05000296/LER-2007-004
| Browns Ferry Unit 3 | |
| Event date: | 11-30-2007 |
|---|---|
| Report date: | 01-28-2008 |
| Reporting criterion: | 10 CFR 50.73(a)(2)(v)(B), Loss of Safety Function - Remove Residual Heat 10 CFR 50.73(a)(2)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident |
| 2962007004R00 - NRC Website | |
I. PLANT CONDITION(S)
Unit 3 was in Mode 3 approximately 950 psig. Units 1 and 2 were operating in Mode 1 at 100 percent RTP (3458 megawatts thermal). Units 1 and 2 were unaffected by the event.
II. DESCRIPTION OF EVENT
A. Event:
On November 30, 2007, at approximately 1052 hours0.0122 days <br />0.292 hours <br />0.00174 weeks <br />4.00286e-4 months <br /> Central Standard Time (CST), with BFN High Pressure Coolant Injection (HPCI) [BJ] steam supply. Just prior to isolating the steam supply, Operations verified by administrative means that the Reactor Core Isolation Cooling (RCIC) [BN] system and two Control Rod Drive [CD] system pumps were available for high pressure injection water source, and entered Technical Specification Limiting Condition for Operation (LCO) 3.5.1.C. A previously identified steam leak on the packing of the HPCI steam line condensate inboard drain valve had increased. To stop the steam leak, the HPCI steam supply line outboard containment isolation valve [FCV] was closed. LCO 3.5.1.0 was exited at 1435 hours0.0166 days <br />0.399 hours <br />0.00237 weeks <br />5.460175e-4 months <br /> CST when the reactor pressure was less than 150 psig.
TVA is submitting this report in accordance with 10 CFR 50.73(a)(2)(v)(B) and 10 CFR 50.73(a)(2)(v)(D) as "any event or condition that could have prevented the fulfillment of a safety function of structures of systems that are needed to: Remove residual heat or mitigate the consequences of an accident.
B. Inoperable Structures, Components, or Systems that Contributed to the Event:
None.
C. Dates and Approximate Times of Major Occurrences:
November 30, 2007, at 1052 hours0.0122 days <br />0.292 hours <br />0.00174 weeks <br />4.00286e-4 months <br /> CST The steam leak was isolated by closing outboard containment isolation valve. Unit 3 entered LCO 3.5.1.C.
November 30, 2007, at 1450 hours0.0168 days <br />0.403 hours <br />0.0024 weeks <br />5.51725e-4 months <br /> CST Unit 3 exited LCO 3.5.1.C.
November 30, 2007, at 1650 hours0.0191 days <br />0.458 hours <br />0.00273 weeks <br />6.27825e-4 months <br /> CST TVA made a 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> non-emergency report per 10 CFR 50.72(b)(3)(v)(B) and 10 CFR 50.72(b)(3)(v)(D).
D. Other Systems or Secondary Functions Affected
None.
E. Method of Discovery
The leak was identified by visual inspection.
F. Operator Actions
Operations closed the HPCI steam supply line outboard containment isolation valve.
G. Safety System Responses
None.
III. CAUSE OF THE EVENT
A. Immediate Cause
The immediate cause for the manual isolation of HPCI was a leak in the HPCI steam line condensate inboard drain valve. An additional through wall leak was identified in a welded connection, a tee to one inch pipe connection just downstream of the HPCI steam line drain pot steam trap outboard maintenance block valves [SHV].
B. Root Cause
The root cause for the manual isolation of HPCI was a packing leak on the HPCI steam line condensate inboard drain valve.
C. Contributing Factors
None.
IV. ANALYSIS OF THE EVENT
On November 30, 2007, at 1053 CST Unit 3 was placed in Mode 3 in order to perform planned midcycle outage activities which included removing HPCI from service and repair a previously identified steam leak on the packing of the HPCI steam line condensate inboard drain valve.
During the reactor shutdown, the volume of the steam leak increased. To minimize the spread of contamination in the area, Operations isolated the steam supply to HPCI and declared HPCI inoperable. Contributing to the steam leak, visual inspection identified a Code Class 2 piping through wall leak in a welded connection just upstream of the HPCI steam line condensate inboard drain valve.
A drain pot is provided upstream turbine stop and HPCI supply valves to prevent the HPCI steam supply line from filling with water. When HPCI is in standby, steam exiting the HPCI main steam line into the drain pot steam trap and through a double maintenance block globe valve arrangement and enters a ninety-degree turn. The steam exits the pipe tee branch prior to entering the HPCI steam line condensate inboard drain valve. The ninety-degree turn of the steam resulted in flow accelerated corrosion wear to the internal land surface of the socket weld branch connection to the pipe tee. This leak contributed to the increased leakage observed.
V. ASSESSMENT OF SAFETY CONSEQUENCES
The safety consequences of this event were not significant. The TSs requires HPCI to be operable in Modes 1, 2, and 3, when the reactor pressure is equal to or greater than 150 psig. HPCI can be inoperable for up to for up to 14 days as long as the RCIC system is operable. During the short duration HPCI was inoperable (approximately 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />), RCIC was operable.
The HPCI steam supply line is provided with a condensate drain pot upstream of the turbine stop and the HPCI supply valves to prevent the steam supply line from filling with water. The drain pot normally routes condensate to the main condenser. Upon initiation of HPCI, the drain pot is automatically isolated. As such, the motive force ability to run the HPCI pump during required operation would not be compromised if called upon.
VI. CORRECTIVE ACTIONS
A. Immediate Corrective Actions
Operations closed the HPCI steam supply line outboard containment isolation valve and entered TS LCO 3.5.1.C.
B. Corrective Actions to Prevent Recurrence (1) The valve stem packing in the HPCI steam line condenser inboard drain valve was replaced.
A section of one inch pipe with the through wall leak was replaced. Pipe wall thickness checks were performed on the piping adjacent to the leak and the wall thickness met the design calculation requirements.
VII. ADDITIONAL INFORMATION
A. Failed Components
None.
B. Previous LERs on Similar Events None.
C. Additional Information
Corrective action document for this report is PER 134495.
D. Safety System Functional Failure Consideration:
This event involves a safety system functional failure according to NEI 99-02.
E. Scram With Complications Consideration:
This event did not result in a complicated scram according to NEI 99-02.
VIII. COMMITMENTS
None.
(1) TVA does not consider the corrective actions a regulatory requirement. The completion of the action will be tracked in TVA's Corrective Action Program.