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On September 19, 2016, the Control Room Ventilation exhaust fan 70FN-4A did not start when it was being placed into service. The fan outlet isolation damper actuator 70MOD-108A(OP) failed to give the fully-open permissive signal to start the fan. Gentle pressure on the actuator linkage allowed the fan to start. Prior to this, on August 16, 2016, during post-maintenance testing, 70FN-4A did not start. Troubleshooting adjusted the linkage and the fan started as appropriate. However, the intermittent fan start issue was caused by the degraded damper actuator 70MOD-108A(OP). Corrective action replaced 70MOD-108A(OP).

This event is reportable per 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by Technical Specifications.

On the morning of June 7, 2016, while operating at 100% power, workers opened doors concurrently when entering a secondary containment access airlock. The individuals involved each closed their respective doors upon encountering this unexpected condition; however, the result was a brief inoperability of secondary containment.

This resulted in an 8 hour reportable event. The Resident Inspector was notified, and an Event Notification was made pursuant to 10 CFR 50.72(b)(3)(v)(C) due to a condition at the time of discovery that prevented the fulfillment of the Secondary Containment safety function (Reference ENS 51985). Following the event, the doors functioned properly, and no deficiencies were noted with either door.

There were no radiological releases associated with this event.

On January 23, 2016, James A. FitzPatrick Nuclear Power Plant (JAF) was ascending in power when screenwell water level started to lower. At 89 percent power, at 22:23, Operators began taking compensatory measures to reduce power and mitigate water level lowering. At 22:40, a manual scram was initiated.

The scram was complicated by a residual transfer that resulted in non-vital equipment trips. This event resulted in the manual actuation of the Reactor Protection System, High Pressure Coolant Injection, Reactor Core Isolation Cooling, Main Steam Isolation Valves and automatic actuation of Emergency Diesel Generators, Emergency Service Water, and containment isolations in multiple systems, reportable per 10 CFR 50.73(a)(2)(iv)(A).

The lowering screenwell water level was caused by frazil ice blockage at the intake structure. The frazil ice stopped affecting screenwell water level after the manual scram. Corrective actions include strengthening mitigating actions in response to frazil ice.

The residual transfer was caused by lubrication hardening in the lower control valve assembly of the 71PCB-10042 breaker. Corrective actions included replacing or reworking the lower control valve assembly.

At 2036 on December 1, 2015, James A. FitzPatrick Nuclear Power Plant (JAF) was operating at 100 percent power when differential pressure of the Secondary Containment exceeded a Technical Specification requirement. The requirement is for the Secondary Containment to have a >1= 0.25 inches of vacuum water gauge compared to the external environment.

This event was caused by hardened grease in the operating mechanism of the motor starter contactor 71MCC-141-062.

This led to a slow start of the above refuel floor Reactor Building exhaust fan 66FN-13B while the intake air supply fans were running. The exhaust fan started, without Plant Operator action, after approximately 60 seconds; however, Reactor Building differential pressure exceeded 0.25 inches of vacuum water gauge for approximately 80 seconds.

When Secondary Containment did not meet the Technical Specification Surveillance Requirement 3.6.4.1.1 for differential pressure, the Limiting Condition of Operation (LCO) was not met. Therefore, Secondary Containment was Inoperable.

Restoration of the LCO was completed within the allowed action completion time. This report is being submitted per 10 CFR 50.73(a)(2)(v)(C) as a condition that could have prevented the fulfillment of safety function to control the release of radioactive material.

At 1408 on September 18, 2015, James A. FitzPatrick Nuclear Power Plant (JAF) was operating at 100 percent power when differential pressure of the Secondary Containment Reactor Building exceeded a Technical Specification requirement. The requirement is for the Secondary Containment to have a >1= 0.25 inch of vacuum water gauge compared to the external environment. During this event, Reactor Building differential pressure decreased below 0.25 inch of vacuum water gauge for approximately 3 minutes. This event was caused by the Refuel Floor Exhaust fan 'A' discharge damper 66A0D-106A going partially closed with concurrent failure of the associated fan discharge damper position indicating switch 66PNS-106A1. This resulted in obstructing exhaust flow from the Reactor Building. To correct the condition the standby exhaust fan was placed in service.

When Secondary Containment did not meet the Technical Specification Surveillance Requirement 3.6.4.1.1 for differential pressure, the Limiting Condition of Operation (LCO) was not met. Therefore, Secondary Containment was Inoperable.

Restoration of the LCO was completed within the allowed action completion time. This report is being submitted per 10 CFR 50.73(a)(2)(v)(C) as a condition that could have prevented the fulfillment of safety function to control the release of radioactive material.

On the morning of July 20, 2015 at 0740 EDT, with the James A. FitzPatrick Nuclear Power Plant (JAF) operating at 100 percent power, the differential pressure (D/P) of the Reactor Building (relative to atmosphere) decreased, resulting in a Technical Specification (TS) surveillance requirement for the Secondary Containment vacuum not being met (>1= 0.25 inches of vacuum water gauge). The decrease in D/P was caused by the opening of the Reactor Building roof envelope during roof replacement activities. The condition of D/P being less negative than 0.25 inches of vacuum water gauge existed for approximately 92 minutes.

When Secondary Containment did not meet the Technical Specification Surveillance Requirement 3.6.4.1.1 for differential pressure, the TS Limiting Condition of Operation (LCO) was not met. Therefore, Secondary Containment was Inoperable. Restoration of the LCO was completed after secondary containment was declared Operable / Degraded. This report is being submitted per 10 CFR 50.73(a)(2)(v)(C) as a condition that could have prevented the fulfillment of safety function to control the release of radioactive material.

At 1655 and 1708 on October 28, 2014, James A. FitzPatrick Nuclear Power Plant (JAF) was operating at 100 percent power when differential pressure of the Secondary Containment Reactor Building exceeded a Technical Specification Requirement. The requirement is for the Secondary Containment to have a >1= 0.25 inch of vacuum water gauge compared to the external environment. The Reactor Building differential pressure decreased below 0.25 inch of vacuum water gauge twice: at 1655 when isolating Reactor Building Ventilation caused by the isolation valve closing sequence; and, at 1708 while restoring Reactor Building 'A' Ventilation caused by the Refuel Floor Exhaust fan 'A' discharge damper 66A0D-106A going partially closed with concurrent failure of the associated fan discharge damper position indicating switch 66PNS-106A1. This resulted in obstructing exhaust flow from the Reactor Building. Each condition existed for approximately a minute.

When Secondary Containment did not meet the Technical Specification Surveillance Requirement 3.6.4.1.1 for differential pressure the Limiting Condition of Operation (LCO) was not met. Therefore, Secondary Containment was Inoperable.

Restoration of the LCO was completed within the allowed action completion time. This report is being submitted per 10 CFR 50.73(a)(2)(v)(C) as a condition that could have prevented the fulfillment of safety function to control the release of radioactive material.

On the morning of December 17, 2013, at James A. FitzPatrick (JAF) Nuclear Power Plant, with the reactor at 100 percent power, performance of ISP-75 commenced at 0810 EST. ISP-75 functionally tests and calibrates the Condensate Storage Tank (CST) Low Water Level instrument channels of the High Pressure Coolant Injection (HPCI) System. During performance of this planned surveillance, the first level switch associated with the "B" CST that was tested (23LS-74B) failed to actuate. At 0938 EST, the Chief Instrumentation and Controls technician performing the test reported the failure of 23LS-74B to the Control Room Supervisor, and was directed to continue testing per ISP-75. Subsequent testing of the redundant "B" CST level switch (23LS-75B) revealed that the level switch actuated at a simulated CST level of 58.5 inches.

The combination of these two deficiencies would have prevented the HPCI automatic suction swap-over function until the "B" CST level dropped to 58.5 inches. This is less than the analyzed Technical Specification (TS) required value for low CST water level of 59.5 inches; per TS 3.3.5.1 Condition D, this would have resulted in the HPCI system being declared inoperable. Therefore, this event is reportable pursuant to 10 CFR 50.73(a)(2)(v)(D) as an event or condition that could have prevented fulfillment of a safety function.

The Reactor Core Isolation Cooling (RCIC) "B" condensate storage tank (CST) level switch (13LS-76B) failed to trip on November 4, 2013 while performing the switch's low water level functional test. The cause of the failure was a misalignment of the microswitch assembly. The microswitch assembly was replaced on September 17, 2013; it passed its functional test but microswitch alignment was not performed per vendor instructions which resulted intermittent performance.

Operable and are unaffected by this microswitch assembly misalignment. Upon discovery, 13LS-76B channel was placed in trip per plant Technical Specifications (TS) and RCIC is Operable. Since, TS require all 4 RCIC CST level switches to be Operable, RCIC was in a condition prohibited by TS. This report is being submitted in accordance with 10 CFR 50.73(a)(2)(i)(B).

The Reactor Core Isolation Cooling (RCIC) "B" condensate storage tank (CST) level switches failed to trip due to corrosion build-up caused by water intrusion. The first instance in which corrosion interfered with the trip mechanism was when 13LS-76B failed to trip due to corrosion while testing on July 16, 2013. The second instance was both 13LS-76B and 13LS-77B failed to trip due to corrosion on August 19, 2013. These two Operable and show no signs of being affected by corrosion or water intrusion. The "B" side channels share a junction box which is evidently the source of water intrusion from environmental conditions of the CST pit.

This deficiency is being corrected by replacing the affected level switches and update testing procedures to identify signs of corrosion.

The Technical Specifications (TS) requires all 4 RCIC CST level switches be Operable. Since two of the level switches were Inoperable due to corrosion the RCIC system also became Inoperable. Since the actions prescribed by the TS were not performed, the RCIC had been in a condition prohibited by TS, 10 CFR 50.73(a)(2)(i)(B).

On June 6, 2012, while the plant was in LCO 3.5.1 Action C.1, High Pressure Coolant Injection (HPCI) inoperable for planned maintenance, during the performance of Motor Operated Valve (MOV) limitorque and as found/as left viper diagnostic testing (for trending, data gathering, preventive maintenance, and corrective maintenance purposes), HPCI Suppression Pool Pump Suction Isolation MOV Valve (23MOV-57) failed to go completely open (it only opened 38%) after being manually closed. Upon discussions with the NRC Resident Inspector, the potential failure of this component of the High Pressure Coolant Injection (HPCI) system (a single train system) to completely open was subsequently determined to be a condition that would have prevented the fulfillment of the safety function of an SSC that mitigates the consequences of an accident and is therefore being reported under 10 CFR 50.73(a)(2)(v)(D). The level of judgment for reporting an event or condition under this criterion is a reasonable expectation of preventing fulfillment of a safety function.

The most probable cause was determined to be high contact resistance on open the limit torque switch most likely due to corrosion on the MOV contacts. Corrective actions included verifying the spring tension and cleaning the torque and limit switch contacts. The valve was then tested and determined to be operating properly.

On October 16, 2012, at 0529, with the reactor in mode 4 and one channel for the Residual Heat Removal (RHR) shutdown cooling isolation function Operable, as permitted by TS 3.3.6.1, Operators identified a rising reactor water level indication on instruments associated with the 3A reactor water level reference leg while actual level remained constant. At 0700, Operators determined this condition rendered the automatic RHR shutdown cooling isolation function on low reactor water level Inoperable. Operators continued to monitor water level and were capable of performing manual isolation. In accordance with Tech Spec 3.3.6.1 Required Action J.1, immediate action was initiated to restore isolation capability. Automatic RHR shutdown cooling isolation capability on low reactor water level was restored at 1040.

The cause was leakage past Reference Leg 3A Backfill System injection isolation valves, 02-3NBI-371 and 02-3NBI-372 after they were isolated for maintenance. This drained the reference leg and caused an inaccurate water level signal.

On September 16, 2012, James A. FitzPatrick Nuclear Power Plant (JAF) was reducing power for its scheduled Refuel Outage 20. During the power reduction, reactor pressure lowered below 800 psig prior to the full insertion of 52 control rods which were within the population for friction test control. These 52 control rods were conservatively declared Inoperable because friction testing was not performed within 14 days. This requirement is in accordance with the General Electric Part 21 notification, SC11-05 Revision 1, for Seismic Input in Channel-Control Blade Interference.

TS LCO 3.1.3 Condition E was entered for greater than 9 control rods declared Inoperable. This requires the plant to be placed in Mode 3 within 12 hours. Mode 3 was entered 2.5 hours later in accordance with the plan to shutdown for the Outage. The control rods remained fully functional and no control rod movement issues were experienced during the shutdown. An NRC notification was made per 10 CFR 50.72(b)(2)(i), initiation of any nuclear plant shutdown required by the plant's Technical Specification. This report is being made per 10 CFR 50.73(a)(2)(i)(A), completion of any nuclear plant shutdown required by the Technical Specifications. The SC11-05 compensatory actions will remain active. New fuel channels will be installed in future refueling outages to reduce the channel to control rod blade friction.

On 1/26/12, a first time low voltage pickup test was performed for 71MCC-163-OE5 (East Crescent Unit Cooler 66UC-22H Fan Motor). The contactor picked up at 102 VAC versus the 90 VAC Level 2(1) Acceptance Criteria. A calculation was performed to determine Level 1(1) Acceptance Criteria for this application. The Level 1 Acceptance Criterion was established as 97 VAC. The Unit Cooler was therefore non-functional, and is assumed to have been non-functional for a period of three years prior to the time of discovery. 66UC-22H is one of five Unit Coolers in the East Crescent Area Ventilation Subsystem.

A review of historical plant data identified five occurrences where the non-functional 66UC-22H resulted in the East Crescent Area Ventilation Subsystem being incapable of performing its specified function, and therefore non-functional. The East Crescent Area Ventilation Subsystem is required to support operability of the ECCS equipment located in the East Crescent. This ECCS equipment was therefore inoperable during the five time periods that were identified. This condition is prohibited by plant Technical Specifications, and resulted in the loss of safety function for the single train HPCI System.

Revision 1 is submitted as clarification, and to correct inaccuracies in the original report relative to how the reporting requirements of 10 CFR 50.73(a)(2)(i)(B) are met by this condition.

On January 11, 2011, with the "A" Refueling Floor Exhaust Radiation Monitor inoperable, the required action for Technical Specification (TS) 3.3.6.2 Condition A was not met within the required completion time of 24 hours. In addition, the required actions for TS 3.3.6.2 Condition C were also not met within the completion time of 1 hour after the action for Condition A was not completed. The failure to perform the TS required actions within the required completion times resulted in a condition prohibited by the TS which is reportable in accordance with 10 CFR 50.73(a)(2)(i)(B).

The apparent cause of this event is that control room personnel failed to verify that the actual plant configuration matched the configuration needed to remain compliant with the TS. Immediate corrective actions included isolating the reactor building ventilation system to restore compliance with the TS and briefing the operating crews on the error prior to assuming future watch standing duties.

The briefings were conducted by operations management who also reinforced expectations regarding shirt turnover and T5 compliance. Additionally, active LCOs are now visibly posted in the control room. Planned corrective actions include providing additional training and simulator scenarios on configuration control.

Safety valves in the Residual Heat Removal and Core Spray systems at the James A. FitzPatrick (JAF) Nuclear Power Plant failed to meet In-Service Testing (1ST) as-found acceptance criteria during surveillance testing conducted in February and March 2010. The most probable cause of the setpoint failure was the presence of internal binding and/or disc to seat corrosion bonding.

Component testing that falls outside the required action range for IST requires that the component be declared inoperable and the applicable Limiting Condition for Operation declared not met. 10 CFR 50.73(a)(2)(i)(B) allows licensees to consider the failure to have occurred at time of discovery unless there is firm evidence to indicate that the condition existed previously. Based on a review of test history, there is indication that this condition existed prior to discovery.

The event is reportable per 10 CFR 50.73(a)(2)(i)(B), "Any operation or condition which was prohibited by the plant's Technical Specifications..." because during the time period described, the Residual Heat Removal and core spray subsystems were inoperable longer than allowed by TS. This event is also reportable per 10 CFR 50.73(a)(2)(vii), "Any event where a single cause or condition caused at least one independent train or channel to become inoperable in multiple systems or two independent trains to become inoperable in a single system".

Review of the as-found test results for 11 Safety / Relief Valve (S/RV) (SB) pilot assemblies removed and replaced in September 2008, determined that 5 S/RVs were,outside the allowable as-found tolerance of 1145 psig +/- 3% (+/- 34.3 psig) required by Technical Specification (TS) Surveillance Requirement SR 3.4.3.1.

The effect of these S/RVs being out of tolerance was analyzed and the results of this analysis show that Reactor Pressure Vessel (RPV) overpressure protection and nuclear plant safety were not adversely affected. Consequently, the safety significance of this event was minimal. The most probable cause for the failure of four of the S/RVs was determined to be corrosion bonding between the S/RV pilot disc and seat, a recognized industry generic problem with two-stage Target Rock relief valves. The fifth failure was determined to be due to significant pilot valve seat leakage which would have required additional steam pressure to overcome the leakage and lift this S/RV.

On 10/07/2008, with the plant in Cold Shutdown (Mode 4), the trip and lockout relay associated with circuit breaker 71-10402 was manually actuated during a functional test resulting in a loss of power to 4160 VAC Emergency Bus 10600, auto-start of the "B" and "D" Emergency Diesel Generators (EDG) and a Primary Containment Isolation System (PCIS) Group 2 actuation. The PCIS Group 2 actuation resulted in the closure of containment isolation valves in multiple systems including Residual Heat Removal (RHR) shutdown cooling (SDC), Reactor Water Clean-Up (RWCU), Reactor Building Ventilation and Containment Atmosphere Monitoring (CAM) systems. Plant components and systems responded as expected with no anomalies noted. Operations restarted plant systems and restored shutdown cooling to service in accordance with plant procedures.

1 The cause of the event was the re-scheduling of a trip and lockout relay functional test outside of the bus outage work window without performing a risk assessment review. The functional test required actuating the trip and lockout relay associated with circuit breaker 71-10402, and as a result, power was lost to the 10600 Emergency Bus. During the event, the redundant 4160 VAC emergency bus and associated loads remained operable. Barriers providing safety to the public were not compromised during this event and the safety significance was minimal.

On July 22, 2002, with the reactor at 100 percent power, during the performance of the Core Spray (CS) Initiation Logic System Functional Test 3J (ST-3J), it was determined that the time delay for both "A' and 'V division CS pump start time delay relays exceeded the values required by Technical Specifications (TS). As part of the extent of condition evaluation on August 24, 2002, with the reactor at 100 percent power, the "C" and "D" Residual Heat Removal (RHR) Pump Start Timer Temporary Surveillance Test 120 (TST-120) was performed on the associated pump start time delay relays.

During this test, it was determined that the time delay for the "D" RHR pump start time delay relay exceeded the value required by TS by 0.03 seconds.

The equipment related root cause of the out of tolerance condition was a lack of relay "exercising" due to the extended test interval of the relays. The human performance related root cause was failure to assume the relay drift was time dependent, as required by procedure. A contributing cause was identified as inadequate guidance in a calculation verification checklist that allowed operating experience considerations to be neglected.

Interim corrective actions included recalibrating the CS and RHR relays and increasing their test frequency. Long-term corrective actions include replacement of the subject relays with a more suitable device and revising the associated calculation verification process.