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On March 11, 2015 at 1631 hours, a review performed by the Operations Surveillance Coordinator discovered that a surveillance performed on March 4, 2015 on the Unit 2 turbine-driven auxiliary feedwater (AFW) pump 24 did not meet the surveillance acceptance criteria for as-found discharge pressure. An operability review was subsequently performed and on March 12, 2015 it was determined that AFW pump 24 was inoperable as of March 4, 2015 at 1507 hours. As a result, the Technical Specification allowed outage time of 72 hours was exceeded and the Configuration Risk Management Program was not applied; this is reportable per 10CFR50.73(a)(2)(i)(B). During the period of AFW pump 24 inoperability, a second auxiliary feedwater pump was also inoperable on March 9, 2015 resulting in a condition that could have prevented the fulfillment of the safety function of systems that are needed to remove residual heat which is reportable per 10CFR50.73(a)(2)(v)(B). AFW pump 24 was not recognized as inoperable due to human error. As a corrective action, the operators were coached and counseled and remediated by Operations Management.

An actual demand for AFW did not occur during the period of inoperability; therefore, there was no adverse effect on the health and safety of the public.

On December 31, 2013, an approximately three gallon per minute Essential Cooling Water (ECW) leak was discovered on Standby Diesel Generator (SDG) 23 at a one-half inch aluminum-bronze threaded connection. The leak was first identified as a 60 drop per minute leak on November 6, 2013. A reportability review completed on January 16, 2014 determined that SDG 23 had been inoperable since the initial leak was discovered, resulting in a safety system inoperability duration of approximately 55 days, 12 hours, and 27 minutes.

This event is reportable under 10 CFR 50.73(a)(2)(i)(B) as a prohibited by Technical Specifications and under 10 CFR 50.73(a)(2)(v) as a condition that could have prevented the fulfillment of a safety function.

The risk significance of the event is considered to be very small. The leaking aluminum-bronze tee and nipple assembly for SDG 23 was replaced on December 31, 2013 and there was no additional damage to any safety-related equipment associated with this event. The event did not have an adverse effect on the health and safety of the public.

The cause of the failure was erosion of the aluminum-bronze nipple and tee assembly that led to a through-wall ECW leak.

Corrective actions include the replacement of the remaining aluminum-bronze nipple and tee assemblies on the SDGs with stainless steel components.

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.

At 07:05 on 1/4/2013, Unit 2, while at 100% power, commenced surveillances OPSP03-RS-0004 and OPSP03-RS-0001 to satisfy the monthly requirements of Technical Specification 4.1.3.1.2. and to demonstrate the shutdown and control rods are Operable by movement of at least 10 steps in any one direction.

During testing, two rods on shutdown bank E (SBE) dropped to the bottom of the core and a manual reactor trip was required. The dropped rods on SBE occurred while inserting shutdown bank C (SBC) rods in 6 steps. After SBE rod M-8 dropped, rod motion was stopped. While validating the dropped rod, a second rod, D-8, in SBE dropped. At 09:41, once both dropped rods were validated by diverse indications of power, flux, and rod positions, a manual reactor trip was performed. Troubleshooting identified the problem as high resistance on Rod Holdout Mode Selector (RHMS) switch contacts in Rod Control Power Cabinet SCDE when the contacts should have been closed. This blocked the multiplexing signal to the SBE Stationary Regulation card resulting in dropped rods.

This condition is considered reportable under 10 CFR 50.73(a)(2)(iv)(A), any event or condition that resulted in manual or automatic actuation of any of the systems listed in paragraph 10 CFR 50.73(a)(2)(iv)(B). 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 11/26/11 at 2121 hours, Unit 2 received the Stator Coil Water (SCW) Differential Temperature high alarm. The crew determined generator thermocouple T6144 on the SCW outlet of Coil 33T was reading higher than the other thermocouples. l&C Technicians conducting a local check subsequently reported the Coil 33T thermocouple was reading within the differential temperature band. On 11/27 multiple Generator Condition Monitoring (GCM) alarms were received. The operating crew subsequently removed the Coil 33T thermocouple from service by substituting a known value. At 0310 on 11/29/11 a Stator Cooling Water trouble alarm was received. Th- Unit 2 Reactor tripped at 0329 hours on 11/29/11 due to Main Generator Lockout. An initial inspection of the main generator revealed significant stator coil damage. Approximately three feet of stator Coil 33T (top coil in slot 33) was melted or missing on the exciter end.

The failure analysis determined the most likely cause was a very small leak in a hollow strand in Coil 33T. Analysis supports that this leak existed for a long time and allowed moisture to travel inside the coil. The moisture degraded the resin in the coil allowing the conductor bundle to come loose. This condition allowed some individual conductor strands to move and vibrate. The strand-to-strand vibrations wore away the insulation and created shorts. The shorts caused excessive heating. The affected area grew due to thermal damage until the coil arced across the missing melted area. The potential exists that the small leak was located in the portion of the coil that is melted/missing. If so, it will not be possible to ascertain the root cause of the leak. After the final failure analysis reports are received, the root cause report and LER will be evaluated and revised if warranted.

This condition is considered reportable under 10 CFR 50.73(a)(2)(iv)(A), any event or condition that resulted in manual or automatic actuation of any of the systems listed in paragraph 10 CFR 50.73(a)(2)(iv)(B). 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 Monday, March 7, 2005, preparations were being made to implement a modification to Unit 1 during its refueling outage. Isolation of two actuation cabinets of the Solid State Protection System was required to complete the modification. Prior to isolation, it was determined that this would make the Cold Overpressurization Mitigation System (COMS) inoperable when Technical Specification 3.4.9.3 required that it be operable. This was resolved by rescheduling the system isolation. Subsequent review found that while installing a similar modification on Unit 2 during the preceding Unit 2 refueling outage, two actuation cabinets were de-energized, making COMS inoperable without compensatory action as required by Technical Specifications. This was found to be reportable on March 11, 2005.

The root cause of this event was that the operational impact on COMS of de-energizing the 'A' and 'B' SSPS actuation cabinets for maintenance was not recognized. Detailed information regarding which equipment/components would be affected was not readily available in a usable format for review. , For corrective action, a load list will be developed for each of the Solid State Protection System actuation cabinets identifying the affected components and their state when the cabinet is de-energized. This information will be included in the applicable operating procedure. As a compensatory action until the corrective action is completed, the system engineer will be contacted to confirm the extent of impact on plant equipment/components prior to implementation of scheduled work activities that include de-energizing SSPS equipment.

This event resulted in no personnel injuries, no offsite radiological releases, and no damage to other safety-related equipment.

On January 25, 2003 with Unit 2 in MODE 5, 2-RH-MOV-0060C, Loop C RHR pump suction valve, failed to open. 2-RH-MOV-0060C failed when the motor stalled and overheated causing the breaker to trip. This motor failure was caused by the motor pinion gear sliding down the motor shaft and contacting the de- clutching mechanism resulting in increased frictional loading. The motor pinion set-screw was not installed correctly in the drilled recess on the shaft. Consequently, when the motor was energized the pinion gear was thrust into the declutching mechanism. Coincident with this condition, the pinion key was also observed to be partially disengaged from the motor shaft keyway; however, this discrepancy was determined not to have contributed to the failure.

Corrective actions include rework of MOV-0060C, inspection and repair as required of all potentially affected Unit 1 and Unit 2 motor operated valves (MOVs), and confirmation that the maintenance procedures for MOVs is adequate to assure proper installation of the setscrews.

This event resulted in no personnel injuries, offsite radiological releases or damage to safety related equipment other than MOV-0060C.

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 November 23, 2017, a routine surveillance on the South Texas Unit 1 Train "C" Control Room Makeup and Cleanup Filtration System failed due to the Train "C" control room makeup filtration system heater de-energizing approximately two minutes after actuation. The makeup filtration system heater de-energized due to an improperly configured jumper on a circuit board associated with the Train "C" control room makeup filtration unit outlet low flow switch. The circuit board had been installed with the improperly configured jumper on September 27, 2017. The circuit board was properly configured and returned to service on November 24, 2017.

This resulted in the Train "C" Control Room Makeup and Cleanup Filtration System being inoperable for 58 days; the associated Technical Specification allowed outage time for this condition is 7 days. The cause of the event is the maintenance work instructions did not include steps to: (1) ensure that the circuit board jumper is in the correct position, and (2) conduct a post-maintenance test to ensure proper operation of the heaters. As a corrective action, the applicable maintenance work instructions will be revised to (1) ensure that the circuit board jumper is in the correct position, and (2) conduct a post-maintenance test to ensure proper operation of the heaters.

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 May 20, 2013 with Unit 1 in Mode 1 at 100 percent power, the auxiliary feedwater (AFW) flow loop 4 channel D high limit was found low out of tolerance during the performance of a scheduled surveillance. This condition resulted in the flow control valve for steam turbine-driven AFW pump not being capable of providing required flow to its respective steam generator under all accident conditions thus making the pump and flow regulating valve inoperable. Subsequently, it was determined that this condition had existed since December 14, 2012 during an earlier troubleshooting activity. The affected components were inoperable for a period longer than permitted by Technical Specifications. The steam turbine-driven AFW pump and flow regulating valve were restored to operable status on May 21, 2013. The overall AFW system safety function was met because multiple trains of AFW were available during this period. This condition was determined to be reportable on May 29, 2013.

The cause of this event was that procedures were not implemented properly due to unclear requirements.

Corrective actions include clarification of procedure guidance.

The risk significance of the event is considered very small. This event did not result in any offsite release of radioactivity or increase in offsite dose rates. There were no personnel injuries or damage to any other safety-related equipment.

On April 30, 2011, South Texas Project (STP) Unit 1 was in refueling outage 1RE16, with the unit in Mode 5, Reactor Coolant System loops not filled. In support of a planned evolution to transfer water from the 1B Recycle Holdup Tank (RHT) to the Volume Control Tank, a Senior Reactor Operator (SRO) assigned to review atypical plant conditions during the outage identified a potential dilution source that was not included in the plant surveillance procedure used to confirm compliance with Technical Specification 3.4.1.4.2 regarding unborated water sources. Although the valves were not secured closed as required by TS, the valves were closed and no dilution occurred.

Technical Specifications were revised in 2003 to remove references to specific valves required to be isolated with respect to unborated water sources and replaced with more generic language. However, the impact of using the RHT as a fill source was not adequately addressed with respect to compliance with the new TS requirements, and thus the surveillance procedure used to ensure compliance did not address all unborated water sources. Because the same TS, plant procedures, and administrative controls applied to both units, Unit 2 was similarly affected.

The corrective action was to revise the plant surveillance procedure used by both Units to ensure compliance with TS 3.4.1.4.2 and TS 3.9.1 to reflect the additional valves that must be secured in the closed position to comply with the TS. This corrective action was implemented in accordance with the STP Corrective Action Program.

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