05000325/LER-2005-005
| Telephone Number (Include Area Code) | |
| Event date: | 07-13-2005 |
|---|---|
| Report date: | 09-12-2005 |
| Reporting criterion: | 10 CFR 50.73(a)(2)(iv)(B), System Actuation 10 CFR 50.73(a)(2)(iv)(A), System Actuation |
| Initial Reporting | |
| ENS 41837 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation, 10 CFR 50.72(b)(3)(iv)(A), System Actuation |
| 3252005005R00 - NRC Website | |
Energy Industry Identification System (EIIS) codes are identified in the text as [XX].
INTRODUCTION
On July 13, 2005, at 0917 hours0.0106 days <br />0.255 hours <br />0.00152 weeks <br />3.489185e-4 months <br />, Unit 1 received a Main Turbine [TA] trip followed by a Reactor Protection System (RPS) [JC] actuation. Plant systems responded per design, including the automatic transfer of loads from the Unit Auxiliary Transformer to the Startup Auxiliary Transformer. All control rods fully inserted.
An expected Reactor Pressure Vessel (RPV) coolant level shrink caused the reactor vessel water level to decrease below the Reactor Vessel Water Level - Low Level 1 setpoint, which resulted in a Primary Containment Isolation System (PCIS) [JM] isolation signal to Group 2 (i.e., Drywell Equipment and Floor Drain, Traversing In-Core Probe, Residual Heat Removal (RHR) Discharge to Radwaste, and RHR Process Sample) primary containment isolation valves (PCIVs), Group 6 (i.e., Containment Atmosphere Control/Dilution, Containment Atmosphere Monitoring, and Post Accident Sampling System) PCIVs, and Group 8 (i.e., RHR Shutdown Cooling Suction and RHR Inboard Injection) PCIVs. Additionally, minimum reactor vessel water level momentarily satisfied the Reactor Vessel Water Level - Low Level 2 actuation logic requirements, which caused a Group 3 (i.e., Reactor Water Cleanup System) isolation to occur. The isolation signals closed all of the PCIVs that were open at the time of the actuations.
Safety/Relief valves (SRVs) [RV] B, C, D, and E operated to control pressure.
At 1303 hours0.0151 days <br />0.362 hours <br />0.00215 weeks <br />4.957915e-4 months <br />, the NRC was notified (i.e., Event Number 41837), in accordance with 10 CFR 50.72(b)(2)(iv)(B), of the Unit 1 RPS actuation and, in accordance with 10 CFR 50.72(b)(3)(iv)(A), of the valid actuation of systems listed in 10 CFR 50.73(a)(2)(iv)(B). This condition is being reported in accordance with 10 CFR 50.73(a)(2)(iv)(A) as an event that resulted in valid actuation of systems listed in 10 CFR 50.73(a)(2)(iv)(B).
EVENT DESCRIPTION
Initial Conditions Unit 1 was in Mode 1, at approximately 100 percent rated thermal power. All required safety-related systems were operable.
Discussion The direct cause of the Main Turbine trip was the shorting to ground of the B phase of the Unit 1 Main Generator [TB] No Load Disconnect Switch (NLDS) [EL], manufactured by Delta-Unibus Corporation, which electrically connects the generator to the main transformer. This ground resulted in actuation of the generator ground current relay and the generator backup lockout relay, followed by fast closure of the turbine control valves. Turbine Control Valve Fast Closure, Control Oil Pressure - Low (i.e., Function 9 of EVENT DESCRIPTION (continued) Technical Specification Table 3.3.1.1-1, "Reactor Protection System Instrumentation") caused the RPS actuation. The generator protection logic and RPS logic functioned as designed. Automatic transfer of loads from the Unit Auxiliary Transformer to the Startup Auxiliary Transformer occurred per design.
As a result of the turbine control valve fast closure and RPS actuation, an expected RPV water level shrink caused reactor water level to momentarily drop to near the Reactor Vessel Water Level - Low Level 2 trip setpoint. All appropriate system isolations and actuations occurred as designed. When RPV. water level dropped below the Reactor Vessel Water Level - Low Level 1 setpoint, PCIS Groups 2, 6, and 8 properly actuated. The minimum RPV water level experienced was sufficient to cause a PCIS Group 3 isolation, isolation of the Reactor Building Ventilation [VA] system and actuation of the Standby Gas Treatment [BH] system, tripping of the reactor recirculation pumps [AD], and initiation of the High Pressure Coolant Injection (HPCI) [BJ] system. HPCI did not inject because reactor vessel water level was restored prior to the HPCI injection valve opening. The momentary RPV water level shrink was not sufficient to fulfill the Reactor Core Isolation Cooling (RCIC) [BN] system logic actuation requirements. Subsequent testing confirmed the proper functioning of RCIC instrumentation. RPV water level was maintained using reactor feed pumps [SJ] and the Control Rod Drive (CRD) [AA] system.
The pressure transient caused by the turbine control valve fast closure also caused SRVs B, C, D, and E to open for one to two seconds. Although the peak reactor pressure of 1108 psig was not high enough to reach any SRV setpoint, fast closure of the turbine control valves causes a pressure wave which is expected to be higher in the steam lines than the RPV. This is a known phenomenon which has been experienced at Brunswick as well as other Boiling Water Reactors.
Both plant and Operator response to this event were as expected.
EVENT CAUSE
The root cause of this event is inadequate design and testing of the NLDS by the vendor; resulting in the NLDS not meeting its nameplate design rating. This resulted in the B phase of the NLDS failing when operated at extended power uprate operating conditions.
The NLDS is manufactured by Delta-Unibus Corporation. Each switch assembly consists of a stack of six bus bars, each containing nine contact fingers on each end. The three phase switches are gang operated with a manual crank. The switch rotates on a center point and mates to three corresponding stationary contact plates at each end. The switch was rated, by the vendor, at 25KV with a 25,000 amp forced cooled and 12,500 amp self-cooled continuous current rating. Subsequent to the Unit 1 NLDS failure, the vendor stated that the switch was tested to the 12,500 amp self-cooled continuous current rating. The 25,000 amp rating was based on calculation, assuming a bus duct cooling total air handling output of 15,300 cfm; however, no documentation of this calculation could be produced by the vendor or found on site. The EVENT CAUSE (continued) Unit 1 NLDS was installed in April 1995, and subsequently inspected each refueling outage with no signs of significant degradation due to overheating.
In a report dated August 27, 2001, the same vendor evaluated the iso-phase system [EL] and confirmed the acceptability of operating under the planned extended power uprate conditions.
Prior to extended power uprate, the NLDS operated at approximately 21,000 amps. Bus duct cooling was provided by two fans: one fan operation yielded 17,500 cfm flow and two fan operation yielded 23,000 cfm flow. The first phase of extended power uprate increased the load on the switch to approximately 22,860 amps and required the operation of two bus duct cooling fans. The final phase of extended power uprate increased the load on the NLDS to approximately 24,300 amps and also increased the capability of the bus bus duct cooling air flow measurements were performed and determined to be sufficient to support vendor design assumptions for the NLDS. The Unit 1 iso-phase bus and bus duct cooling are sufficiently similar that the Unit 2 measurements are also applicable to Unit 1.
Based on the fact that the NLDS switch was being operated at less than the continuous rating of 25,000 amps and the provided forced air bus duct cooling exceeded the vendor design assumptions, it is concluded that the NLDS did not meet its nameplate rating.
CORRECTIVE ACTIONS
A temporary modification has been installed on both Unit 1 and Unit 2 which replaced the NLDSs with removable bus bars. The ability to remove the bars within one hour, consistent with Brunswick commitments with respect to General Design Criterion 17, "Electric power systems," was confirmed.
Permanent corrective actions, which maintain the ability to implement the delayed source of off-site power (i.e., Unit Auxiliary Transformer Backfeed) within one hour, are currently being investigated and are planned to be completed during the B116R1 refueling outage (i.e., the March 2006, refueling outage for Unit 1) and during the B218R1 refueling outage (i.e., the March 2007, refueling outage for Unit 2).
SAFE1 Y ASSESSMENT The safety significance of this condition is considered minimal.
The failure of the NLDS caused an automatic RPS actuation; however, during this event all systems functioned as expected, resulting in low safety significance. The NLDS is not a required active component to implement the delayed source of off-site power (i.e., Unit Auxiliary Transformer Backfeed), but it must be opened to facilitate the lineup. In this event, the failure caused the switch to stick closed and mechanical SAFETY ASSESSMENT (continued) assistance was required to open the switch. However, this activity was completed in a relatively short time (i.e., approximately 1 to 1.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />). Therefore, if the backfeed lineup had been required, the necessary NLDS lineup could have been achieved in relatively short order.
PREVIOUS SIMILAR EVENTS
A review of events which have occurred within the past three years has not identified any previous similar occurrences related to inadequate vendor design.
COMMITMENTS
No regulatory commitments are contained in this report. Those actions discussed in this submittal will be implemented in accordance with corrective action program requirements.