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On August 5, 2014, control room operators identified one steam generator (SG) protection level channe indicator as drifting high and approaching its 3 percent level deviation limit. Subsequent troubleshooting performed on October 10, 2014 identified the level transmitter as inoperable due to exceeding its Technical Specification (TS) calibration acceptance criteria. A past functionality evaluation was completed on February 12, 2015. This evaluation determined that the best estimate for when the transmitter would have exceeded its TS calibration acceptance criteria was August 19, 2013.

The cause of the SG protection level channel drifting was due to premature failure of its level transmitter due to a manufacturing defect. Vendor testing confirmed that a center diaphragm oil leak was the cause of the transmitter output drift.

This report is made in accordance with 10CFR50.73(a)(2)(i)(B), Any operation or condition which was prohibited by the plant's Technical Specifications.

On 6/28/16 at 04:22 Salem Unit 2 automatically tripped from 100% power on Generator Protection. The reactor trip was initiated due to a Main Turbine (MT) trip caused by a Main Generator ProtectiOn signal.

All emergency core cooling systems and emergency safeguards feature systems functioned as expected.

The motor driven and steam driven auxiliary feedwater pumps started as expected on steam generator low level. Operators stabilized the plant in Mode 3 with decay heat removal via the main steam dump valves and auxiliary feedwater system.

Investigation identified that a broken current transformer core ground wire internal to the A Main Power Transformer (MPT) was intermittently touching the X1 and X2 low voltage connections inside the transformer bushing compartment causing a ground fault. This caused the turbine generator trip.

This report is being made in accordance with 10CFR50.73 (a)(2)(iv)(A), "Any event or condition that resulted in manual or automatic actuation of any of the systems listed in paragraph (a)(2)(iv)(B)," for this event actuation of the Reactor Protection System (RPS) and the Auxiliary Feedwater System (AF).

On 2/14/16 at 20:58 Salem Unit 2 automatically tripped from 100% power on Generator Protection.

The trip was initiated due to a Main Turbine trip caused by a Main Generator Protection signal. All emergency core cooling systems and emergency safeguards feature systems functioned as expected. The motor driven and steam driven auxiliary feed pumps started as expected on steam generator low level. Operators stabilized the plant in Mode 3 with decay heat removal via the main steam dump valves and auxiliary feed water system. Condenser vacuum remained available for the duration of the event. Operators also ensured a normal offsite electrical power lineup. Investigation identified a Stator Water Cooling valve leak dripping onto a relay, shorting the relay wiring terminations. This caused the turbine generator trip.

This report is being made in accordance with 10CFR50.73 (a)(2)(iv)(A), "Any event or condition that resulted in manual or automatic actuation of any of the systems listed in paragraph (a)(2)(iv)(B)," for this event actuation of the Reactor Protection System and the Auxiliary Feedwater System.

On January 19, 2016, while reviewing outage data, plant staff recognized that anomalous data collected in October 2015, for the 21 Auxiliary Feed Pump time response loop resulted in failure to meet a surveillance, rendering that channel of Auxiliary Feedwater automatic actuation inoperable. In November 2015, the isolation valve for the pressure override defeat pressure transmitter was found closed. The pressure transmitter provides an input into the 21 AFW Pump run-out protection circuit. With the isolation valve closed, it would take longer to sense pump discharge head and consequently the opening of the auxiliary feed pump flow control valves would be slower than normal. This condition resulted in 21 Auxiliary Feedwater Pump loop time response greater than Technical Specification (TS) acceptance criteria. The failed channel was not recognized and the TS action was not taken, resulting in a condition prohibited by TS. The investigation revealed that the condition most likely existed since April 20, 2015, when maintenance activities were performed on the auxiliary feedwater pump discharge pressure transmitter. The isolation valve was opened and the surveillance was performed satisfactorily.

This report is being made in accordance with 10CFR50.73 (a)(2)(i)(B), "Any operation or condition which was prohibited by the plant's Technical Specifications.

On October 28, 2015, Salem Unit 1 was in Mode 1 operating at 100 percent power and Unit 2 was in Mode 6 with fuel movement in progress. The Salem Unit 1 Control Room Emergency Air Conditioning System (CREACS) train was in single train filtration mode supplying air to the common Control Room due to outage activities on Unit 2.

At 0628, the Salem Unit 1 CREACS train was declared inoperable due to failure of its charcoal filter surveillance test, resulting in both units CREACS trains being inoperable. Unit 1 entered Technical Specification (TS) 3.0.3, and Unit 2 suspended fuel movement to comply with TS 3.7.6, Action c.

At 0950, the Unit 2 CREACS train was returned to service and aligned to single train filtration mode supplying air to the common Control Room. Unit 1 exited TS 3.0.3, meeting the requirement of TS 3.7.6.1, Action a., to restore a single train of CREACS to operable.

This event was caused by less than adequate procedure guidance and ownership of the surveillance activity by the maintenance shop responsible for performing the work. The direct cause of the TS entry was the filter failure due to aging.

This event is reportable under 10 CFR 50.73(a)(2)(i)(B), as a condition prohibited by the plant's TS, and 10 CFR 50.73(a)(2Xv)(D), as a condition that could have prevented the fulfillment of a safety function.

(Limit to 1400 spaces, i.e., approximately 15 single-spaced typewritten lines) On 1/16/15, irradiated fuel was being moved in the Salem Unit 1 Fuel Handling Building (FHB) in support of fuel sipping activities. Fuel Handling Building Ventilation system operability was being monitored via a camera focused on the local indication which was displayed in the Control Room as permitted by station procedures.

While fuel was being moved, the local differential pressure indicator oscillated between negative and slightly positive. Fuel movement was not secured as required by Technical Specification 3.9.12 when negative building differential pressure (D/P) was not maintained A causal evaluation determined that FHB equipment issues led to the FHB D/P alarm being locked in. A separate causal evaluation determined that Operations control room crew members failed to apply fundamentals of control board awareness and effective crew teamwork. Operating crew expectations were reinforced with respect to the assignment of personnel for continuous monitoring of equipment, and the underlying equipment deficiencies were corrected.

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

On June 22, 2015, at 1406, control room operators were notified by chemistry personnel that the Salem Unit 1 Containment Spray Additive Tank Sodium Hydroxide (NaOH) concentration was less than the minimum concentration by weight as required by Technical Specification (TS). Salem entered TS Action Statement 3.6.2.2.a for low NaOH concentration in the Containment Spray Additive Tank. On June 23, 2015 at 1908, NaOH concentration was returned to its minimum required TS value and the plant exited TS 3.6.2.2.a.

This report is made in accordance with 10 CFR 50. 73(a)(2)(i)(B) for "Any operation or condition which was prohibited by the plant's Technical Specifications ... " and 10 CFR 50.73(a)(2)(v) for "Any event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to: ... (C) Control the release of radioactive material; or (D) Mitigate the consequences of an accident.

On October 19, 2014, at 2051, while performing a unit shutdown in preparation for its twenty-third refueling outage, Salem unit 1 control room operators initiated a manual reactor trip at approximately 20 percent reactor power. The manual reactor trip was inserted due to concerns with the 1 B Main Power Transformer, which had been in service with identified oil leakage. All control rods fully inserted on the trip.

The auxiliary feedwater system actuated as designed in response to low steam generator levels. Decay heat removal was via the steam dumps to the main condenser. The plant was stabilized in Hot Standby.

Operators failed to recognize parameters on 1 B Main Power Transformer which would have required them to enter an Adverse Condition Monitoring Plan. Entry into the plan would have required them to perform a fast load reduction and remove the main turbine from service at 40 percent power. Salem Generating Station will fully integrate procedure use and adherence principles and behaviors throughout Operations.

This report is made in accordance with 10 CFR 50.73 (a)(2)(iv)(A), "Any event or condition that resulted in manual or automatic actuation of any of the systems listed in paragraph (a)(2)(iv)(B) ... "for a manual reactor trip and for automatic actuation of the auxiliary feedwater system.

On August 27, 2014, the 11 Safety Injection (SI) pump was being tagged out for planned maintenance. At 0243, the 11 SI pump was declared inoperable when its 4 kilovolt (kV) supply breaker was racked out. At 0248, the 12 SI pump failed to start on demand when operators were attempting to fill the 14 SI Accumulator. The unit entered Technical Specification (TS) 3.0.3 for inoperability of two SI pumps. At 0301, the 11 SI pump was realigned, tested and returned to service and the unit exited TS 3.0.3. The apparent cause of the 12 SI pump failure to start was due to a failure of the spring release solenoid in the pump's breaker.

This report is made in accordance with 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: ...(D) Mitigate the consequences of an accident" for inoperability of both SI Pumps.

On April 8, 2014 at 2112, Salem Unit 1 control room operators received an alarm indicating failure of the 12 Essential Controls Inverter. At 2113, operators observed indications of a trip of the 11 Steam Generator Feedwater Pump (SGFP). Operators manually initiated a Main Turbine automatic runback by manually tripping the 11 SGFP in accordance with procedures. At 2114, operators manually tripped the reactor due to a low level in the 13 Steam Generator (SG). All control rods fully inserted on the trip. All three Auxiliary Feedwater (AFW) pumps started as expected in response to low SG levels and decay heat was removed by the steam dumps to the main condenser. Operators entered the emergency procedures for the plant trip and stabilized the plant in Mode 3 (HOT STANDBY).

The cause of this event was due to a loss of power to the 11 SGFP speed probes. A ground on the electrical bus providing power to the speed probes was repaired.

This report is made in accordance with 10 CFR 50.73(a)(2)(iv)(A), "any event or condition that resulted in manual or automatic actuation of any of the systems listed in paragraph (a)(2)(iv)(B)" for a manual reactor trip and automatic actuation of the AFW system.

On June 2, 2004 at approximately 1230 hours, the 1SVV26 valve (service water to the turbine building isolation valve) was declared inoperable as a result of investigation into an abnormal condition with Service Water in the turbine building. A plant shutdown was initiated in accordance with Technical Specification 3.6.1.1 "Primary CONTAINMENT INTEGRITY".� On June 2, 2004, non-licensed operations personnel identified an abnormal condition in the control of the turbine building service water pressure. During a routine tour of the turbine building while returning Unit 1 from its sixteenth refueling outage, the operator noticed that the temperature in the number 11 main turbine lube oil heat exchanger was approximately 110 degrees F.� Further investigation revealed that the service water to the turbine building regulating valve (1ST1) was full open with only 72 psig in the service water turbine header downstream of 1ST1. These conditions, low pressure and high temperatures, were not normal for the plant conditions at the time.

Further troubleshooting indicated that the service water to the turbine building isolation valve (1SW26) had been improperly installed and its motor operator improperly set up. The root cause of the event is attributed to failure to follow the process of match marking to assure that the actuator was properly installed with respect to the valve position.� Corrective actions taken were: the valve actuator was removed, the valve disc was rotated 180 degrees, and re-tested satisfactorily. Additional corrective actions will include revising the applicable installation procedures, including lessons learned for similar activities in upcoming outages and evaluating the event for inclusion in the continuing training program. This event is being reported under the requirement of 10CFR50.73(a)(2)(i)(A), as a completion of a plant shutdown to comply with Technical Specifications.