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On April 29. 2017 at 18:44. the Reactor was manually tripped by the operators at approximately 12% power in response to a feedwater isolation caused by I ugh Steam Generator (SG) Level on the 'B' SG. The feedwater isolation signal P-14 was automaticall) actuated at 18:43 when the 'B' SG level reached the setpoint 0 r 90.8?..o narrow ranue level. The plant was being started up following the major work perlbrmed for Refueling Outage 18. No adverse consequences resulted from this event.

Post-trip investigation revealed that FW-LT-502-V 1 L (the Variable leg pressure isolation for FW-LT-502) had not been restored to the required open position during routine instrument line filling and venting. On April 26. 2017. l&C' performed hacklilline of the reference legs on multiple steam generator level channels. including FW-1.T-502. the '13' SG wide range level instrument.

1:W-LT-502- VII. not being restored to the open position caused the 'B' SG wide range indication to respond slowly to level changes resulting in overfeeding the 'B' steam generator. The cause of the event was determined to be failure of the l&C technician to properly implement maintenance fundamentals during the performance of restoration of FW-LT-502. Individual perlbrmance was corrected. A contributing cause was determined to be improper characterization or SG level hack fill activity as skill-of-the-craft. Planned corrective actions include development of a maintenance procedure to provide specific step-by-step instructions.

On April 6, 2014, while the plant was in refueling outage sixteen, it was determined during surveillance testing that three of four reactor coolant pump (RCP) undervoltage (UV) reactor trip channels exceeded the Technical Specification (TS) channel response time acceptance criteria of 1.5 seconds for the RCP UV reactor trip function. The condition for the RCP UV time delay relays exceeding tolerance was experienced on all four channels; however, only three of the four channels did not meet their TS required response times. Since this condition involved multiple similar components, there is evidence indicating that this condition may have arisen over time and three channels of RCP UV were inoperable concurrently. This resulted in the plant operating in a condition prohibited by the TS.

The root cause was determined to be the revisions of the Design Control Manual in 1991 and earlier did not require a failure modes and effects analysis as part of the design change packages that installed the E7022PA relays. The RCP UV time delay setting was not identified as a critical attribute and the manufacturer's recommendations for applications requiring very precise time delay settings were overlooked and not incorporated into station procedures. Corrective actions already taken include the replacement of one relay and adjustment of all relays to acceptable response times.

Planned corrective actions are to revise procedures to energize relays for at least 3 hours before performing testing, to perform rechecks at 72 hours during outages and perform additional rechecks if adjustments were made.

On 12/7/12, with the plant in Mode 1 at 100% power, Service Water Cooling Tower level was discovered to be below the Technical Specification (TS) limit of 42.15 feet. Following discovery, a fast fill of the cooling tower was performed to restore water level above the TS limit. It was subsequently determined that cooling tower water level was below the TS limit for approximately 17 days.

adverse consequences resulted from this event and no safety system functional failure occurred since there was sufficient water in the cooling tower to maintain the cooling tower functional at all times.

No The cause of the event was failure to use diverse means to validate the accuracy of a potentially inaccurate cooling tower level indicator. Corrective actions included restoring level in the Service Water Cooling Tower and increasing the use of operator fundamentals.

On September 25, 2012 with the unit in a refueling outage and defueled, station personnel, while reviewing a design change for installation of new circuit boards in the solid state protection system, identified a deficiency in the procedure that performs response time testing of the reactor trip breakers (RTB). The RTB have two diverse trip methods: the undervoltage circuit and the shunt trip circuit. When a RTB is opened through the shunt trip circuit, two coils (STA and SH TR) must function in order to open the breaker. A review of the existing test method found that the shunt trip circuits for both RTB had not been adequately tested. Further, a review of previous revisions of the surveillance procedures concluded that the response time of the shunt trip circuit had never been adequately tested.

This event is similar to and has the same cause as the inadequate time response testing reported in LER 2012 001. The cause of both events was ineffective methods utilized in the mid 1980's to verify that surveillance test procedures ensured compliance with the TS. The corrective actions for this condition included revising the surveillance procedure and obtaining response times, which were found to be within acceptable limits. A review of the adequacy of time response testing is ongoing to address the extent of condition. No adverse consequences resulted from this event.

At approximately 1226 on October 6, 2011 with the plant operating in Mode 1 at 100% power, Seabrook experienced a plant trip on low steam generator water levels following loss of an operating main feed pump. The main feed pump tripped on low suction pressure while restoring a condensate pump to service following maintenance. During restoration of the pump, air entered the condensate system and caused a drop in condensate pump discharge pressure, which resulted in a low pressure condition at the suction of the main feed pump. The trip of the main feed pump on low suction pressure initiated a turbine setback; however, with reduced feedwater flow, steam generator levels decreased to the low level reactor trip setpoint. The automatic systems functioned as designed. The emergency feedwater system automatically actuated and recovered steam generator levels. No adverse consequences resulted from this event.

The cause of this event was the lack of a procedure for restoring a condensate pump to service during operation at power. The corrective action revised the operating procedure to provide instructions for filling and venting a condensate pump following maintenance.

On March 15, 2010 during operation in mode 1 at 100% power, both trains of the containment enclosure emergency air cleanup system (CEEACS) were rendered inoperable due to an opening in the ventilation area boundary. For approximately five hours on March 15 and approximately 4 hours on March 17, a door in the containment enclosure boundary (CEB) was opened to support planned maintenance activities in the positive displacement charging pump room. Under accident conditions, the CEEACS maintains a negative pressure in the enclosure surrounding the containment to prevent uncontrolled releases of radioactivity into the environment.

However, the breach in the CEB created by the open door would have prevented both trains of the CEEACS from establishing the minimum required negative pressure in the enclosure. This condition placed the plant in Technical Specification (TS) 3.0.3, although it was unrecognized at the time, and resulted in a loss of safety function for the CEEACS. The causes of the event included lack of programmatic controls to ensure the control room is notified prior to propping open a CEB door and historical guidance that led the operators to believe that only TS 3.6.5.2, Containment Enclosure Boundary Integrity, applied when a CEB door was open. The planned corrective actions will strengthen an existing program to address opening CEB doors and revise the TS.

On April 5, 2007 with the unit in Mode 1 at 100% power, Seabrook Station declared the turbine driven emergency feedwater pump (TDEFWP) inoperable because the turbine steam supply valve stroke time was outside its acceptable limit. The design basis stroke time for the steam supply valve is five to 15 seconds; however, a review of past surveillance tests revealed that the actual stroke time was less than five seconds. This condition, which rendered the TDEFWP inoperable, existed on three occasions because the surveillance test for measuring the valve's stroke time incorrectly specified a minimum stroke time of four seconds rather than five seconds.

The valve stroke time was adjusted and restored to an acceptable value. The cause of the event was a human error in 1989 that failed to identify that a design change inserted an incorrect minimum stroke time in station documents. While the technical specifications require a plant shutdown if an emergency feedwater pump is inoperable for greater than 72 hours, the plant continued to operate in Mode 1 for more than 72 hours on three occasions with the TDEFWP inoperable. Consequently, this event resulted in a condition prohibited by the technical specifications. The TDEFW pump remained functional and no adverse consequences resulted from this event.

On April 13, 2005 at 0350 with the plant in Mode 6 and core reload in progress, an actuation of the reactor protection system (RPS) resulted from a low water level in steam generator (SG)-B.

While SG-B was in wet lay-up recirculation, an incorrect valve alignment resulted in an inadvertent transfer of water from SG-B to SG-D. This transfer of water lowered the level in SG-B to the low water level reactor trip setpoint, resulting in an actuation of the RPS. This valid actuation of the RPS did not actuate any other components because the reactor trip breakers were already open and the emergency feedwater system was removed from service. The cause of this event was an inadequate procedure. The procedure that controlled filling and recirculation of the SGs during shutdown did not include sufficient instructions to prevent transferring water between SGs. The corrective actions for this condition included revising the procedures to prevent cross-connecting the SG flow paths. No adverse consequences resulted from this event.

On July 24, 2002, with the plant operating at 100 % power, a surveillance test was performed on emergency diesel generator (EK) DG-1B (DG-1B). After approximately three hours of fully loaded operation of DG-1B, plant operators noted that the kilovolt amperage reactive (kVAR) indication was fluctuating. As a result of the fluctuation, plant operators subsequently shutdown the engine and declared DG-1B inoperable at 2302 on July 24, 2002.

Technical Specification (TS) 3.8.1.1 Action statement b. requires that when one diesel generator is inoperable, the operability of the remaining diesel must be demonstrated operable within 24 hours. TS 3.8.1.1 Action b. also identifies that the operability of the remaining diesel generator need not be verified if it has been successfully operated within the last 24 hours, or if currently operating, or if the diesel generator became inoperable due to 1.) Preplanned preventive maintenance or testing; 2.) An inoperable support system with no potential common mode failure for the remaining diesel generator, or 3.) An independently testable component with no potential common mode failure for the remaining diesel generator. Subsequent analysis of the event determined that the decision not to test DG-1A within 24 hours was not consistent with guidance provided in TS Bases section 3/4.8.1.

The failure to meet the requirements of TS 3.8.1.1 action b. is a condition prohibited by the Technical Specifications and is reportable pursuant to the requirements of 10 CFR 50.73(a)(2)(i)(B). Subsequent testing of DG-1A was satisfactorily completed at 0247on July 31, 2002. Additional corrective actions to prevent recurrence have been identified. There were no adverse safety consequences as a result of this event.