05000260/LER-2008-001
| Docket Numbersequential Revmonth Day Year Year Month Day Yearnumber No. None N/A | |
| Event date: | 10-04-2008 |
|---|---|
| Report date: | 11-24-2008 |
| Reporting criterion: | 10 CFR 50.73(a)(2)(iv)(B), System Actuation 10 CFR 50.73(a)(2)(iv)(A), System Actuation |
| 2602008001R00 - NRC Website | |
I. PLANT CONDITION(S)
Prior to the event, Units 1, 2, and 3 were operating in Mode 1 at 100 percent thermal power (approximately 3458 megawatts thermal). Units 1 and 3 were unaffected by the event.
II. DESCRIPTION OF EVENT
A. Event:
On October 4, 2008 at 2208 hours0.0256 days <br />0.613 hours <br />0.00365 weeks <br />8.40144e-4 months <br />, Central Day Light Time (CDT) the Unit 2 reactor automatically scrammed following a turbine generator load reject signal. At approximately 2107 hours0.0244 days <br />0.585 hours <br />0.00348 weeks <br />8.017135e-4 months <br /> CDT, just prior to the reactor scram, operations noted the 500 kV Unit Station Service Transformer (USST) [EL] 2B tap changer operating excessively and the generator was experiencing field voltage, transfer voltage, and phase amperage swings. Operations decided to place the voltage regulator in the manual control mode in accordance with Operating Instruction, 2-01-47, Turbine-Generator System. However, when Operations transferred the voltage regulator from the auto mode to the manual mode, Unit 2 received a turbine trip and subsequent automatic reactor scram.
During the event, all automatic functions resulting from the scram occurred as expected. All control rods [AA] inserted. The primary containment isolation system (PCIS) [JE] isolations:
Group 2 (residual heat removal (RHR) system [BO] shutdown cooling), Group 3 (reactor water cleanup (RWCU)) [CE], System Group 6 (ventilation), and Group 8 (traversing incore probe (TIP)) [IG] were received along with the auto start of the control room emergency ventilation (CREV) [VI] system and the three standby gas treatment (SGT) [BH] system trains. As a result of the low reactor water level and high reactor pressure, Operations briefly entered Emergency Operating Instruction, (2-E0I-001) Reactor Pressure Vessel Control.
Following verification that the 2-A0I-100-1, Reactor Scram, actions were completed the reactor mode switch was placed in shutdown. Operations reset the reactor scram by 2211 hours0.0256 days <br />0.614 hours <br />0.00366 weeks <br />8.412855e-4 months <br /> CDT. By approximately 2227 hours0.0258 days <br />0.619 hours <br />0.00368 weeks <br />8.473735e-4 months <br /> CDT, operations reset the PCIS actuations and secured the SGT and CREV systems.
TVA is submitting this report in accordance with 10 CFR 50.73(a)(2)(iv)(A), as an event that resulted in a manual or automatic actuation of the systems listed in paragraph 10 CFR 50.73(a)(2)(iv)(B) (i.e., reactor protection system including reactor scram or trip, and general containment isolation signals affecting containment isolation valves in more than one system).
B. Inoperable Structures. Components. or Systems that Contributed to the Event:
N6ne.
C. Dates and Approximate Times of Major Occurrences:
October 4, 2008 at 2208 hours0.0256 days <br />0.613 hours <br />0.00365 weeks <br />8.40144e-4 months <br /> CDT� Unit 2 received an automatic reactor scram.
October 5, 2008 at 0116 hours0.00134 days <br />0.0322 hours <br />1.917989e-4 weeks <br />4.4138e-5 months <br /> CDT� TVA made a four hour non-emergency report per 10 CFR 50.72(b)(2)(iv)(B) and an eight hour non-emergency report per 10 CFR 50.72(b)(3)(iv)(A).
D. Other Systems or Secondary Functions Affected
None.
E. Method of Discovery
The turbine trip and reactor scram were immediately apparent to the control room staff through numerous alarms and indications.
F. Operator Actions
Operations personnel responded to the event according to applicable plant procedures. The scram was uncomplicated. The operator actions taken in response to the scram were appropriate. These actions included the verification that the reactor had shutdown, the expected system isolations and indications had occurred, and subsequent restoration of these systems to normal pre-scram alignment.
G. Safety System Responses
The RPS logic responded to the turbine trip per design to initiate the reactor scram. All control rods inserted. The PCIS isolations Group 2 (RHR system shutdown cooling), Group 3 (RWCU system), Group 6 (ventilation), and Group 8 (TIP) isolation were received as expected, due to the lowering of the reactor water level, along with the auto start of the CREV system and the three SGT system trains. Emergency core cooling system actuation was not required.
III. CAUSE OF THE EVENT
A. Immediate Cause
During the performance of 2-01-47, contacts 7 and 8 on the Voltage Regulator Auto/Manual Transfer Relay (43A relay) [RLY] failed to make-up when transferring the voltage regulator from automatic to manual control.
B. Root Cause
The root cause of this event was a failure of the design change process. The process did not provide a prompt to consider contact wetting and signal threshold when selecting a relay to switch low energy control signals. This resulted in a General Electric (GE) model HFA relay, with poor contact material for the application, installed in a low energy control circuit. The signal switched by contacts 7 and 8 of the 43A relay was only of sufficient power to switch semiconductor controlled rectifiers. The event was result of the installation of a relay in an application for which it was poorly suited.
C. Contributing Factors
None.
IV. ANALYSIS OF THE EVENT
WA analyzed the failed relay and the preliminary results indicate intermittent high contact resistance.' The GE HFA relay is designed with silver alloy contacts rated for up to 250 VDC or 575 VAC and up to 30 amp current. The application literature does not provide a minimum voltage if the final analysis results affect the root cause. TVA will submit a revised LER.
or current threshold and there are no published values or any recommendations for minimum voltage and current required to assure contact connections.
Silver alloy relay contacts used in low energy applications will oxidize because of the absence of contact sparking from the typical relay contact making and breaking functions. The sparking of the contact surfaces promotes a self-cleaning mechanism that reduces the tarnish buildup on the contact surfaces. TVA has determined the GE HFA relay was not suitable for the application which it was being used, low energy switching.
V. ASSESSMENT OF SAFETY CONSEQUENCES
high side breaker trip and subsequent reactor scram on turbine control valve fast closure. The safety consequences of this event were not significant. All safety systems operated as required.
PCIS groups 2, 3, 6, and 8 isolations were as expected. Operator actions were appropriate and consistent with plant procedures. Although the Emergency Core Cooling Systems were available, none were required. Reactor water level lowered to level 3, but remained above level 2; therefore, high pressure coolant injection [BJ] and reactor core isolation injection [BN] systems did not actuate. No main steam relief valves [SB] actuated. The turbine bypass valves [JI] maintained reactor pressure. The main condenser remained available for heat rejection. Reactor water level was recovered and maintained by the reactor feed water [SJ] and condensate [SG] systems.
Therefore, TVA concludes that the event did not affect the health and safety of the public.
VI. CORRECTIVE ACTIONS
A. Immediate Corrective Actions
Operations personnel placed the reactor in a stable condition in accordance with plant procedures.
B. Corrective Actions to Prevent Recurrence 2 1. TVA replaced the 43A relay in main-generator voltage regulator circuit with a relay that is better suited for a low energy application.
2. TVA will revise the Technical Evaluation Considerations Checklist to address contact selection for relays installed in low energy circuits.
VII. ADDITIONAL INFORMATION
A. Failed Components
None.
B. Previous LERs on Similar Events previous event, the 43A relay had reached the end of its life. The corrective action from that event, which included replacing the relay, would not have prevented the event discussed in this LER.
C. Additional Information
TVA does not consider these corrective actions as regulatory requirements. TVA will track the completion of these actions In the Corrective Action Program.
Corrective action document PER 153987.
D. Safety System Functional Failure Consideration:
This event is not a safety system functional failure in accordance with NEI 99-02.
E. Loss of Normal Heat Removal Consideration:
The condenser remained available, providing a normal heat removal path following the reactor scram. Accordingly, this event did not result in a scram with a loss of normal heat removal as defined in NEI 99-02.
VIII. COMMITMENTS
None.