05000341/LER-2006-002
| Docket Number06 15 2006 2006 - 002 - 00 07 26 2006 05000 | |
| Event date: | 06-15-2006 |
|---|---|
| Report date: | 07-26-2006 |
| Reporting criterion: | 10 CFR 50.73(a)(2)(iv)(A), System Actuation |
| Initial Reporting | |
| ENS 42643 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation |
| 3412006002R00 - NRC Website | |
Initial Plant Conditions:
Mode� 1 Reactor Power� 100 percent
Description of the Event
On June 15, 2006, at 1053 hours0.0122 days <br />0.293 hours <br />0.00174 weeks <br />4.006665e-4 months <br /> EDT, a reactor scram occurred from 100% power as a result of a main turbine [TA] / generator [TB] trip. A generator differential relay trip string operated in response to an internal fault to ground of the high voltage Z-phase of main unit transformer 2B [EL]. This resulted in a main turbine trip. A reactor scram occurred as designed from the turbine control valve fast closure signal. The reactor protection system (RPS) [JD] performed as expected, and all rods were fully inserted into the core. Reactor water level reached a low of approximately 134 inches above top of active fuel and recovered to normal automatically without operator intervention. Subsequent to the event, the main steam isolation valves (MSIVs) remained open and reactor water level was maintained in the normal band of 173 to 214 inches. Reactor water was supplied by the condensate [SD] and reactor feedwater systems [SJ], and the resultant reactor steam was sent to the condenser [SG] via the main turbine bypass lines. Pressure control was maintained by the main turbine bypass valves.
Reactor dome pressure peaked at about 1077 psig. With reactor pressure maintained below the Safety Relief Valve (SRV) setpoints, none of the SRVs lifted. Reactor water Level 3 isolations [JM] occurred as expected.
These included isolation Group 4 (Residual Heat Removal Shutdown Cooling and Head Spray), Group 13 (Drywell Sumps), and Group 15 (Traversing In-core Probe System) isolations.
At the time of the scram, main transformer 2B cleaning was taking place. At 1053 hours0.0122 days <br />0.293 hours <br />0.00174 weeks <br />4.006665e-4 months <br /> EDT, a Main Transformer 2B Oil Temperature High alarm was received, immediately followed by the generator differential relaying and turbine trip alarms. The transformer pressure relief valves opened in response to the pressure surge.
Oil emitted from the relief valves and from piping adjacent to transformer oil pump No. 3, and the transformer shell was observed to be bowed. The transformer deluge initiated in response to the operation of a transformer external heat sensor and deenergization of the transformer. There was no external fire as a result of the event.
A 4-hour notification of this event was made to the NRC in accordance with 10 CFR 50.72(b)(2)(iv)(B) at 1338 hours0.0155 days <br />0.372 hours <br />0.00221 weeks <br />5.09109e-4 months <br /> ET on June 15, 2006 (EN 42643).
Main unit transformer 2B is a three phase, 800 MVA, 21.1 kV (delta connected) to 345kV (grounded Y connected) power generator step-up transformer. It is one of two, approximately 50% capacity, three-phase transformers used to convert the power produced in the main generator to 345 kV for transmission purposes.
It was determined that it would take some time to prepare a spare transformer to replace main transformer 2B.
Therefore, the damaged transformer 2B was isolated from main transformer 2A in preparation for near term plant operation using only the 2A transformer. The plant was restarted and the unit was synchronized on June 18, 2006. The plant was subsequently shut down on July 8, 2006 for replacement of main unit transformer 2B.
Cause of the Event
The event was caused by an internal fault to ground of the high voltage Z-phase winding of main unit transformer 2B. The most probable cause of the internal fault is that two adjacent transformer oil coolers were taken out of service together and washed with cold water which caused an arc on the Z-phase 345 kV winding to ground. The investigation is continuing to rule out several additional potential causes, and the team performing the investigation has indicated that an inspection of the internals of the failed transformer and possibly some failure analysis of internal transformer components may be needed before making final conclusions regarding the cause of the fault itself.
Analysis of the Event
The main transformers have no safety-related function. The generator and turbine trips functioned as designed.
The reactor scrammed as designed from the turbine control valve fast closure signal. The plant response to the turbine trip was as expected and was enveloped by the more severe turbine trip without bypass transient described in the UFSAR. There was no challenge to the integrity of the reactor coolant system or the main steam system.
The lowest reactor water level during the transient was measured to be approximately 134 inches above top of active fuel which is below the reactor water Level 3 isolation trip setpoint. Reactor water Level 3 isolations occurred as expected. These included isolation Group 4 (Residual Heat Removal Shutdown Cooling and Head Spray), Group 13 (Drywell Sumps), and Group 15 (Traversing In-core Probe System) isolations. The highest reactor pressure received was about 1077 psig which is below the safety relief valve setpoints; 5 each at 1135, 1145, and 1155 psig. Subsequent to the unit trip, reactor pressure was adequately controlled using the main turbine bypass valves, and reactor water level was controlled using the condensate and feedwater systems.
Therefore, since the generator, turbine and reactor protection systems performed as designed, and since plant response was enveloped by the UFSAR transient analyses, there was no undue risk to the health and safety of the public as a result of this event.
Corrective Actions
Electrical testing was performed on the failed transformer that more specifically identified the location of the internal fault to be between the high voltage transformer bushing and the Z-phase high voltage winding of the transformer or on the first few turns of the Z-phase high voltage winding.
As an interim measure, the plant was restarted on June 18, 2006 and run at a reduced power level using only transformer 2A to deliver power to the 345 kV electrical system. The plant was subsequently shutdown on July 8, 2006 to replace main unit transformer 2B and returned to 100% power on July 22, 2006.
Recommended action to address the probable cause includes ensuring that when multiple coolers are simultaneously removed from service for cleaning or maintenance that there is no adverse impact on oil flows in the transformer. However this is preliminary, and a final set of corrective actions will be developed within the corrective action process when the probable cause has been validated and the final cause analysis has been completed.
This event has been documented in the Fermi 2 corrective action program, CARD 06-24046. The event was caused by an internal fault to ground of the high voltage Z-phase winding. An investigation is continuing to validate the probable cause for the internal ground fault and to rule out other possible causes. This could result in the identification of additional corrective actions to minimize future occurrences of this type. Any further corrective actions identified as a result of these evaluations will be tracked and implemented commensurate with the established processes and priorities of the corrective action program.
Additional Information
A. Failed Components: Main Unit Transformer Component: 800 MVA, 65°C rise, Three Phase Power Generator Step Up Transformer, 345-21.1 kV Function: Generator Voltage Step-up Transformer Manufacturer: Cooper Power Systems (now Pennsylvania Transformer Technology) Model Number: None Failure Cause: Internal Fault B. Previous LERs on Similar Problems:
None. There have been no main unit transformer failures in the last decade at Fermi 2.