with respect to unclear specificity of requirements for vendor performed testing and inadequate methods of verification for ensuring vendor compliance with engineering specifications.

This event is reportable in accordance with 10 CFR 50.73(a)(2)(iv)(A) as an actuation of the reactor protection system and an actuation of the high pressure coolant injection system while the reactor was critical.

Corrective actions include correcting the wiring of the CT circuits, verifying all the requirements in the engineering specification have been met, revising the associated electrical drawings, and revising engineering procedures to require the listing of critical attributes for equipment/components and to define testing criteria/verification methods to be performed when factory acceptance testing or modification functional testing cannot be performed to verify the functionality of equipment/components.

On July 17, 2012, at 1118, Nine Mile Point Unit 1 (NMP1) experienced an automatic reactor scram on high neutron flux due to a failure of the Electronic Pressure Regulator (EPR). Following the reactor scram, the High Pressure Coolant Injection (I-IPCI) system automatically initiated on low Reactor Pressure Vessel (RPV) water level as designed. Failure of the Linear Variable Differential Transformer (LVDT) for servo position feedback (DT-1) to the EPR circuitry resulted in the EPR circuitry sending a close signal to the Turbine Control Valves (TCVs), resulting in a high neutron flux scram.

The root cause of this event is the Operational Decision Making Issues (ODMI) checklist and associated monitoring plan had unclear roles and responsibilities assigned which resulted in less than adequate communication, oversight of the plan's implementation, and assessment of the monitoring plan's data.

This event is reportable in accordance with 10 CFR 50.73 (a)(2)(iv)(A) as a valid actuation of the reactor protection system and initiation of the high pressure coolant injection system.

Actions included removing the.EPR from service, procedure revisions and training for ODMIs and abnormal condition monitoring and contingency planning. In addition, the EPR electronics and DT-1 were replaced in the 2013 NMP1 refueling outage. Previous LERs for similar EPR failures include 1987- 014, 1992-003 and 1994-005.

At 2051 on May 2, 2011, Nine Mile Point Unit 1 (NMP1) experienced a turbine trip while operating at approximately 47 percent power (867 MWth). The main turbine master trip solenoid (MTS) actuated due to oil pressure fluctuations that allowed the pressure to drop below the MTS trip setpoint. These fluctuations were caused by leaking fittings on the MTS oil supply lines, binding of the secondary speed relay linkage, and main shaft oil pump discharge pressure fluctuations. The turbine trip initiated the high pressure coolant injection (HPCI) system as designed. The scram caused a drop in the reactor pressure vessel (RPV) water level that was mitigated by the HPCI injection. At 2052, RPV water level was restored above the HPCI low level actuation setpoint and the HPCI system initiation signal was reset.

The root cause of the event was inadequate implementation of management job performance standards which resulted in the development and implementation of work performance documents which lacked sufficient detail associated with turbine maintenance activities.

The immediate corrective action was to repair the turbine exciter/generator Falk coupling installation, replace the tubing and connections to the MTS supply lines, repair the secondary speed relay linkage, and repair the gears to the main shaft oil pump. Procedures will be developed to detail the disassembly, inspection, reassembly and testing of the NMP1 turbine, generator, exciter and control components.

There have been no similar LERs at NMP1.

On June 12, 2006, with Nine Mile Point Nuclear Station (NMPNS) Unit 1 reactor plant in the Startup mode at 0% power, 5 psig and 192 degrees Fahrenheit, reactor water level increased to the high level trip setpoint when plant operators placed the Feedwater system in the long path recirculation configuration to support chemistry sampling. This resulted in a valid Main Turbine Trip signal and actuation of the High Pressure Coolant Injection (HPCI) initiation logic. HPCI is a mode of operation that uses selected equipment of the condensate and feedwater system to perform its function.AAt the time of the event, HPCI was not required to be operable with reactor pressure less than 110 psig. In accordance with operating procedures, the feedwater booster pumps were not required to be in service and their control switches were in pull-to-lock.

Without the booster pumps running, the feedwater pumps' start permissive circuitry is not satisfied. Therefore, though the HPCI start logic was actuated, injection did not occur and was not required.

The cause of this event is inadequate implementation of previous operating experience. Similar level control problems occurred in the past without the lessons learned incorporated into operating procedures to warn operators of possible consequences.

To prevent recurrence, the applicable operating procedure will be revised to establish the proper sequence for placing the Feedwater systerri in long path recirculation configuration during plant startup and a precaution will be added to alert operators about potential reactor level control problems.