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On May 1, 2016 at 2020 hours, STP Unit 1 experienced a Main Generator lockout due to a ground relay actuation resulting in an automatic turbine trip that lead to an automatic reactor trip. Visual inspections revealed that a rubber boot located where Main Generator phase B enters the isolated phase bus duct was degraded. A piece of the boot was hanging down and intermittently contacting the generator bushing causing a resistance path to ground, resulting in a Main Generator lockout and turbine trip signal. With the reactor at greater than fifty percent power, the automatic reactor trip was initiated in response to the turbine trip. The Auxiliary Feedwater (AFW) system actuated in response to low Steam Generator level. All safety systems operated as expected.

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As immediate corrective actions, the A, B and C phase rubber boots were replaced in Unit 1. The cause evaluation determined that the design of the rubber boot and its retaining ring is inadequate. Design change packages are being developed to permanently remove the rubber boots and retaining rings for both Unit 1 and Unit 2.

The automatic actuation of the Reactor Protection System and automatic AFW actuation are both reportable under 10 CFR 50.73(a)(2)(iv)(A). The event was of very low risk significance and no radioactive release occurred; therefore, there was no adverse effect on the health and safety of the public.

On December 21, 2015, at 1519 hours, Operators manually tripped the Unit 1 Main Turbine due to excessive load swings caused by Main Turbine Governor Valve 2 (GV2) oscillations. Prior to and following the trip of the Main Turbine, the Steam Dumps did not respond as expected, resulting in a Main Feedwater Isolation at 1524 hours due to rising Steam Generator (SG) level. Operators initiated a manual reactor trip at 1533 hours due to lowering SG levels. Approximately six seconds after the reactor trip, the Auxiliary Feedwater (AFW) system automatically actuated on a SG low level signal.

The cause of the GV2 oscillations was an intermittent ground on the signal wire to the Linear Variable Differential Transmitter (LVDT) for GV2. The fluctuations in steam flow due to the GV2 oscillations caused the spring clips in the valve positioners that modulate the Group 1 Steam Dumps to become dislodged, causing the Group 1 Steam Dumps to be unresponsive. As corrective actions, the LVDT and associated cabling for GV2 was replaced and the Group 1 Steam Dump valve positioners were repaired. The manual actuation of the Reactor Protection System and subsequent automatic AFW actuation are both reportable under 10 CFR 50.73(a)(2)(iv)(A). The event was of very low risk significance and no radioactive release occurred; therefore, there was no adverse effect on the health and safety of the public.

On December 19, 2013, while in Mode 3 preparing the Unit 2 secondary plant for startup, conditions occurred where it became necessary to break vacuum on the main condenser. The Operator closed the Main Steam Isolation Valves (MSIVs) using the Main Steam Isolation Actuation switch due to the urgency to prevent damage to the main turbine.

This action constitutes a valid manual actuation of multiple MSIVs and is therefore reportable under 10 CFR 50.73(a)(2)(iv)(A).

The risk significance of the event is considered to be very small. This event did not result in any offsite release of radioactivity or increase the offsite dose rates, and there were no personal injuries or damage to any safety-related equipment associated with this event.

The cause of the event was unspecific guidance in the off normal procedure for secondary plant stabilization. The failure of the bearing oil lift piping placed the Control Room Staff in a situation that required prompt action to prevent equipment damage, and the Staff made a decision to use the MSI Actuation switch as a result of the unspecific written guidance to ensure MSIVs and Main Steam Isolation Bypass valves (MSIBs) are closed.

The corrective action will be to revise the off normal procedure for secondary plant stabilization to provide specific direction for the switches to use for closing the MSIVs.

On October 31, 2013, at approximately 1834 Central Daylight Time during review of industry operating experience, South Texas Project (STP) determined an unanalyzed condition exists related to the Control Room (CR) fire analysis. The original design of ammeter circuits which provide CR current indication for the non-Class 48 VDC battery and battery charger circuits and for the non-Class turbine lube oil emergency pump control circuit does not include overcurrent protection features to limit fault current. In the postulated event, a fire in the CR could cause a ground loop through unprotected ammeter wiring or control circuit wiring and potentially result in excessive current flow and heating to the point of causing a secondary fire outside the CR in the cable raceways.

The postulated secondary fire could affect the availability of equipment needed to place the plant in a safe shutdown condition during a CR fire event. This scenario has not been analyzed in accordance with 10 CFR 50 Appendix R. Compensatory fire watch measures have been implemented and remain in place for the affected fire zones in the plant.

The cause was determined to be that the original design of the affected CR circuits did not adequately address fire protection program requirements. A design change is planned to correct the latent design deficiencies by providing circuit protection on affected CR circuits.

With Essential Cooling Water (ECW) Pump 2B unknowingly inoperable, the plant staff was unaware that the associated Limiting Conditions of Operation (LCO) were not met when Unit 2 reached greater than 5% rated thermal power and entered Mode 1 on 01/07/2013 at 0053, in violation of LCO 3.0.4. This event is considered reportable under 10 CFR 50.73(a)(2)(i)(B).

On 01/06/2013 at 2100, just prior to the mode change, a temperature excursion began on the ECW Pump 2B lower motor bearing, which peaked below the alarm setpoint before returning to normal by 01/07/2013 at 0125.

This excursion was identified on 01/14/2013. Analysis of subsequent vibration data indicated a bearing defect with a step increase in vibration data. Without reasonable assurance that the pump would meet its mission time, ECW Pump 2B was declared inoperable on 01/15/2013 at 1200. Due to lack of any other abnormal temperature or vibration data available for the degraded condition, the pump is considered to have been inoperable since the start of the temperature excursion.

The bearing degradation was due to insufficient tolerance in the motor shaft endplay, as set during refurbishment.

Corrective actions are planned to specify this design parameter for subsequent refurbishments, and to increase endplay adjustment shim thickness in the affected ECW pump motors to reduce bearing wear.

On November 20, 2011 at 0546 hours (CS'), STP Unit 2 transitioned modes from Mode 4 to Mode 3. Prior to the mode change, the Solid State Protection System (SSPS) generated turbine trip signals were defeated by a maintenance work activity that installed a jumper in both channels (Train R and S) of non-class relays to the turbine trip circuit. The SSPS signals to the non-class relays that were defeated by the jumpers included the turbine trip from reactor trip breakers open (P-4), turbine trip from a reactor trip signal (P-16), and the turbine trip from Steam Generator HI-HI (P-14). In accordance with Technical Specification (TS) 3.3.2 Item 5a and 5b, P-4 and P-14 are required in Modes 1, 2, and 3. The jumpers were removed around 0930 on November 20, 2011 with U2 still in Mode 3. Since Unit 2 had changed Modes from 4 to 3 with TS 3.3.2 Item 5a and 5b and the associated Limiting Conditions of Operation (LCO) Actions not met, this is a condition prohibited by Technical Specification 3.0.4. A review of the performance of this activity in previous outages was conducted. It was identified that a similar event had occurred during 2RE14 in April of 2010. This event, including the one in April 2010, was reported as required by 10 CFR 50.72(b)(3)(v) parts (C) and (D).

The Cause of the event was determined to involve the revision of the associated maintenance work activity's Preventive Maintenance Instruction (PMI). Specifically, the MODE requirement prerequisites in the PMI were revised without full consideration of the Operational restrictions associated with changing plant conditions during procedure performance. The corrective action to prevent reoccurrence includes removing the mode restrictive steps of the associated PMI while adding them to the 7300 ProtectionSystem Channel Trip Function Bypass procedure.

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 October 16, 2008, while planning fuel movements in the Unit 2 spent fuel pool (SFP), a Category 11 fuel assembly was discovered in a location where only Category 9 fuel is allowed. Following this discovery, the incorrectly stored fuel was removed from its location and placed in an area of the SFP with no adjacent fuel assemblies. A Category 11 assembly is less reactive than a Category 9 assembly, and the as-found configuration was bounded by the safety analysis.

The investigation identified that the error occurred in the mapping of the SFP storage configuration, which is subsequently used to create fuel transfer forms (FTF). Both the FTF preparer and verifier performed inadequate self checking and review. Contributing factors included a lack of detailed written guidance for performing this task and that the Reactor Engineer (RE) preparing the FTF did not realize that some fuel assemblies had decayed directly from a Category 8 to a Category 11. This resulted in fuel moves that stored a Category 11 assembly adjacent to Category 9 assemblies, which is not permitted by the Technical Specifications. A procedural guideline to control the process of developing the SFP configuration map is being developed to prevent future occurrences. In addition, all individuals who are responsible for performing this task were briefed on management expectations related to preparation, peer checking, and attention to detail. Both Unit 1 and Unit 2 SFPs were checked for a similar condition. No other occurrences of incorrectly stored fuel were identified.

NRC FORM 366 (9-2007) PRINTED ON RECYCLED PAPER

On March 5, 2007, Unit 2 Auxiliary Feedwater Pump 23 was started for a post maintenance test. During the test, it was noted that the pump discharge flow was not as expected. Investigation determined that the closed Long Path Recirculation Isolation Valve 2-AF-0092 was leaking by its seat. It was determined that there was no lubrication of the portion of the valve stem just below the actuator. When the valve actuator was disassembled, the stem nut was found broken into two pieces. The valve was repaired and lubricated on March 9, 2007.

The operational impact of this condition was that the design bases flow to the steam generator was not achieved for this condition such that Auxiliary Feedwater Pump 23 and its associated flow path were inoperable. On March, 14, 2007 it was determined that this condition existed for a period of time longer than the allowed outage time of the Technical Specifications.

The cause of the stem nut failing is that no periodic preventive maintenance existed to lubricate the stem.

Corrective actions include (1) repair and lubrication of 2-AF-0092, (2) verification of the functionality of the long path recirculation isolation valves for each AFW System train in both units, (3) cleaning, lubrication and inspection of auxiliary feedwater system long path recirculation isolation valves in both units, (4) review of the adequacy of current preventive maintenance scope and frequencies of risk-significant valves in the auxiliary feedwater system and (5) revision of surveillance procedures to include testing to verify that the auxiliary feedwater flow path long path recirculation isolation valves do not have seat leakage.

This event resulted in no personnel injuries, no offsite radiological releases, and no damage to other safety-related equipment. The event was of very low safety significance.

On July 7, 2002 Unit 2 was operating in Mode 1 at 100% power. The Unit 2 main turbine generator tripped automatically due to a High-High level in the 2B steam generator (SG). The reactor tripped automatically as a result of the main turbine trip. The trips occurred shortly after the Channel II inverter and distribution panel de-energized. The loss of the distribution panel and inverter resulted in the loss of power to the instrumentation channels selected to control narrow range steam generator water level. This failure resulted in loss of SG level signal to all four SG Main Feedwater Regulating Valve (MFRV) control circuits because they were all selected to the same channel. This caused the MFRVs to go fully open. With the MFRVs fully open, water level increased in all four steam generators. Steam generator 2B reached its high-high level set point resulting in the main turbine trip and the feedwater isolation signal.

The cause of the inverter failure and distribution panel loss of power was a change in breaker E2D11/3A characteristics. As the breaker has aged, the time differential between opening of the breaker contacts has increased.

As a result, the contact opening has become more sequential and less simultaneous. The second cause of the reactor trip was having all four steam generator level control switches aligned to a single control channel coupled with the loss of power to instruments on that channel. Corrective actions include splitting the SG level channels to two separate control channels, revising a procedure to deselect the channel affected by the battery charger swap at the SG level controls and inverter replacement. Additionally, the installation and testing of suppression diodes to Class lE battery charger relays was included. This event resulted in no personnel injuries, offsite radiological releases or damage to safety related equipment. There were no challenges to plant safety and the plant responded as expected.

On April 12, 2003, with South Texas Project Unit 1 in a refueling outage, personnel discovered deposits at two Bottom Mounted Instrument (BM1) nozzles of the reactor vessel. This condition was identified during the station's regular bare metal inspection of the reactor vessel bottom penetrations, which is done as part of the RCS Pressure Boundary Inspection for Boric Acid Leaks Program. A small amount of residue was noted around the circumference of BM1 nozzle Penetrations #1 and #46 where they enter the reactor vessel.

The residue consisted of approximately 150 milligrams of material from penetration number 1 and approximately 3 milligrams from penetration number 46. No wastage was observed on the outside of the bottom head, and samples of the residue were collected and analyzed. Both deposits contained boron and elevated levels of lithium consistent with reactor coolant system (RCS) leakage. Cesium isotopic analysis indicated an approximate age of 4 years for each sample.

Ultrasonic testing was performed on all of the 58 BMI penetrations. Cracks were found in Penetrations #1 and #46, however, no cracks were found in any other penetration. The root cause is the use of Alloy 600 combined with nozzle manufacturing and installation methods that further increased the susceptibility of the metal to stress corrosion cracking when in contact with primary water.

The nozzles at Penetrations #1 and #46 were repaired prior to restart of Unit 1.

This event resulted in no personnel injuries, no offsite radiological releases, and no damage to safety-related equipment other than the affected BMI penetrations. There were no challenges to plant safety.

At 1808 hours on December 15, 2002, Unit 2 was at 100% power when it was manually tripped due to excessive vibration in Low Pressure Turbine 22. Subsequent investigation identified that a blade had cracked and broken off and was ejected from the low pressure turbine into the condenser. Additional cracked blades were found in Low Pressure Turbines 22 and 23.

The cause of the blade cracking was a design flaw with the rotor train (natural frequency modes near 120 Hz) and a faulty new generator rotor (differences between old and new rotor cause increased rotor train response). These flaws were not recognized by the vendor, Siemens-Westinghouse, due to errors in their modeling of the Turbine-Generator rotor system. Corrective actions include repairing the Unit 2 rotor system and damaged blades, installing vibration monitoring equipment, and evaluating the data taken during and after the Unit 2 restart. Subsequent studies confirmed that the corrective actions were effective in reducing torsional vibrations and the plant has operated continuously since March 2003.

This event resulted in no personnel injuries, offsite radiological releases or damage to safety related equipment. There were no challenges to plant safety and the plant responded as expected.

On October 13, 2001 Unit 1 was shutdown in Mode 6 in refueling outage 1RE10. Information was received from an offsite vendor that during pressurizer safety valve "as found" set point testing, valve N1RCPSV3451 had a lift pressure of 2406 psig which is low outside of the Technical Specification required setpoint of 2485 psig +/-2% (2435.3 to 2534.7). Valve N1RCPSV3452 had an "as found" lift pressure of 2411 psig. On October 15, 2001 the vendor reported that safety valve N1RCPSV3450 had an "as found" lift pressure of 2422 psig. These test results constitute a violation of Technical Specification 3.4.2.2, Reactor Coolant System - Operating. The root causes of the valves failing the "as found" lift tests include: (a) the inherent differences between the "as left' test conditions and the "as found" test conditions, plus nozzle loading effects which are inducing stresses and misalignments in the valves, and (b) the narrow tolerance band of +/- 2% which is too restrictive considering the valve nozzle loading effects and these inherent differences. Corrective actions include installation of replacement valves with "as left' lift settings of 2485 psig +/- 1%, and requesting a Technical Specification change to optimize setpoint tolerances for the Pressurizer Safety Valves "as found" lift setpoints.

The "as found" Pressurizer Safety Valve setpoints did not violate any safety analysis limits and did not adversely impact Reactor Coolant System overpressurization or Departure from Nucleate Boiling Ratio analysis.

On September 4, 2003, Unit 1 was operating at 100% power when a routine surveillance test run of Auxiliary Feedwater Pump (AFWP) 11 was attempted. When operators attempted to start the pump, the supply breaker failed to close. The pump had been successfully run twice since the breaker was overhauled in June 2003. After the breaker was replaced with a spare, the surveillance was completed satisfactorily.

The cause of the failure was determined to be increased mechanical resistance of the breaker mechanism caused by a random build up of tolerances from wear and case distortion which our existing overhaul program did not identify, coupled with a significant reduction in latch spring rotational torque capability (6 turn spring).

It was determined that AFWP 11 was out of service while Standby Diesel Generator (SDG) 13 was out of service on August 18 and 19, 2003, in violation of Technical Specification 3.8.1.1, Action D.

This event resulted in no personnel injuries, no offsite radiological releases, and no damage to safety-related equipment. There were no challenges to plant safety.