05000237/LER-2012-002
| Docket Number | |
| Event date: | |
|---|---|
| Report date: | |
| Reporting criterion: | 10 CFR 50.73(a)(2)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident |
| 2372012002R01 - NRC Website | |
PLANT AND SYSTEM IDENTIFICATION
Dresden Nuclear Power Station (DNPS) Units 2 and 3 are General Electric Company Boiling Water Reactors with a licensed maximum power level of 2957 megawatts thermal. The Energy Industry Identification System codes used in the text are identified as [XX].
A. � Plant Conditions Prior to Event:
Unit: 02 � Event Date: 5-22-2012 � Event Time: 1055 hours0.0122 days <br />0.293 hours <br />0.00174 weeks <br />4.014275e-4 months <br /> CDT Reactor Mode: 1 � Mode Name: Power Operation � Power Level: 100 percent Unit: 03 � Event Date: 6-10-2012 � Event Time: 0200 hours0.00231 days <br />0.0556 hours <br />3.306878e-4 weeks <br />7.61e-5 months <br /> CDT Reactor Mode: 1 � Mode Name: Power Operation � Power Level: 100 percent
B. Description of Event:
Turbine Building. The leak was from the High Pressure Coolant Injection (HPCI) [BJ] Inlet Drain Pot Inboard Drain line to the Main Condenser [SG]. Following removal of piping insulation, it was determined that the piping had a through-wall leak on a 90 degree Chrome-Molybdenum socket elbow upstream of Air Operated Valve 2-2301-29. The Unit 2 HPCI system was isolated and declared inoperable and Technical Specification 3.5.1, Condition G was entered and required actions taken.
Additionally, on June 10, 2012, at 0200 hours0.00231 days <br />0.0556 hours <br />3.306878e-4 weeks <br />7.61e-5 months <br /> CDT plant personnel identified a small steam leak in the Unit 3 Turbine Building. The leak was from the HPCI Inlet Drain Pot Inboard Drain line to the Main Condenser. Following removal of piping insulation, it was determined that the piping had a through-wall leak on a 90 degree Chrome-Molybdenum socket elbow upstream of Air Operated Valve 3-2301-29. The Unit 3 HPCI system was isolated and declared inoperable and Technical Specification 3.5.1, Condition G was entered and required actions taken.
In each case, the Unit 2 and Unit 3 HPCI systems were taken out of service to secure the leaks and allow repair activities to be performed. The piping sections were replaced with stainless steel piping components and the HPCI systems were returned to service on May 25, 2012, and June 12, 2012, respectively.
Upon isolating the HPCI systems, this event became reportable pursuant to 10 CFR 50.73(a)(2)(v)(D), "Any event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to mitigate the consequences of an accident.
C. Cause of Event:
Based on a failure analysis, the failure of the HPCI drain lines was due to local internal thinning from a mechanical erosion mechanism.
The HPCI drain system is designed to remove condensation in the steam turbine supply line (2(3)- 2305-10"-B) above the turbine steam supply valve (MO 2(3)-2301-3). The drain path directs flow to the main condenser.
The HPCI drain line passes condensate from the HPCI drain pot to the main condenser. The condensate seen in the system is in the form of two-phase flow (both liquid and gaseous steam) at an elevated temperature due to the pressure loss present in this line. Two-phase flow is especially erosive to carbon steel materials. This line carries a steam/condensate mixture from the 400°F/1000 psi drain pot to the condenser vacuum. Due to the pressure drop, the two-phase mixture accelerates as the condenser is approached. In 1997, degradation from flow accelerated corrosion (FAC) was identified in the HPCI drain pot line piping to the main condenser. The piping was replaced with a more FAC resistant material, Chrome-Molybdenum.
Liquid impingement erosion occurs when the impacts from the high velocity water droplets damage the pipe surface. Velocity and impact angle are two factors that can affect the erosion. Based on the cratered appearance of the eroded surfaces, most of the thinning was due to liquid droplet impingement erosion. Liquid impingement erosion is caused by the impacts of high-velocity water droplets on the pipe surface. The through wall leaks occurred toward the downstream side of the elbow, where the droplet impact angle was high (i.e., close to 90 degrees).
The elbows were sectioned to allow for inner surface inspections. Both leaks occurred in areas of local internal thinning near the outside of the bend. The thinning was greatest where the impact angle of the incoming steam/liquid mixture was high.
On the Unit 3 elbow, some of the thinning resulted in a linear gouged appearance (Figure 1).
Thinning was also observed on the butt ends of the downstream pipe. All the thinned surfaces exhibited irregular, coarse cratered features (Figure 2). The cratered surface appearances were typical of a mechanical erosion mechanism (e.g., liquid impingement erosion) as opposed to flow accelerated corrosion. The locally gouged surface regions on the Unit 3 elbow suggested that some flashing erosion had also occurred.
Safety Analysis:
The safety significance of this condition is low. The Automatic Depressurization and Low Pressure Emergency Core Cooling Systems [BO] [BM] were available to provide makeup to the reactor vessel inventory in the event of an accident or transient. Additionally, the respective Isolation Condenser [BL] systems were available for reactor vessel pressure control, if required. Therefore, health and safety of the public were not compromised as a result of this condition.
Corrective Actions:
The following actions were taken to address the identified conditions.
Failed elbows have been replaced. The 2-2301-29 AOV body has been replaced. In order to evaluate the extent of condition, nondestructive examinations (NDE) are scheduled to be completed on selected elbows in January 2013. Based on the results of NDE, portions of the HPCI drain piping will be replaced during scheduled HPCI maintenance in March 2013. Any degraded piping components that remain will be scheduled for replacement during the upcoming Unit 2 refueling outage, D2R23.
Failed elbows have been replaced. The 3-2301-29 and 3-2301-30 A0Vs have been replaced as part of extent of condition from a through wall leak on the 2-2301-29 AOV. Piping elbows have been replaced in the Turbine Building. Extent of Condition NDE was completed on a sampling of the Reactor Building piping elbows. Due to the identification of wall thinning, all elbows were inspected in the Reactor Building. Elbows that were found degraded were replaced with more resistant stainless steel elbows. All degraded piping components have been replaced on Unit 3.
For the remaining Chrome-Molybdenum portions of piping, preventative maintenance activities have been created to periodically perform NDE to identify degradation.
F. � Previous Occurrences:
A review of DNPS Licensee Event Reports (LERs) for the last three years revealed the following reportable conditions related to HPCI inoperabilities:
- LER 237/2009-002, "Unit 2 High Pressure Coolant Injection Suction Valve Fails to Close"
- LER 237/2011-002, "Steam Leak Results in HPCI Inoperability"
- LER 249/2010-003, "Steam Leak Results in HPCI Inoperability.
The corrective actions from the above Licensee Event Reports would not have prevented the current HPCI inoperability.
G. � Component Failure Data:
Manufacturer N/A Model N/A Component Type 1" Schedule 80 A335 P11 (Chorme Moly) 90° socket elbow Figure 1 — This photo shows linear gouges on the thinned surface of the Unit 3 elbow.
The gouges are consistent with a mechanical erosion mechanism (e.g., flashing or liquid impingement erosion).
Figure 2 - Th's stereoscope photo shows the through wall leak in the Unit 2 elbow.
Note the cratered appearance of the adjacent thinned surface. The wall thickness measured approximately 0.015" thick at the failure edge.