Semantic search
| Entered date | Event description | |
|---|---|---|
| ENS 46554 | 19 January 2011 17:44:00 | Part 21 reportable defect foreign material (FM) was discovered in a spare heat exchanger (HX) when visually inspected on 10/19/10 as part of contingency planning for potential installation of the HX during the 3EOC�25 refueling outage. Visual inspections with a video probe (fiberscope) were being performed on the inlet/outlet channels and the tubes of a spare HX to verify that no FM was present. However, when performing these inspections, a problem was encountered in that maintenance was unable to disassemble and remove the bonnet from the lower (inlet) pressure seal connector on the HX. Subsequently, on 10/19/10 a fiberscope inspection was performed of the "back side" of the pressure seal bonnet by inserting a fiberscope thru the inlet nozzle access. A foreign object that appeared as a u-shaped piece of thin wire was seen just behind the pressure seal bonnet, laying in the bottom of the body. Due to the inability to disassemble the pressure seal connector, the affected HX was not installed, The FM was retrieved from the spare HX on December 27,2010 and its size and material type confirmed. The "U-shaped" material is type 304 stainless steel and appears to be a metal shaving. It is about 1-1/2" in length if the "u" was stretched out, 3/32" wide and less than 1/64" thick. The HX was intended for use as a Reactor Coolant System Letdown Cooler. It was ordered in 2006 and was supplied by Energy Steel Supply Company (ESSC), Catalog 10 350952, SIN N32389-1, Purchase Order No. DP 19279. Initial Safety Significance: This event has no actual significance since the issue was discovered prior to installation of the component and the component was not installed. However, Part 21 requires evaluation based on the assumption that the component was installed in the as-found condition. On 1/6/2011, Oconee Engineering concluded that, in some low probability scenarios, this FM could constitute a Substantial safety hazard. Per the postulated scenarios, the FM would be flushed out of the cooler when placed in service. A low potential exists that the FM could be trapped in a downstream valve and damage the seat, resulting in leakage. The cooler outlet valve and the next valve in series are containment isolation valves. If the FM caused leakage in one of those valves and the other was affected by a postulated single failure, any resultant leakage would constitute containment leakage. Also, in some event scenarios, unacceptable leakage past the cooler outlet valve seat could render the Oconee Standby Shutdown Facility (SSF) Reactor Coolant Make-up System inoperable. Therefore, Oconee concludes this issue meets the Part 21 definition as a reportable defect. Corrective Action(s): The affected spare cooler was not installed. Subsequently, the FM was removed. A second spare cooler was inspected, no similar FM was found, and the second cooler was installed. The NRC Resident Inspector will be notified. |
| ENS 46544 | 14 January 2011 17:19:00 | This report is being made per paragraphs 50.73(a)(1) and 50.73(a)(2)(iv)(A) to address an actuation of the Emergency Feedwater (EFW) System on Oconee Unit 3 on 11/18/10 while moving the 3A Motor Driven EFW Pump (MD EFWP) control switch from position 'Auto 1' to 'Auto 2.' EFW is a system named in 50.73(a)(2)(iv)(B). The 3A MD EFWP was inadvertently started during operation of the control switch in the Oconee Unit 3 Control Room. The start signal was a manual start when the operator moved the control switch beyond the intended position. The functioning/behavior of the MD EFWP control switch and human error are being investigated in the site corrective action program. This is considered an INVALID signal with respect to 50.73(a)(2)(iv)(A). The manual start only affected the 3A MD EFWP. On 11/18/10, a Unit 3 startup from a refueling outage was in progress. Unit 3 was in Mode 3. While performing a step in OP/3/A/1102/001 (Controlling Procedure for Unit Startup), the Operator inadvertently started 3A MD EFWP when positioning 3A MD EFWP control switch from position 'Auto 1' to 'Auto 2.' Specific Information Required per NUREG 1022: (a) The specific train(s) and system(s) that were actuated: The specific train(s) and system(s) that were actuated was the 3A MD EFWP and the A train of EFW. The 3B MD EFWP and the Turbine Driven EFW Pump were not affected by this event. (b) Whether each train actuation was complete or partial: The manual actuation was considered complete (i.e. all necessary components responded to the start signal to provide EFW to the Steam Generator (SG). The A train control valve (3FDW-315) was open, as expected for the evolutions in progress. This allowed EFW to reach the SG. C) Whether or not the system started and functioned successfully: The 3A MD EFWP and train started and operated successfully until secured by Operations personnel. Initial Safety Significance: None, there was no significant transient. Corrective Action(s): EFDW was secured within approximately one minute by placing 3A MD EFWP control switch in the Auto 2 position. This event has been entered into the site corrective action program for resolution. The licensee notified the NRC Resident Inspector. |
| ENS 45180 | 1 July 2009 16:19:00 | On 5-19-09 ONS (Oconee Nuclear Station) Unit 3 was in Mode 3 during startup from a refueling outage. At 1609 EDT the 3A Motor Driven Emergency Feedwater Pump (MDEFWP) unexpectedly started when the control switch was placed in the AUTO2 position as part of system alignment prior to unit startup. Investigation found that the impulse line for the hydraulic oil pressure switch on the operating 3A Main Feedwater Pump was clogged, causing sensed pressure to read below setpoint. Repositioning the control switch enabled the 3A MDEFWP auto start circuitry, which immediately actuated due to the pre-existing false low pressure indication. Several other redundant indications validated that the pressure signal to the pressure switch was false and that actual hydraulic oil pressure remained above the pressure switch setpoint. Although the pressure switch did see low pressure in the impulse line, the actuation is considered invalid since the signal was based on a false reading that did not represent actual plant conditions. Therefore this report is being made under 10 CFR 50.73(a)(1) and 50.73 (a)(2)(iv)(A). Per NUREG-1022, Rev. 2 the following information is requested: A) The specific train(s) and system(s) that were actuated. 3A Motor Driven Emergency Feedwater Pump (MDEFWP) which feeds the 3A Steam Generator (SG). B) Whether each train actuation was complete or partial. The train actuation was considered complete. The pump started per the signal and operated as required/expected in response to the signal. This pump is the only component in the train which receives a specific signal as part of the actuation circuitry. C) Whether or not the system started and functioned successfully. The 3A MDEFWP started and the system functioned successfully. The EFW control valve (3FDW-315) is set to control at 30 inches (SG startup level) versus 25 inches for Main Feedwater control. Therefore the SG level increased and the train then controlled at approximately 30 inches while an investigation determined the reason for the actuation (as explained above). The 3A MDEFWP was stopped at 2050 EDT and returned to normal status. Initial Safety Significance: Due to low feedwater demand at the time, there was little impact on the unit. Since the SG level was maintained above the normal control system setpoint, Main Feedwater flow was automatically reduced to compensate for the EFW flow. The 3A MDEFWP and associated pressure switch/actuation circuit were declared inoperable during pump shutdown and restoration to normal. Corrective Action(s): After troubleshooting identified the clogged impulse line, it was isolated and cleared. The 3A MD EFWP and the associated pressure instruments were returned to service. The licensee notified the NRC Resident Inspector. |
| ENS 43558 | 9 August 2007 10:41:00 | Event: On August 7, 2007, Duke Energy (Duke) completed a reportability determination which concluded that two relays contained deficiencies and were reportable under Part 21. The relays were Commercial Grade Items dedicated by Duke. Following dedication, a bench test performed on August 26, 2004 revealed that relay contacts were not set up properly at the factory. Eight other relays from the same purchase order were acceptable. The relays were Magnecraft Struthers-Dunn part number 219ABAP-115/125D. The Part 21 evaluation in 2004 was terminated based on incorrect guidance in the applicable Duke administrative directive. The directive error was identified March 29, 2007 and a review of prior Part 21 reportability determinations was initiated. The original 2004 problem report on these relays was reopened, leading to this Part 21 report being made at this time. Initial Safety Significance: None. The defective relays were never installed. The intended applications could not have resulted in a significant safety hazard. However, the Duke administrative directive on Part 21 evaluations states that all potential applications where the component might be installed as a substitute must be considered. Duke has concluded that installation in some unspecified application 'could have resulted in a significant safety hazard' and therefore the issue is being reported. Corrective Action(s): In 2004: There were eight (8) additional relays from the same purchase order. These were retested and found acceptable. The two identified defective relays were returned to the manufacturer. The manufacturer concluded that the relay contacts were improperly assembled. They consider this an isolated case. In 2007: The Duke administrative directive on Part 21 evaluations was corrected. Previous Part 21 determinations were reviewed, leading to this report. NRC Resident Inspector was notified of this Part 21 notification by the licensee. |
| ENS 43146 | 6 February 2007 10:56:00 | This report is being made per paragraphs 50.73(a)(1) and 50.73(a)(2)(iv)(A) to address two actuations of the Emergency Feedwater (EFW) System on Oconee Unit 1 on 12/8/06 by the Steam Generator (SG) Dry-out Protection Circuit. EFW is a system named in 50.72(b)(3)(iv)(B). By design, the SG Dry-out Protection Circuit actuates whenever two Extended Start-up level indications (two of two actuation logic) in either SG are lower than the setpoint (i.e. below 21 inches) for more than 30 seconds. This start circuit is not credited in Oconee safety analyses as performing a required safety function, therefore this signal is considered an INVALID signal with respect to 50.73 (a)(2)(iv)(A). Upon actuation, the circuit starts both Motor Driven Emergency Feedwater Pumps (MD EFWPs) on the affected unit. It does not send a start signal to the Turbine Driven Emergency Feedwater Pump. Per the startup procedure, Condensate Booster Pumps (CBP) feed the SGs until a main Feedwater pump (FDWP) is placed in service. Operators begin startup of a FDWP when the Reactor Coolant System (RCS) temperature is between ~395 degrees to 475 degrees. The Unit is then maintained at ~ 475 degrees RCS temperature and 500 - 550 psig SG pressure until a FDWP is in service. On 12/8/06, a Unit 1 startup from a refueling outage was in progress. RCS temperature was approximately 475 deg. (Mode 3) when the RCS heat-up was suspended due to issues with the 1A FDWP Turbine which delayed placing it in service. Steam pressure was being maintained approximately 530 psig (in the procedural band of 500-550 psig) per the unit startup procedure. In addition, a 'SG Hot Soak' was in progress. For this evolution, SG level was raised to 75% (Operating Range) then Operators took manual control to individually blow down 1A and the 1B SGs to low levels (25 inches) while attempting to maintain level above 21 inches. During this evolution, 1B SG levels decreased below minimum level. Operators initiated actions to recover level but at 2143 the 1A and the 1B MD EFW Pumps auto-started on dry-out protection. From their observation of the level displays, the Operators thought that the actuation logic had not been met (i.e. level had not been less that 21 inches for 30 seconds). Therefore they considered the actuation to be spurious. Based on this understanding and concerns about possible overfeeding and RCS overcooling (due to the relatively low decay heat load starting up from a refueling outage), EFW was secured and reset at 2144. SG Blowdown activities continued per procedure. At 2207, in response to lowering 1A SG levels, the dry-out protection feature again initiated an auto start of the 1 A and 1 B MD EFW Pumps. Based on his review of SG levels, the CR SRO believed that the second EFW actuation was invalid and directed that EFW be secured. EFW was secured and reset at 2208. At 2241 hrs SG outlet pressure was lowered and maintained within a band of 490-520 psig. Subsequent review of computer data indicated that a dry-out condition (i.e. less than 21 inches SG level for 30 seconds) did exist for both actuations. Therefore both actuations were valid in that actual plant conditions satisfied the initiation criteria, but, as stated above, the SG Dry-out Protection signal is considered an INVALID signal with respect to 50.73 (a)(2)(iv)(A). Additional review by Mechanical-Civil Engineering personnel determined that the Unit 1 CBPs operate at approximately 15 psig lower discharge pressure than the Unit 2 and 3 CBPs, apparently due to lower discharge pressures on the Unit 1 Hotwell pumps. That being the case, the Unit 2 and 3 CBPs, apparently due to lower discharge pressures on the Unit 1 Hotwell pumps. That being the case, the Unit 1 CBPs in service could not develop sufficient head pressure to maintain adequate flow to the SGs over the full operating operating band of 500 - 550 psig allowed by current operating procedure guidance. As steam pressures approached or exceeded 535 psig, the ability to feed the SGs using the CBPs was reduced, ultimately leading to the dry-out condition. The issue of these pump discharge pressures being slightly lower than expected had not been recognized previous to this event. The event investigation noted that during past startups, a main FDWP was normally placed into service promptly, which may have avoided using the CBPs to feed the SG above 535 psig. In this case, alignment of a main FDWP was delayed, which led to the event. Specific Information Required per NUREG 1022: (a) The specific train(s) and system(s) that were actuated. The specific train(s) and system(s) that were actuated were the 1 A and 1 B Motor Driven (MD) Emergency Feedwater (EFW) Pumps and the associated A and B trains of EFW. The Turbine Driven EFW pump does not receive this signal and was not challenged by the event. (b) Whether each train actuation was complete or partial. Both actuations were considered complete (i.e. all necessary components responded to the start signal and associated control signals to provide EFW to the SG(s)). (c) Whether or not the system started and functioned successfully. In both cases, the system started and operated successfully until secured by Operations personnel. Initial Safety Significance: None, there was no significant transient. Corrective Action(s): As stated above, EFDW was secured and reset at 2208. At 2241 hrs SG outlet pressure was lowered and maintained within a band of 490-520 psig. Unit 1 continued startup and subsequently reached Mode 1. This event has been entered into the site corrective action program for resolution. The licensee notified the NRC Resident Inspector. |
| ENS 42641 | 14 June 2006 19:08:00 | 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 42576 | 15 May 2006 13:48:00 | 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 42043 | 6 October 2005 15:53:00 | A licensed employee had a confirmed positive for alcohol during a random fitness-for-duty test. The employee's access to the plant has been suspended. Contact the Headquarters Operations Officer for additional details. |
| ENS 41966 | 31 August 2005 17:38:00 | Event: At 1428 hours on 8/31/2005, Oconee Unit 3 tripped. A routine test of the alternate power source for the Control Rod Drive System was in progress when power to the Control Rod Drive system was interrupted, which resulted in a reactor trip. AC power transferred to the Start-up source (switchyard). Normally the Main Steam Header pressure control setpoint is automatically increased for post-trip RCS temperature control. This did not occur. As a result the RCS cooled down to approximately 536F (versus a normal post-trip temperature of approximately 555F), reducing RCS pressure to the actuation setpoint for Engineered Safeguards Channels 1 and 2. This started the High Pressure Injection pumps in ECCS mode, caused partial containment isolation and initiated start-up of both Keowee Hydro Units (emergency power). Because Start-up power was available, Keowee did not supply power but remained in stand-by. At 1133 hours Operators terminated ECCS injection. Initial Safety Significance: Because RCS pressure decreased below normal post-trip levels which resulted in an ECCS actuation, this is considered an abnormal transient. Unit 3 has been stabilized and at this time the actual event is considered to have low safety significance. The exact cause of the loss of power to the Control Rod Drive system is unknown, but is under investigation. It is suspected that that loss also resulted in the failure of the Main Steam Header Pressure to shift to the post-trip Main Steam pressure control setpoint. Corrective Action(s): Operations stabilized Unit 3. A post-trip investigation is in progress, per site procedures and directives. All control rods fully inserted as a result of the reactor trip. No primary or secondary reliefs or PORVs lifted. Pressurizer level decreased off-scale low and was recovered prior to securing the High Pressure Injection pumps (the licensee estimates approximately 3000 gallons was injected). Current RCS temp is 542F (Tave) with RCS pressure in the normal post-trip band. Decay heat is being removed by the Steam Generators to Condenser through the Turbine Bypass Valves. Main Feedwater remained in service during the transient. The licensee informed the NRC Resident Inspector and does not plan a press release at this time.
During this event, the Engineering Safeguards (ES) System was manually bypassed at 14:33 on 8-31-05 to restore both High Pressure Injection (HPI) System trains to a normal lineup following an ES-initiated safety injection. Manually bypassing ES for both trains of HPI required entry into Tech Spec 3.0.3 at 15:33 on 8-31-05. Tech Spec 3.0.3 requires shutdown of Unit 3 to Mode 3 by 03:33 on 9-1-05 and to Mode 4 by 09:33 on 9-1-05. This condition was discovered to apply at 21:15 on 8-31-05. Initial Safety Significance: Units 1 and 2 remain at 100% power with no issues following the Unit 3 ES Actuation and Keowee Hydro Unit emergency start. Unit 3 remains in Mode 3. No other safety systems have actuated or exhibited abnormal behavior. Therefore, the safety significance of this condition is LOW. Corrective Action(s): Restore ES System to Automatic for the HPI System. The licensee reported this under 10 CFR 50.72(b)(2) (i), Technical Specification Shutdown. The licensee will notify the NRC Resident Inspector. R2DO (Lesser) notified. |
| ENS 41869 | 25 July 2005 18:38:00 | As a result of NRC Bulletin 2005-01 "Material Control and Accounting at Reactors and Wet Spent Fuel Storage Facilities", Oconee has been conducting an inventory of Special Nuclear Materials (SNM), other than complete fuel assemblies, stored in the spent fuel pools at Oconee. One canister, documented as containing 383 fuel pins, was found to actually contain 382 fuel pins. At this time it is uncertain if this is a record keeping error or an actual "lost" pin. Initial Safety Significance: The inventory process for other canisters is not complete, and it is possible that the pin may be in another container. These containers being inventoried have been stored underwater in the spent fuel pool for years. The affected canister was filled in 1982. Oconee has no reason to believe that this pin or any other SNM has been stolen or unlawfully diverted. For reference, one fuel assembly contains 208 fuel pins. Corrective Action(s): The inventory process is continuing. This notification is being trade per 10 CFR 74.11. The NRC Resident Inspector will be notified.
On July 17, 2005 at 1838 (ET) Oconee reported that during an inventory of Special Nuclear Material (SNM), other than complete fuel assemblies stored in the spend fuel pools at Oconee, one canister, documented as containing 383 fuel pins, was found to actually contain 382 fuel pins. At that time it was uncertain if this is a record keeping error or an actual "lost" pin. Further investigation has located the suspect fuel pin in a different canister; consequently, this issue no longer meets the reporting requirements as previously stated and this report is being retracted. Initial Safety Significance: There is no initial safety significance. Corrective Action(s): No additional corrective actions planned at this time. R2DO (C. Julian), NMSS EO (M. Burgess) and IRD Manger (M. Leach) notified. NRC resident Inspector was notified of this retraction by the licensee. |
| ENS 41850 | 18 July 2005 15:53:00 | Event: Keowee Hydro Station provides emergency power to the three Oconee units via two independent emergency power paths designated as the Overhead Path and the Underground Path. Either of the two Keowee Hydro Units (KHU) can be dedicated to either path, and Keowee Operations rotates which unit is aligned to which path, nominally on a monthly basis. On 7-18-05, as part of a corrective action from a previous event, Oconee reviewed power configurations for Keowee components/circuits with alternate power sources and discovered an alignment which presented a single failure vulnerability which could impact both paths. A review of Keowee Operating Procedures revealed that KHU-1 was designated as the normal source for control relays associated with the overhead path regardless of which unit was aligned to the underground path. KHU-1 was currently aligned to the underground path. It was determined that a postulated single failure of that DC power source would prevent KHU-1 from starting (which would affect the underground path) and would also prevent the main output Air Circuit Breakers from closing in the overhead path. As a result, Operations declared entry at 1130 hours (EDT) into Technical Specification (TS) 3.8.1 condition C for the Overhead power path being inoperable (a 72 hour allowed completion time). A review of available information indicates that this condition has existed whenever KHU-1 was dedicated to the underground path. This condition is being reported as an unanalyzed condition per guidance in NUREG 1022 section 3.2.4. Initial Safety Significance: The postulated single failure has not occurred. If the postulated single failure occurred during a design basis event, it is expected that, without credit for Operator intervention, both KHUs would fail. Operations would have been able to realign the KHU-2 to the Underground path and/or to have started and aligned a combustion turbine at Lee Steam Station. Such actions would be adequate for LOOP and station blackout scenarios, but would not be adequate for LOCA/LOOP scenarios. Therefore, the potential single failure condition being reported could have potentially resulted in a loss of safety function. Corrective Action(s): The immediate corrective action was to realign the affected DC control circuit power source to KHU-2, which was aligned to the overhead Path. The TS condition was exited at 1200 hours (EDT) when this realignment was complete. The licensee notified the NRC Resident Inspector. |
| ENS 41728 | 24 May 2005 20:00:00 | Event: On 5-19-05, Oconee discovered that an electrical contactor had failed at Keowee Hydro Station. This contactor normally can provide auxiliary power from one Keowee Hydro Unit (KHU) to cooling fans on the Keowee Main Transformer, which is part of the Overhead power path (one train of emergency power to the three Oconee units). At the time, power to the cooling fans was being provided by an alternate power source. A problem report (PIP) was written and an Operability Assessment concluded that the Overhead power path was fully operable. On 5-24-05 at 1350 hours, it was recognized that the alternate power source supplying the cooling fans was supplied from the auxiliary power bus associated with the KHU then aligned to the Underground power path (the redundant train of emergency power to the three Oconee units). It was recognized that this alignment presented a single failure vulnerability in that loss of the auxiliary power bus for the KHU aligned to the Underground path could also result in loss of Main Transformer cooling on the Overhead power path. As a result, Operations declared entry at 1350 hours into Technical Specification (TS) 3.8.1 condition C for the Overhead power path being inoperable (a 72 hour allowed completion time). A review of available information indicates that the electrical contactor actually failed on or before 5-2-05. Therefore the period of vulnerability to this potential single failure was approximately 22 days. This condition is being reported as an unanalyzed condition per guidance in NUREG 1022 section 3.2.4. Initial Safety Significance: If the postulated single failure occurred during a design basis event, it is expected that, without credit for Operator intervention, both KHUs would fail, but the failure is not expected until a minimum of one hour after the loss of auxiliary power. During this time Operations would have been able to realign the KHU with auxiliary power to the Underground path and/or to have started and aligned a combustion turbine at Lee Steam Station. Therefore, the condition being reported is not expected to result in a loss of safety function. Corrective Action(s): The immediate corrective action was to realign the Keowee units to the opposite power paths. This aligned the KHU capable of supplying power to the Main Transformer cooling fans to the Overhead path. The KHU associated with the failed contactor was aligned to the Underground path. The TS condition was exited at 1540 hours when this realignment was complete. The licensee notified the NRC Resident Inspector. |
| ENS 40902 | 28 July 2004 09:52:00 | Event: At 08:00 hours Oconee Unit 1 initiated a unit shutdown per Technical Specification (TS) 3.0.3. Unit 2 initiated shutdown at 0900 (ET). It is expected that Unit 3 will initiate shutdown at 1000 hours. Target for entry into Mode 3 is 1300 hours on all units. At 0129 hours all three Oconee units received a number of alarms related to power to the 230 KV switchyard (SWYD) battery chargers. At 0200 hours Operations determined that both AC power sources to the SWYD battery chargers required by TS 3.8.3 had tripped and declared entry into TS 3.0.3 because no specific condition of TS 3.8.3 applied. Evaluation for potential applicability of other reporting criteria is still in progress. Initial Safety Significance: The SWYD batteries currently have normal voltage (being monitored hourly) but are NOT considered operable per TS 3.8.5 at this time, which would also require TS 3.0.3 entry. However, if voltage drops too low the ability to remotely operate SWYD power circuit breakers would be affected, which would impact SWYD isolation capability. Local manual operation would still be possible, and operations personnel are stationed in the SWYD as a contingency. Corrective Action: 1. Maintenance has identified a fault in a power transfer switch. Actions have been completed to isolate the fault and restore power to the battery chargers. 2. Measurements of battery voltages are being taken hourly. A surveillance will be performed to verify TS 3.8.5 compliance after the charger power supply is restored. 3. Shutdown of Oconee units will follow schedule above unless power and battery voltages are restored sooner (as expected). The electrical grid is stable and standby emergency power remains operable. The NRC Resident Inspector has been informed. The licensee does not intend to make any State, local or other Federal notifications or issue any press release at this time.
At 0945 EDT both SWYD battery chargers were energized to restore battery parameters. At 1205 EDT the affected batteries were declared operable and all three (3) Units exited their respective LCOs. Units 1, 2, and 3 are currently holding at 80%, 84% and 89% power, respectively, and will commence power escalation after review and closeout of their paperwork. Notified R2DO (Decker). |
| ENS 40724 | 4 May 2004 19:08:00 | NOTE: Oconee Unit 2 is DEFUELED (No Mode) in a refueling outage. Oconee has discovered a new scenario where the double ended guillotine rupture addressed by IE Bulletin 80-04 is not the worst case with respect to containment pressure following a Main Steam Line Break (MSLB). Therefore this scenario is being reporting as an Unanalyzed Condition and a potential loss of the containment safety function. This new scenario involves a range of MSLB break sizes smaller than the double ended guillotine rupture addressed by IE Bulletin 80-04, with the break located inside containment, and with a concurrent Loss Of Offsite Power (LOOP). This event scenario is still being evaluated but it appears to result in containment pressures in excess of the 59 psig limit discussed in the UFSAR. Preliminary results indicate that pressure would not exceed the containment 'ultimate capacity' of 144 psig. Analysis has shown that the Steam Generator tube stresses remain within acceptable limits for this event scenario so that no additional RCS leakage would occur. As a result, the offsite dose for this scenario is bounded by previous scenarios for a MSLB outside containment. Background The AFIS (Automatic Feedwater Isolation System) Circuitry required by Tech Specs 3.3.11, 3.3.12, and 3.3.13 is intended to isolate Feedwater from the steam generators in the event of a Main Steam Line Break (MSLB) by closing the Feedwater Control Valves and preventing operation of the Emergency Feedwater Pumps. Tech Spec 3.7.3 requires the Feedwater Control Valves to be operable and provides an 8 hour Allowed Outage Time (AOT) if they are not. If the AOT is exceeded, the affected unit must be in Mode 3 within an additional 12 hours. The Feedwater Control Valves are air operated and fail as-is on loss of Instrument Air. Low MS pressure causes AFIS to signal the valves to close. Emergency Feedwater Pumps are interlocked based on rate of MS pressure drop. Scenario: ONS identified a new scenario involving a MSLB smaller than the double ended guillotine rupture addressed by IE Bulletin 80-04, located inside containment, and occurring concurrent with a LOOP. In this scenario, the LOOP results in the loss of power to the permanently installed plant instrument air compressors, so that instrument air pressure would begin to decay. The smaller MSLB break size slows the rate of pressure loss from the affected MS line. Break sizes exist such that by the time the MS system pressure decays to the AFIS actuation setpoint, instrument air pressure might become inadequate to close the Feedwater Control Valves. Also, the low rate of change of MS pressure might not satisfy the AFIS rate based setpoint for actuating the EFW pump interlock. If the control valves remain open or if the EFW pumps are allowed to operate, additional inventory would reach the steam generators and flash to steam. Since the scenario requires the break to be located inside containment, this would result in increased containment pressures. Initial Safety Significance: The Main Steam Line Break inside containment is a low probability event. Also, although the MSLB scenario includes the assumption of some primary to secondary leakage, the analysis shows that Steam Generator tube stresses remain within acceptable limits for these break sizes, so that no additional RCS leakage would occur. As a result, the offsite dose for this scenario is still bounded by the scenario for a break outside containment. Therefore this event is not significant with respect to the health and safety of the public. Corrective Action(s): A diesel compressor connected to the Instrument Air header has been placed in operation to assure a source of instrument air in the event of a LOOP. Additional actions for permanent resolution are being evaluated. The licensee will notify the NRC Resident Inspector. |
| ENS 40686 | 20 April 2004 10:55:00 | By design, the Steam Generator (SG) Dry-out Protection Circuit actuates whenever two level indications (two of two actuation logic) in either SG are lower than the setpoint for more than 30 seconds. This start circuit is not credited in any ONS safety analysis, therefore this signal is considered an INVALID signal with respect to 50.73 (a)(2)(iv)(A). Upon actuation, the circuit starts both Motor Driven Emergency Feedwater Pumps (MDEFWPs) on the affected unit. It does not send a start signal to the Turbine Driven Emergency Feedwater Pump. Shortly after entering Mode 4, a control operator stopped one of two operating Reactor Coolant Pumps per the Unit shutdown procedure. A second control operator was manually controlling Feedwater and reduced flow to control the system cooldown rate, without recognizing that the 2B SG had reached the low level setpoint for SG Dry-out Protection Circuit actuation. In this event, the 2B SG level trains A and B indicated lower than the setpoint value (-21 inches) for more than 30 seconds, so the SG Dry-out Protection Circuit started the 2A and 2B MDEFWPs. The actuation was considered complete and the system started and functioned successfully. Both MDEFWPs started. The 2B SG control valve, 2FDW-316, opened and fed the 2B SG from the 2B MDEFWP for approximately one minute until the SG level reached the EFDW control setpoint (30 inches). The 2A pump did not feed the 2A SG because 2A SG level remained well above the EFDW control setpoint so there was no demand for the 2A SG control valve, 2FDW-315, to open. The licensee notified the NRC Resident Inspector.
This update is to clarify a typographic misspelling on the first sentence of the last paragraph of this event notification which should read (~(approximately) 21 inches) instead of (-21 inches). Notified R2DO(Julian). |
| ENS 40557 | 1 March 2004 04:17:00 | The licensee reported that both digital trains of the automatic feedwater isolation system were declared inoperable when one channel's input failed to zero and about the same time the second channel showed a shift in readouts which was fairly significant that they also declared it inoperable. These two channels have a shared neutral bus and it is believed that there may be a loose connection somewhere in the circuit. They are currently troubleshooting the problem. Plant will initiate a unit shutdown if the problem cannot be corrected by 0600 on 03/01/04 (12-hour LCO A/S). The NRC Resident Inspector will be notified.
Update- FNS 40557, dated 3-1-04, addressed an apparent loss of safety function on Oconee Unit 2. Specifically, the Automatic Feedwater Initiation System (AFIS) was considered inoperable, and therefore unable to perform its required safety functions. During that event, Operations shift personnel conservatively declared AFIS Channel 2 inoperable because it demonstrated an unexpected shift in readout concurrent with the failure of Channel 1. Subsequently Duke power concluded that Channel 2 remained capable of performing its safety function despite the shift in readout, which was in the conservative direction. Therefore, Duke Power has concluded that there was no reportable loss of safety function associated with this event and hereby retracts ENS notification 40557. Duke Power notes that, during the event, both channels were intentionally disabled for a brief period as a planned part of the repair activity. This was done to prevent the possibility of a spurious actuation during the repair. However, per guidance in NUREG 1022, removal of both trains of a safety function as part of a planned activity which results in entry into a Tech Spec action statement is not reportable. Initial Safety Significance: Operations declared TS 3.3.13 Condition B, which allowed 12 hours to come to Mode 3. Repairs were completed prior to initiation of shutdown. Corrective Action(s): A loose wiring connection was repaired. The NRC Resident Inspector was informed. |
| ENS 40330 | 18 November 2003 11:05:00 | A vendor supervisor was determined to be under the influence of illegal drugs during a random fitness for duty screening. The vendor supervisor's access to the plant has been terminated. Contact the HOO for additional details. The NRC Resident Inspector was notified of this event. |
| ENS 40192 | 23 September 2003 11:15:00 | During a scheduled bare metal visual inspection of the Unit 1 reactor vessel head prior to RV head retirement, evidence of possible through wall leakage was observed on two control rod drive mechanism (CRDM) and one thermocouple (T/C) penetrations (nozzles 6 and 16 and T/C nozzle 7). Of these locations, only the T/C had been previously repaired (plugged) in December 2000. Initial Safety Significance: Any RCS leakage from these penetrations would have been below the threshold of measurability by the reactor coolant system leakage measurement process. Total measured RCS leakage prior to unit shutdown was varying between 0.15 gallons per minute and .24 gallons per minute. Corrective Action: The reactor vessel head is scheduled for replacement during the present refueling outage. Therefore, there are no plans at this time to perform additional inspections or repairs on the current head. The NRC Resident Inspector was notified. |