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On June 12, 2016, with Millstone Power Station Unit 3 operating in MODE 1 at 100% power, operators identified the third stage of the "A" Reactor Coolant Pump (RCP) seal had failed, which resulted in an unidentified Reactor Coolant System leak greater than the Technical Specification (TS) limit of 1 gallon per minute. Operators initiated a plant shutdown as required by TS 3.4.6.2 ACTION Statement b. During the downpower, steam generator levels were not adequately maintained and the Engineered Safety Features Actuation System generated a Turbine Trip and Feed Water Isolation on Steam Generator Water Level - High-High being exceeded on the 'B' steam generator.

In response, operators manually tripped the reactor at 23:37 (MODE 1, at approximately 20 % power). The auxiliary feedwater system started as designed.

Safety systems functioned as expected. There were no radiological challenges as a result of the event. The plant entered COLD SHUTDOWN on June 14, 2016 at 01:29.

The cause of the unidentified leak was a failed third stage on the "A" RCP seal. The seal was replaced.

The cause of the feedwater transient and resultant manual reactor trip was due to operator performance in controlling steam generator level. This is being addressed in the Corrective Action Program.

This event is being reported in accordance with 10 CFR 50.73(a)(2)(iv)(A) as an event that resulted in manual or automatic actuation of systems listed in 10 CFR 50.73(a)(2)(iv)(B). Additionally, the plant shutdown is being reported in accordance with 10 CFR 50.73 (a)(2)(i)(A) as the completion of any nuclear plant shutdown required by the plant's Technical Specifications.

(MPS3) performed the 'B' train Supplementary Leak Collection and Release System (SLCRS) Negative Pressure Verification Surveillance. This test was completed with unsatisfactory results. Technical Specification (TS) Limiting Condition for Operation (LCO) 3.6.6.1 was entered. Later, on April 9, 2016, with the reactor in MODE 1 and approximately 24 percent power, MPS3 operators conducted the 'A' train SLCRS Negative Pressure Verification Surveillance with unsatisfactory results. Because both trains of SLCRS failed the required surveillances, TS LCO 3.6.6.2 was entered. Operations continued with the planned plant shutdown associated with the RFO and entered COLD SHUTDOWN, MODE 5 at 1241 on April 10, 2016.

SLCRS did not meet the acceptance criteria due to the aggregate impact of a number of dampers not providing effective isolation.

SLCRS was restored to operable condition prior to entering MODE 4 when starting back up from RF017. Detailed procedural steps are being developed for verifying the closed position of SLCRS isolation dampers and being incorporated into the damper post maintenance testing matrix. Associated surveillance procedures are being revised to improve monitoring program for SLCRS isolation dampers.

Since both trains of SLCRS failed to meet TS acceptance criteria, this condition is reportable pursuant to 10CFR50.73(a)(2)(v)(C) as a condition that could have prevented the fulfillment of a safety function for systems or structures to control the release of radioactive material, and 10CFR50.73(a)(2)(v)(D) to mitioate the consequences of an accident.

On June 11, 2015, while Millstone Power Station Unit 2 (MPS2) was in MODE 1 operating at 100 percent power, Engineering identified that due to a degraded check valve, the post-accident radioactivity release rates assumed in the FSAR could be affected. While performing 'B' High Pressure Safety Injection (HPSI) pump in-service testing, the measured flow was lower than expected. Because both trains of HPSI, Low Pressure Safety Injection (LPSI) pumps, and Containment Spray (CS) pumps share a common minimum flow recirculation line back to the Refueling Water Storage Tank, back-leakage through one of the idle pump's recirculation check valves was postulated as the cause of the observed drop in recirculation flow. Troubleshooting was performed, and it was determined that the minimum flow check valve associated with the 'A' CS pump, 2-CS-6A, was back-leaking. The associated minimum flow isolation valve was closed to eliminate the flow path. Back-leakage of the minimum flow recirculation check valves on the HPSI, LPSI, and CS pumps was not previously considered in radiological release analysis. This leakage had the potential to adversely affect calculated post-Loss of Coolant Accident recirculation phase radioactivity release rates under some postulated scenarios.

This event is being reported as an event or condition that could have prevented fulfillment of a safety function to control the release of radioactive material under 10 CFR 50.73(a)(2)(v)(C). The cause of the event was a failed open check valve. As a corrective action, the failed check valve 2-CS-6A has been repaired.

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1. EVENT DE3CRIIPT

• On June 11, 2015, while Millstone Power Station Unit 2 (MPS2) was in MODE 1 operating at 100 percent power, Engineering identified that due to a degraded check valve, the post-accident radioactivity release rates assumed in the FSAR could be affected. While performing 'B' High Pressure Safety Injection (HPSI) pump in-service testing, the measured flow was lower than expected. Because both trains of HPSI, Low Pressure Safety injection (ILPSO pumps, and Containment Spray (CS) pumps share a common minimum flow recirculation line back to the Refueling Water Storage Tank (RWST), back-leakage through one of the idle pumps recirculation check valves was postulated as the cause of the observed drop in flow. Troubleshooting was performed, and it was determined that a degraded minimum flow check valve associated with the 'A' CS pump (2-CS-6A) was back-leaking into the “A" train suction line and flowing to the RWST through 2-CS-14A (RWST suction check valve) and normally open 2-CS-13.1A (RWST suction line isolation).

The associated minimum flow isolation valve for 2-CS-6A was closed to eliminate the path and the valve was repaired.

Subsequently, engineering evaluation determined that during a loss of power to one facility or train of the Emergency Core Cooling System (ECCS), this back-leakage flow path could result in more leakage to the RWST than had been previously considered in the accident analysis. This leakage was evaluated for the potential to adversely affect calculated post—Loss of Coolant Accident recirculation phase radioactivity release rates under some postulated scenarios. Specifically, without power on the affected (i.e.: back-leaking) train, the CS discharge flowpath would not automatically open resulting in leakage to the RWST.

Prior to this discovery, the East time that the 'A' containment spray pump was run was on April 15, 2015, which would have opened 2-CS-6A. On this basis, it was concluded that this condition existed from April 15, 2015 to June 11, 2015. During this period, the 'A' Emergency Diesel Generator (EDG) was inoperable 4 times for a total of approximately 25 hours. However, all 4 times were for surveillances. At no time during this period was any maintenance done on the 'A' EDG. It is judged that, between accident initiation and commencement of sump recirculation (approximately 2 hours with only one train available), the EDG could have been made available.

This event is being reported as an event or condition that could have prevented fulfillment of a safety function to control the release of radioactive material under 10 CFR 50.73(a)(2)(v)(C). Note: The initial non-emergency report (#51149) of this issue on June 11, 2015 was subsequently updated on July 10, 2015. An additional unidentified release path from the original design of the plant was reported to the NRC as a follow-up notification on July 10, 2015.

BACKGROUND

The MPS2 Containment Spray (CS) system functions as an engineered safety feature to limit containment pressure and temperature after a loss-of-coolant accident (LOCA) and Main Steam Line Break (MSLE) accident, and thereby reduce the potential for leakage of airborne radioactivity to the outside environment. A minimum flow recirculation line is included in the design for recirculating water from the outlet of the pump to the RWST.

With the CS system operating during a design basis accident, a small portion of the CS pump discharge flow recirculates to the RWST during the injection phase; however, the recirculation line is isolated from the RWST when transferring to sump recirculation. All seven ECCS/CS pumps (2 LPSI, 2 CS, and 3 HPSI) have minimum flow recirculation lines that tie into one common header to the RWST. Exhibit A attached to this LER is a sketch depicting the configuration.

Evaluation of this failure identified that during a SBLOCA (Small Break Loss of Coolant Accident) concurrent with a loss of power to the "A" train associated with the leaking 2-CS-6A, the operating (opposite) train HPSI pump would pressurize the common recirculation header during the injection phase of the accident as was described above. In the operator response to this postulated event when the 2-CS-6A leaks to the RWST, suction 2-CS-13.1B is manually isolated terminating the release to the RWST. However, it was additionally identified that the "A" train suction header would pressurize because of the continued back leakage with none of the "A" train pumps flowing due to loss of power and no open flowpath (to containment spray or RWST). This pressurization would continue, exceeding the design pressure of the suction header (60 psig) ultimately reaching 500 psig, the lift setpoint for the two "A" train shutdown cooling heat exchanger relief valves downstream of the "A" LPSI and CS pumps. These relief valves discharge to the EDST (Equipment Drains Sump Tank) which is located outside the filtered ventilation boundary. Upon emptying of the RWST and initiation of sump recirculation, the described back-leakage flowpath would contain sump fluid. This additional unidentified release path from the original design of the plant was reported to the NRC as a follow-up notification on July 10, 2015.

For this accident and radiological release sequence to occur the following are required:

• 2-CS-6A back-leakage

• SBLOCA

• Loss of Offsite Power (LOOP)

• Loss of the "A" train of onsite electric power

• SBLOCA break size that results in RCS re-pressurization and sustained RCS pressures above 500 psig, such that HPSI would continue to pressurize the recirculation header

• Fuel damage While the discussion above relates to 2-CS-6A and the "A" train, back leakage from any of the minimum flow check valves and a concurrent loss of power to that train will have a similar outcome.

2. CAUSE:

The cause of the event was a failed-open check valve. Leakage of these check valves was not considered as a failure mode in the Millstone Unit 2 FSAR or original design basis.

3. ASSESSMENT OF SAFETY CONSEQUENCES:

An Operability Determination has been prepared and approved to document the radiological consequences of the condition. The radiological consequences of ECCS/CS min-flow check valve(s) leakage were evaluated for 5 gallons per minute of post LOCA containment sump liquid relieving to the Equipment Drains Sump Tank. This evaluation considered a 30 day unfiltered ground release and used a best estimate source term (gap release, 1% partitioning, etc.). This leakage was added to the consequences of previously identified leak paths, which had been analyzed using design basis LOCA analysis assumptions. The maximum train as found leakage was .089 gpm, well below the 5 gpm limit using best estimate source term.

Even with the addition of the minimum-flow leakage, the control room and offsite dose consequences are within the regulatory limits of 10CFR50.67,

4. CORRECTIVE ACTION:

During the recently completed 2R23 refueling outage, leak testing of ail MPS2 ECCS/CS min-flow check valves was completed. The testing was performed at 500 psig. The results were scaled to 1200 psid to reflect the highest HPSI discharge pressure. The resultant maximum as-found leak rate was 0.089 gpm through the 'A' ECCS/CS train. The failed check valve 2-CS-6A has been repaired. The 'B' HPSI check valve 2-SI-422, the check valve with the highest as-found leakage rate of 0.085 gpm, was repaired and retested. The maximum ECCS/CS pump min-flow as-left check valve leak rate in a train is 0.004 gpm.

Additional corrective actions are being taken in accordance with the station's corrective action program.

5. PREVIOUS OCCURRENCES:

• None 6. Energy Industry Identification System (EIIS) codes:

• Pump — P

• Valve — V

• Tank —T

• Containment Spray — CS

• Safety Injection — Si

On February 19, 2015, with Millstone Power Station Unit 3 (MPS3) at 100% power and in operating mode 1, an individual on a fire watch rove processed through a dual train high energy line break (HELB) door normally and upon checking the door after passage the individual noted the door did not latch. The Control Room was promptly notified./ An operator was dispatched to investigate. The operator exercised the door lock-set mechanism freeing the latch allowing the door to properly latch. The door was inoperable for approximately 7 minutes. Technical Specification 3.0.3 was entered and exited appropriately.

Although no definite failure mechanism was identified, the door was experiencing high usage due to compensatory fire watch roves entering/exiting the door. The door lockset mechanism was manually manipulated and then tested several times satisfactorily by maintenance personnel. Further, the door design has the door swing such that the HELB event would act to open the door when the lockset mechanism fails. Engineering is evaluating the adequacy of the preventive maintenance frequency. Additionally, a design change to reverse the door swing such that the HELB event would cause the door to close and thus not rely on the lock-set mechanism is being considered. Additional corrective actions are being taken in accordance with the station's corrective action program.

This event is being reported pursuant to 10 CFR 50.73(a)(2)(v)(D), as a condition that could have prevented the fulfillment of a safety function for systems needed to mitigate the consequences of an accident.

On May 25, 2014, with Millstone Power Station (MPS) Unit 2 and 3 (MPS2 and MPS3) in operating MODE 1, operating at 100% reactor power, a total loss of offsite power occurred in the MPS switchyard. Both MPS2 and MPS3 experienced a turbine trip on power to load imbalance followed by an automatic reactor trip. Both units' safety related emergency diesel generators (EDGs) automatically started and supplied power to their respective safety busses. As designed, the motor driven auxiliary feedwater (AFW) pumps automatically started on MPS2 and all AFW pumps automatically started on MPS3.

MPS declared an Unusual Event (UE) following the reactor trips and the NRC was notified (EN50142 for MPS2 and EN 50141 for MPS3). Following stabilization of both MPS2 and MPS3, the UE was terminated.

With both MPS2 and MPS3 at full power and one of the Transmission Owner (TO) 345 kV lines out of service for scheduled work, a phase to ground fault occurred on one of the phases on a motor operated disconnect (MOD) on one of the three remaining TO 345 kV lines. The fault was caused by an insulator failure of a MOD switch at a TO substation (offsite). This fault was also sensed as an instantaneous ground in one of the two remaining TO 345 kV lines resulting in this line also tripping. With three of the four TO 345 kV lines out of service, the MPS total electrical output overloaded the single remaining TO 345 kV Line which then also tripped resulting in a total loss of offsite AC power to MPS.

The TO replaced the faulty components and is investigating additional corrective actions. Additional corrective actions are being taken in accordance with the station's corrective action program.

This event is being reported per 10 CFR 50.73(a)(2)(iv)(A) as an event that resulted in a manual or automatic actuation of systems listed in 10 CFR 50.73(a)(2)(iv)(B)(1), (6), and (8). Actuations of the reactor protection system, the AFW system, and the EDGs are reportable under this paragraph.

On April 10, 2014, with Millstone Power Station Unit 2 in MODE 6 at 0% reactor power, while de-terminating the motor leads for the 'B' Motor Driven Auxiliary Feedwater (MDAFW) Pump motor, foreign material (ty-wraps and a plastic bag) were found inside the cable environmental seal (Raychem boot) of the 'A' phase. An inspection of the electrical motor leads revealed no damage occurred. This motor was last re-terminated In May 2000. The motor leads to the other phases did not have any foreign material inside the Raychem boot. Since the Raychem boot was not in the as tested environmentally qualified (EQ) configuration the 'B' MDAFW pump was considered inoperable.

Plant Technical Specifications (TS) 3.7.2.1 Action d, requires, if two AFW pumps are inoperable in operating MODES 1, 2, and 3, the plant must be placed in at least HOT STANDBY within six hours and in HOT SHUTDOWN within the following 12 hours.

A review of the control room logs for the past three years determined there were 4 occasions where there were two AFW pumps inoperable for longer than allowed by TS.

The direct cause was an historical inappropriate maintenance practice which rendered the MDAFW pump inoperable.

The 'A' phase motor lead was subsequently properly re-terminated.

This condition is being reported under 10 CFR 50.73(a)(2)(i)(B) as any operation or condition which was prohibited by the plant's Technical Specifications.

While Millstone Power Station Unit 3 (MPS3) was operating at 100 percent power in Mode 1 on March 12, 2014, operations determined that a concern identified by Engineering as a result of recent industry operating experience (NRC Event Number 49889) could result in an unanalyzed condition. Engineering's review of the direct current (DC) circuits associated with the main turbine emergency lube oil and main generator emergency seal oil pumps determined the described condition to be applicable to MPS3.

This condition is reportable pursuant to 10 CFR 50.73(a)(2)(ii)(B) as an unanalyzed condition that significantly degraded plant safety. A prompt notification per EN49903 was submitted to the NRC on March 12, 2014.

The cause of the condition was a manufacturer's design error that was installed during plant construction.

Compensatory fire watches have been implemented for affected areas of the plant. Plant modifications are planned that will protect or isolate the affected circuits leaving the initial fire area.

On November 9, 2013, at 1514, Millstone Power Station Unit 2 (MPS2) experienced a turbine trip and an automatic reactor trip from 95% power MODE 1.due to loss of condenser vacuum. The Unit was in the process of condenser backwashing operations when condenser vacuum was lost due to unexpected pump ramp-down of the 'C' circulating water pump (CWP) when the 'D' CWP was secured as required by procedure.

All control rods inserted on the reactor trip. An auxiliary feedwater (AFW) automatic start occurred post trip, as expected per design, and all other safety systems functioned as required.

The direct cause of the event was the MPS2 'C' CWP ramped off due to failure of contacts on a time- delay relay to deenergize as designed.

The defective relay was replaced. Additional corrective actions are being taken in accordance with the station's corrective action program.

This event is being reported per 10 CFR 50.73(a)(2)(iv)(A) as an event that resulted in a manual or automatic actuation of systems listed in 10 CFR 50.73(a)(2)(iv)(B). Actuations of the reactor protection system and the AFW system are reportable under this paragraph.

At 19:30 on June 7, 2012, with Millstone Power Station Unit 2 (MPS2) operating at 100 percent power in Mode 1, it was determined that a series of gaps in a high energy line break (HELB) barrier rendered equipment in the west 480VAC switchgear room inoperable. The Shift Manager entered Technical Specification (TS) 3.8.2.1 Action, TS " and TS 3.3.3.5 Action "a". The openings were sealed and the equipment restored to operable 3.8.2.1A Action "c status at 16:05 on June 8, 2012. At the time of discovery, appropriate and timely actions were taken that met the TS action requirements. There is evidence that this condition has existed since initial construction. Since the HELB barrier required to maintain operability of bus 22E, Inverters 5 and 6, and remote shutdown panel C-21 was non-functional for an extended period of time, the Actions for TS 3.8.2.1, TS 3.8.2.1A and TS 3.3.3.5 were historically not met. This condition is being reported pursuant to 10 CFR 50.73(a)(2)(i)(B) any operation or condition prohibited by the plants technical specifications" The apparent cause, dating back to original construction, is that no construction details were developed for sealing Q-decking when the ribbing is perpendicular to the top of the wall. As noted above, the gaps were subsequently sealed and an extent of condition inspection was conducted. Additional gaps in the same wall did not affect safety related equipment. No other gaps were identified. This report assumes the steam from a HELB in the turbine building would have affected the operability of safety related equipment in the west 480VAC switchgear room.

Upon further engineering analysis, it was determined that for limited exposure times safety functions could have been prevented for certain postulated high energy line breaks. Therefore, this condition is also being reported pursuant to 10 CFR 50.73(a)(2)(v)(A),(D). I

On March 7, 2013, with Millstone Power Station Unit 2 in MODE 1 at 100% power, during a turbine driven auxiliary feedwater (TDAFW) pump surveillance test, the operators left the door to the TDAFW pump room open. This condition existed for approximately 30 minutes. The door is a high energy line break (HELB) barrier. With the door open there is no HELB protection for the motor driven auxiliary feedwater (AFW) pumps thus potentially rendering both trains of AFW inoperable. Additionally, during the surveillance run the TDAFW pump was declared inoperable.

The HELB requirements during operation of the TDAFW pump were not fully considered during the pre-job brief.

Management has reinforced expectations to Operations Department personnel and station personnel on the need to ensure the requirements for any barrier are met prior to opening any door or duct. Training for Operations, Maintenance and Engineering is planned to reinforce understanding of expectations concerning passive design features, like flood barriers, fire doors and HELB barriers. Additional corrective actions are being taken in accordance with the station's corrective action program.

This event is being reported pursuant to 10 CFR 50.73(a)(2)(v) as any event or condition that alone could have prevented the fulfillment of the safety function of structures or systems that are needed to: (B) Remove residual heat; and (D) Mitigate the consequences of an accident.

At 0938 on January 15, 2013, with Millstone Power Station Unit 2 (MPS2) in Mode 1, operating at 100 percent power, while performing a monthly required channel check on the safety valve's position indication, technicians discovered that the channel B primary safety valve acoustic valve monitor system (AVMS) position indicator failed to meet acceptance criteria contained in Surveillance Procedure SP2410A. In this instance, the technicians had expected to observe a frequency peak at or near 74.25 Hz on the AVMS' output, which is induced by an operating reactor coolant pump. After reviewing a printout obtained from the instrumentation loop, it was determined that the frequency peak expected at or near 74.25 Hz was not detected. Therefore, the AVMS channel was declared inoperable and Operators entered Technical Specification (TS) 3.3.3.8, Accident Monitoring Instrumentation, Action 3, for Item 6, Safety Valve Position Indicator, which specifies that alternate indications shall be checked once each shift. On January 17, 2013, upon reviewing the results from the previous month's completed channel check surveillance performed in December 2012, it was discovered that the instrument had also failed to meet the acceptance criteria for a channel check in SP2410A at the time. However, it was not recognized that the surveillance results did not meet acceptance criteria, so the instrument was not declared inoperable at the time.

This condition is being reported pursuant to 10 CFR 73(a)(2)(i)(B) as any operation or condition which was prohibited by the plant's Technical Specifications.

The cause was determined to be inadequate procedure guidance in SP2410A which led to confusion when interpreting surveillance results. The surveillance procedure has been revised to include clear acceptance criteria for a channel check.

On, September 14, 2011, with Millstone Power Station Unit 2 (MPS2) in Model, at 100 % power, a historical condition was discovered where the surveillance procedure used to test the reactor trip circuit breakers (TCBs) specified the TCBs be closed (i.e., applying power to the control rod drive motors thus enabling the control element assemblies (CEAs) to be capable of being withdrawn) prior to demonstrating the TCBs to be OPERABLE. This is contrary to the requirements of Technical Specification (TS) 4.0.4 which prohibits entry into an operational mode or other specified condition unless the surveillance requirement(s) have been performed within the stated interval. This condition is being reported pursuant to 10 CFR 73(a)(2)(i)(B) as an operation or condition prohibited by TS.

The cause was determined to be an inadequate procedure review. During the implementation process for a 2003 TS change, when the surveillance procedure was revised, it was not recognized that the surveillance procedure test method for the TCBs allowed MPS2 to enter a mode or condition prior to demonstrating the TCBs to be operable as required by TS 4.0.4. The surveillance procedure is being revised to specify an alternate method for testing the TCBs that does not result in rendering the CEA drive system capable of CEA withdrawal prior to closing the TCBs for performance of Matrix Logic and Trip Path testing.

At 1152 on June 20, 2011, with Millstone Power Station Unit 2 operating at 59 percent power in Mode 1, the reactor tripped automatically on low steam generator water level. The decreasing water level condition was due to a low suction pressure trip on the "B" steam generator feed pump (SGFP) that occurred while placing the "A" SGFP in service. The event is being reported pursuant to 10 CFR 50.73(a)(2)(iv)(A) as an event that resulted in a manual or automatic actuation of any of the systems listed in 50.73(a)(2)(iv)(B). The actuation of the Auxiliary Feedwater Actuation System also is a reportable condition under the same paragraph.

The cause of the event was gaps in the application of operator fundamentals and some procedure quality issues associated with operations procedure OP 2204, Load Changes.

Procedure OP 2204 has been revised to ensure the second steam generator feedwater pump is placed in service at a lower power level. Additional corrective actions to address the underlying causes of the gaps in the application of operator fundamentals are being addressed in accordance with the station's corrective action program.,