Semantic search
| Discovered date | Reporting criterion | Title | Event description | |
|---|---|---|---|---|
| ENS 40225 | 5 October 2003 07:00:00 | 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident | Inoperable Trains of Control Room Emergency Filtration at Hope Creek | While performing common mode failure testing of the Emergency Diesel Generators (EDG), the 'C' EDG was declared INOPERABLE for planned installation of required test equipment. Concurrent with the inoperability of the 'C' EDG, the 'B' Control Room Emergency Filtration (CREF) System has been INOPERABLE for emergent corrective maintenance since 10/2/03 at 0502. Because the 'C' EDG is the emergency power supply for the 'A' CREF train, 'A' CREF was also declared INOPERABLE and Technical Specification 3.0.3 was entered as of 0300 hrs on 10/05/03. At 0430 hrs on 10/05/03, the test equipment was removed from 'C' EDG, thereby restoring it and 'A' CREF to an operable status, and Technical Specification 3.0.3 was exited. Testing did verify the absence of a common mode failure and all EDG's are operable. The Control Room Ventilation System provides heating, cooling, ventilation, and environmental control for the control room and adjacent areas. Under accident conditions, CREF ensures that the control room will remain habitable during and following all design basis accidents. Because the CREF system is required to automatically respond in the event of a design basis accident, having both trains of CREF inoperable at the same time impacted the ability to mitigate the consequences of an accident. Therefore, this event is being reported in accordance with 10CFR50.72(b)(3)(v)(D). The plant is currently in HOT SHUTDOWN for repair of an emergent turbine hydraulic fluid leak, with decay heat removal to the main condenser via turbine bypass valves. The NRC resident inspector was notified by the licensee.
At the time of the original notification, both trains of Control Room Emergency Filtration (CREF) were declared inoperable impacting the ability of CREF to mitigate the consequences of an accident. The "B" train was inoperable for emergent corrective maintenance and the "A" train was declared inoperable when test equipment was connected to the "C" emergency diesel generator (EDG). The "C" EDG provides emergency power to the "A" train of CREF. Subsequent to this event, an evaluation of the test equipment impact to the "C" EDG was performed and determined that the "C" EDG would still be capable of providing emergency power to the "A" CREF train in the event offsite power is lost. Therefore, the "A" CREF train remained available to respond to a design basis accident. Thus, the safety function would have been fulfilled." R1DO (Brain McDermott) notified. The NRC Resident Inspector will be notified of this retraction by the licensee. |
| ENS 40350 | 23 November 2003 10:19:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation | Reactor Was Manually Tripped After a Control Rod Dropped During Low Power Physics | During performance of low power physics testing for dynamic rod worth measurements, control rod bank D was being withdrawn. At control bank D position of 209 steps, control rod 1D4 dropped into the reactor core. The control room crew entered the abnormal operating procedure for a dropped (control) rod at 0507. Based upon the dropped control rod causing the reactor to go subcritical, the abnormal operating procedure directs that all (control) rods to be inserted. Based upon the control bank D not being fully withdrawn and not in the proper bank overlap due to low power physics testing, the Control Room Supervisor directed the reactor to be (manually) tripped. The crew entered the emergency operating procedure at 0519. All equipment functioned as designed and all major equipment is available. (The crew) exited the emergency operating procedures at 0538. The plant is currently stable in mode 3 at normal operating temperature and pressure. The cause of the drop rod is reported to be a blown fuse on the stationary coil. All reactor coolant pumps are in service and decay heat removal is through the steam dumps to the condenser. All control rods fully inserted when the reactor was manually tripped. Feedwater to the steam generators is being supplied by the auxiliary feedwater system. The licensee has notified the NRC Resident Inspector and will be notifying the LAC (Lower Alloways Creek) Township. |
| ENS 40406 | 22 December 2003 14:27:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Reactor Trip Due to Main Turbine Trip | At 0827 on 12/22/2003, Comanche Peak Unit Two (2) tripped due to a turbine trip > 50%. The turbine trip was caused by ingestion of a small metallic cover plate into the main generator exciter housing, as witnessed by maintenance personnel. A small fire ensued, which self-extinguished in five (5) minutes. An Aux Feedwater auto start (ESF actuation) occurred due to normal post-trip steam generator shrink. The turbine-driven and both motor-driven aux feedwater pumps started as designed. All control rods inserted into the core upon trip. The local electrical grid is stable. The number one (1) steam generator atmospheric relief valve cycled as designed upon the secondary pressure transient. The number three (3) Reactor Coolant Pump tripped during the transfer of power sources post-trip. Unit 1 was not affected by the trip. Unit 2 is stable in Mode 3. Damage assessment is in progress which will determine future (near-term) plant mode of operation. RCPs are in operation transferring decay heat to the steam generators. Decay heat removal is through the MSIVs to the main condenser using the turbine steam dump valves. Both motor-driven AFW pumps are running to maintain Steam Generator levels. The trip of the number (3) Reactor Coolant Pump is being investigated. The licensee notified the NRC Resident Inspector. |
| ENS 40424 | 3 January 2004 01:38:00 | 10 CFR 50.72(a)(1)(i), Emergency Class Declaration | Unit 1 Declared an Unusual Event Due to 14 Gpm Unidentified Rcs Leakage | At 2038EST Unit 1 Control Room Operators observed and quantified unidentified RCS leakage of approximately 14 gpm based on containment sump pump operation and a corresponding decrease in VCT level. Unit 1 was preparing for startup and there were no ongoing maintenance activities at the time. The licensee declared an Unusual Event entering their emergency procedures to isolate and identify the source of the leakage. As a result, a pressurizer sample line was isolated which terminated the leakage. The licensee will remain in the Unusual Event until an investigation is completed confirming that this was the source. There was no measured increase in radiation levels/humidity inside containment or radioactive release to the environment. At the time of the report, 3 of the 4 RCPs were operating for forced circulation with the 4th RCP secured earlier in the day during a test. All ECCS systems are available including the EDGs, if needed. Normal makeup is in service to maintain RCS inventory with MFW supplying the Generators for decay heat removal via the steam bypass to the Main Condenser. The licensee informed state/local agencies and will inform the NRC Resident Inspector. At 2158EST the NRC determined that this event did not require entry into the Monitoring Phase of Normal Mode.
The licensee terminated the NOUE at 2353 hours EST on 01/02/04. The leak has been identified as coming from a relief valve flange on the pressurizer sample line. Maintenance activities are on-going to repair the leak and the reactor remains in mode 3. The licensee has notified state and local government of the NOUE termination and will be notifying the NRC Resident Inspector. Notified R2DO (David Ayres), FEMA (Dan Sullivan), DIRO (Tim McGinty), NRR (Pao-Tsin Kuo), NRC (Thomas) |
| ENS 40451 | 15 January 2004 23:50:00 | 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident | Potential Gas Binding of Centrifugal Charging Pump | The following information was obtained from the licensee via facsimile: During routine 31-day ECCS (Emergency Core Cooling System) venting per SR (Surveillance Requirement) 3.5.2.3 on January 7, 2004, a higher than normal amount of gas was vented from a location on a line off the common suction line for both charging pumps (NV pumps) for Unit 1. The amount of gas vented was not initially considered to be an operability concern. As a conservative measure the frequency of venting was increased from monthly to weekly. Follow-up venting on January 14 indicated the amount of gas vented from this location had increased. Gas was also collecting at a second location at a high point in the NV system. The second location was near the normally-closed valve 1ND-28A. 1ND-28A completes the lineup for 'piggy-back' flow from the Train 'A' decay heat removal system (ND) into the NV system. The type of gas from both locations was determined to be hydrogen. The increased presence of gas was considered a potential operability concern and an operability evaluation was initiated. Venting was increased to once per shift. The source of the hydrogen gas intrusion is unknown and is being investigated. On January 15 at 1850 (EST) it was determined that the amount of gas discovered on January 14 at both locations was greater than what is bounded by current analysis to ensure gas binding of both NV pumps would not have occurred. Since January 14, subsequent venting at the first location (NV pump common suction line) has resulted in gas volumes within the analysis limits. The amount of gas at the second location (Train 'A' piggy-back tie in) initially decreased but increased again on January 15. As a result, the power was removed from 1ND-28A to prevent the transfer of gas into the NV pump suction line. This action results in Unit 1 Train 'A' of ECCS being inoperable and entry into TS (Technical Specification) 3.5.2 Action A1 on January 15 at 1857(hrs). Train 'B' of ECCS is considered currently operable with 1ND-28A closed and continued increased venting. Licensee notified the NRC Resident Inspector. This places Unit 1 in a 72-hr Limiting Condition for Operation (LCO). Unit 2 is not affected.
UPDATE ON POTENTIAL FOR GAS BINDING CENTRIFUGAL CHARGING PUMPS On January 15, 2004, Catawba reported potential for gas binding Unit 1 centrifugal charging pumps (Refer to Event Number 40451). Normally-closed valve 1ND-28A completes the lineup for 'piggy-back' flow from the Train 'A' decay heat removal system (ND) for Train 'A' of ECCS. Gas accumulation near 1ND-28A became an operability concern on January 15 for both centrifugal charging pumps. On January 15, 1ND-28A was deenergized (power removed) to prevent the potential transfer of gas into ECCS suction piping. Deenergizing this valve placed Unit 1 into the 72 hour action statement of TS 3.5.2 (ECCS) and 3.6.6 (containment spray). Subsequent ultrasonic testing (UT) of several ECCS vent locations, including the one at 1ND-28A, revealed the piping to be essentially full of water. Based on the UT results, Catawba concluded the gas intrusion was a discrete event and that a current gas production mechanism did not exist. Based on the ECCS piping remaining essentially full of water over a period of approximately 60 hours, power was restored to 1ND28A and Catawba exited TS 3.5.2 and 3.6.6 at 1725 on January 18. Catawba continued with UT a several ECCS locations every six hours as a prudent measure. At 0350 on January 19, UT revealed a void at the 1ND-28A location that was larger than the currently established acceptance criteria. The gas was vented and water solid conditions established at 0506. TS 3.0.3 was entered from 0350 until 0506 due to the discovery of the gas at 1ND-28A. The cause of the gas intrusion into the ECCS piping continues to be investigated. Frequent UT and venting (if necessary) continues while the root cause evaluation is in progress. Power was removed from 1ND-28A and the 72 hour action statements of TS 3.5.2 and 3.6.6 entered at 0715 on January 19. Licensee notified the NRC Resident inspector. The Reg 2 RDO(Haag) was informed |
| ENS 40537 | 22 February 2004 20:10:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Manual Scram at Peach Bottom 2 Due to Decreasing Condenser Vacuum | Peach Bottom Unit 2 reactor was manually scrammed due to degrading main condenser vacuum. The reactor was manually scrammed prior to reaching the automatic scram setpoint. All plant systems responded as expected with no significant issues noted. A Group II and Group III Primary Containment Isolation was received due to reactor water level passing through 1 inch. All isolation systems responded as required and repositioned to their expected positions. The licensee also indicated that all control rods properly inserted into the core. The method of decay heat removal was using the main condenser. The licensee initiated a post scram review to identify and correct the source of degrading vacuum. The licensee also indicated the manual scram was initiated at 25 inches and lowering of condenser vacuum. The licensee notified the NRC Resident Inspector. |
| ENS 40570 | 6 March 2004 05:50:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Manual Reactor Trip at Millstone 2 Due to Spurious Trip of the "B" Feed Pump | The licensee reported that the "B" Steam Generator Feed Pump tripped unexpectedly and would not reset causing lowering steam generator water levels. Operators manually tripped the reactor and all control rods properly inserted. The auxiliary feed water (AFW) system automatically initiated to restore steam generator water levels. The lowest steam generator water level observed during the event was 55% level as opposed to the normal level of 70%. No primary relief valves lifted. Operators established decay heat removal capability using AFW system and the atmospheric steam dump valves. The licensee initiated a post trip review to determine the cause of the feed pump trip. The NRC Resident inspector has been notified by the licensee. |
| ENS 40591 | 16 March 2004 01:20:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Automatic Reactor Trip at Millstone 2 Due to Spurious Loss of One Main Feed Pump | The licensee reported that an automatic reactor trip occurred on 3/15/04 at 2020 EST due to the spurious trip of one main feed pump which caused a low steam generator water level trip signal. The plant has two main feed pumps. Operators reset the tripped main feed pump but steam generator levels didn't recover in time. The lowest level observed was in the "B" steam generator at 15% level as compared to the normal level of 65%. The trip setpoint is at 50% level. All control rods properly inserted into the core. The auxiliary feed water system automatically initiated as designed and expected. The plant remains stable in mode 3 while the licensee commenced the post trip review to determine the cause of the main feed pump trip. Decay heat removal was established using the AFW system to feed steam generators and bleed steam to the main condenser through the condenser dump valves. The licensee notified the NRC Resident Inspector. |
| ENS 40639 | 3 April 2004 15:50:00 | 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Valid Actuation of Auxiliary Feedwater System During Maintenance | This is an 8-hour notification being made to report that a valid ESF Auxiliary Feed actuation occurred. Salem Unit 1 is in mode 5 with RHR providing shutdown cooling. '11' Aux Feed Pump was in service to fill '13' and '14' steam generators for wet lay-up conditions. Actual levels were low in both '13' and '14' steam generators but jumpers were installed on steam generator narrow range level channel III and IV to prevent an ESF actuation. On 4/03/04 at 1050 AM, a breaker effecting reactor protection system channel III was cleared and tagged as part of preparations to remove 1C 4KV vital bus from service. The actual low level in '13' and '14' steam generators along with the power loss to channel III caused 2 out of 3 logic to be satisfied and initiated an AFW actuation. '11' Auxiliary Feed Pump remained running. '12' Auxiliary Feed Pump auto started. '13' Auxiliary Feedwater Pump was removed from service prior to the actuation and did not start. The '13' and '14' steam generators continued to fill. '11' and '12" Auxiliary Feed Valves (11AF21 and 12AF21) were closed and no level rise was observed. The breaker was restored and reactor protection system channel III was placed back in service. All auto start signals cleared after power was restored and the '12' Aux Feed Pump was stopped at 1101. There were no unusual or unexpected plant response from the actuation. All safety systems and equipment performed as expected. Entry into mode 6 is expected this afternoon and progress of the refueling outage is expected to continue. There were no personnel injured. The licensee will inform the Lower Alloways Creek Township (LAC) and has informed the NRC Resident Inspector.
On April 3, 2004 at 1410 PSEG made an 8 hour notification to report a valid ESF actuation of the auxiliary feedwater system (Event Number 40639). At the time of the report 11 Auxiliary feedwater pump was in service to fill the 13 and 14 steam generators for wet lay-up. The levels on those generators were low (as previous plant condition had demanded) and the jumpers had been installed in the level detectors to prevent the automatic start of the auxiliary feedwater pumps. 12 auxiliary feedwater pump was out of service. The steam driven auxiliary feedwater pump was tagged out of service. Core heat removal was being provided by the Residual Heat Removal System. On April 3, with the steam generator level being carried below the low level setpoint, in accordance with procedures, as a result of other activities associated with the refueling outage the installed jumpers were removed causing the auto start of the 12 pump. Subsequent investigation Into this event and further review of NUREG 1022 has determined that the condition described above is not reportable under the requirements of 10CFR50.72(b)(3)(iv) or 50.73(a)(2)(iv). As stated In NUREG 1022 the intent of reporting under this paragraph is '..to report actuations of systems that mitigate the consequences of significant events .. The Staff does not consider this to include single component actuation because single components of complex systems, by themselves usually do not mitigate the consequences of significant events.' Furthermore valid signals are defined as ' those signals that are Initiated in response to actual plant conditions .. Satisfying the requirements for initiation of a safety function of the system.' (emphasis added on safety function). In this particular event the required Safety Function to maintain the core cooled and decay heat removal was being accomplished by the Residual Heat Removal System and it remained unaffected throughout this event. The plant was in a condition where the steam generators in conjunction with the Auxiliary Feedwater System were not part of the ultimate heat sink or a principal means to remove decay heat. The Auxiliary Feedwater System was only functional and available to provide a means to place the steam generators in wet lay-up in support of outage activities. The 11 pump was already in service providing for this non-safety related function. Thus the auto start of the 12 pump was not as a result of a valid signal for a significant event that required initiation of a mitigating function; e.g. an ESF actuation. Therefore this event was not reportable under 10CFR50.72 or 50.73, as per the guidance provided in NUREG 1022. The licensee notified the NRC Resident Inspector. Notified R1DO(Della Greca). |
| ENS 40665 | 11 April 2004 04:23:00 | 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Plant Had a Valid Esf Signal to Start 1C Emergency Diesel Generator | THIS IS AN 8-HOUR NOTIFICATION TO REPORT A VALID ESF SIGNAL TO START 1C EMERGENCY DIESEL GENERATOR THAT OCCURRED ON 4/11/04 AT 0023. Salem Unit 1 is defueled. The spent fuel pool cooling system is providing decay heat removal. Spent fuel pool temperature is being maintained at 106 degrees. RCS temperature is 75 degrees. The RCS is vented to atmosphere. Reactor level is 97.5 feet. 1C emergency diesel generator is cleared and tagged for maintenance. 13 station power transformer was returned to service on 4/10/04 at 2347. The operating crew briefed expected response and abnormal procedures if the 4kv vital bus did not transfer during the retest of 13 station power transformer. Operations successfully retested 1A and 1B 4kv vital bus transfer from 14 station power transformer to 13 station power transformer and back to 14 station power transformer in accordance with station operating procedures. Operations attempted to retest the 1C 4kv vital bus transfer from 14 station power transformer to 13 station power transformer. When the operator attempted to close 13CSD in feed breaker, the 14CSD in feed breaker opened as designed, but 13CSD breaker failed to close. The 1C 4kv vital bus deenergized due to both offsite power source in feed breakers opening and 1C emergency diesel generator unavailable. An ESF signal to start the 1C emergency diesel generator was provided by the safeguards equipment cabinet (SEC). Since the 1C emergency diesel was cleared and tagged for maintenance, it did not start. The cause of the failure to transfer is not known at this time. The operating crew implemented the appropriate abnormal operating procedures for the de-energized 1C 4kv vital bus. Operator and plant response was as expected. Decay heat continues to be removed by the spent fuel pool cooling system. Outage incident response team is evaluating and troubleshooting the cause of the loss of power to 1C 4kv vital bus. ORAM risk remains yellow. There were no personnel injured during the event. The licensee will inform Lower Alloways Creek (LAC) Township and the NRC Resident Inspector.
The licensee provided the following information via facsimile: On April 11, 2004 at 0023 PSEG made an 8 hour notification to report a valid ESF actuation of the 1 'C' Emergency Diesel Generator (Event Number 40665). At the time of the event Salem Unit 1 was defueled. The spent: fuel pool cooling system was providing decay heat removal and spent fuel pool temperature was being maintained at 106 degrees. RCS temperature was 75 degrees and the RCS was vented to atmosphere. The 1 'C' EDG was cleared and tagged for maintenance. The 13 Station Power Transformer (SPT) had been returned to service on 4/10/04 at 2347. The operating crew was briefed on the expected response and reviewed the abnormal procedures if the 4kv vital bus did not transfer during the retest of 13 SPT. Operations successfully retested 1 'A' and 1 "B" 4kv vital bus transfer from 14 SPT to 13 SPT and back to 14 SPT in accordance with station operating procedures. When Operations attempted to retest the 1 'C' 4kv vital bus transfer from 14 SPT to 13 SPT, the 14 SPT in feed breaker opened as designed, but 13 SPT breaker failed to close and the 1 'C' 4kv vital bus de-energized. A signal to start the 1 "C" EDG was provided by the safeguards equipment cabinet (SEC), because the 1 'C' EDG was cleared and tagged for maintenance it did not start. Decay heat continued to be removed by the spent fuel pool cooling system. Subsequent Investigation into this event and further review of NUREG 1022 has determined that the condition described above is not reportable under the requirements of I0CFR50.72(b)(3)(iv) or 50.73(a)(2)(iv). NUREG-1022, section 3.2.6 states that valid signals are those signals that are initiated in response to actual plant conditions or parameters satisfying the requirements for initiation of the safety function of the system. In this case, plant conditions were such that it did not require the 1 'C' EDG to be capable of starting and loading automatically in response to an undervoltage signal. The reactor was defueled and spent fuel cooling system providing fuel cooling was unaffected by the event. NUREG-1022 states that train level actuations are reportable. However, in this instance, the EDG did not actuate because it was removed from service and was not required to be operable. NUREG-1022 states that single component actuations are typically not reportable because single components of complex systems, by themselves, usually do not mitigate the consequences of significant events. With the 1 'C' EDG removed from service, the 1 'C' bus undervoltage signal is not sufficient to complete the full actuation logic to mitigate the event. Therefore this event was not reportable under 10CFR50.72 or 50.73, as per the guidance provided in NUREG 1022. The licensee will notify the NRC Resident Inspector. Notified R1DO (Richard Conte) |
| ENS 40832 | 22 June 2004 17:13:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation | Automatic Reactor Scram Following an Electrical Yard Manipulation | Unit 2 reactor scrammed at 13:13 (EDT) following an electrical yard manipulation. The reactor scram occurred as a result of an RPS (Reactor Protections System) actuation following an automatic trip of the main turbine from a generator lockout. All control rods inserted (fully). The plant is stable (in mode 3). No ECCS (Emergency Core Cooling System) or safety relief valve actuations have occurred. This report is being made pursuant to 50.72(b)(2)(iv)(b). At this time the plant is stable, as expected. An investigation is in progress to determine the reason for the electrical fault. All plant systems functioned as required and decay heat removal is being performed via bypass to the main condenser. The licensee notified local and State authorities and the NRC Resident Inspector. |
| ENS 40910 | 30 July 2004 17:00:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(a)(1)(i), Emergency Class Declaration | Alert Declared at Columbia Generating Station | The following information was obtained by the licensee via facsimile: Reactor SCRAM received at 0924 (hrs) PDT. Initial indications are the scram signal was caused by RPS (Reactor Protection System) High Pressure. Following the scram, 2 (two) control rods did not immediately indicate (fully inserted). Control room staff entered (procedure) PPM5.1.2 and took the required actions. All control rods subsequently indicated (fully inserted). An ALERT Classification was declared at 1000 (hrs) based on PPM 13.1.1 Criteria 2.2.A.1, 'RPS Setpoint exceeded and automatic actions failed to result in a rod pattern which alone assures reactor shutdown'. Manual actions resulted in all rods (fully inserted) and reactor power (less than or equal to) 5 percent. All other plant systems responded as expected with the exception of a wetwell-to-drywell vacuum breaker which indicates open. Investigation into the cause of the scram and actual control rod position is ongoing. Further details will be provided when available. The licensee also reports that no relief valves lifted during the transient. Decay heat removal is via the main condenser. Reactor level is steady at 36 inches. Reactor temperature and pressure are 507 degrees and 710 psig respectively. Offsite power is available. All emergency systems are available in standby. The licensee has notified the NRC Resident Inspector of the incidents. The NRC entered Monitoring mode at 1327 hrs EDT with Region IV leading. The NRC exited Monitoring at 1530 hrs. EDT and returned to Normal mode. Notified HHS (Ayles) as well as others noted in notification block.
At 1358 (hrs.) EDT on 7/30/04, NRC was notified of an Alert at Columbia Generating Station (EN #40910). This is a follow-up to inform NRC that the event was terminated at 1457 (hrs) (EDT) (1157 PDT). All control rods are inserted. Reactor is shutdown and water level is normal. All required emergency systems are operable. All offsite and onsite power sources are operable. Reactor pressure is normal. The licensee has notified the NRC Resident Inspector, State of Washington and local authorities of the termination. The NRC Operations Center notified R4DO(Bywater), DHS, FEMA, DOE(NRC), USDA, EPA and CDC(HHS).
At 1358 EDT on July 30, 2004, NRC was notified of an Alert at Columbia Generating Station (EN #40910). A subsequent notification was made to inform the NRC that the event was terminated at 1157 PDT (1457 EDT) on July 30, 2004. This is a follow-up to inform the NRC that Columbia Generating Station is retracting its Alert Emergency Declaration due to the following reason. Following the RPS actuation, control rod position indication for two control rods was indeterminate for approximately two minutes to the control room staff. A subsequent review of control rod position indication from the Plant Data Information System (PDIS), Rod Worth Minimizer (RWM) logs, and Auto Scram Timer (AST) data by Columbia Generating Station personnel shows that all rods were successfully inserted to the 'Full-in' position following the initial RPS actuation, assuring that the reactor was shutdown under all conditions. The Emergency Action Level for this Alert classification requires that the following three conditions be met: Any RPS set point (including manual) has been exceeded per T.S. 3.3.1.1 AND RPS actuation failed to result in a control rod pattern which alone always assures reactor shutdown under all conditions AND Manual actions (mode switch in shutdown, manual push buttons, and ARI) result in reactor power LE 5%. Since all rods were successfully inserted without the assistance of any manual actions and within the Technical Specification required time, Columbia Generating Station staff now believes that no emergency classification should have been made, and we are retracting the Alert emergency classification from this event notification. The problem with control rod position indication following the scram is being addressed through our corrective action program. The licensee notified the NRC Resident Inspector and will notify local, State, and other Government Agencies of this update. Notified R4 DO (Runyan). |
| ENS 40921 | 4 August 2004 14:24:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation | Unexpected Reactor Trip During Maintenance Activities | At 1024 EDT a reactor trip occurred during maintenance activities involving the control rod drive trip breakers. All control rods fully inserted. The unit is currently stable with decay heat removal via the main steam system through the turbine bypass valves to the main condenser. Post trip response was normal with the following exceptions noted: 1. #4 main turbine stop valve may not have fully closed. 2. A #2 Steam Generator Safety Valve may be lifting early (lifted at 1010 psi rather than the 1050 psi setpoint). 3. Turbine Bypass valve SP13A3 stuck slightly open - isolated. All offsite power lines have been verified operable and both EDGs are available in standby, if needed. The licensee informed the local sheriff's department as required whenever a Steam Generator Safety valve lifts and the NRC Resident Inspector. |
| ENS 41028 | 9 September 2004 05:06:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation | Turbine Trip/Reactor Trip | Salem Unit 2 experienced a Turbine Trip > P-9 which initiated a Reactor Trip. All rods fully inserted. Aux Feedwater auto start initiated on steam generator low-low level. The cause of the turbine trip is Generator Diff (Differential Current) or Loss of Field. Decay heat removal is via the steam dumps to the main condenser. All safety related systems are available and functioned as designed. The 500 KV breaker 2-10 was cleared and tagged prior to the trip. Upon the turbine/reactor trip, the 500KV breakers 1-9 and 9-10 opened as designed. Due to the 2-10, 1-9, 9-10 breakers being opened, the 500 KV transmission line 5037 is de-energized. Two offsite power sources are available and all 3 Emergency Diesel Generators are operable. The 5037 line will be energized following restoration from scheduled maintenance. There were no personnel injuries. The licensee stated that the NRC resident inspector and the local township were notified. |
| ENS 41109 | 10 October 2004 22:14:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation 10 CFR 50.72(b)(2)(iv)(A), System Actuation - ECCS Discharge | Manual Reactor Scram Due to a Steam Leak in the Turbine Building | At 1814 (hrs. EDT) on October 10, 2004, Hope Creek Generating Station was manually scrammed due to a steam leak in the Turbine Building. All Control Rods inserted fully. Subsequent to the manual actuation of the Reactor Protection System, reactor pressure was reduced to minimize the effects of the steam leak. Degrading Main Condenser Vacuum following the scram resulted in trips of all operating Reactor Feed Pump Turbines at 10 (inches) HgA. The High Pressure Coolant Injection (HPCI) and Reactor Core Isolation Cooling (RCIC) Systems were manually initiated for reactor level control and the Main Steam Isolation Valves (MSIV's) were closed to isolate the leak - MSIV closure was completed prior to reaching the Main Condenser Vacuum isolation setpoint of 21.5 (inches) HgA. During plant stabilization, Reactor Water Level lowered below the RPS actuation setpoint of 12.5 inches four separate times. First, following the initial scram. Second, immediately following initiation of the HPCI and RCIC systems, when the 'A' and 'B' Reactor Water Level channels lowered to -38 inches (Level 2). Level 2 is the HPCI and RCIC actuation setpoint and Primary Containment Isolation actuation setpoint for Groups 2, 7, 8, 9, 12, 13, 14, 17, 18, 19, and 20 valves. Because only two of the four Level 2 instrument channels actuated, the isolation of these systems was channel dependent and occurred as required by the respective isolation logic. Third, following manual closure of the MSIVs. Finally, Reactor Water Level lowered below 12.5 inches following reset of the original manual scram signal which resulted in an automatic scram signal. RCIC was re-initiated manually to restore Reactor Water Level. No personnel were injured during this event. The plant is currently stable in OPCON 3 with reactor pressure at 615 psig. Pressure control (decay heat removal) was transitioned to HPCI in pressure control mode during plant stabilization. Reactor Water Level is being maintained with the Secondary Condensate Pumps. Two loops of RHR in Suppression Pool Cooling mode are in service with Suppression Pool Temperature at 110 degrees F in compliance with Technical Specification 3.6.2.1 Action b.2. Actions to determine the cause of the steam leak and effect repairs are in progress. The licensee will inform Lower Alloway Creek Township and has informed the NRC resident inspector.
On steam leak investigation, a walk down of the turbine building condenser bay determined the source of the leak to be a failure of an 8 inch moisture separator dump line. The line break is located approximately one foot from the condenser shell penetration. An additional investigation into the root cause of the failure has commenced. The NRC Resident Inspector was notified and Lower Alloway Creek Township will be notified. The Reg 1 RDO (Richard Barkley) and EO (Chris Grimes) were informed. HOO Note: See Event # 41110 |
| ENS 41165 | 1 November 2004 22:44:00 | 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Emergency Diesel Generator Automatic Start | At 1644 (11/01/04), with River Bend Station in Mode 5 (Refueling), voltage on offsite power line Reserve Station Service (RSS) No. 2 was lost. This offsite power line is the 230 KV power supply to the Division 2, 4160 volt safety related electrical bus. The Division 2 emergency diesel generator (EDG) automatically started and loaded on a loss of voltage to the 4160 volt safety bus. At the time of the event, Division 2 Residual Heat Removal (RHR) was in the fuel pool cooling assist mode and the pump secured due to the loss of power. It was subsequently restarted and continues to provide the shutdown cooling function. The following systems were isolated as a result of this event: Reactor Water Clean-up, Alternate Decay Heat Removal, and Floor Drains. Investigation of the cause of the event is ongoing. There was no impact on spent fuel pool level or temperature. At the event reporting time, power to the bus was still being provided by the Division 2 EDG with plans to restore normal power shortly. The licensee informed the NRC Resident Inspector. See also similar event EN # 41164 of 10/31/04. |
| ENS 41168 | 2 November 2004 19:05:00 | 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Unplanned Diesel Generator Start on a Valid Bus Undervoltage Signal | On November 2, 2004, at 11:05 PST, with Diablo Canyon Unit 2 in Mode 6 (Refueling), Emergency Diesel Generator (EDG) 2-1 auto started on an unplanned actuation signal from a valid 4160 volt Bus G undervoltage signal. All equipment responded as designed. After the EDG started, the auxiliary feeder breaker opened, and loads were automatically sequenced onto the EDG. At the time of the event, test equipment was being connected in preparation for an instrumented manual test start of EDG 2-1 prior to maintenance. On November 2, 2004, at 1708 PST, operators transferred Bus G to auxiliary power and shutdown DG 2-1. Prior to the event, Bus G was being supplied by auxiliary power, with startup power cleared for planned maintenance. Bus G was being prepared to be cleared for maintenance, therefore, required equipment was in-service on the other buses. Buses F and H were unaffected by this event and remain operable on auxiliary power, with EDG 2-2 (Bus H) and 2-3 (Bus F) operable. The following decay heat removal trains are powered from Bus G: Residual Heat Removal Pump 2-1 remained in standby, Component Cooling Water Pump 2-2 started on the transfer to EDG, and Auxiliary Saltwater Pump 2-2 re-started. Unit 2 is in day 9 of a refueling outage, with the reactor head removed, the refueling cavity filled, and the upper internals installed with rods latched. Unit 1 was unaffected and continues to operate in Mode 1 (Power Operation) at 100 percent power. The cause of the Bus G undervoltage signal is being investigated. The licensee stated that no undervoltage was seen on any other equipment but the undervoltage relays on Bus G did sense an undervoltage. Residual Heat Removal was unaffected by the event. Bus G has been returned to its pre-event configuration and is considered operable. The other EDGs were fully operable at the time of the event and there were no significant LCOs at the time. All systems functioned as required. The licensee has notified the NRC Resident Inspector |
| ENS 41209 | 19 November 2004 16:07:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Automatic Reactor Trip Due to Turbine Trip on Main Generator Trip | The following information was obtained from the licensee via facsimile: 1. SYSTEMS AFFECTED: Reactor trip, Aux feed water actuation. 2. ACTUATIONS AND THEIR INITIATING SIGNALS: Reactor trip - Loss of Load Turbine Trip, Aux Feed Water (AFW) - 21% (on the narrow range indication) in Steam Generators. 3. CAUSES: Reactor tripped due to an undetermined cause in the main generator end of the secondary plant. AFW started as expected on EFAS (Emergency Feedwater Actuation Signal) at 21% from a trip at 100%. 4. EFFECT OF EVENT ON PLANT: Plant is stable at 545F (and) 2250 (psi) hot standby conditions and will remain here until cause determination made as to cause of trip. 5. ACTIONS TAKEN OR PLANNED: Maintain hot standby conditions for post trip review. CONTINUATION SHEET: 1) Remain in Mode 3 for cause determination post-trip review to provide actual mode required. 2) Estimate restart date pending cause determination and any repairs required. 3) All rods inserted, no primary or secondary reliefs lifted, electrical grid stable, all safety systems performed as expected, no effect on Unit 3. Electrical power supplied from offsite power. Decay heat removal is via steam dump to condenser. The licensee has notified the NRC Resident Inspector. |
| ENS 41297 | 27 December 2004 22:20:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation | Manual Reactor Trip Following Problem with Steam Generator Water Level Control | The licensee reported a "manual reactor trip due to low steam generator level caused by feedwater control system malfunction." The licensee stated that it manually tripped the reactor with steam generator water level at approximately 40% and decreasing. Steam generator water level control was restored following the trip using auxiliary feedwater. All rods fully inserted on the trip. No safety or relief valves lifted. Auxiliary feedwater was manually actuated and decay heat is currently being discharged via the atmospheric dump valves. Unit 1 is at full power and unaffected and the grid is stable. The plant was in no major LCOs at the time. All systems functioned as required. The licensee is still investigating the feedwater control system malfunction. The NRC Resident Inspector has been notified.
The original notification stated that decay heat was being discharged via the atmospheric dump valves post-trip when the decay heat removal mechanism being used was steam dump to the condenser via the steam bypass control system. Additionally, although the auxiliary feedwater system was used to deliver water to the steam generators post-trip, the main feedwater system was available for this function. The investigation into the feedwater malfunction is still in progress. The NRC Resident Inspector has been informed. R2DO (Moorman) notified. |
| ENS 41347 | 19 January 2005 18:51:00 | 10 CFR 50.72(b)(2)(xi), Notification to Government Agency or News Release 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Callaway Automatic Reactor Trip on Low Steam Generator Level | Unit experienced an automatic reactor trip following a momentary loss of power to a process control system power supply that resulted in a low Steam Generator water level. This event is being reported in accordance with 10CFR50.72(b)(2)(iv)(B) due to an automatic Reactor Trip and subsequent Aux Feedwater actuation and Feedwater isolation. On 1/19/2005 at 12:51 CST with Callaway plant at 100% reactor power, a Reactor Trip occurred on low Steam Generator 'A' level due to an apparent momentary loss of power in Control Cabinet (Relay Panel) RP043. A failed Primary Power Supply to RP043 replacement was in progress at the time of the trip. A momentary power spike on the in-service backup power supply caused the Main Feedwater Regulating valve (MFRV) 'A' to shut and both Main Feedwater Pumps (MFPs) went to their low speed stops. Attempts by the Reactor Operator to take manual control of 'A' MFRV and the MFPs were unsuccessful resulting in the Reactor Trip. Following the reactor trip all systems responded as designed with no abnormal responses. The plant is currently stable in Mode 3 with RCS pressure at 2237 psig and RCS temperature at 557.8 F. The Auxiliary Feedwater is currently supplying the Steam Generators with steam flow to the Main Condenser for decay heat removal. All control rods fully inserted. Both NRC Resident Inspectors were contacted and responded to the Control Room. Corporate Communications will be providing public information on the plant trip to the media. |
| ENS 41382 | 7 February 2005 21:58:00 | 10 CFR 50.72(b)(3)(v)(B), Loss of Safety Function - Remove Residual Heat | Residual Heat Removal System Inoperable Due to Emergency Diesel Generator Trip During Testing | This report is being made pursuant to 10CFR50.72(b)(3)(v)(B) 'Any event or condition that at the time of discovery could have prevented the fulfillment of the safety function of structures or systems that are needed to: (B) Remove residual heat;' This report is being made due to a trip of the Emergency Diesel Generator during testing that resulted in the RHR loops potentially becoming depressurized. This has the potential to render all RHR Shutdown Cooling unavailable and prevent the removal of decay heat. Sequence of events (all times CST): At 12:00 (02/07/05), Shutdown Cooling was removed from service to prepare for Sequential Load testing of DG #1. This was a planned evolution. At this time decay heat was being removed by the fuel pool cooling system with 2 fuel pool cooling pumps and 2 fuel pool cooling heat exchangers. Time to boil was calculated to be 26 hours. At 15:58, the Sequential Load Test commenced on the inoperable DG. The DG came up to speed and sequenced on the initial loads (RHR pumps, a CS pump and a SW pump). Shortly into the sequencing of the DG, the DG tripped due to a blown fuse in the DG control circuit. Sequential loading was not completed. The trip occurred between 13 seconds and 20 seconds of the sequential load. This resulted in the initial loads losing power. Procedurally, the minimum flow valves for the RHR and CS pumps were being remotely opened from the Control Room at the time the DG tripped. This resulted in low-pressure alarms on both RHR systems and one CS system. One fuel pool cooling pump was deenergized, per design, during the sequential load test. Both fuel pool cooling heat exchangers remained in service. With these conditions, the fuel pool cooling lineup does not qualify as an alternate decay heat removal method. At 16:04, both RHR loops were declared inoperable due to depressurizing the RHR loops. At 16:02, the tripped fuel pool cooling pump was restored to operation and previous decay heat removal was restored. No unexpected rise in temperature occurred during the time that only 1 fuel pool cooling pump was in operation. This reestablished the fuel pool cooling system as an alternate decay heat removal method. At 19:11, the B loop of RHR was returned to a standby lineup and declared operable. At this time investigation into why the DG fuse blew is ongoing. All indications are that other equipment performed as designed. The licensee notified the NRC Resident Inspector.
The following is a correction to the original report received via facsimile (licensee text in quotes): Instead of the minimum flow valves for RHR and CS being opened, the suppression pool inboard cooling valve for RHR and the test line recirculation valve for CS were being opened. The licensee will notify the NRC Resident Inspector. Notified R4 DO (T. Pruett)
The following information was provided by the licensee (licensee text in quotes): On 2/7/2005 at 1558 CST, Cooper Nuclear Station made an 8 hour 50.72 non-emergency notification to the NRC. The report was made pursuant to 10 CFR 50.72(b)(3)(v), 'Any event or condition that at the time of discovery could have prevented the fulfillment of the safety function of structures or systems that are needed to: (B) Remove residual heat.' A control power failure during Emergency Diesel Generator #1 (DG) surveillance testing resulted in the loss of the Residual Heat Removal (RHR) pressure maintenance pump. This resulted in the potential de-pressurization and unavailability of all RHR Shutdown Cooling (SDC) and the ability to remove decay heat using RHR. NUREG 1022 Revision 2 defines the safety functions to be considered for Reportability under this section of the rule as being those that are listed in the regulation itself. Thus, the lost safety function being reported was 'remove decay heat'. Plant conditions prior to the testing were: Mode 5 (Refueling) with the Reactor Vessel and Drywell heads removed and reactor water level flooded up and Spent Fuel Pool transfer gates removed. Division II RHR was in service providing SDC for decay heat removal. In preparation for the DG testing and in accordance with Technical Specifications, all RHR SDC was removed from service. With RHR SDC out of service, reactor coolant circulation was verified to be by natural circulation with operators monitoring reactor coolant temperatures once per hour. Alternate decay heat removal was provided by the credited lineup of two Fuel Pool Cooling (FPC) pumps and two FPC heat exchangers. FPC receives cooling water from the Reactor Equipment Cooling System (REC), which in turn is cooled by the Service Water System (SW). During the preparation period (approximately 4 hours) for the DG #1 testing, reactor coolant temperature was allowed to slowly go from 85 degrees Fahrenheit to 90 degrees Fahrenheit. During load sequencing testing of DG #1, the DG tripped due to a control system failure and de-energized the Division I 4160 Volt (V) critical bus. (Note: The bus was previously de-energized for a short period of time as part of the test.) This caused the pump providing pressure maintenance for the RHR to trip potentially depressurizing the RHR loop (Division II) that had been lined up to provide SDC. A conservative decision was made to declare Division II SDC inoperable during the DG trip recovery. If the test had proceeded as planned one RHR pump would have been running in Division I in the test mode (pumping water to the suppression pool). No RHR pumps would have been running in Division II (lined up to allow the Division I test to be conducted). DG #2 remained in normal standby lineup. Division II 4160 V bus was energized supplying power to connected loads. Due to the DG #1 trip the Division I 4160 V bus was deenergized. Shutdown Cooling using RHR could not be placed in service as a result of the test lineup established for DG #1 testing. Reactor coolant circulation was by natural circulation and reactor decay heat removal was by one FPC pump and two FPC heat exchangers. The trip of one FPC pump is expected and verified during this surveillance test. REC was operating with cooling supplied by Division II SW. During the period of time after the DG trip and prior to the restoration of electrical power to the Division I 4160 V bus, coolant circulation continued by natural circulation with one FPC pump and two FPC heat exchangers providing decay heat removal. At approximately the time of the DG trip coolant temperature was 90 degrees Fahrenheit. Just after power was restored coolant temperature was 89 degrees Fahrenheit. Operators had adjusted REC temperatures and flows to provide additional cooling to Fuel Pool Cooling. An additional FPC pump was started to provide a two FPC pump and two FPC heat exchanger lineup for reactor decay heat removal. The small variation in coolant temperature demonstrates that the FPC lineup was adequate to provide decay heat removal. Engineering performed an evaluation to investigate bulk water temperature response to the event with one FPC pump and two heat exchangers supplying cooling with the fuel pool gates removed. The results show extended periods of time for pool heat-up and are considered bounding. It takes 21 hours for the pool temperature to reach 150 degrees Fahrenheit and 94 hours for the bulk temperature to reach a maximum value of 182 degrees Fahrenheit. Based on this evaluation CNS concludes the maximum bulk temperature would not exceed 182 degrees Fahrenheit. As discussed above, RHR SDC was removed from service to support Emergency Diesel Generator surveillance testing. While RHR SDC was out of service, reactor coolant circulation was provided by natural circulation. At the same time, the safety function of decay heat removal was provided by Fuel Pool Cooling. Since the decay heat removal safety function was never lost this is not a reportable event. The licensee notified the NRC Resident Inspector. Notified the R4DO (Graves).
The following is a change to paragraphs 3 and 4 of the above retraction statement During sequential load testing of DGI, the normal expected response after loads are sequenced on, is to have an RHR pump in each division recirculating back to the suppression pool via the suppression pool cooling line. This path is established when the respective RHR pump automatically starts. During load sequencing testing of DG # 1, the DG tripped due to a control system failure and de-energized the Division I 4160 Volt (V) critical bus. (Note: The bus was previously de-energized for a short period of time as part of the test.). Due to the timing of the DG failure, both RHR pumps started and both suppression pool cooling valves were opened. Subsequently the DG tripped and the RHR pumps stopped due to no power available. The suppression pool cooling valves were unable to be closed prior to depressurizing both RHR loops. A conservative decision was made to declare Division II SDC inoperable during the DG trip recovery. DG #2 remained in normal standby lineup. Division II 4160 V bus was energized supplying power to connected loads. Reactor coolant circulation was by natural circulation and reactor decay heat removal was by one FPC pump and two FPC heat exchangers. The trip of one FPC pump is expected and verified during this surveillance y test. REC was operating with cooling supplied by Division II SW. The NRC Resident Inspector will be informed. Reg 4 RDO(Linda Howell) was notified. |
| ENS 41383 | 8 February 2005 01:23:00 | 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Manual Reactor Trip During Startup Due to Indication of Misaligned Rod | The following information was provided by the licensee via facsimile: While withdrawing Control Bank 'A' during the Reactor Startup, Rod B-10 indicated a rapid drop from approximately 42 steps to 17 steps on the CERPI (Computer Enhanced Rod Position Indication) panel. The reactor operator stopped withdrawal of 'A' control bank and the CERPI indication for rod B-10 remained at 17 steps. The remaining CERPIs in 'A' control bank varied from 40 to 45 steps. The startup was terminated and the reactor was manually tripped in accordance with AP-1 and 1-E-0 (was) initiated. All systems functioned as required on the trip. Initial investigation by I & C and Engineering found no problems with the CERPI indication. Rod Drop time data from the CERPI program shows all rods in Control Bank 'A' had a drop time of 0.32 to 0.38 seconds with the exception of B-10, which had a drop time of 0.18 seconds. An investigation is ongoing as to the cause of rod B-10 misalignment. This notification is being made pursuant to 10 CFR 50.72(b)(3)(iv)(A). The NRC resident was notified of this event. The reactor was subcritical in the Source Range at the initiation of the event. All rods inserted fully during the manual reactor trip. S/G level is being maintained by main feedwater and decay heat removal is via the S/G PORV. |
| ENS 41386 | 8 February 2005 15:20:00 | 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident | Steam-Driven Auxiliary Feedwater (Afw) Pump Declared Inoperable Due to Design Issue | The following information was obtained from the licensee via facsimile: At 0920 (hrs.) CST, on February 8, 2005, Fort Calhoun Station declared the steam driven auxiliary feedwater (AFW) pump (FW-10) inoperable due to discovery of a design problem with the pump turbine. The station entered the appropriate technical specification action statement at that time. The pertinent action statements for auxiliary feedwater ((T.S.) 2.5.1) read as follows: B (Action statement): With one AFW train inoperable for reasons other than condition A, restore the AFW train to OPERABLE status within 24 hours. C (Action statement: If the required action and associated completion times of condition A or B are not met, then the unit shall be placed in MODE 2 in 6 hours, in MODE 3 in the next 6 hours, and less than 300 (degrees) F without reliance on the steam generators for decay heat removal within the next 18 hours. A change to the design basis is in progress to allow the pump to be made operable within 24 hours. The design problem is due to the AFW pump drains. The manufacturer states that the drain lines must drain below the level of the AFW turbine. The current configuration is that the drains are aligned to the condenser which is approximately 18 feet above the elevation of the AFW turbine. This is not a problem during normal AFW turbine operation as the condenser would most likely be in service. However, the condenser cannot be relied upon during all accident conditions that require AFW actuation. The licensee has notified the NRC Resident Inspector.
The licensee faxed the following retraction: Fort Calhoun Station (FCS) has conducted a thorough engineering evaluation of the effects on water in the turbine exhaust housing of the steam driven feedwater pump (FW-10). It was concluded that FW-10 was able to perform its design function based on the results of the evaluation. FW-10 was determined to be operable as required during past plant operation whether or not condenser vacuum was available. The conclusion was based on four points: 1. The preparer's experience with a multi-stage turbine that was started with water up to the centerline of the rotor and sustained no damage. 2. OPPD's strong evidence that FW-10 has been operated multiple times with some water in the casing. 3. A simple conservative analysis of the forces on a turbine blade when operated in a water submerged condition. The blade stresses were determined to be well below allowables for the loading condition presented with the blade moving through the static water volume during a startup event. 4. In addition, inspection of the turbine in 1998 and 2005 does not show any adverse indications of stress or wear. Therefore this notification is being retracted.. The plant is presently in a scheduled refueling outage. The licensee will notify NRC Resident Inspector. |
| ENS 41453 | 1 March 2005 20:45:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation | Manual Reactor Trip During a Rapid Shutdown for Steam Leak Repair | The following information was provided by the licensee via facsimile (licensee text in quotes): (The licensee) reduced power on Unit 2 due to a steam leak on a moisture separator reheater vent line. The reactor was manually tripped at 20% reactor power per normal shutdown sequence. All systems and components operated correctly. Unit restart will commence following completion of a planned refueling outage. All rods fully inserted. One steam line secondary PORV lifted and reseated. Decay heat removal is via AFW and steam bypass valves to the main condenser. The steam leak was reported to be on a 2-inch MSR vent line elbow. The licensee has notified the NRC Resident Inspector.
The following information was obtained from the licensee via facsimile (licensee text in quotes): On March 1, 2005, McGuire Unit 2 experienced a steam leak on a two-inch pipe in the heater bleed steam system. In consideration of that leak, Unit 2 was shutdown by manually tripping the reactor. This was reported as an unplanned valid actuation of the reactor protection system (10CFR 50.72 (b) (2)(iv)(B)). Reference Event Report 41453. The manual reactor trip of Unit 2 was not required to mitigate the steam leak. However, in consideration of the steam leak, a decision was made to perform a shutdown of Unit 2 using the normal reactor shutdown procedure. This procedure requires that the control rods be inserted by manually tripping the reactor. As per guidance provided in NUREG-1022, the above actions do not satisfy the criteria for reporting under the requirements of 10CFR 50.72 (b) (2)(iv)(B) or any other reporting criteria. Therefore, McGuire is retracting Event Report 41453. The licensee has notified the NRC Resident Inspector. Notified R2DO (Cahill). |
| ENS 41528 | 24 March 2005 21:08:00 | 10 CFR 50.72(b)(3)(ii)(B), Unanalyzed Condition | Unanalyzed Condition Relating to the Integrity of the Diesel Generator Exhaust Stacks During a Tornado | The following information was obtained from the licensee via facsimile (licensee text in quotes): While evaluating the capability of the plant to withstand a tornado it was identified that the Diesel Generator Exhaust Stacks may not maintain their design structural integrity. This would place the plant in an unanalyzed condition, however expert engineering judgment is that the damage to the Emergency Diesel Generator Exhausts would not reduce the capacity below that required to ensure decay heat removal. Currently the plant is in refueling shutdown and the Emergency Diesel Generators are not required to be operable per Technical Specifications. This condition will be corrected prior to plant startup. Power is still being supplied to the plant from the Reserve and Tertiary Auxiliary Transformers. This event was determined to be reportable per 10CFR50.73(a)(2)(ii)(B) and further review of the reporting criteria identified that if there is any doubt, this condition should be reported under 10CFR50.72(b)(3)(ii)(B). At the request of the Plant Manager at approximately 2100 on 3/25/05, the Shift Manger and Shift Technical Advisor independently reviewed the reporting criteria. Based on the statement in NUREG 1022, Rev 2, when applying engineering judgment and there is doubt regarding whether to report or not, the commission's policy is that the licensees should make the report, it was decided to report per 10CFR50.72. The licensee has notified the NRC Resident Inspector. |
| ENS 41531 | 28 March 2005 01:30:00 | 10 CFR 50.72(b)(3)(v)(B), Loss of Safety Function - Remove Residual Heat 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident | Electrical Safety Bus Trip During Quad Cities Unit 1 Refueling Outage | The following information was obtained from the licensee via facsimile (licensee text in quotes): At 1930, Unit 1 experienced a loss of 480 VAC busses 18 and 19. This caused a loss of power to the Control Room Emergency Ventilation System (CREVS) and the CREVS Air Conditioning System (CREVS AC). This event also caused a loss of power to the U1 equipment that was supporting the Alternate Decay Heat Removal (ADHR) mode of operation. Power was restored to Bus 19 at 2001 and Bus 18 at 2013. The restoration of Bus 18 also restored power to CREVS and CREVS AC. All systems supporting ADHR were restored by 2015. At the time of the occurrence, the estimated time to boil without decay heat removal capability was 571 minutes. All isolations and actuations occurred as expected. The cause of the bus trips is being investigated. This Event is being reported under 50.72 (b)(3)(v)(B) and 50.72 (b)(3)(v)(D). The licensee stated at the time of the event, Busses 18 and 19 were cross-tied and the feeder breaker to Bus 18 tripped open. The breaker was changed out and power to Busses 18 and 19 restored. The cause of the Bus 18 feeder breaker trip has not yet been determined. The licensee has notified the NRC Resident Inspector.
The licensee stated that the Alternate Decay Heat Removal pumps from Unit 2 remained in service so that all decay heat removal was not lost. The Unit 1 primary coolant system temperature increase during the 45 minute duration of this event was approximately 1 degree. R3DO (Kozak) has been notified. |
| ENS 41653 | 30 April 2005 01:55:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Manual Reactor Trip - Lowering Steam Generator Level on Loop #1 | At 2155 EDT on 4/29/2005, Vogtle Unit 1 was manually tripped from 100% power due to lowering steam generator level on loop #1. The main feedwater regulating valve was in manual control and a repair plan was in progress to replace a controlling card which failed earlier in the day. The manual reactor trip caused an automatic aux. feedwater actuation of the motor driven and turbine driven feedwater pumps. All other equipment responded as expected on the trip. At approximately 1600, the loop #1 main feed regulating valve had failed shut while in the automatic mode of operation. The operator shifted control to manual and opened the valve, preventing a reactor trip. At 2155 the recovery plan was being implemented using a plant procedure. While performing the procedure, the loop #1 feed regulating valve shut. The reactor was manually tripped on lowering steam generator level. All rods fully inserted after the manual reactor trip. Decay heat removal is to the main condenser with steam generator level being maintained using the motor driven aux. feedwater pumps. The plant is in its normal shutdown electrical lineup. The licensee notified the NRC Resident Inspector. |
| ENS 41654 | 1 May 2005 04:21:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Manual Reactor Trip Due to Loss of Condensate Pump | The plant was in Mode 1 at 100% power. At 0021 (EDT) the reactor was manually tripped following a loss of 1B Condensate pump per AOP-010, Feedwater Malfunctions. The cause of the 1B Condensate pump trip is not known at the present time. The plant is stable in Mode 3 at normal temperature and pressure. All safety systems functioned as expected; AFW automatically actuated due to low level in the steam generators to provide continued decay heat removal. All control rods fully inserted on the manual reactor trip. Secondary PORVs opened on the trip and reclosed. Steam generators are discharging steam to the main condenser using the turbine steam dump valves. AFW has been secured and main feedwater is operating to maintain SG levels. The licensee notified the NRC Resident Inspector. |
| ENS 41655 | 1 May 2005 15:09:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Manual Reactor Trip Due to Main Turbine High Vibration | Seabrook Station initiated a Manual Reactor Trip during initial start of the main turbine following a refueling outage. Turbine vibrations elevated to the automatic trip setpoint during initial increase to normal operating speed. The reactor was manually tripped to allow breaking main condenser vacuum and reduce main turbine speed. The plant is currently stable in Mode 3. All control rods (fully) inserted and decay heat removal is via the main condenser steam dumps. Emergency feedwater (EFW) pump actuation occurred because of lowering steam generator level due to the reactor trip. Steam generator level control was maintained using EFW. Condenser vacuum was broken until the turbine vibration alarms cleared and was then restored, allowing the condenser to be used for dumping steam. The licensee notified the NRC Resident Inspector. |
| ENS 41752 | 7 June 2005 16:25:00 | 10 CFR 50.72(b)(3)(ii)(B), Unanalyzed Condition | Unanalyzed Potential Impact on Emergency Diesel Generator Operability | At 1125 on 6/7/2005 it was determined that the Emergency Diesel Generators A and B were out of service due to the possibility of Tornado Missiles potentially collapsing the D/G Fuel Oil Tank Vents. The Emergency Diesel Generators are required as a support system for RHR Decay Heat Removal and RHR was also declared inoperable at the same time. Technical Specification requirements for RHR Decay Heat Removal are, if less than the required number of heat sinks are operable, then corrective action shall be taken immediately to restore the minimum number to operable status. Actions are being taken to restore full operability of the Emergency Diesel Generators A and B. Currently RHR is operating and providing decay heat removal and Emergency Diesel Generators are available as a support system for RHR. Event Report # 41528 had similar issues associated with the Emergency Diesel Generators exhaust ducts and their ability to withstand tornado forces. The licensee notified the NRC Resident Inspector. * * * RETRACTION FROM G. RISTE TO P. SNYDER ON 7/26/05 AT 1541 * * * Event Notice #41752 was initiated on 6/7/2005 to report an unanalyzed condition with the Emergency Diesel Generators A and B. The initial analysis for tornado missile strike probability results for the Emergency Diesel Generator fuel oil tank vent lines indicated they could be damaged by a tornado missile to the point they would potentially adversely affect Diesel operability. Additional analysis was performed and it was determined that the original fuel tank oil vent line configuration was acceptable. The licensee notified the NRC Resident Inspector. Notified R3DO (Mark Ring). |
| ENS 41836 | 17 May 2005 05:42:00 | 10 CFR 50.73(a)(1), Submit an LER | Invalid Actuation of the "B" Residual Heat Removal (Rhr) Pump. | July 12, 2005 Telephone Report in Accordance with 10 CFR 50.73(a)(2)(iv)(A) Invalid Actuation of the "B" Residual Heat Removal (RHR) Pump. SPECIFIC TRAINS AND SYSTEMS THAT WERE ACTUATED During a maintenance activity involving replacement of a safeguards relay, "B" Train RHR Pump 2P-10B was started inadvertently. The RHR pump is part of the emergency core cooling system (ECCS). DESCRIPTION OF WHETHER EACH TRAIN ACTUATION WAS COMPLETE OR PARTIAL On May 17, 2005, Unit 2 was in a shutdown condition (MODE 6) for routine refueling outage. At approximately 0042, Unit 2 RHR Pump 2P-10B was inadvertently started. Since RHR Pump 2P-10A had already been running for normal shutdown decay heat removal, the inadvertent start of the B RHR pump resulted in both RHR pumps running. Operations observed an increase in RHR flow but initially attributed the flow change to the RHR Heat Exchanger (HX) Bypass Flow Control Valve, which was operating in automatic. At the time of the inadvertent pump start, technicians were landing a wire as part of performance of a procedure to replace a safeguards relay. During this activity, the technicians heard a breaker close in the 480 VAC safeguards bus. Primary Plant Computer System (PPCS) computer data indicates that this breaker closure corresponded to the 2P-10B RHR Pump start. The technicians were not aware that this breaker closure was caused by their activity. The inadvertent RHR pump start was identified at 0525. The investigation of this event determined that a current path was created during the relay replacement, which caused starting of 2P-10B. No other ECCS components were actuated during this event. A review of the activity could not determine the specific wire that was lifted landed to cause the pump start. Rather several wire combinations were noted, each of which could have caused what is commonly referred to as a 'sneak' current path. These current paths can result in the RHR pump starting circuit being energized. DESCRIPTION OF WHETHER OR NOT THE SYSTEM STARTED AND FUNCTIONED SUCCESSFULLY This event was not safety significant. The RHR pump started and functioned successfully. The RHR pump was the only ECCS component in the system affected. Since the pump was aligned in the standby mode to provide normal decay heat removal cooling, its start appropriately resulted in additional cooling flow being pumped to the reactor core. The RHR pump was secured and returned to standby mode following discovery of this condition. As corrective action, a procedure change was initiated to add a precaution statement to ensure the associated safeguards relay cabinet is deenergized to the extent possible prior to similar maintenance activities to prevent inadvertent safeguards actuations. This item is documented in the PBNP corrective action process system (CAP 064616). The NRC Resident Inspector was notified of this event report by the licensee. |
| ENS 41844 | 14 July 2005 21:10:00 | 10 CFR 50.72(b)(3)(ii)(B), Unanalyzed Condition | Station Blackout Temperature Analysis Higher than Rcic Governor Documentation | During fact gathering in response to an NRC inspection inquiry, it was determined that documentation does not exist that demonstrates that the Reactor Core Isolation Cooling (RCIC) Electronic Governor Module (EGM) would be able to operate during the required Station Blackout (SBO) coping mission time at the postulated post SBO RCIC room temperature of 206.4F. Current documentation supports operation up to 150F. The EGM is a skid-mounted module that provides speed control signals for the RCIC Woodward Governor. Failure of the EGM would result in a loss of speed control for the RCIC turbine. This could result in an overspeed, underspeed or no change condition. Overspeed of the turbine would result in a mechanical overspeed trip. This device is not in the EQ program but is Augmented Quality. RCIC continues to perform its Technical Specification required functions as defined in the Bases of Technical Specification (TS) 3.5.3. The TS function is to respond to transient events by providing makeup coolant to the reactor. The RCIC Room temperatures for the postulated TS transient events is less than the currently documented component qualification temperature. The RCIC is not an ESF system and no credit is taken in the safety analysis for RCIC system operation but is retained in the TS based on its contribution to the reduction of overall plant risk per Criterion 4 of 10 CFR 50.36. The RCIC system design requirements ensure that the criteria of 10CFR50 Appendix A, GDC 33, are satisfied. Due to the lack of supporting documentation for the EGM, the beyond design basis regulatory SBO rule requirements of 10 CFR 50.63 may not be met. This condition could potentially result in an unanalyzed condition that could significantly degrade plant safety and is therefore reportable under 10 CFR 50.72(b)(3)(ii). An analysis of the RCIC Room Heat Up Rate calculation is being performed as there are conservatisms built into the calculation that when removed will result in a lower temperature than 206.4F. Additional actions in progress include, establishing appropriate protected pathways to minimize the potential for a Loss Of Off-Site Power which could result in a SBO, performance of temperature qualification testing at SBO temperatures for the EGM, and performance of an extent of condition review for remaining RCIC components to ensure temperature qualification is met for the SBO rule. In parallel with temperature qualification testing, a modification to relocate the EGM to an area outside the RCIC room that has a lower SBO profile temperature is being pursued in the event that temperature qualification is not successful. The licensee notified the NRC Resident Inspector.
A 8-hour notification was made on July 14, 2005, in accordance with 10 50.72(b)(3)(ii)(B), Unanalyzed condition. The report was made because documentation did not support the continued operation of Reactor Core Isolation Cooling (RCIC) Electronic Governor Module (EGM) during the required Station Blackout (SBO) coping mission. Since the initial report, the post SBO room heatup calculation was evaluated and determined that the decay heat removal function during the SBO coping mission was met. The decay heat removal function during SBO coping period is achieved by either High Pressure Core Spray (HPCS) or RCIC systems. In addition, the other RCIC functions (i.e., Remote Shutdown, and Safe Shutdown Fire) were evaluated and determined to be met. Since the RCIC functions and the decay heat removal and vessel inventory functions during the SBO coping mission were maintained, the plant was not in an unanalyzed condition and this issue is not reportable. Since the condition is not reportable EN 41844 is retracted. The licensee notified the NRC Resident Notified R3DO (K. O'Brien) |
| ENS 41848 | 18 July 2005 13:52:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation | Automatic Reactor Scram | Unit 1 reactor automatically scrammed at 09:52 as a result of an RPS Actuation following a main turbine trip caused by unit protection relaying. All control rods inserted. The plant is stable. No ECCS or SRV actuations occurred. This report is made pursuant to 50.72(b)(2)(iv)(B). An investigation into the cause is currently in progress. The plant is currently stable in mode 3. No safety relief valves actuated. The current decay heat removal path is normal feedwater to the reactor steaming through the turbine bypass valves to the condenser. No other safety systems actuated. Electric power to the safety busses was supplied via normal offsite power. No bad weather conditions are present. Current reactor pressure is 900 psi with temperature at about 540 degrees. Currently troubleshooting is ongoing to investigate the cause of the trip. The licensee currently plans to stay in mode 3 until the investigation is complete. No safety related systems are currently out of service. There was no estimated restart date. The licensee notified the NRC Resident Inspector. |
| ENS 41868 | 25 July 2005 04:00:00 | 10 CFR 50.72(b)(2)(xi), Notification to Government Agency or News Release 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation 10 CFR 50.72(b)(2)(iv)(A), System Actuation - ECCS Discharge | Automatic Reactor Trip Caused by Failure in Switchyard | At 1525 the plant experienced a load reject generator trip due to a catastrophic failure in the 345 Kv switchyard. A reactor scram occurred as a result. The degraded AC power system prevented a fast transfer from occurring. Degraded bus voltage caused the emergency diesel generators (EDGs) to start. A residual bus transfer restored power to the 4 Kv busses. The (main steam isolation valves) (MSIVs) closed on a low-low reactor water level of 82.5 inches. (Reactor Core Isolation Cooling) and (High Pressure Coolant Injection) (HPCI) also started on the low-low reactor vessel water level. The (Safety Relief Valves) were cycled twice for pressure control. OT 3100 Reactor Scram procedure was executed. EOP-3 was entered due to elevated torus water temperature and both loops of (Residual Heat Removal) (RHR) are in torus cooling. Water level has restored and is being maintained by feedwater. The MSIVs have been reopened and the scram reset. EDGs were secured. The plant is currently shutdown and stable with all control rods fully inserted. Decay heat removal is being accomplished with HPCI in pressure control mode. The licensee is transitioning to feeding with normal feedwater and steam exhausting through drains. Both trains of RHR are providing torus cooling. Electric power is being provided by offsite power. The licensee is currently investigating the event in the switchyard. The licensee notified the NRC Resident Inspector and will issue a press release.
Corrected incorrect entry for Scram Code from N (N/A) to A/R (Automatic/with Rod Motion). R1DO (Glenn Meyer) notified. |
| ENS 41911 | 11 August 2005 14:48:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Manual Reactor Trip on a Condensate Pump Bus Lockout | On 8/11/2005, a manual reactor trip was initiated due to lowering steam generator level caused by a partial loss of main Feedwater. The partial loss of feedwater was caused by the differential lock out of the non-vital 2A2 4160 V bus which resulted in loss of the 2A Condensate Pump that tripped the 2A Main Feedwater Pump. All rods inserted and no Steam Generator Safety Valves lifted. The differential lock out of the non-vital 2A2 4160 V (bus) deenergized the 2A3 vital 4160V bus, starting the 2A Emergency Diesel Generator and the 2A3 loads were sequenced on the Emergency Diesel Generator per design. Subsequently, the Auxiliary Feedwater System was automatically initiated due to lowering steam generator levels. All safe shutdown equipment operated as expected. The plant is stable in Mode 3, Hot Standby conditions, with decay heat removal being accomplished by steaming to the Main Condenser and Feedwater to the steam generators supplied by the Main Feedwater system. The Offsite power grid is available and stable. The '2C' Auxiliary Feedwater Pump was out of service for routine surveillance and it had no effect on the cause of the trip nor had any effect on the trip recovery. St. Lucie is investigating the cause of the lockout on the 2A2 4160V bus. Unit 1 was not affected by this event. At the time of this report, the 2A Emergency Diesel Generator was still loaded while investigations were underway. Steam generator level is being maintained using main feed. The licensee notified the NRC Resident Inspector. |
| ENS 41927 | 18 August 2005 13:49:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Automatic Scram Due to Loss of a Power Board | Unit 1 scrammed from 100% power due to a loss of power board 11 coincident with 1/2 scram present already on RPS channel 12 due to (instrumentation and control) (I&C) testing. A loss of power board 11 causes a loss of 11 RPS trip bus which in turn produces a 1/2 scram. Loss of power board 11 is currently under investigation. In addition during the scram, HPCI injected into the reactor vessel on a turbine trip signal to maintain reactor water level. Currently, the reactor is in hot shutdown with reactor water levels being maintained in the normal level band at 74 inches with feedwater in automatic. Reactor pressure is currently 920 psig and being maintained in automatic with turbine bypass valves. Plan is to stay in hot shutdown and complete scram recovery procedures. All control rods fully inserted. No safety relief valves actuated. Electrical busses were being supplied by normal offsite power. Emergency diesel generators are available. The decay heat removal path is currently normal feedwater to the reactor vessel through the turbine bypass valves to the condenser. There was no impact on Unit 2. The licensee is going to suspend any high risk maintenance activities on Unit 2. The licensee notified the NRC Resident Inspector. |
| ENS 42056 | 15 October 2005 11:02:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Auxiliary Feedwater Actuation on a Manual Reactor Trip | Auxiliary Feedwater actuation due to low steam generator level following a manual reactor trip. At 0702 on 10/15/05, a manual reactor trip was initiated due to decreasing level on the 3C steam generator. Auxiliary Feedwater system actuated as expected due to post-trip steam generator level decrease. 3C steam generator level was restored using Auxiliary and Main feed. The cause of the loss of steam generator level control is under investigation. The plant is stable in Mode 3 with the Auxiliary Feedwater system in standby. All control rods fully inserted. The decay heat removal path is normal feedwater through the steam generators and out the atmospheric relief valves. There are no primary to secondary steam generator tube leaks. Safety related electrical busses are powered via normal offsite power. Emergency diesel generators are available if needed. There was no impact on Unit 4. The licensee notified the NRC Resident Inspector. * * * UPDATE AT 1147 ON 10/19/05 FROM E. TREMBLAY TO P. SNYDER * * * Updated to include notification under 10 CFR 50.72 (b)(2) for manual reactor trip. The licensee notified the NRC Resident Inspector. R2DO (Ernstes) notified. |
| ENS 42173 | 29 November 2005 04:20:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Automatic Reactor Trip Following Main Feed Pump Trip | At 22:19 CST, Main Feedwater Pump B tripped on over current. A secondary plant runback from 100% power was automatically initiated. During the secondary plant runback, the reactor automatically tripped on Steam Generator B low-low level at 22:20 CST. All three Auxiliary Feedwater pumps automatically started due to low-low Steam Generator level. The plant has been stabilized at Hot Shutdown (RCS temperature approximately 547 degrees F, RCS pressure approximately 2235 psig). Investigation into the cause of the trip is on-going. This event is being reported under 10CFR50.72(b)(2)(iv)(B) for actuation of the reactor protection system (RPS) when the reactor is critical and 10CFR50.72(b)(3)(iv)(A) for valid actuation of the Auxiliary Feedwater System. All control rods fully inserted on the automatic trip. Steam generator water levels have recovered to indicate in the narrow range. The current decay heat removal path is auxiliary feedwater to the steam generators steaming through the power operated relief valves. There are no known primary to secondary leaks. All safety related buses are powered from offsite power. Emergency diesel generators are available and in standby. The licensee notified the NRC Resident Inspector. |
| ENS 42180 | 1 December 2005 19:45:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Automatic Reactor Trip Due to Low Steam Generator Level | While reducing power in order to enter containment, and following a manual main turbine trip due to high vibration, an automatic reactor trip on low steam generator level was received as a result of the turbine trip transient. Containment was being entered to investigate the source of an RCS identified leakage, which was less than the Technical Specification limit. In conjunction with the reactor trip, an automatic actuation of the Auxiliary Feedwater System was received as expected. All control rods fully inserted on the automatic trip. The current decay heat removal path is via the steam dumps to the main condenser. No primary or secondary relief valves lifted during the transient. There are no known primary to secondary leaks. All safety related buses are powered from offsite power. With the exception of one diesel out of service for planned maintenance, all emergency diesel generators are available and in standby. Unit 2 was not affected. The licensee notified State and local agencies and the NRC Resident Inspector. |
| ENS 42277 | 20 January 2006 13:56:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation | Rps Actuation | On 1/20/2006 at 0730 hrs, a Unit 2 control room annunciator was received indicating high conductivity/sodium in the main condenser. The Chemistry Dept. confirmed the sodium level was high indicating saltwater intrusion from a tube leak in the 2B2 Condenser Waterbox. Per the Secondary Chemistry Off-Normal Procedure, a rapid downpower to less than 5% power was initiated to remove the affected waterbox from service. It was decided to go ahead and remove Unit 2 from service rather than remain critical at a low power level. The downpower was planned to decrease power to approximately 25%, perform a manual transfer of plant electrics to the auxiliary transformers, and then manually trip the reactor in accordance with plant procedures. All systems worked as planned during the downpower and the reactor was manually tripped at approximately 25% power at 08:56 hrs. Standard Post Trip Actions and the Reactor Trip Recovery Procedure were carried out without incident. All control rods fully inserted and no Steam Generator (S/G) Safety Valves lifted. Feedwater to the S/G was supplied by the Main Feedwater pumps during the shutdown and later transferred to the Auxiliary Feedwater pumps. All safe shutdown equipment operated as expected. The plant is stable in Mode 3, Hot Standby conditions, with decay heat removal being accomplished by steaming through the Atmospheric Dump Valves. The Main Feedwater pumps remain available if needed. Unit 1 was not affected by this event. The licensee notified the NRC Resident Inspector. |
| ENS 42367 | 23 February 2006 15:22:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Manual Reactor Trip Due to Loss of Main Feedwater | Loss of main feedwater occurred due to an instrument air line failure during a maintenance activity. The reactor was manually tripped and all control rods inserted fully. Auxiliary feedwater received an auto start signal and is providing feedwater to the steam generators. No safety relief valves or PORVs lifted. Decay heat removal is via the turbine bypass valves to the condenser. The plant is in a normal shutdown plant electrical lineup and there was no effect to Unit 3. The licensee notified the State of Connecticut and the city of Waterford. A media press release will be made at a later time. The licensee notified the NRC Resident Inspector. |
| ENS 42395 | 8 March 2006 16:09:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Automatic Reactor Trip as a Result of a Turbine Generator Trip | This 4-hour notification is being made in accordance with 10CFR50.72(b)(2)(iv)(b). Salem Unit-1 reactor automatically tripped at 1109 (RPS actuation). The trip was initiated due to turbine trip. The cause of the turbine trip is being investigated. All safety systems functioned as designed with the exception of control rod 1SC1, which did not fully insert. 1SC1 indicates 16 steps. It should indicate zero steps when fully inserted. Auxiliary Feedwater pumps started as expected. Off-site power is available. Emergency diesel generators are available but not required at this time. During the implementation of the EOP's, a steam leak was reported in the Turbine Building. The Main Steam Isolation Valves (MSIV's) were closed as a conservative measure. This is an 8-hour reportable occurrence in accordance with 10CFR50.72(b)(3)(iv)(a). The leak was subsequently identified as a feedwater leak on the 11CN32 (11 Steam Generator Feed Pump suction valve). The Condensate System was placed in a normal shutdown line-up and the leak is not an impact to personnel safety or plant stability. Decay heat removal is via the atmospheric steam dumps at this time. The MSIV's are being bypassed to restore the main condenser as a heat sink. Salem Unit-1 is currently in Mode 3 with reactor coolant system temperature at approximately 549 deg F with pressure at 2235 psig. There was no equipment out of service that contributed to this event and there were no personnel injuries or radiological occurrences associated with this event. The licensee has notified the NRC Resident Inspector and will be making State and local notifications. A press release is expected. |
| ENS 42557 | 5 May 2006 21:00:00 | 10 CFR 50.72(b)(3)(v)(B), Loss of Safety Function - Remove Residual Heat | Potential Loss of Rhr | At 1600 CST on May 5, 2006, the Kewaunee Power Station (KPS) declared both trains of Residual Heat Removal (RHR) inoperable due to a vulnerability to internal flooding caused by possible ruptures of non-seismically qualified piping during a seismic event. Since the KPS RHR system is not protected from non-seismically induced piping breaks in the auxiliary building basement KPS does not presently meet the design criteria in the KPS USAR for the RHR system. The specific design criteria is stated in USAR section B.5 'Protection of Class I Items' and states that Class I items are protected against damage from 'Rupture of a pipe or tank resulting in serious flooding or excessive steam release to the extent that the Class I function is impaired.' With KPS in Intermediate Shutdown and both trains of RHR inoperable, KPS meets the Technical Specification requirement for Decay Heat Removal Capability with two (2) Steam Generators operable to remove decay heat. This event is being reported under 10CFR50.72(b)(3)(v)(B) for 'Any event that at the time of discovery could have prevented the fulfillment of the safety function of systems that are needed to remove residual heat.' The licensee notified the NRC Resident Inspector. |
| ENS 42576 | 15 May 2006 14:59:00 | 10 CFR 50.72(b)(3)(iv)(A), System Actuation | Momentary Loss of Dhr Due to Automatic Actuation of the Keowee Emergency Power Supply | Event: At 10:59 hours on 5-15-06, while in Mode 6 following completion of refueling activities, Oconee Unit 3 experienced a lockout of CT-3, the transformer for the Startup power source, which was in service at the time. This resulted in a momentary loss of AC power to the unit. Keowee Hydro Station, the Oconee emergency power source received an automatic emergency start signal, started, and closed in to supply power via the Underground Emergency Power path within approximately 40 seconds. Initial Safety Significance: Initial conditions of significant systems: Normal power via backcharge of main transformer was not available. The Fuel Transfer Canal was full and valves open connecting it to the Spent Fuel Pool. Time to core boil was 58 minutes per procedure. The Equipment Hatch was open. The initial loss of power resulted in interruption of Decay Heat Removal (DHR) Cooling, Spent Fuel Pool Cooling, and other support systems. Power was automatically restored and the affected systems returned to service promptly. Therefore there was no safety significance to this event. Reactor Coolant System heated up from approximately 80F to approximately 89.5F during this event. Corrective Action(s): As stated, Keowee started and supplied power automatically. The appropriate Abnormal Procedures were entered to restore power and restart these systems. DHR was restored at 11:13. Actions were initiated to achieve Containment Closure due to the loss of DHR. The Equipment Hatch was closed by 11:40. Backup power is available from Central Switchyard via CT-5. The cause of the initiating transformer lock out is under investigation. The licensee informed the NRC Resident Inspector. |
| ENS 42592 | 20 May 2006 18:21:00 | 10 CFR 50.72(a)(1)(i), Emergency Class Declaration | Unusual Event - Reactor Trip of Both Units Due to Loss of All Offsite Power | The licensee experienced a reactor trip to Units 1 & 2 due to loss of all offsite power. This anomaly was believed to be from an overcurrent condition in a relay, and limited to the Catawba switchyard. The reactor tripped due to actuation of the reactor protection system (RPS), and all rods for both Units fully inserted as designed. The Unit 1 Pressurizer PORV did lift momentarily. The decay heat is being released through the secondary PORV's, and steam generator level is being maintained with the auxiliary feedwater system (AFW). Presently, Units 1 & 2 are in EAL 4.5.U.1 (Loss of Offsite Power to Essential Busses for greater than 15 minutes). The licensee indicated there are no steam generator tube leaks in either unit. The licensee activated the TSC at 15:50 EDT. The licensee notified the NRC Resident Inspector, as well as State and local government.
The licensee terminated from the Unusual Event at 0140 EDT on 5/21/06 based on restoration of offsite power to all essential buses. The licensee is no longer in a Tech Spec cooldown LCO and both units have secured from further cooldown and have stabilized conditions in Mode 3. Both units are still on natural circulation with AFW cooling and decay heat removal through secondary PORVs. The licensee will notify the NRC Resident Inspector. R2DO (Widmann), NRR (Ross-Lee), IRD (Blount), FEMA (Kimbrell) and DHS(York) have been notified |
| ENS 42641 | 14 June 2006 18:00:00 | 10 CFR 50.72(b)(3)(ii)(A), Seriously Degraded | Leaking Decay Heat Removal Isolation Valve Bypass Line | On 2-21-06, during a tour of containment during normal operation at 100% power, a small leak (one (1) to three (3) drops per second) was noted from a 1/2 inch line connected to the decay heat removal (DHR) drop line. It was identified as being a body-bonnet leak on valve 1LP-167 subject to a TS limit of 10 gpm. At approximately 1400 hours on 6-14-06 following a shutdown for an unrelated issue, the source was identified as a leak at a weld in a "tee" joint adjacent to 1LP-167. This is considered RCS pressure boundary leakage, subject to a TS limit of zero leakage. The leak was isolated by closing a normally open valve in the 1/2 inch line and the leakage stopped. Initial Safety Significance: The leak is in a 1/2 inch line which provides over pressure protection from thermal expansion in the volume between 1LP-1 and 1LP-2 (the main pressure boundary isolation valves between the high pressure RCS and the LPI (DHR) system). The leak rate (1 to 3 drops per second) was not significant, except that it was RCS pressure boundary leakage. 1LP-1 is normally closed, but must be opened to establish a DHR path. Valve 1LP-167 is a 1/2 inch check valve which would have limited RCS leakage. Thus, if the leak had grown, it would have been limited to the amount of seat leakage past either 1LP-167 or 1LP-1. It would also have been limited by the 1/2 inch size of the line containing the leak." Technical Specification LCO 3.4.13 applies to RCS leakage in modes 1 to 4. The licensee plans to fix the leak prior to entry into mode 4. The licensee notified the NRC Resident Inspector.
On 6-14-06 at 1908 hours Oconee reported an RCS pressure boundary leak in a 1/2 inch line connected to the decay heat removal (DHR) line near valve 1LP-1 inside containment. Oconee has reviewed the event in greater detail and has concluded that the event is not reportable. The Basis for TS 3.4.13 states that RCS LEAKAGE includes leakage from connected systems up to and including the second normally closed valve (or outermost isolation valve for systems penetrating containment). However TS 1.1 contains a definition of LEAKAGE which includes 'Pressure Boundary LEAKAGE: LEAKAGE (except SG LEAKAGE) through a nonisolable fault in an RCS component body, pipe wall, or vessel wall.' The leakage in this event was isolable, and therefore does not meet the definition of Pressure Boundary LEAKAGE. Therefore the zero leakage criterion of TS 3.4.13 does not apply to this leak. The applicable criterion is 10 gpm identified LEAKAGE. Since the leak does not meet the criterion as Pressure Boundary LEAKAGE, the leak was isolable, and the applicable TS LEAKAGE limit was not exceeded, this event does not meet the reportability criteria for 10 CFR 50.72 or 50.73 and event notification 42641 is hereby RETRACTED. Additional information and clarification: "During normal operation the leak was isolated by one barrier (valves 1LP-167 and 1LP-1, closed in parallel). The leakage observed on 2-21-06 during a containment tour at Mode 1 was recorded as 1 drop per second. As stated in the initial notification, at that time the leak was believed to be a body-bonnet leak. It was observed at Mode 1 again on 5-25-06 and recorded as 3 drops/second. On 6-14-06, the leakage was recorded as one drop/second while at reduced pressure in Mode 4, before the DHR systems was placed in service. At that point, the leak was isolated by closing an additional valve (1LP-166, normally open), and the leak stopped. The Low Pressure Injection system was placed in service for DHR, which opened 1 LP-1. Later, with system pressure at approximately 285 psig in Mode 5 (outside the applicability of TS 3.4.13), 1LP-166 was reopened to allow additional verification of the leak location. At that time the leak was described as a 'spray' but no leak rate was measured before 1LP-166 was reclosed. The leak rate at that time was estimated as well less than 10 GPM. Corrective Action: The affective section of 1/2 inch pipe and associated fittings have been removed for transfer to a Duke laboratory for analysis. Repairs will be completed prior to return to mode 4. The licensee notified the NRC Resident Inspector. Notified the R2DO (Bonser). |
| ENS 42642 | 15 June 2006 07:00:00 | 10 CFR 50.72(b)(2)(xi), Notification to Government Agency or News Release 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation 10 CFR 50.72(b)(2)(iv)(A), System Actuation - ECCS Discharge | Reactor Scram While Shifting Power Supplies | At approximately 0300 hours on 15 June, the Susquehanna Unit One reactor automatically scrammed due to an apparent neutron monitoring trip while transferring Reactor Protection System power supplies. All rods (fully) inserted, and both reactor recirculation pumps tripped. Reactor water level lowered to -38" causing level 3 (+13") and level 2 (-38")isolations, and was restored to normal level (+35") by RCIC and subsequently the feedwater system. All isolations at this level occurred as expected. No steam relief valves opened. Pressure was controlled via turbine bypass valve operation. All safety systems operated as expected. A reactor recirculation pump was restarted to re-establish forced core circulation. The reactor is currently stable in condition 3. An investigation into the cause of the shutdown is underway. Unit Two continued power operation. The NRC resident inspectors were notified. A press release will occur. After the scram, HPCI automatically started but was manually shut down with RCIC maintaining vessel level. Decay heat removal is being maintained with main feedwater and the turbine steam dumps. The electrical grid is stable. No major LCOs were in affect at the time of the event. |
| ENS 42864 | 26 September 2006 19:13:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation | Manual Reactor Trip Due to Reactor Coolant Pump Seal Leakage. | Salem Unit 2 was manually tripped from 94.1 percent reactor power due to Reactor Coolant Pump "21" number 1 seal leakoff exceeding 6 gpm in accordance with abnormal operating procedure. Reactor Coolant Pump "21" was subsequently stopped upon reactor trip verification in accordance with the Abnormal Operating Procedures. Forced reactor coolant system circulation is via the remaining 3 reactor coolant pumps. All safety systems functioned as designed. Auxiliary feedwater pumps started as expected, offsite power is available, Emergency Diesel Generators are available but not required at this time. Decay heat removal is via steam dumps to the main condenser. Salem Unit 2 is currently stable in Mode 3 (Hot Standby). There is no equipment out of service that contributed to this event. There were no personnel injuries or radiological occurrences associated with this event. The licensee is investigating to determine the cause of the abnormal reactor coolant pump seal leakoff flow rate. The licensee notified local government officials. The licensee notified the NRC Resident Inspector. |
| ENS 42888 | 7 October 2006 22:01:00 | 10 CFR 50.72(a)(1)(i), Emergency Class Declaration | Manual Scram Due to Unusual Noise in Turbine Building | The main turbine cross-under safety relief valves lifted for no known reason and blew siding off the side of the Unit 2 Turbine building. This siding hit the feeder lines to the A & C Reserve Station Service Transformers (RSSTs). The operator manually scrammed the plant due to swings in steam generator level and unusual noise coming from the turbine building . Unit 2 shutdown currently de-energized A & C Reserve Station Transformers, which effects D & E transfer buses. This also effects 1J bus, which is de-energized, and 1H & 2J buses which are energized with #1 diesel and #3 diesel. Decay heat removal is being performed thru the SG PORV's and auxiliary feedwater system, with forced cooling from the "B" RCP. Safety related systems are available if required. Notified USDA (A. Jimenez) in addition to the other agencies already identified. The licensee notified the NRC Resident Inspector, as well as State and local agencies.
The site terminated the Alert at 05:40 due to having the "A" RSST in service with bus 1J being powered from its normal power supply. No damage was found from the displaced siding with the exception of the "C" RSST (which should be repaired around noon). The "C" RSST is currently tagged out for maintenance. The licensee notified the NRC Resident Inspector, state, and local governments. Notified: R2DO (Decker), R4DO (Pick), NRR (Dyer, Weber, Quay), IRD (Blount, Wilson), R2 (McCree), DHS (Gray), FEMA (Dunker), DOE (Steve Bailey), EPA (Allison), USDA (Dean Giles), and HHS (Lt. Smith).
At 1827 hours on 10/07/06, an Emergency Notification System (ENS) notification was made for an Alert declaration at Surry Power station. The steam discharge from the turbine system safety valves that had lifted caused pieces of siding from the turbine building to dislodge and come in contact with two phases of the overhead bus for the 'A' and 'C' reserve station service transformers (RSST). The basis for the declaration was the Emergency Action Level (EAL) Tab K-11: 'Notification of missile impact causing damage to safety-related equipment or structures'. Upon further review, the RSSTs were determined not to be safely-related equipment. Therefore, the conditions for an Alert emergency did not exist and the notification is being retracted. A notification will be made to the Virginia Department of Emergency Management. This is being reported In accordance with 10 CFR50.72, (b) (2) (xi). As noted in EN# 42890, conditions for a Notification of Unusual Event (NOUE) did exist at the time of the Alert notification. The licensee notified the NRC Resident Inspector. Notified the R2DO (Henson). |
| ENS 42920 | 19 October 2006 18:47:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation | Manual Reactor Trip Following the Trip of Secondary Condensate Pumps | The following event description is based on information currently available. If through subsequent reviews of this event, additional information is identified that is pertinent to this event or alters the information being provided at this time, a follow-up notification will be made via the ENS or under the reporting requirements of 10CFR50.73. On October 19, 2006, at approximately 1147 Mountain Standard Time (MST) Palo Verde Unit 3 plant operators manually tripped the reactor from approximately 100% rated thermal power. The reactor was tripped when lowering hotwell levels caused two condensate pumps to trip. The preliminary cause for the lowering hotwell level was the hotwell draw-off valve spuriously failing open. Unit 3 was at normal temperature and pressure prior to the trip. All CEAs inserted fully into the reactor core. This was an uncomplicated reactor trip. No ESF actuations occurred and none were required. Safety related buses remained energized during and following the reactor trip. The offsite power grid is stable. No significant LCOs have been entered as a result of this event. There was no loss of normal heat removal capabilities, or loss of any safety functions associated with this event. No major equipment was inoperable prior to the event that contributed to the event. The event did not result in any challenges to fission product barriers and there were no adverse safety consequences as a result of this event. The event did not adversely affect the safe operation of the plant or the health and safety of the public. The Resident Inspector was informed of the Unit 3 reactor trip and this notification. The current decay heat removal path is auxiliary feedwater supplying water to the steam generators steaming to the condenser. Emergency Diesel Generators are available. |