05000410/LER-2001-001
| Event date: | 05-16-2001 |
|---|---|
| Report date: | 05-02-2002 |
| Reporting criterion: | 10 CFR 50.73(a)(2)(iv)(A), System Actuation |
| 4102001001R01 - NRC Website | |
I. Description of Event
On May 16, 2001, at 1019 hours0.0118 days <br />0.283 hours <br />0.00168 weeks <br />3.877295e-4 months <br />, Nine Mile Point Unit 2 automatically scrammed from 90 percent core thermal power due to Turbine Stop Valve closure. The plant was at 90 percent power because of loss of position feedback signal for the "B" Recirculation loop Flow Control Valve. The cause of the Combined Intercept Valve and Stop Valve closure was a failure of Electro Hydraulic Control System (EHC) Hydraulic Trip Pressure Relay KT106.
After the initial scram level transient, reactor water level was recovered with "A" and "C" feedwater pumps. Due to known level control valve leak-by, the "C" feedwater pump was removed from service with reactor water level rising to 197 inches. The "A" feedwater pump automatically tripped moments later on level 8 (202.3 inches). After the level 8 trip cleared and was reset, the "K feedwater pump was restarted and level was stabilized in the normal level band.
Minimum reactor water level reached 140 inches while the maximum level was 213 inches, during scram recovery actions.
Pressure control was maintained using the Turbine Bypass Valves in automatic following the scram. None of the Safety Relief Valves lifted as a result of a high pressure condition nor were they expected to lift as a result of the scram. Cooldown rate remained less than 100 degrees Fahrenheit per hour during the scram recovery.
All Control Rods fully inserted following the scram.
Primary containment isolation valve group 4 (Residual Heat Removal (RHS) radwaste discharge and sampling valves) and group 5 (Shutdown cooling and other RHS system valves) received isolation signals due to reactor water level going below the level 3-isolation setpoint (159.3 inches). The primary containment isolation group 4 and group 5 valves were in their normal, closed position; therefore the valves did not change position.
There were no Emergency Core Cooling System (ECCS) automatic initiation signals received during the transient.
The Reactor Core Isolation Cooling system remained in standby during the transient.
At 1204 hours0.0139 days <br />0.334 hours <br />0.00199 weeks <br />4.58122e-4 months <br /> a plant cooldown began and at 2002 hours0.0232 days <br />0.556 hours <br />0.00331 weeks <br />7.61761e-4 months <br /> the plant was in cold shutdown.
Reactor scram was caused by Turbine Stop Valve greater than 7 percent closed position signal resulting from failure of Turbine EHC Hydraulic Trip Pressure relay KT106. Contact 3-8 of relay KT106 provides power to downstream relays which if de-energized ultimately result in the closure of the Combined Intercept Valves, Control Valves and Stop Valves. The failure mechanism for Relay KT106 was a high resistance contact causing an "all valves closed" signal for the turbine. A new relay was tested satisfactorily and installed.
I. Description of Event (cont'dl During the cause investigation, it was identified that in 1997 General Electric (GE) had issued Technical Information Letter (TIL) 1212-2, "Plant Scram Frequency Reduction Features for BWR and PWR Nuclear Turbines with MK I or MK II EHC Controls," which included recommendations to address potential problems associated with relay KT106. KT106 is an Agastat 125 volt direct current (VDC) relay whose contacts are used in a 24 VDC application. Use of 125 VDC relays in low voltage and low current applications causes the normally closed contacts to develop an oxide buildup resulting in high resistance. GE TIL 1212-2 recommended wiring a parallel contact for KT106. NMPC decided not to implement the parallel contacts but rather to monitor contact resistance. GE TIL 1212-2 recommended replacing the relay when contact resistance exceeded 1.0 ohms. Post scram resistance measurements of contact 3-8 ranged between 0.4 and 62 ohms. The most recent resistance measurement taken during Refueling Outage 7 (RFO7) was 0.28 ohms which had increased from 0.15 ohms when measured in RFO6.
II. Cause of Event
The cause of the reactor scram was high resistance in normally closed contact 3-8 of relay KT106. The high resistance led to relays downstream de-energizing and closing the Combined Intercept Valves, Turbine Stop Valves and Control Valves. The reactor scram resulted from the Turbine Stop Valves being greater than 7 percent closed.
A contributing cause was inadequate preventative actions in that GE TIL 1212-2, item All, recommendations for relay KT106 were not fully utilized to eliminate the scram potential nor was a replacement frequency for the relay established.
Ill. Analysis of Event This event is reportable in accordance with 10 CFR 50.73(a)(2)(iv)(A) as an automatic actuation of the Reactor Protection System that resulted in a reactor scram.
All Control Rods fully inserted following the scram as verified by use of the Rod Sequence Control System and full core displays. During the event, no Emergency Core Cooling equipment started or should have started. The Reactor Core Isolation Cooling system remained in standby during the transient. Cooldown rate remained less than 100 degrees Fahrenheit per hour during the scram recovery.
A PRA screening of the event concluded that the event was not risk significant. The PRA Analysis determined a Core Damage Probability of 8.2E-7 for this event.
Based on the above the event did not pose a threat to the health and safety of plant personnel or the public.
IV. Corrective Actions
1. The relay was replaced and satisfactorily tested.
2. A design change was implemented during Refueling Outage 8 in March-April, 2002, to replace the existing trip relay KT106 with a relay having contacts of an alternate, more reliable design.
3. A determination has been made to periodically replace KT106.
V. Additional Information
1. Failed Components Relay KT106, Agastat 125VDC relay, Manufactured by Agastat, Part Number 117D9900G0001 2. Previous similar events: None 3. Identification of components referred to in this Licensee Event Report Components IEEE 805 System ID IEEE 803A Function Recirculation System AD N/A Reactor Protection System JC N/A Feedwater System SJ N/A Electro Hydraulic Control System TG N/A Main Steam System SB N/A Containment Isolation System JM N/A Turbine Bypass Control System JI N/A Emergency Core Cooling Systems BG,BM,BO N/A Residual Heat Removal System BO N/A Isolation Cooling System BN N/A Control Rod Drive System AA N/A Valve AD,SB FCV Valve SJ LCV Valve BO SMV Valve SB,JI ISV, RV Relay TG RLY Contact TG N/A Pump SJ P Control Rod AC ROD