05000298/LER-2003-004
| Cooper Nuclear Station | |
| Event date: | 05-26-2003 |
|---|---|
| Report date: | 04-01-2004 |
| Reporting criterion: | 10 CFR 50.73(a)(2)(iv)(A), System Actuation |
| 2982003004R01 - NRC Website | |
PLANT STATUS
Cooper Nuclear Station (CNS) was in Mode 1 (Run) at 89% power at the time of the manual reactor scram.
Reactor power had been lowered from 100% in response to a main turbine high vibration.
BACKGROUND
The CNS turbine (EIIS:TRB) is an 1800 revolution per minute tandem-compound, non-reheat unit with 44-inch last stage blades. It consists of a double flow high pressure turbine and two double flow low pressure turbines. There are nine stages in the high pressure turbine and nine stages in each low pressure turbine.
Exhaust steam from the high pressure turbine passes through moisture separators (EllS:SEP) before entering the two low pressure turbines.
EVENT DESCRIPTION
On May 26, 2003, at 1321 hours0.0153 days <br />0.367 hours <br />0.00218 weeks <br />5.026405e-4 months <br />, there was a step change in main turbine vibration indication (EllS:V1) from less than 4 mils to 10.2 mils on the number five bearing. The Control Room indications were validated to be true with the locally installed monitoring system. A controlled shutdown to less than 25% power was unsuccessful as the bearing vibration slowly increased as power was reduced. The reactor was manually scrammed at 1727 hours0.02 days <br />0.48 hours <br />0.00286 weeks <br />6.571235e-4 months <br /> followed by the manual trip of the main turbine. Maximum vibration indicated prior to the turbine trip was 12.3 mils.
Subsequent to the scram, reactor vessel water level dropped to approximately 30 inches below instrument zero, resulting in Primary Containment Isolation System Group 2, 3, and 6 isolations (EllS:JM), start of High Pressure Coolant Injection (HPCI) (EIIS:BJ) and Reactor Core Isolation Cooling (RCIC) (EIIS:BN) systems, and automatic trip of the Reactor Recirculation pumps. An evaluation of plant response determined all control rods fully inserted and systems controlling reactor pressure and level responded as designed.
With no Reactor Recirculation pumps in-service, flow of cold water from the Control Rod Drive system and from reactor feedwater collected in the bottom head region. The cold water influx caused the bottom head region of the reactor to cool rapidly. This resulted in the reactor vessel drain temperature lowering from 389 degrees Fahrenheit to 279 degrees Fahrenheit during a one hour period, exceeding the 100 degrees per hour Technical Specifications cooldown limit. With the lower head cooling at a higher rate than the saturation temperature of the reactor pressure vessel, the Technical Specifications pressure-temperature curve was also exceeded for temperatures in the lower head region. Reactor pressure was lowered to restore plant parameters within the limits of the pressure-temperature curve.
At 2340, on May 26, 2003, the operators commenced slowly raising reactor water level to promote natural circulation. At approximately 0330 on May 27, 2003, as water level reached 48 inches above instrument zero, natural circulation started causing a heatup of the bottom head. The bottom head metal temperatures rose from 137 degrees Fahrenheit to 242 degrees Fahrenheit in a one hour period exceeding the Technical Specifications limit of 100 degrees per hour. The heatup rate limit for the bottom head drain temperature was subsequently exceeded at 0625 when Shutdown Cooling was placed in service. The drain temperature rapidly went from 109 degrees Fahrenheit to 279 degrees Fahrenheit.
An engineering assessment of the thermal transients and exceeding the Technical Specifications pressure- temperature limits demonstrates that adequate structural integrity is maintained for the reactor pressure vessel.
Supporting stress and fatigue analyses show the fatigue impact of the scram event is not significant.
The HPCI and RCIC actuations, and Reactor Recirculation pump trips occur at the Level 2 Technical Specifications setpoint of 42 inches below instrument zero. A review of the setpoint calculation determined that the actual trip point of the related instruments could be lowered while still maintaining adequate margin to the Technical Specifications setpoint based on the approved setpoint methodology for CNS. Lowering the setpoint reduces the probability of a loss of forced circulation in the reactor vessel and challenges to safety systems if a similar event were to occur in the future. Prior to plant startup from the forced outage, the settings of the instruments related to the Level 2 setpoint were adjusted from 25.59 inches below instrument zero to 33.43 inches below instrument zero.
BASIS FOR REPORT
This event is reportable in accordance with 10 CFR 50.73(a)(2)(iv)(A) as any event or condition that resulted in manual or automatic actuation of any of the systems listed in paragraph (a)(2)(iv)(B) of this section." The following systems from paragraph (a)(2)(iv)(B) actuated during this event: Reactor Protection System, HPCI, RCIC, and Containment Isolation System Groups 2 and 6.
CAUSE
The most probable cause for the turbine blade failure in the low pressure turbine is material condition. The failure mechanism is consistent with age-related/end-of-life type failures. Long term corrective action will be to replace the low pressure turbine rotors with new rotors.
SAFETY SIGNIFICANCE
The May 26, 2003, scram and the associated plant and operator responses fall within the bounds of CNS probabilistic risk assessment transient initiator T3A. The T3A transient scenario contains the following sequence of events:
This transient occurs when the reactor scrams due to various trips such as manual scram, turbine-generator trip or other automatic trip signals without a loss of offsite power. This transient does not result in an immediate loss of the condenser as a heat sink but can cause trip of the feedwater system. The feedwater system can be restarted once the trip signal is removed.
The risk significance of this event does not significantly affect the CNS risk as described by the probabilistic risk assessment and established by the baseline reliability of equipment or systems. The use of the condenser as a heat sink during shutdown was not affected by the event and the actual damage was limited to the main turbine components. The risk is considered to be much less than the 1E-06 threshold for risk significant changes in core damage frequency. The condition does not challenge a fuel, reactor coolant pressure, primary containment, or secondary containment boundary. The condition does not impact the plant's ability to safely shutdown or maintain the reactor in a safe shutdown condition. The plant was not placed in an unanalyzed condition nor was there any impact on compliance to plant license or design requirements for safety functions or important to safety component functions. Consequently, the safety significance of this event is very low.
CORRECTIVE ACTIONS
Immediate Actions:
1. Manually scrammed the reactor, tripped the main turbine, and placed the unit in a cold shutdown condition.
2. Obtained initial visual exam of the blade root specimen, which concluded the crack is consistent with high cycle fatigue.
3. Performed magnetic particle and eddy current testing on both faces of the last four rows on both LP1 and LP2 spare rotors.
4. Replaced blades with crack indications on the spare rotors.
5. Replaced the in-service LP1 and LP2 low pressure rotors with the spare rotors.
Long Term Actions:
Long term corrective action will be to replace the low pressure turbine rotors with new rotors during the next refueling outage.
PREVIOUS EVENTS
There have been no recent reportable events related to turbine vibration at CNS. LER 2003-003 documents exceeding the Technical Specifications heat-up rate limit. LER 94-015 documents excessive heat-up and cooldown rates during stratification events.