05000530/LER-2004-002
| Docket Number | |
| Event date: | 06-07-2004 |
|---|---|
| Report date: | 04-25-2006 |
| Reporting criterion: | 10 CFR 50.73(a)(2)(iv)(A), System Actuation 10 CFR 50.73(a)(2)(v), Loss of Safety Function |
| Initial Reporting | |
| ENS 40795 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation |
| 5302004002R01 - NRC Website | |
1. REPORTING REQUIREMENT(S):
This LER f50-530/2004-002-00) is being submitted pursuant to 10 CFR 50.73(a)(2)(iv)(A), to report a reactor protection system (RPS) (EIIS: JC) initiated reactor trip, while critical on June 7, 2004 at approximately 1458 hours0.0169 days <br />0.405 hours <br />0.00241 weeks <br />5.54769e-4 months <br /> Mountain Standard Time (MST).
On June 7, 2004 at 1757 hours0.0203 days <br />0.488 hours <br />0.00291 weeks <br />6.685385e-4 months <br /> MST, APS made notification of the event to the Nuclear Regulatory Commission (NRC) via the emergency notification system (ENS# 40795).
2. DESCRIPTION OF STRUCTURE(S), SYSTEM(S) AND COMPONENT(S):
The main turbine (EIIS: TA) is equipped with an electro-hydraulic-control (EHC) system that combines the principles of solid-state electronics and high-pressure hydraulics (EIIS: TG) to control steam flow through the turbine. The control system has three major subsystems: speed control unit, load control unit, and valve flow control units.
The steam bypass control system (SBCS) (EIIS: JI) controls the positioning of the turbine bypass valves, through which steam is bypassed around the turbine into the unit condenser, with exception of two valves which dump steam to atmosphere. These two valves are the last to open and first to close during steam bypass operation.
The reactor power cutback system (RPCS) (EIIS: JD) is a control system designed to accommodate loss of load or loss of one main feed pump events by providing a "step" reduction in reactor power. The step reduction in reactor power is accomplished by the simultaneous dropping of one or more pre-selected groups of full strength regulating control element assemblies (CEAs) (EIIS: AA) into the core.
3. INITIAL PLANT CONDITIONS:
On June 7, 2004, at approximately 1458 MST, Palo Verde Unit 3 was in Mode 1 (POWER OPERATION), operating at approximately 99 percent power. There were no major structures, systems, or components that were inoperable at the start of the event that contributed to the event.
4. EVENT DESCRIPTION:
On June 7, 2004 at approximately 1458 hours0.0169 days <br />0.405 hours <br />0.00241 weeks <br />5.54769e-4 months <br /> the Unit 3 main turbine EHC system experienced a malfunction that caused the main turbine intercept valves to fast close and the control valves to stroke closed. Approximately 4 seconds into the event the SBCS quick opened its valves and RPCB signals were generated. All eight SBCS valves quick opened and control rods for regulating groups 4 and 5 fully inserted into the core. Some moisture separator reheater (MSR) relief valves lifted and reset. Approximately 1 second after the closure of the main turbine intercept valves, three of the intercept valves started to reopen resulting in approximately 180 megawatt increase in generator output. The other three intercept valves did not indicate reopening. The primary and secondary relief valves did, not lift.
Reactor power decreased as expected and leveled off at approximately 57 percent then started to increase. Approximately 10 seconds after the RPCB, three channels (A, B, D) of the core protection calculators (CPC) (EllS: JC) generated a low Departure from Nucleate Boiling Ratio (DNBR) reactor trip. Channel C was inoperable and in bypass at the time of the trip.
All control rods inserted into the core. The feedwater control (FWCS) (EllS: JB) and SBCS systems operated to maintain steam generator level and reactor coolant system (RCS) heat removal. Pressurizer level and pressure control systems (EDS: AB) operated to maintain level and pressure.
The control room staff entered the standard post trip procedure and classified the event as an uncomplicated reactor trip. No other safety system actuations occurred and none were required. The operators elected to take manual control of the FWCS downcomer valves on both steam generators to facilitate a fasterestoration of pressurizer level and pressure to normal values. RCS Pressure and lerl control were somewhat impacted by planned work on NGN-L12 (no power to some pressurizer heaters) and planned work on a charging pump.
Off site power remained available throughout the event as did normal heat removal through the condenser. The NRC operations center was called and notified of the event at 2057 hours0.0238 days <br />0.571 hours <br />0.0034 weeks <br />7.826885e-4 months <br /> EST (reference ENS 40795).
5. ASSESSMENT OF SAFETY CONSEQUENCES:
The reactor trip did not result in a transient more severe than those already analyzed in the updated Final Safety Evaluation Report Chapters 6 and 15. The primary system and secondary pressure boundary limits were not approached and no violations of the specified acceptable fuel design limits (SAFDL) occurred.
The event did not result in any challenges to the fission product barriers or result in the release of radioactive materials. Therefore, there were no adverse safety consequences or implications as a result of this event and the event did not adversely affect the safe operation of the plant or health and safety of the public.
The condition would not have prevented the fulfillment of any safety function and did not result in a safety system functional failure as defined by 10CFR50.73(a)(2)(v).
6. CAUSE OF THE EVENT:
An evaluation of the EHC malfunction and subsequent reactor trip was conducted in accordance with the PVNGS corrective action program.
A problem in the EHC speed control circuit resulted in an EHC system malfunction.
Based on the equipment root cause of failure investigation, the most probable cause was determined to be a loose middle spacer connection on the EHC backup speed pickup amphenol.
The cause of the reactor trip was due to conservative core protection calculator values for Regulating Group 4 rodded radial peaking factors (RPF) with respect to cycle specific design parameters and the installed value of azimuthal tilt (Tq) was larger than necessary for the current core conditions. This resulted in excessive calculated power peaking following the reactor power cutback.
The conservative values were established focusing on fuel safety and did not adequately consider the impact of the bounding CPC RPF constants and the larger value of Tq on reactor power cutback (RPCB) events.
Furthermore, it was discovered during the investigation that an opportunity to identify the CPC RPF and Tq overly conservative values was missed in February 2004 following a successful reactor power cutback event in Unit 3.
7. CORRECTIVE ACTIONS:
Primary and backup main turbine speed pickup amphenols were replaced in Unit 3 and all circuit cards in the EHC speed circuit were replaced in Unit 3.
Unit 1 and Unit 2's amphenols were checked and tightened.
The conservatisms in the RPF and the value of Tq were reduced to optimize performance in all three units. In addition, the procedures and guidelines used to establish these values were revised to balance fuel safety issues with event response capabilities.
8. PREVIOUS SIMILAR EVENTS:
Subsequent to this Unit 3 event a similar event occurred when Unit 2 experienced a loss of the main turbine from approximately 100 percent power and a subsequent RPCB on July 14, 2004 due to a near by lighting strike. In that event a reactor trip also occurred on low DNBR. That event was submitted in LER, 5000529, NPF-51, 2004-002-00.