05000446/LER-2006-003
| I I) Docket Ler Number (6) Page(3) | |
| Event date: | |
|---|---|
| Report date: | |
| Reporting criterion: | 10 CFR 50.73(a)(2)(iv)(A), System Actuation 10 CFR 50.73(a)(2)(v), Loss of Safety Function |
| 4462006003R00 - NRC Website | |
I.DDESCRIPTION OF THE REPORTABLE EVENT
A. REPORTABLE EVENT CLASSIFICATION
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).
B. PLANT OPERATING CONDITIONS PRIOR TO THE EVENT
On October 29, 2006, Comanche Peak Steam Electric Station (CPSES) Unit 2 was in Mode 1, operating at 80% power following completion of the ninth refueling outage.
C. STATUS OF STRUCTURES, SYSTEMS, OR COMPONENTS THAT WERE INOPERABLE AT
THE START OF THE EVENT AND THAT CONTRIBUTED TO TEE EVENT
There were no inoperable structures, systems, or components that contributed directly to the event.
D. NARRATIVE SUMMARY OF THE EVENT, INCLUDING DATES AND APPROXIMATE
TIMES
On October 29, 2006 Comanche Peak Steam Electric Station (CPSES) Unit 2 was in Mode 1 operating at approximately 80% power following the completion of the ninth refueling outage. At 1518 hours0.0176 days <br />0.422 hours <br />0.00251 weeks <br />5.77599e-4 months <br />, while holding for xenon stabilization in preparation for an incore/excore calibration, a Balance Of Plant operator (utility, licensed) took manual control of the Steam Generator (SG) 3 Main Feedwater (MFW) flow control valve and raised demand to match feed flow and steam flow.
After the operator raised the feed flow demand at the SG3 MFW flow control valve, feed flow began to rise and actually exceeded steam flow. The feed flow demand at the SG3 MFW flow control valve was then reduced to lower feed flow to match the steam flow when feed flow dropped off drastically. Demand was once again raised (to 100%) but feed flow continued to lower. The Unit Supervisor (utility, licensed) ordered a reactor trip at 1520 hours0.0176 days <br />0.422 hours <br />0.00251 weeks <br />5.7836e-4 months <br /> due to SG3 level lowering uncontrollably. SG3 level was approximately 40% at the time of the trip and lowering rapidly.
Auxiliary feedwater automatically started as expected due to Lo Lo level in SG3. All systems responded normally during and following the trip and the unit was stabilized in Mode 3.
E. THE METHOD OF DISCOVERY OF EACH COMPONENT OR SYSTEM FAILURE, OR
PROCEDURAL OR PERSONNEL ERROR
Operators (utility, licensed) in the Unit 2 Control Room received a "Steam Generator 3 Steam and Feedwater Flow Mismatch" alarm.
II.�COMPONENT OR SYSTEM FAILURES
A. FAILURE MODE, MECHANISM, AND EFFECT OF EACH FAILED COMPONENT
Not applicable — there were no component failures associated with this event.
B. CAUSE OF EACH COMPONENT OR SYSTEM FAILURE
Not applicable — there were no component failures associated with this event.
C. SYSTEMS OR SECONDARY FUNCTIONS THAT WERE AFFECTED BY FAILURE OF
COMPONENTS WITH MULTIPLE FUNCTIONS
Not applicable - there were no component failures associated with this event.
D. FAILED COMPONENT INFORMATION
Not applicable - there were no component failures associated with this event.
III. ANALYSIS OF THE EVENT
A. SAFETY SYSTEM RESPONSES THAT OCCURRED
Both Motor Driven Auxiliary Feedwater Pumps (AFW) and the Turbine Driven Auxiliary Feedwater Pump started.
B. DURATION OF SAFETY SYSTEM TRAIN INOPERABILITY
Not applicable — there was no safety system train inoperability that resulted from this event.
C. SAFETY CONSEQUENCES AND IMPLICATIONS OF THE EVENT
A loss of normal Feedwater resulting from pump failure, valve malfunction, or loss of offsite power leads to a reduction in the capability of the secondary system to remove heat generated in the reactor core. These events are analyzed in section 15.2.7 of the CPSES Updated Final Safety Analysis Report (UFSAR) which uses conservative assumptions in the analysis to minimize the energy removal capability of the Auxiliary Feedwater system.
The October 29, 2006 event occurred with the reactor at approximately 80 percent power. All systems and components functioned as designed. The event is bounded by the UFSAR accident analysis which assumes an initial power level of 102 percent and the worst single failure in the Auxiliary Feedwater system for a loss of Feedwater event. There were no safety system functional failures associated with this event. The UFSAR analysis shows that a loss of normal Feedwater does not adversely affect the core, the reactor coolant systems, or the steam system; therefore, this event posed no threat to the health and safety of the public.
Based on the above, it is concluded that the health and safety of the public was unaffected by this condition and this event has been evaluated to not meet the definition of a safety system functional failure per 10CFR50.73(a)(2)(v).
IV. CAUSE OF THE EVENT
The cause of this event was believed to be a loose wire on the SG3 Feedwater regulating valve Weidmuller terminal block. The loose wire in the Feedwater regulating valve control circuit caused a high resistance connection and voltage drop that caused the solenoid valve in the pneumatic control system to vent air while still supplying air from the positioner. This loss of air caused a loss of control and closure of the Feedwater regulating valve. The loose connection was most likely the result of poor workmanship during initial installation of the field cable (believed to be installed during Unit 2 construction).
In 1987, prior to the startup of Units 1 and 2, loose connections in Weidmuller terminals blocks were identified.
As part of the corrective actions for Unit 1, the safety related terminals were inspected and tightened as required. Due to the stage of Unit 2 construction, the Unit 2 corrective actions involved procedure changes to verify tightness. Based on the estimated time of the cable installation, the affected cable's tightness should have been verified under the improved termination procedures. However, it could not be specifically determined how the affected cable became loose.
V. CORRECTIVE ACTIONS
Feedwater regulating valves and all four Unit 2 Feedwater regulating bypass valves for tightness. Although some lack of full tightness conditions were identified, the associated design functions would have been performed for all of these conditions.
As a part of the CPSES Corrective Action Program, the tightness of Weidmuller terminals in Unit 1 Feedwater regulating and bypass valve terminal boxes will be verified. Additionally, maintenance procedures will be revised to require a check of tightness of both the instrument and field terminals -whenever either side of a circuit is being worked on a Weidmuller terminal block.
VI. PREVIOUS SIMILAR EVENTS
There have been no previous similar reportable events at CPSES in the last three years.