05000374/LER-2015-003
| Lasalle County Station, Unit 2 | |
| Event date: | 08-07-2015 |
|---|---|
| Report date: | 10-06-2015 |
| Reporting criterion: | 10 CFR 50.73(a)(2)(ii)(A), Seriously Degraded |
| Initial Reporting | |
| 3742015003R00 - NRC Website | |
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LaSalle County Station Unit 2 is a General Electric Company Boiling Water Reactor with 3546 Megawatts Rated Core Thermal Power.
A. CONDITION PRIOR TO EVENT:
Unit(s): 2 Reactor Mode(s): 3 Event Date: August 7, 2015 Event Time: 1345 CST Mode(s) Name: Hot Shutdown Power Level: 0 percent
B. DESCRIPTION OF EVENT:
On August 7, 2015, Unit 2 was in Mode 3 for a planned maintenance outage. At 1300 hours0.015 days <br />0.361 hours <br />0.00215 weeks <br />4.9465e-4 months <br />, during the initial drywell entry, a steam leak was observed on the Reactor Recirculation (RR)[AD] system line 2RR94AB-3/4", which is upstream of valve 2B33-F080B (RR Pump Discharge Valve 2B33-F067B Inspection Port - Reactor Side Upstream Stop Valve). At 1345 hours0.0156 days <br />0.374 hours <br />0.00222 weeks <br />5.117725e-4 months <br />, the leak was determined to be pressure boundary leakage.
Technical Specification 3.4.5, "RCS Operational Leakage," Required Actions C.1 and C.2 were entered, which require the unit to be in Mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in Mode 4 in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />, respectively. Unit 2 entered Mode 4 at 2209 hours0.0256 days <br />0.614 hours <br />0.00365 weeks <br />8.405245e-4 months <br /> on August 7, 2015.
This condition was reported (EN# 51300) on August 7, 2015, to the NRC in accordance with 10 CFR 50.72(b)(3)(ii)(A) for the pressure boundary leakage as a principal safety barrier being in a seriously degraded condition.
C. CAUSE OF EVENT:
The cause for the steam leak on line 2RR94AB-3/4" was determined to be poor weld quality and vibration induced fatigue due to Reactor Recirculation system operation.
D. SAFETY ANALYSIS:
The safety significance of the event was minimal. Makeup capability was adequate to compensate for the leak.
All Emergency Core Cooling Systems (ECCS) were operable and capable of fulfilling their intended safety functions during the period of excessive leakage. The event did not constitute a safety system functional failure.
E. CORRECTIVE ACTIONS:
The leak was repaired by replacing line 2RR94AB-3/4", which included removal of the inspection/vent valves and installation of a pipe cap.
LaSalle County Station, Unit 2 05000374
F. PREVIOUS OCCURRENCES:
On April 27, 2013, LaSalle Unit 1 was in Mode 2 (Startup) following a forced outage. At 1800 hours0.0208 days <br />0.5 hours <br />0.00298 weeks <br />6.849e-4 months <br /> CDT, during a walk down of the drywell, a steam leak was observed coming from the Reactor Core Isolation Cooling Steam Supply Inboard Isolation Bypass/Warm up Valve (1E51-F076), a normally-closed, one inch, motor operated valve. The leak was determined to be on the valve bonnet extension-to-bonnet upper seal weld. At 2124 hours0.0246 days <br />0.59 hours <br />0.00351 weeks <br />8.08182e-4 months <br /> CDT the leak was classified as reactor coolant pressure boundary leakage, and Technical Specification (TS) 3.4.5 Condition C was entered. TS 3.4.5 Required Actions C.1 and C.2 require that the unit be in Mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, and Mode 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.
The apparent cause was a weld defect or discontinuity from the original weld construction (i.e., manufacturing, installation/construction errors, etc.) of the upper seal weld that propagated through wall as a result of system loading and conditions (i.e., high pressure steam) during normal plant operations. Corrective actions included repair of the defective seal weld area.
On February 9, 2011, LaSalle Unit 1 was in Mode 2 (Startup) following a forced outage. A steam leak was observed coming from the Reactor Core Isolation Cooling Steam Supply Inboard Isolation Bypass/Warm up Valve (1 E51-F076), a normally-closed, one inch, motor operated valve. The leak was determined to be on the valve bonnet extension-to-bonnet upper seal weld. At 1804 hours0.0209 days <br />0.501 hours <br />0.00298 weeks <br />6.86422e-4 months <br />, the leak was classified as pressure boundary leakage, and Technical Specification (TS) 3.4.5 Condition C was entered. TS 3.4.5 Required Action C.1 and C.2 require that the unit be in Mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and Mode 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.
The equipment apparent cause evaluation determined that the cause was a weld defect or discontinuity from the original weld construction (i.e., manufacturing, installation/construction errors, etc.) of the upper seal weld that propagated through wall as a result of system loading and conditions (i.e., high pressure steam) during normal plant operations. Corrective action included repair of the defective upper seal weld area.
On March 12, 2005, during a scheduled refueling outage on Unit 2, a pinhole leak in a Class 1 weld on the outboard Main Steam Isolation Valve drain line (21321-F028D) was discovered during a hydrostatic test of the reactor coolant pressure boundary. The apparent cause of the leak was a weld inclusion or defect from a Class 1 weld made in 1995.
The weld was repaired, non-destructive surface examination performed, and the hydrostatic test was re-performed successfully within acceptance criteria.
G. COMPONENT FAILURE DATA:
No component failures occurred during this event.