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At 0411 EDT on April 15, 2015 the Beaver Valley Power Station (BVPS) Unit 1 reactor was manually tripped from approximately 85 percent power following a condensate pump trip. Prior to the manual reactor trip the unit was performing an emergent power reduction after the identification of a degrading condition on the "A" condensate pump motor. All control rods fully inserted into the core. The auxiliary feedwater system actuated as designed.

The unit was stabilized in Mode 3 with the normal main feedwater system in service and the auxiliary feedwater system properly secured.

The "A" condensate pump trip was caused by the failure of the inboard motor bearing due to lack of oil lubrication.

The root cause evaluation determined that responses to technical questions were provided without the appropriate technical rigor or validation of assumptions regarding acceptable oil level for the pump motor.

This event was reported (EN 50985) as an event or condition that results in the actuation of the reactor protection system when the reactor is critical, 10 CFR 50.72(b)(2)(iv)(B) and specified system actuation, 10 CFR 50.72(b)(2)(iv)(A). This event is reportable pursuant to 10 CFR 50.73(a)(2)(iv)(A) as a condition that resulted in the manual actuation of the Reactor Protection System, 10 CFR 50.73(a)(2)(iv)(B)(1), and the automatic actuation of the Auxiliary Feedwater System 10 CFR 50.73(a)(2)(iv)(B)(6).

On January 6, 2014, the Beaver Valley Power Station (BVPS) Unit 1 tripped from full power due to a main transformer differential protection main unit generator trip as a result of a main unit transformer failure. All three Auxiliary Feedwater (AFW) pumps automatically started, as expected, due to lowering steam generator levels. The Turbine Driven Auxiliary Feedwater (TDAFW) pump ran for 1 hour and 49 minutes at which time the pump tripped due to governor oscillations. The TDAFW pump was declared inoperable. Subsequent investigation determined that the governor oscillations were due to a misadjusted governor needle valve that was last set during refueling outage 1R22 in October, 2013. Therefore the pump was inoperable from the time Mode 3 was entered on November 1, 2013 at 1006 hours. Technical Specifications (TS) require three trains of AFW to be operable in Modes 1 through 3. Entry into Mode 3 and operation with an inoperable pump, for longer than permitted by the TS, constitute conditions prohibited by TS. During this time each of the Motor Driven AFW pumps were rendered inoperable, separately, for maintenance and/or testing. This constitutes a condition that could have prevented the fulfillment of a Safety Function. The governor has been properly adjusted and the appropriate procedures will be revised.

This event is being reported under 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by Technical Specifications and under 10 CFR 50.73(a)(2)(v)(B) as a condition that could have prevented the fulfillment of a Safety Function - Remove Residual Heat.

As a result of recent industry operating experience (OE 305419, EN 49411, EN 49419) regarding the impact of unfused Direct Current (DC) ammeter circuits in the Control Room, Virgil C. Summer Nuclear Station (VCSNS) performed a review of ammeter circuitry. On October 16, 2013, the review determined the described condition to be applicable to VCSNS resulting in an unanalyzed condition with respect to 10CFR50 Appendix R analysis requirements.

The wiring design for the ammeters contains a shunt in the current flow from each DC battery or charger. The ammeter wiring attached to the shunt does not contain fuses. It is postulated that a fire could cause one of the ammeter wires to hot short to ground. Concurrently, the fire could cause another DC wire from the opposite polarity on the same battery or the same battery charger to also short to ground. This would cause a ground loop through the unfused ammeter cable. The potential exists that the cable could heat up causing a secondary fire in the ammeter raceway. The secondary fire could adversely affect safe shutdown equipment and potentially cause the loss of the ability to safely shutdown per 10CFR50 Appendix R.

The apparent cause of this event is double short to ground faults of opposite polarity were not considered during the design process of the Battery System. A corrective action has been added to the National Fire Protection Association (NFPA) 805 implementation to provide a permanent solution to address this unanalyzed Appendix R condition. As an interim action, roving fire watches have been established for the affected areas.

During the Beaver Valley Power Station (BVPS) Unit 1 1R22 Refueling Outage, a through wall defect was discovered during a planned visual examination of the Reactor Containment Building (RCB) steel liner. The BVPS Unit 1 containment design consists of an internal steel liner that is surrounded by reinforced concrete.

Investigation and laboratory analysis determined that there were indications of two through wall penetrations with a possible third penetration slightly off-set from the second. The total combined area of the three penetrations was calculated to be 0.395 square inches. A visual inspection of 100 percent of the accessible liner area was completed. No additional significant indications of corrosion were identified. Prior to startup from 1R22, the RCB steel liner was repaired and tested satisfactory.

The direct cause of this event was determined to be pitting type corrosion, originating from foreign material introduced during the original construction of the containment wall.

An evaluation determined that there is reasonable assurance that the containment was operable during the period of time that the plant was operated with the small areas of through wall corrosion on the steel liner.

Therefore, there was no loss of safety function and the safety significance is considered to be very low. This event is being reported under 10 CFR 50.73(a)(3)(ii)(A) as a condition resulting in a principal safety barrier being degraded.

On July 10, 2013, at 09:50 PDT, while performing the periodic hot-washing of the 500 kV insulators, a flashover of the Phase A 500 kV to ground across the Phase A lightning arrestor occurred and actuated the 500 kV differential relay. The actuation of the 500 kV differential relay opened the Unit 2 generator output breakers to isolate the generator, which then actuated a turbine trip. Since Unit 2 was operating above the 50 percent power permissive, the reactor protection system initiated a Unit 2 reactor trip. All plant equipment responded as designed.

Diablo Canyon Power Plant (DCPP) staff determined the root cause of this event to be the hot-washing of the Phase A transmission line string insulators (500 kV dead-end insulators) with inadequate controls for oversight of supplemental PG&E transmission line personnel and on-line maintenance risk analysis that resulted in a conductive overspray, which induced an external arc around the lightning arrester insulation resulting in flashover. The corrective action to prevent reoccurrence involves the development and implementation of a maintenance strategy for 500 kV dead-end insulators to ensure they remain adequately contamination free, structurally sound, and minimize risk to DCPP.

There were no personnel injuries, no offsite radiological releases, and no damage to safety-related equipment associated with this condition. This condition did not have an adverse effect on the health and safety of the public.

On June 25, 2013 with the plant in Mode 1, the "A" Chiller (XHX0001A) shut down during a fast bus transfer of its 7.2 kV bus power supply due to the tripping of two molded case circuit breakers (MCCBs) located on the "A" Chiller skid. The "A" Chiller was running prior to a planned fast transfer of its 7.2 kV bus power supply from the normal power source (115kV) to the alternate source (230kV). Troubleshooting found both compressor motor MCCBs in the tripped condition.

The instantaneous trip calibration of the MCCBs was designed to trip the breakers with an incoming current greater than the nominal value of 2000A, and a current greater than this magnitude was experienced during this event. Trips of the MCCBs require local operator action to restart the chiller. A subsequent restart attempt resulted in both compressor motors not starting. The "A" Chiller has peen considered to be inoperable since being placed into service August 5, 2011 due to the inability of the chiller to respond to Engineered Safety Features (ESF) sequencer demand following a grid perturbation similar to the bus voltage transient that occurred with a "fast transfer" scenario. The Chilled Water System is an attendant cooling water system that supports the Control Room Emergency Filtration System (CREFS). VCSNS Technical Specifications (TS) 3.7.6 requires two trains of CREFS to be operable while in Mode one through four.

The MCCBs on the Chiller skid have been adjusted to trip at higher amperage. The instantaneous trip setting for the MCCBs has been changed from 2000A to an instantaneous trip range of 3063A to 3938A.

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Waterford 3 declared Emergency Diesel Generator B (EDG-B) inoperable on May 22, 2013 due to inability to maintain room temperature within design limits. Subsequent trouble shooting revealed that the variable pitch room exhaust fan had failed due to separation of the fan hub from the hub sleeve. Examination of recent operating data showed that the first evidence of fan failure had been during a surveillance test the previous month. An apparent cause evaluation determined the probable cause of the failure to be the result of repairs made during a previous (1999) fan motor replacement. These repairs caused additional stresses on the fan hub components which eventually resulted in fan hub separation from the hub sleeve. The EDG-B room exhaust fan was repaired and EDG-B operability was restored on May 26, 2013. Safety significance for the event is characterized as low to moderate. This condition is reportable under the following criteria:

10 CFR 50.73(a)(2)(i)(B), 10 CFR 50.73(a)(2)(ii)(B), and 10 CFR 50.73(a)(2)(v)(D).

A review of plant reactor coolant temperature trends from a planned outage shows that on April 29, 2013, reactor coolant temperature was raised from approximately 135 degrees F to approximately 180 degrees F as a planned evolution. On April 30, 2013, RCS temperature was raised from approximately 180 degrees F to approximately 345 degrees F as a planned evolution. Additionally, on April 30, 2013, plant operations involving water additions to the Volume Control Tank were conducted. A review of the Station Log shows that only one ENI log channel was operable during these evolutions. These evolutions were prohibited by the plant's Technical Specifications under these conditions.

TS 3.3.1 Action 4 requires, with only one log power channel operable in Mode 5 or Mode 4, suspending "all operations involving positive reactivity changes," and is clarified by an applicable note which states, "Limited plant cooldown or boron dilution is allowed provided the change is accounted for in the calculated shutdown margin.

Planned corrective action is to revise the TS bases for TS 3.3.1 to emphasize the limitations for usage of the note applicable to Action 4.

The planned heatup and dilution evolutions had no discernable effect on nuclear safety.

Refueling Outage Cycle 17, Unit 2 source range (SR) instrument N-32 experienced an unexpected increase in indicated counts per second (cps). Other available SR indications showed no rise in cps. At the time, SR instrument N-31 was inoperable. Since operators considered N-32 inoperable while N-31 was already inoperable, the audible count rate in the control room was no longer reliable. DCPP determined this condition constituted a loss of a safety function required to maintain the reactor in a safe shutdown condition and was reportable in accordance with 10 CFR 50.73(a)(2)(v)(A).

Following a vendor failure analysis, DCPP determined that a discontinuity in the cable insulation shield caused the N-32 high count rate readings. DCPP replaced the faulted cable. This condition did not adversely affect the health and safety of the public.

At 09:31 on September 3, 2011, with Millstone Power Station Unit 2 operating at 100 percent power in Mode 1, the "A" train service water loop was declared inoperable when leakage from a degraded service water spool piece degraded beyond pre-established limits. Plant Technical Specification 3.7.4.1 stipulates with one service water loop inoperable, restore the inoperable loop to operable status within 72 hours or be in cold shutdown (Mode 5) within the next 36 hours. Since the leak was unisolable, operators commenced a plant shutdown.

Cold Shutdown Mode 5 was entered at 17:03 on September 4, 2011.

The direct cause of the service water leak was a degraded coating on the piping flange located in the "A" train 10-inch service water line to the emergency diesel generator heat exchangers. The degradation mechanism of the flange is attributed to galvanic corrosion of the carbon steel material. Carbon steel is anodic to the adjacent alloy surfaces.

The pipe spool flange was replaced.

This event is being reported pursuant to 10 CFR 50.73(a)(2)(i)(A) as completion of a nuclear plant shutdown required by the plant's Technical Specifications.

On the morning of April 6, 2004, a Tornado Warning was issued for the South Texas Project. Unit 1 was in Mode 1 at 100% power. Unit 2 was in Mode 5 in a refueling outage. The Unit 1 Control Room directed all plant personnel to seek shelter over the public address system at 1140. Security Officers in elevated and ground positions were relocated inside the Mechanical Electrical Auxiliary buildings. Officers at the station checkpoints were relocated to the East Gate House and the Nuclear Support Center. At 1143 a Security Alert was declared by the Security Force Supervisor as defined in the Safeguards Contingency Plan.

Since the requirements of 10 CFR 73.55(e) and (h) were not met, the Unit 1 Shift Supervisor invoked 10CFR50.54(x) at 1151 for the protection of security personnel. The declaration of a Security Alert is an entry condition into the site Emergency Plan at the Unusual Event level. In accordance with site procedures the Unit 1 Shift Supervisor declared an Unusual Event at 1151.

The Owner Controlled Area and Protected Area patrols were secured at 1151 for their safety. At 1300, after the weather subsided, the security force began recovery by returning to the pre-tornado warning positions. At 1319, the site exited the Security Alert and the Unusual Event. The intrusion detection and threat assessment equipment were tested and compensatory measures established if appropriate. A search of the Protected Area was conducted and completed satisfactorily at 1422.

z NRC FORM 366 (7-2001