05000445/LER-2003-003
| Event date: | |
|---|---|
| Report date: | |
| Reporting criterion: | 10 CFR 50.73(a)(2)(iv)(B), System Actuation 10 CFR 50.73(a)(2)(iv)(A), System Actuation |
| 4452003003R00 - NRC Website | |
I. DESCRIPTION OF REPORTABLE EVENT
A. REPORTABLE EVENT CLASSIFICATION
The subject event is reportable pursuant to the requirements of 10CFR50.73(a)(2)(iv)(A), "...any event or condition that resulted in manual or automatic actuation of any of the systems listed in paragraph (a)(2)(iv)(B).
Specifically, 10CFR50.73(a)(2)(iv)(B)(1), reactor protection system (RPS) including: reactor scram or reactor trip and 10CFR50.73(a)(2)(iv)(B)(6), PWR auxiliary or emergency feedwater system.
B. PLANT OPERATING CONDITIONS PRIOR TO THE EVENT
and Unit 2 were in Mode 1, with Unit 1 at 100 percent power and Unit 2 at 99.8 percent power.
C. STATUS OF STRUCTURES, SYSTEMS, OR COMPONENTS THAT
WERE INOPERABLE AT THE START OF THE EVENT AND THAT
CONTRIBUTED TO THE EVENT
There were no Technical Specification inoperable structures, systems, or components that contributed to the event.
D. NARRATIVE SUMMARY OF THE EVENT, INCLUDING DATES
AND APPROXIMATE TIMES
On May 15, 2003 at 0252 a B—phase to ground fault occurred on the Parker line approximately four miles from the CPSES 345kV switchyard. The failure of the switchyard breaker protection to adequately recognize and clear the fault resulted in a total loss of the 345kV switchyard. The fault detector relays (MIS: (FK)(51)) in both the primary and backup protection schemes of the CPSES Parker line circuit breaker did not function properly. Due to the failure of the primary and backup protection schemes for the CPSES to Parker transmission line breaker, the fault resulted in a total loss of the CPSES 345kV switchyard approximately 20 seconds after the fault began.
The Reactor Coolant Pumps (EIIS:(AB)(P)) sensed low voltage due to the loss of non-safety related ac power and Units 1 and 2 reactors tripped at approximately 1.5 seconds after failure of the switchyard breaker protection.
Both unit generator breakers (EIIS:(TB)(BKR)) tripped due to generator distance relaying actuating generator lockout relays (EIIS:(TB)(86)) and subsequent load rejection protection circuits tripped both turbines.
All plant actuations occurred as designed. The Reactor Coolant Pumps tripped as expected due to the loss of non-safety bus voltage and the Reactor Coolant Pumps coasted down. The Auxiliary Feedwater Pumps actuated and provided auxiliary feedwater to the steam generators (SG) as designed. The Reactor Operators controlled AFW (Auxiliary Feedwater) flow and maintained the SG water levels. Main Feedwater isolation occurred immediately following the reactor trip as expected.
Natural circulation flows were established within one minute and adequate subcooling maintained. The reactors were maintained in Mode 3 under natural circulation until the Reactor Coolant Pumps were started at 0533 for Unit 1 and 0625 for Unit 2.
The system response of the Unit 1 and Unit 2 trips and the operator actions were consistent with the plant design and the supporting analyses presented in CPSES Final Safety Analysis Report (FSAR).
E. THE METHOD OF DISCOVERY OF EACH COMPONENT OR
SYSTEM FAILURE, OR PROCEDURAL OR PERSONNEL ERROR
Control board indicators and alarms alerted the reactor operator (utility, licensed) in each unit that the generator breakers were open, the reactor trip breakers were open, and the Reactor Coolant Pumps were tripped.
H. COMPONENT OR SYSTEM FAILURES
A. FAILURE MODE, MECHANISM, AND EFFECTS OF EACH FAILED
COMPONENT
The trip of Units 1 and 2 as a result of a disturbance on one of the 345kV transmission lines was not expected. TXU Energy believes that the primary and backup fault detection circuit relays did not function as designed.
B. CAUSE OF EACH COMPONENT OR SYSTEM FAILURE
Management oversight of switchyard activities, maintenance practices, and protective circuit design contributed to a high resistance build-up on the contacts of the fault detection circuit relays which prevented successful isolation of the grid disturbance.
C. SYSTEMS OR SECONDARY FUNCTIONS THAT WERE AFFECTED
BY FAILURE OF COMPONENTS WITH MULTIPLE FUNCTIONS
Not applicable -- no failure of components with multiple functions have been identified.
D. FAILED COMPONENT INFORMATION
Manufacturer: � General Electric NSS/A-Model Number: � Model 12CHC21A2A Fault detector relays
HL ANALYSIS OF THE EVENT
A. SAFETY SYSTEM RESPONSES THAT OCCURRED
1. The reactor trip breakers opened.
2. The main turbine tripped (turbine stop valves closed).
3. The control rod drive mechanism allowed all the control rods to fully drop into the core.
4. All auxiliary feedwater (AFW) pumps started automatically and delivered water to all steam generators as required.
5. The Atmospheric Relief Valves (ARVs) actuated to control steam line pressure, and thus RCS temperature as designed.
6. The Unit 1 Safety Related 6.9kV busses preferred power supply was slow transferred to its alternate power supply as designed.
B. DURATION OF SAFETY SYSTEM TRAIN INOPERABILITY
Not applicable — No safety system was rendered inoperable.
C. SAFETY CONSEQUENCES AND IMPLICATIONS
The event is bounded by the analysis of the loss of non-emergency AC power to the station auxiliary transient as described in section 15.2.6 of the FSAR.
The analysis uses conservative assumptions to demonstrate the capability of pressure relieving devices and the adequacy of the secondary heat removal systems.
A loss of non-emergency AC power to the station auxiliaries is classified as an ANS Condition II transient - a fault of moderate frequency. The loss of non-emergency AC power to the station auxiliaries would also result in a loss of normal feedwater, as the condensate pumps would lose power to operate; loss of the main condenser as a heat sink due to loss of Circulating Water; and loss of forced cooling due to loss of Reactor Coolant Pumps. Following the Reactor Coolant Pump coastdown, the natural circulation capability of the RCS provides an alternate means to remove residual and decay heat from the core. The residual and decay heat is removed by the secondary system by steaming through either the main steam safety valves or the atmospheric relief valves. (For this event, only the atmospheric relief valves were required for decay heat removal and the main steam safety valves were not challenged.) The steam generator liquid inventory is replenished by the Auxiliary Feedwater System. The analysis presented in section 15.2.6 of the FSAR demonstrates that the natural circulation flow in the RCS following a loss of AC power event is sufficient to remove residual heat from the core without violating any event acceptance criteria.
During the event, the Auxiliary Feedwater System of each unit responded as expected and maintained the necessary steam generator heat transfer capability. The atmospheric relief valves were used to provide a controlled steam release path. There were no equipment malfunctions or failures that complicated the plant response or otherwise elevated risk beyond the initiating event. The CPSES 138kV switchyard provided power to class lE buses during this event. This event is bounded by the analysis of a Station Blackout and the loss of normal feedwater flow described in the FSAR in which conservative assumptions are made in the analysis to minimize the energy removal capability of the Auxiliary Feedwater system. This transient was assumed to be initiated from full power.
There were no safety system functional failures associated with this event.
Based on this analysis it was concluded that this event did not adversely affect the safe operation of CPSES Units 1 and 2 or the health and safety of the public.
IV. CAUSE OF THE EVENT
A fault on the Parker 345kV transmission line in conjunction with failure of primary and backup protection relays for the CPSES to Parker switchyard breaker, caused the remote grid breakers to trip and de-energize the CPSES 345kV switchyard resulting in the trip of Units 1 and 2 reactors. Management oversight of switchyard activities, maintenance practices, and protective circuit design contributed to a high resistance build-up on the contacts of the fault detection circuit relays which prevented successful isolation of the grid disturbance.
V. CORRECTIVE ACTIONS
The distribution/transmission company, Oncor, replaced the fault detector relays and adjusted the setpoints of the relays to prevent cycling of the contacts. Oncor ensured the remaining switchyard protection relays would function as designed by documenting and evaluating protection relay targets in the 345kV switchyard.
Additionally, the 345kV switchyard East and West bus lockouts were tested to verify operability and that lockouts functioned correctly. Furthermore, Oncor has evaluated their activities as performed under the ERCOT (Electric Reliability Council of Texas) guidelines and has determined that the grid continues to be highly reliable.
As part of the corrective action program, TXU Energy is improving management oversight of switchyard activities to reduce the potential of a similar event. Some of the improvements include the following:
1. Tracking of switchyard equipment within the CPSES Preventative Maintenance Program and documenting equipment related issues in the corrective action program.
2. Performing post work reviews and tracking of switchyard maintenance activities by TXU Energy personnel.
3. Enhancing Oncor's switchyard maintenance calibration and testing process to provide more detailed specific instructions.
4. Review and, if necessary, change the setpoints of the switchyard fault detector relays and eliminate supervision of ground relays by switchyard fault detector relays.
VI. PREVIOUS SIMILAR EVENTS
Although there have been previous events that resulted in RPS actuation due to a grid disturbance (refer to LER 445/91-013-00, LER 445/91-019-00, LER 445/91- 021-00, and LER 445/91-022-00), the evaluation performed during the aforementioned LERs did not consider the impact on the fault detector relays.
Therefore, corrective actions taken to resolve the root causes of the previous events would not have prevented this event.