|Report date||Site||Event description|
|05000498/LER-2017-001||11 May 2017||South Texas|
On March 10, 2017, during a Technical Specification surveillance, the as-found operating time of one of four undervoltage timing relays in a Safety related 4.16kV switchgear was greater than the Technical Specification allowable value. The relay was retested without making any changes to the relay timing or the test configuration.
The second test resulted in a lower value that was within the Technical Specification allowable value but outside the acceptance criteria of the procedure. A third test (and subsequent follow-up testing) resulted in values that met Technical Specification limits. The associated channel was declared Operable.
On March 14, 2017, an engineer reviewed the surveillance results and questioned the reliability of the relay based on its behavior. The Control Room was contacted and the relay was replaced. Based on the engineer's analysis, the Shift Manager determined that the relay should not have been declared Operable on March 10. The Technical Specification Action Statement required the inoperable channel to be placed in the tripped condition within 72 hours. This Action was not met and is reportable as a condition prohibited by Technical Specifications per 10 CFR 50.73(a)(2)(i)(B). 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.
|05000498/LER-2016-002||29 June 2016||South Texas|
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.
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.
|05000498/LER-2016-001||22 March 2016||South Texas|
On January 26, 2016, at 2324 hours, the Control Room received a Steam Generator Steam Flow/Feed Flow mismatch alarm. Operators found Steam Generator (SG) Train C Feedwater Regulating Valve closed and in manual. SG C Feedwater Regulating Valve could not be manually reopened. At 2325 hours, Operators manually tripped the Unit 1 reactor due to lowering level on SG C. The Auxiliary Feedwater (AFW) system automatically actuated on a SG low level signal and operators took manual control of AFW at 2327 hours.
The cause of loss of Main Feedwater to SG C was a failure of the Manual 7300 Series Tracking Driver (NTD) circuit card which forced SG C Feedwater Regulating Valve-closed and prevented the operators from taking manual control or switching back to automatic valve control. As a corrective action, the Manual NTD circuit card was replaced. 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.
|05000498/LER-2015-001||18 February 2016||South Texas|
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.
|05000499/LER-2015-001, Technical Specification Action Statement Time Exceeded Due to Turbine-Driven Auxiliary Feedwater Pump Test Failure Not Recognized||5 May 2015||South Texas|
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.
|05000499/LER-2013-004||20 March 2014||South Texas|
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.
|05000499/LER-2014-001||17 March 2014||South Texas|
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.
|05000498/LER-2013-003||23 December 2013||South Texas|
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.
|05000498/LER-2013-001||15 August 2013||South Texas|
On May 1, 2013, during performance of a routine surveillance, maintenance personnel determined that the Channel A Overpower Delta Temperature (OPDT) reactor trip setpoint Delta-Flux Penalty summing amplifier (NSA card) had failed low, effectively disabling the associated OPDT setpoint correction, which caused Delta Temperature / T-Average Channel A to be inoperable. Further investigation determined that there was evidence that the failure occurred on April 17, 2013. Thus, the Delta Temperature / T-Average channel was inoperable for approximately fifteen days, which is longer than permitted by Technical Specifications 3.3.1 and 3.3.2.
The failed circuit card replacement was completed on May 2, 2013 and after satisfactory surveillance testing on May 3, 2013, Delta-Temperature / T-Average Channel A was declared operable.
The risk significance of the event is considered very small. This event did not result in any offsite release of radioactivity or increase of offsite dose rates, and there were no personnel injuries or damage to any other safety- related equipment associated with this event.
The cause of the failure was determined to be random electronic component failure. Corrective actions will include revision to the channel check surveillance procedure to reduce the allowable acceptance criteria range for the OPDT setpoint.
|05000499/LER-2013-003||13 May 2013||South Texas|
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.
|05000499/LER-2013-001||28 February 2013||South Texas|
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 220.127.116.11.2. 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.
|05000499/LER-2011-003||30 January 2012||South Texas|
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.
|05000499/LER-2008-001||11 December 2008||South Texas|
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
|05000498/LER-2006-006||8 November 2007||South Texas|
Train D inverter following an electrical transient. The loads included a qualified display processing system (QDPS) cabinet that provides auxiliary feedwater (AFW) flow indication and control functions for the Train D turbine driven AFW train. As a result of the loss of AFW flow instrumentation, STP Unit 1 entered Technical Specification (TS) 18.104.22.168 Action 35, and TS 22.214.171.124 Action b. The allowed outage time for the AFW flow indication is 48 hours and expired at 0945 CST on December 17, 2006. The allowed outage time for the turbine-driven (TD) AFW train is 72 hours and would have expired at 0945 CST on December 18, 2006.
STPNOC determined the AFW flow instrumentation channel could not be restored prior to the expiration of the allowed outage times and requested enforcement discretion. NRC granted the enforcement discretion at 0839 on December 17, 2006, effective until 2145 hours on December 18, 2006.
STPNOC found that two of three Electrically Erasable, Programmable, Read-Only Memory (EEPROM) chips located on a QDPS central processing unit (CPU) circuit board had been damaged due to the electrical transient. STPNOC replaced the damaged EEPROMs and affected downstream circuit boards. QDPS Cabinet D2 and the functions above were declared operable at 2155 hours on December 17, 2006.
The electrical transient was caused by a capacitor failure in inverter 1202. The capacitor failure was due to a manufacturing defect. The affected capacitor bank was replaced on December 20, 2006.
|05000499/LER-2007-001||10 May 2007||South Texas|
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.
|05000499/LER-2005-003||10 May 2005||South Texas|
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 126.96.36.199 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.
|05000499/LER-2002-003||1 August 2004||South Texas|
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.
|05000498/LER-2004-004||7 June 2004||South Texas|
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
|05000498/LER-2003-003||15 October 2003||South Texas|
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.
|05000498/LER-2003-002||30 September 2003||South Texas|
At 0149 on March 1, 2003, a 24-volt DC (VDC) power supply in the Unit 1 Condensate Polishing System failed. This failure caused the Condensate Polishing service vessel outlet valves to close, as well as failure of the system bypass valve to open on high Condensate System differential pressure. The pressure transmitter signal that is required for opening the bypass valve was also not available due to the failed power supply. With all Condensate Polishing service vessel outlet valves closed and the system bypass valve closed, condensate flow to the deaerator was isolated. The Unit 1 reactor was manually tripped because of the ensuing decrease in deaerator level.
The cause was a design characteristic in which loss of one power supply disabled the differential pressure signal required to open the system bypass valve and the signal required to maintain the output valves open for the normal system flow path. The power supply was determined to have failed due to age-related degradation.
The affected power supply units have been replaced. A lock-up feature has been incorporated to ensure the Condensate Polishing Service Vessel outlet valves are locked in place in the event of a power supply failure.
A fault tolerant power circuit will be developed and installed to prevent recurrence.
This event resulted in no personnel injuries, offsite radiological releases, or damage to safety-related equipment. There were no challenges to plant safety.
|05000499/LER-2002-004||1 July 2003||South Texas|
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.
|05000498/LER-2003-001||20 March 2003||South Texas|
On January 19, 2003 at 1255, Unit 1 was in Mode 1 at 100% power and Unit 2 was in Mode 3 with the 2A and 2D Reactor Coolant Pumps running. While placing the North Bus Shunt Reactor in the switchyard in service, Unit 1 Standby Transformer received a lockout due to an over-current condition on the neutral of the Shunt Reactor. This caused the North Bus to clear and isolate the North Bus Shunt Reactor.
Unit 1 experienced a partial Loss of Offsite Power (LOOP) to Standby Bus 1G and 1H which supply power to Engineered Safety Feature (ESF) Trains 1B and 1C. The Train 1B and Train 10 Emergency Diesel Generators (EDG) started as a result of the ESF Actuation - LOOP. The Train 1C components automatically loaded per design. The Train 1B Sequencer did not automatically load resulting in the manual loading of the Train 1B components by the Reactor Operators.
Unit 2 experienced a partial LOOP due to the loss of the Unit 1 Standby Transformer which was supplying power to Auxiliary Busses 2F, 2J and Standby Bus 2F, which supplies ESF Train 2A. The Train 2A Emergency Diesel Generator automatically started and loaded as expected.
The cause of the loss of Unit 1 Standby Transformer was de-energizing the switchyard North Bus, which provides power, to the Standby Transformer, due to a malfunctioning motor operated circuit switcher.
There was no impact to radiological safety, safety of the public or safety of station personnel.
Corrective actions include changing the protective relay scheme for the Shunt Reactor.
|05000498/LER-2001-002||12 December 2001||South Texas|
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 188.8.131.52, 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.
|05000498/LER-2001-001||19 November 2001||South Texas|
On September 17, 2001, Unit 1 was in Mode 1 in coastdown operations in preparation for a refueling outage. A Train C Essential Cooling Water system outage was entered at 0200 hours in order to perform scheduled maintenance. On September 21, 2001, the Train C Essential Cooling Water pump was started in order to perform post-maintenance surveillance testing. The pump ran for approximately 10 minutes with what was thought to be adequate cooling and lubrication water flow. At approximately 2106 hours, the pump was manually stopped when output pressure dropped to zero. The pump was observed to come to an abrupt stop. Subsequent investigation identified that significant damage had occurred to the No. 2 pump bearing, and the lower pump shaft exhibited indications of overheating. The root cause of the pump damage was determined to be foreign material, which caused insufficient cooling/lubricating flow by obstructing the bearing flow orifices. Because pump repair time would exceed the 7-day Allowed Outage Time of Technical Specification 3.7.4, enforcement discretion was requested to permit continued operation of the unit while the pump was repaired. Enforcement discretion was granted on September 23 at 1800 hours. Repair work was completed and on September 26, 2001 at 0905 hours the Train C Essential Cooling Water system and the associated systems it supports were restored to operable status.
Corrective actions include revising operating procedures to contain additional pump stop criteria based on indicated lube water flow, and revising maintenance procedures to add specific foreign material exclusion/cleaning requirements prior to pump reassembly.
This event was reviewed for risk impact and found to be risk insignificant since the conditional core damage probability was approximately 8.24E-7.
|05000498/LER-2003-005||3 November 504 JL||South Texas|
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 184.108.40.206, 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.