05000324/LER-2001-001
| Docket Number | |
| Event date: | 02-23-2001 |
|---|---|
| Report date: | 04-18-2001 |
| Reporting criterion: | 10 CFR 50.73(a)(2)(iv)(A), System Actuation |
| 3242001001R00 - NRC Website | |
Energy Industry Identification System (EIIS) codes are identified in the text as [XX].
INTRODUCTION
On February 23, 2001, at approximately 2220 hours0.0257 days <br />0.617 hours <br />0.00367 weeks <br />8.4471e-4 months <br />, a Unit 2 turbine Electro-Hydraulic Control (EHC) system [JJ] malfunction annunciator was received and turbine bypass valves [JI] were observed to be opening by control room personnel. Annunciators and indications were received in the control room in response to a generator primary lockout and turbine trip. All four emergency diesel generators (EDGs) [EK] automatically started as designed, but did not load due to no loss of electrical power to the emergency buses. Within approximately 11 seconds, operators inserted a manual trip of the reactor protection system (RPS) [JC] and the reactor was shut down. An expected reactor vessel coolant level shrink occurred causing coolant level to decrease to approximately 138 inches above instrument zero (i.e., instrument zero is approximately 7.5 inches above the top of active fuel). The level transient resulted in the initiation of primary containment isolation [JM] signals for group 2, 6, and 8 isolation valves, as well as an automatic trip of the RPS. The plant responded as designed to the event.
At the time of the event, Unit 2 was in Mode 1 operating at approximately 37 percent of rated thermal power (RTP). On February 24, 2001, at 0053 hours6.134259e-4 days <br />0.0147 hours <br />8.763227e-5 weeks <br />2.01665e-5 months <br />, notification was made to the NRC (Event Number 37777) in accordance with 10 CFR 50.72(b)(2)(iv)(B) for an event or condition that resulted in actuation of the RPS when the reactor is critical, and in accordance with 10 CFR 50.72(b)(3)(iv)(A) as any event or condition that resulted in valid actuation of specified systems. This event is being reported in accordance with 10 CFR 50.73 (a)(2)(iv)(A) as an event or condition that resulted in manual or automatic actuation of the RPS, containment isolation signals affecting containment isolation valves in more than one system, and EDGs.
EVENT DESCRIPTION
On February 23, 2001, at 2056 hours0.0238 days <br />0.571 hours <br />0.0034 weeks <br />7.82308e-4 months <br />, operators commenced Unit 2 reactor shutdown, from approximately 99 percent of RTP, for a scheduled refueling outage. All Emergency Core Cooling systems as well as on-site/off-site power sources were operable. By 2220 hours0.0257 days <br />0.617 hours <br />0.00367 weeks <br />8.4471e-4 months <br />, reactor power had been reduced to approximately 37 percent of RTP. At that time, control room operators received an "EHC ELEC MALFUNCTION" annunciator, followed by numerous other annunciators and indications. The malfunction resulted in closure of turbine control valves and combined intermediate valves. In anticipation of rising reactor pressure, three turbine bypass valves opened, resulting in a decrease in first stage turbine pressure which bypassed RPS >/=. 30 percent RTP "Turbine Stop Valve — Closure" and "Turbine Control Valve Fast Closure, Control Oil Pressure — Low" trip functions.
Annunciator "TURB CV FAST CLOS/SV/RPT TRIP BYPASS," was received, alerting the operators to this condition. The open turbine bypass valves also resulted in a generator trip on reverse power and a subsequent turbine trip. All four EDGs started but did not load because electrical power was not lost to the emergency buses. The turbine trip did not result in a reactor trip at 37 percent RTP due to the RPS trip functions being bypassed, as designed.
Approximately 11 seconds after the turbine trip, reactor operators inserted a manual RPS trip to shut down the reactor. All control rods fully inserted and an expected reactor vessel coolant level shrink occurred causing coolant level to decrease from approximately 187 (normal) to 138 inches above instrument zero. The level transient resulted in the initiation of primary containment isolation signals for group 2 (i.e., Drywell Equipment and Floor Drain, Traversing In-core Probe, Residual Heat Removal (RHR) Discharge to Radwaste, and RHR Process Sample isolation valves), group 6 (i.e., Containment Atmosphere Control/Dilution, Containment Atmosphere Monitoring, and Post Accident Sampling System isolation valves), and group 8 (i.e., RHR Shutdown Cooling Suction and RIIR Inboard Injection isolation) valves, as well as an automatic trip of the RPS. The required equipment responded as designed and the group 2, and 6 valves, that were open at the time of the event, closed upon receipt of the isolation signals. The group 8 valves were already closed at the time of the event.
Operators performed the required actions in accordance Emergency Operating Procedure 2E0P-01- RSP, "Reactor Scram Procedure.
On February 23, 2001, at 2221 hours0.0257 days <br />0.617 hours <br />0.00367 weeks <br />8.450905e-4 months <br />, the reactor mode switch was placed in the "shutdown" position, at 2226 hours0.0258 days <br />0.618 hours <br />0.00368 weeks <br />8.46993e-4 months <br />, the RPS trip logic was reset, and at 2229 hours0.0258 days <br />0.619 hours <br />0.00369 weeks <br />8.481345e-4 months <br />, the reactor mode switch was locked in "shutdown." By 2307 hours0.0267 days <br />0.641 hours <br />0.00381 weeks <br />8.778135e-4 months <br /> all four EDGs were shut down, and at 2308 hours0.0267 days <br />0.641 hours <br />0.00382 weeks <br />8.78194e-4 months <br />, 2EOP-01-RSP was exited. By February 24, 2001, at 0014 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br />, all four EDGs were placed in the standby mode. At 0550 hours0.00637 days <br />0.153 hours <br />9.093915e-4 weeks <br />2.09275e-4 months <br />, Unit 2 entered mode 4 (i.e., cold shutdown).
EVENT CAUSE
The cause of the event is attributed to a false high turbine speed signal being detected by the frequency-to-voltage converter card in the EHC system. An intermittent electrical connection resulted in electrical noise being induced on the speed circuit. An actual source of the electrical noise could not be identified or duplicated; however, the plant response was duplicated on the plant simulator by simulating the high turbine speed signal.
After the event, maintenance personnel conducted an immediate field investigation and identified an intermittent open connection in a junction box located on the front standard of the turbine. A wire termination with a loose crimped ring lug on the field side (i.e., field cable going into the termination box) of the termination block was the source of the intermittent connection. The lug connection was tight at the terminal block, where a screw held the ring lug in place, but the wire could be moved inside the barrel portion of the lug where the lug was crimped to the wire. This termination is for one of the two wires carrying the turbine primary speed pickup signal from the speed pickup to the frequency to voltage converter card. The lug and crimped connection appeared to be from original construction of the plant.
CORRECTIVE ACTIONS
The lug was replaced and terminated in accordance with plant procedures. The other electrical terminations in the junction boxes on the turbine were checked for similar conditions (i.e., loose terminations) and none were identified. The lug and its section of crimped wire were sent to the Harris Energy and Environmental Center for evaluation. The evaluation determined that the wire was not fully inserted into the barrel of the lug when the connection was originally crimped.
The EHC system was aligned and tested in accordance with special process procedures OSPP- EHC001, "Electro Hydraulic Controls System Alignment," and OSPP-EHC003, "Main Turbine Alarm and Trip Functional Test." No additional equipment malfunctions were identified as part of the alignment/test activities. On March 27, 2001, the turbine/generator was brought on line at the completion of the refuel outage. Since that time, no operational or EHC system anomalies related to the event have been identified.
Additionally, reviews of maintenance/corrective action history and termination procedures were conducted, as well as discussions with maintenance personnel, to identify any potential emerging trend related to crimping of lugs for wire terminations. No such trend was identified. To gain additional experience with this issue, inspections of associated Unit 1 turbine electrical junction boxes are planned for a future appropriate time (e.g. outage of sufficient duration). As part of the established training program, a training needs analysis will be conducted to determine applicability for lessons learned dissemination and the event will be discussed as a part of licensed operator continuing training.
SAFETY ASSESSMENT
The safety significance of this event is considered to be minimal. All required systems responded to the transient as designed and so the consequences of the transient on the fuel and vessel overpressure were minimal. The analyses in Chapter 15 of the Updated Final Safety Analysis Report fully bounded this event.
PREVIOUS SIMILAR EVENTS
A similar previous event of an RPS actuation caused by a turbine supervisory equipment-related malfunction was documented by LER 2-99-002. A turbine high vibration trip signal was initiated due to failed electrical connections on a vibration detector. These were spot welded connections internal to the detector and that model of detector was changed out. The corrective actions associated with