05000361/LER-2003-001
| San Onofre Nuclear Generation Station (Songs) Unit 2 | |
| Event date: | 02-01-2003 |
|---|---|
| Report date: | 03-24-2003 |
| Reporting criterion: | 10 CFR 50.73(a)(2)(iv)(A), System Actuation |
| 3612003001R00 - NRC Website | |
1 FACIJTY NAME 2 DOCKET NUMBER 05000-361 2003 6 LER NUMBER —001 — 0 Event Date: � February 1, 2003 Reactor Vendor:
� Combustion Engineering Power: � 100 percent
Background:
The Main Generator Excitation and Voltage Control System has the following main functions:
- The Main Generator Excitation and Voltage Control System controls the magnetic strength of the Main Generator rotor field, which, in turn, controls the terminal voltage and reactive power of the Main Generator.
- The Main Generator Excitation and Voltage Control System automatically trips the generator excitation under upset, emergency or faulted conditions.
The Automatic Voltage Regulator (AVR) controls the voltage to the Main Exciter field. A trip signal from a Main Generator Protection Trip will initiate the AVR's suppression circuit.
The Field Suppression Relay is the master protection relay common to both channels of the AVR. Once the Field Suppression Relay is actuated, the AVR trips both channel breakers, thereby de-energizing the rotor field windings. The rotor field degradation is sensed by the Main Generator Loss of Field Relay, which initiates a turbine trip at its setpoint.
Description of the Event:
On 02/01/03, while Unit 3 was defueled for Cycle 12 refueling and Unit 2 was operating in Mode 1 at 100 percent power, a Technician (utility, non-licensed) was conducting planned functional testing of the Unit 3 Main Transformer [EL] and Main Generator [EL] protective relays within the Unit 3 relay protection cabinet (RPC) [TL], 3L070. Since the 6.9kV breaker control power needed for the test was supplied by Unit 2, the Technician attempted to establish a control power reference connection within the Unit 2 RPC [TL], 2L070. The Technician, however, misidentified the reference terminal and incorrectly connected to the Field Suppression Relay [TL] for the Unit 2 Main Generator.
The Technician initiated his test at 0310 PST, which immediately resulted in the actuation of the Unit 2 Field Suppression Relay. This initiated the following automatic and sequential events at Unit 2: (1) actuation of generator loss of field relay, (2) generator/turbine trip, (3) reactor trip, and (4) initiation of emergency feedwater. Systems responding to the event performed as designed. Additionally, Operator responses were correct and timely.
Southern California Edison (SCE) previously reported this event in accordance with 10CFR50.72(b)(2)(iv)(B) and 10CFR50.72(b)(3)(iv)(A). This follow-up Licensee Event Report is being submitted in accordance with 10CFR50.73(a)(2)(iv)(A).
1 FACILITY NAME 1 DOCKET NUMBER 05000-361 2003 6 LER NUMBER —001 — 0 Cause of the Event.
This event was caused by personnel error. The Technician made an incorrect terminal connection to the Field Suppression Relay in the Unit 2 relay protection cabinet.
SCE has also concluded that the procedural guidance was not adequate in relation to the complexity of this work and the potential consequences, which resulted in an inadequate pre-work discussion ("tailboard") and over-reliance on "skill of the craft.
Completed Corrective Actions:
A site-wide briefing was conducted to review this event and communicate management expectations to exercise caution in error-likely situations.
A physical barrier has been placed on the relay protection cabinet for each Unit to prevent unreviewed and/or unplanned access.
Planned Corrective Actions:
SCE will appropriately discipline personnel involved in this event.
SCE will also improve the procedural guidance for work within the relay protection cabinet and other areas that are subject to similar risks and consequences.
Safety Significance:
SCE characterizes this event as a decrease in heat removal by the secondary system turbine plant. The event is bounded by the safety analysis for the Loss of Condenser Vacuum (LOCV) event described in UFSAR 15.2.1.3 and 15.10.2.1.3.
The LOCV leads to a loss of normal feedwater flow and a loss of turbine load. In this event, the loss of feedwater was a direct consequence of the Main Generator/Turbine trip and slow bus transfer of auxiliary power (see Additional Information, Part B, below). Operators maintained cooling with the Auxiliary Feedwater System and Steam Bypass Control System. Because this event did not result in a loss of heat sink, SCE considers the event less severe than the LOCV.
Additionally, the Main Feedwater Pumps (MFWP) could have been restarted, if needed.
An assessment of the conditional core damage probability (CCDP) and the conditional large early release probability (CLERP) for the February 1, 2003 event determined that the Unit 2 CCDP and CLERP were 4.5E-6 and 1.8E-7, respectively. The assessment was based on the reported actual component unavailability and system alignments at the time of the event.
Based on the above, SCE concludes that this event was of low to no safety significance. There were no consequences to public health and safety.
1 FACLITY NAPE 2 DOCKET NUMBER 05000-361 2003 B LER NUMBER —001 — 0
Additional Information:
A T In 2002, SCE submitted LERs for the following reactor trips:
- Steam Bypass Control System (SBCS) failure due to an inadequate calibration procedure caused an automatic reactor trip. Corrective actions focused on the SBCS calibration procedure (LER 2-2002-003).
- Main Feedwater (FW) Controller failure due to age-related degradation of a controller component card caused an automatic reactor trip. Corrective actions focused on the faulty component (LER 2-2002-006).
- Pressurizer Spray Valve failure caused a manual reactor trip. The root cause investigation for the equipment failure is ongoing (LER 2-2002-007).
Corrective actions for the events listed above focused on procedural or mechanical causal factors and, therefore, would not be expected to prevent the reactor trip event reported in this LER.
- Main switchyard breaker trip due to personnel error caused a loss of offsite power and automatic reactor trip. A San Diego Gas & Electric (SDG&E) technician exceeded his authorized work scope within the SDG&E portion of the San Onofre switchyard.
Corrective actions focused on establishing work controls for non-SCE personnel working in the main switchyard (LER 3-2002-001).
Although this event has some similarity to the event reported herein, SCE believes that they differ to the extent that corrective actions taken for the switchyard event would not be expected to prevent the reactor trip event reported in this LER.
B. T Temporary Loss of Main Feedwater Pumps (MFWP) K005/P063 and K006/P062 Normally, upon a Main Generator/Turbine trip, a "fast" transfer of non-1E power takes place from the Unit Auxiliary Transformer (UAT) to the Reserve Auxiliary Transformer (RAT) within five to ten cycles (80-160 milliseconds). However, due to the Loss of Field trip of the Main Generator, the RAT incoming supply voltage and phase did not closely match the UAT bus voltage and phase. Consequently, a "fast" bus transfer was inhibited. The transfer relay prevented the bus transfer until the voltage had decayed below the setpoint of the residual voltage relay. This "slow" bus transfer scheme typically takes between several hundred milliseconds to a couple of seconds, depending on the motor load on the bus.
A review of the Digital Fault Recorder (DFR) traces taken during the Unit 2 trip shows that the medium voltage non-1E buses 2A03 and 2A07 experienced degraded voltage conditions for approximately 360 and 710 milliseconds, respectively. At that time, non-1E bus 2A07 was powering the in-service MFWP Lube Oil Pumps, P122 for K006/P062 and P123 for K005/P063. The degraded voltage condition in 2A07 caused the fuses for P122 and P123 to blow and the pumps stopped. Subsequently, each of the Main Feedwater Pumps tripped on low lube oil pressure.
6 LER NUMBER PAGE (3) 1 FACILITY NAVE 2 DOCKET NUMBER 05000-361 2003 —001 — The 2A03 and 2A07 bus voltages returned to normal upon transfer to the RAT, at which time the standby Lube Oil Pumps powered from 2A03 auto-started.
With the restoration of the medium voltage non-1E power buses and availability of MFWP lube oil, one or both of the MFWPs could have been restarted, if needed.