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On May 19, 2017, at 0206 hours, an unexpected Reactor Protection System (RPS) actuation occurred during pre-startup testing. The reactor was shutdown at the time, with all control rods inserted. The portion of the test that was in progress is designed to actuate the RPS from a loss of load input signal. To facilitate this part of the test with the reactor in a shutdown mode, one of two conditional steps in the procedure is to be taken. The generator motor operated disconnect 389 (MOD-389) is required to be in the open position, or protective trip circuity for the generator is required to be bypassed.

Due to a conditional step of the test procedure being misinterpreted by a Nuclear Control Operator (NCO), MOD-389 was left in the closed position and the generator protective trip circuity was not bypassed. This resulted in the RPS actuation occurring prior to the preplanned sequence. The RPS responded as designed. All components operated as expected for the plant conditions.

The cause of the unexpected RPS actuation was human performance errors during procedure performance, e.g., lack of self-validation/verification, misinterpretation of information, and lack of peer check verification.

Corrective actions from the event include the removal of the NCO's licensed operator qualifications until remediated and initiation of a standing order requiring peer check verification for all procedure conditional steps until the applicable administrative procedure is revised. Additionally, a case study of the event will be included in a 2017 operations high intensity training session.

On September 16, 2015, at approximately 0117 hours, an anomaly within the digital electro-hydraulic (DEH) turbine control system initiated a turbine trip. As designed, the turbine trip actuated the reactor protection system to automatically trip the reactor due to a loss of load and the auxiliary feedwater system started automatically to recover steam generator levels.

The direct cause of the event is the turbine tripped due to actuation of the "DEH controller loss of power" turbine trip logic. Troubleshooting and analysis determined there was a failure of a power supply module on a circuit board in the DEH turbine control system. Subsequent to the power failure on the circuit board, a second failure, either a loss of power to the overspeed protection control (OPC) distributed processing units (DPUs) or a loss of communications between the primary and backup OPC DPUs, occurred resulting in an actuation of the "DEH controller loss of power" turbine trip logic.

The root cause of the event is that the design of the DEH system contains unnecessary trip logic associated with turbine overspeed monitoring. Corrective actions include a modification to remove the DEH system OPC loss of power and loss of communications trip logic.

At 1102 on August 13, 2013, both control room ventilation filtration system trains were declared inoperable in accordance with Technical Specification (TS) 3.7.10, Condition B, due to the inability to fully close control room envelope (CRE) boundary door-15. At 1111 on August 13, 2013, door-15 was closed and TS 3.7.10, Condition B, was exited. TS 3.7.10 allows CRE boundary doors to be opened intermittently, under administrative control for preplanned activities, provided the doors can be rapidly restored to the design condition.

During preplanned maintenance activities, workers attempting to exit the CRE area were unable to open door-15 via normal operation of the door's hand wheel. Recent frequent operation of door-15 may have caused deformation of a cotter pin within the door's normal operating mechanism. Deformation of the cotter pin could cause the normal operation of door-15 to function intermittently. To allow exiting, workers opened door-15 using the emergency egress latch that activated an alarm condition on the door. During exiting, inadvertent operation of the door's hand wheel in the closed direction caused the door's latching pins to extend out causing interference between the door and the door frame preventing door-15 from fully closing.

Due to the door being in an alarmed condition, the door's latching pins were unable to be immediately retracted. After approximately nine minutes, the door's latching pins were retracted by use of the emergency egress latch and the door was restored to the design condition, i.e., closed.

The cotter pin was replaced. Future potential corrective actions include increased preventative maintenance frequency to replace the cotter pin and restricting the use of the emergency egress latch.

On February 10, 2013, due to a slowly lowering level trend in the component cooling water (CCW) surge tank, investigations began to identify a potential CCW leakage path. On February 14, 2013, at 2030 hours, the right train of the CCW system was declared inoperable due to the identification of an approximate 40 gallons per hour CCW leak into the service water system section of the "A" CCW heat exchanger. The "A" CCW heat exchanger is one of two essentially identical ASME Section III class 3 heat exchangers installed in the CCW system.

Technical Specification 3.7.7.A.1 requires restoration of an inoperable CCW system train within 72 hours. Due to the inability to repair the leak within the required 72 hour time frame, a plant shutdown was initiated at 1300 hours on February 15, 2013. The plant entered Mode 3 at 1649 hours on February 15, 2013. At 1111 hours on February 16, 2013, the plant entered Mode 5 to execute repairs.

The majority of CCW leakage was attributed to one tube, located in the center of the tubesheet, within the CCW heat exchanger. Very minor leakage was identified from the tube plug area of seven previously plugged tubes. Due to the inability to fully isolate CCW system flow into the heat exchanger, the failed tube could not be inspected to determine a definitive failure mechanism.

Mechanical type tube plugs were installed in the tubes where leakage was identified.

On August 12, 2012, with the plant in Mode 3, a primary coolant system pressure boundary leak was identified in control rod drive mechanism (CRDM) number 24 upper housing assembly. Upon identification, the plant was placed in Mode 5 to effect repairs.

Initial examination, using liquid penetrant testing in the area of the leak, identified a 1/8" x 1/16" L-shaped crack indication on the outside surface of the type 316L stainless steel pipe section of the CRDM-24 upper housing assembly. Subsequent non-destructive and destructive examinations revealed a total of nine axially oriented crack indications, located in the proximity of an inside surface weld onlay. One of the nine crack indications was a through-wall crack at the leak point approximately 3" in length.

The CRDM-24 upper housing assembly was removed and replaced with an upper housing assembly of modified design. Examinations using ultrasonic testing of eight additional CRDM upper housing assemblies were performed on an area 1" below to 1-1/2" above the area of interest. No deficiencies were noted.

The direct cause for the cracking identified in CRDM-24 was transgranular stress corrosion cracking (TGSCC). TGSCC was the result of stress in the proximity of the inside surface weld onlay caused by manufacturing irregularities and misalignments between CRDM-24 upper housing assembly and supporting components. Based on the lack of crack indications in the additional eight upper housing assemblies examined, the failed CRDM-24 upper housing assembly was subject to an additional stress that has not yet been identified.

On October 14, 2008, after completing reviews of evaluations performed by Entergy Nuclear Operations, Inc. (ENO) engineering, the Nuclear Regulatory Commission (NRC) closed an unresolved issue related to potentially non-conservative setpoints for the low suction pressure trip (LSPT) of the auxiliary feedwater (AFW) pumps. The potentially non-conservative setpoints, which were first identified on February 13. 2006, could have existed at certain Condensate Storage Tank (CST) levels and AFW pump flow rates.

The CST is the normal suction source of the AFW pumps. In the extreme unlikelihood of a tornado, a tornado-generated missile could have caused a rupture near the bottom of the CST. The rupture may have allowed rapid draining of the CST, without completely emptying the tank. Subsequent automatic operation of the AFW pumps after a plant trip could have caused the onset of vortexing within the CST, leading to air entrainment in the auxiliary feedwater suction piping and pumps. This entrained air could have rendered the AFW pumps inoperable. Consequently, the AFW system may not have been capable of supplying the steam generators with Lake Michigan water, as outlined in the Palisades Nuclear Plant design basis.

This condition is being reported in accordance with 10 CFR 50.73(a)(2)(v)(D) as a condition that could have prevented the fulfillment of the safety function of a system needed to mitigate the consequences of an accident.

On July 15, 2008, with the plant in Mode 1 at 100% power, Entergy Nuclear Operations, Inc. personnel discovered that the Palisades Nuclear Plant region 1 spent fuel pool (SFP) storage racks contain less neutron absorber material than assumed in the SEP criticality analysis of record. This neutron absorber material is relied on to maintain the region 1 SFP storage racks within the Technical Specification (TS) 4.3.1.1.b criticality requirements. � The TS reflects credit for the neutron absorber material in maintaining SFP criticality within limits. At the time of discovery, SFP boron concentration was 2732 ppm.

� TS 4.3.1.1.b requires that Keff for region 1 fuel racks be less than or equal to 0.95 if fully flooded with unborated water.

With soluble boron required to maintain Keff less than or equal to 0.95 in the region 1 fuel racks, assuming nominal enrichment, PNP no longer complies with TS 4.3.1.1.b.

The degraded neutron absorber material did not involve an immediate safety concern at the time of discovery because the SFP boron concentration was 2732 ppm, and a SEP criticality operability assessment concluded that a soluble boron concentration of 150 ppm is required to maintain a Keff less than or equal to 0.95 in the region 1 racks. � In addition, plant procedures required that SFP boron concentration be maintained at a minimum of 2550 ppm in Modes 1 through 4. In Modes 5 and 6, 1800 ppm was required. A past operability evaluation confirmed that SFP boron concentration had been maintained greater than 2550 ppm in recent years. Compensatory measures are in place. This condition does not represent a safety system functional failure. This is reportable in accordance with 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by TS.

On March 26, 2008, with the plant in Mode 1 at 100% power, during planned maintenance on high pressure safety injection (HPSI) pump P-66A, operators experienced difficulty in removing the P-66A 2400VAC breaker 152-207 from its cubicle. A mechanism-operated cell (MOC) switch operator (bayonet) located inside the breaker cubicle was found with two broken connections, The condition of the MDC switch bayonet would have prevented operating a contact that provides a permissive to open HPSI subcooling control valve CV-3071, thereby rendering P-66A inoperable. It was concluded that the MOC switch bayonet failed when breaker 152-207 operated on January 3, 2008. The MOC switch bayonet was replaced on March 26, 2008.

The cause was determined to be that the MOC switch bayonet design is marginal for the force applied by the stored energy vacuum breaker 152-207. The contributing cause is a failure to validate that the MDC switch used during manufacturer testing matched the switches installed at the plant.

The opposite train MOC switch bayonet was inspected and no damage was found. Subsequently the MDC switch bayonets for the safety bus switchgear were inspected. Replacement of the MOC switch bayonet and others of the same type in stored energy breaker cubicles is planned.

On March 25, 2003, at 1116 hours, with the plant in Mode 6, a loss of offsite power occurred while installing a signpost. The signpost penetrated a buried conduit, damaging a control power cable associated with both offsite power feeds. As a result, the safety-related and non-safety related buses de-energized, which caused a loss of shutdown cooling flow. The emergency diesel generators started and loaded safety-related buses, as expected. An Alert was declared at 1126 hours. Shutdown cooling -flow through the core was restored in approximately 20 minutes. The Alert was downgraded to an Unusual Event at 1231 hours. The Unusual Event was exited on March 27, 2003, at 1737 hours, when offsite power was fully restored.

This occurrence is reportable in accordance with 10 CFR 50.73(a)(2)(v)(B) as an event that prevented the fulfillment of the safety function of a system needed to remove residual heat, and in accordance with 10 CFR 50.73(a)(2)(iv)(A), as an event that resulted in automatic actuation of the emergency AC electrical power system.

NRC FORM 368 (7-2001)

On January 15, 2003, at 2015 hours, with the plant in Mode 1, it was determined from a review of surveillance procedure basis information, that all four steam generator (SG) reactor protection system (RPS) low-level trip setpoints in each SG were set such that the trip could occur below the allowable value specified in Technical Specification (TS) 3.3.1. The SG low-level trip setpoints were declared inoperable. It was determined that this condition had existed since 1998.

TS 3.3.1 requires four associated instrument channels, for the SG low-level RPS trip functions, to be operable in Modes 1 and 2, and in Modes 3, 4 and 5 when more than one full-length control rod is capable of being withdrawn and the primary coolant system boron concentration is less than refueling boron concentration. TS 3.3.1 does not provide a condition for four SG level instrument channels being inoperable. Therefore, TS 3.0.3 was entered. Nuclear Management Company, LLC, (NMC), requested enforcement discretion to extend the completion times in TS 3.0.3 by an additional 36 hours to avoid a plant shutdown. The Nuclear Regulatory Commission Staff verbally exercised discretion on January 16, 2003 at 0017 hours.

This occurrence is reportable in accordance with 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by Technical Specifications.

On December 1, 2002, at approximately 2154 hours, with the plant operating at 100% power, an automatic reactor trip occurred on main generator loss of load. The loss of load occurred when a transmission tower's static line hanger failed, allowing one of two static lines to contact a 345 KV transmission line, tripping the main generator. The static line also contacted the rear bus in the switchyard that supplies the plant non-1E 4160 volt startup transformers. The rear bus tripped on a fault-to-ground causing a loss of non-1E 4160 volt AC buses. Consequently, both main feedwater pumps tripped, and the auxiliary feedwater system started automatically on low steam generator level, as expected.

The plant was maintained at or near normal operating pressure and temperature subsequent to the trip, on natural circulation, since startup power for primary coolant pumps was also lost. The plant was returned to service on December 5, 2002.

This event is reportable in accordance with 10 CFR 50.73(a)(2)(iv)(A) as an event that resulted in an automatic reactor trip and automatic actuation of the auxiliary feedwater system.