05000321/LER-2012-003
| Edwin I. Hatch Nuclear Plant Unit 1 | |
| Event date: | 03-13-2012 |
|---|---|
| Report date: | 05-10-2012 |
| Reporting criterion: | 10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications 10 CFR 50.73(a)(2)(i) |
| 3212012003R00 - NRC Website | |
PLANT AND SYSTEM IDENTIFICATION
General Electric - Boiling Water Reactor Energy Industry Identification System codes appear in the text as (EIIS Code XX).
DESCRIPTION OF EVENT
On 3/13/2012, with the unit in Mode 4 for conducting a Reactor Pressure Vessel (RPV) Pressure Test inspection following refueling, a through-wall leak was identified in a small bore line (specifically in a 3/4 inch elbow) located inboard of the HPCI 1E41-F002 valve prior to the point at which the line connects to the Main Steam Line "B" piping (EIIS Code SB).
The physical discoloration of the pipe and surrounding insulation surrounding the leak appear to support the judgment that the leak had existed for some period of time during the previous cycle. Initial evaluation of the crack in the subject HPCI piping and elbow concluded that the most apparent cause of the weld defect that led to the leak was inadequate root penetration in the weld that over time likely propagated through the wall of the pipe. The actual cause has not yet been fully determined.
Following removal and repair of the subject piping, a leak test was performed at 920 psig with no leaks identified.
CAUSE OF EVENT
The leak identified during this event was in the thicker portion of the fillet weld adjacent to the socket elbow. The subject weld was an original construction Class 1 Tungsten Inert Gas (TIG) weld that was inspected both visually and by Penetration Test (PT) at the time the weld was performed. Initial evaluation of the crack in the subject HPCI piping and elbow by a Southern Nuclear (SNC) Metallurgist Principal Engineer (PE) and a person from Quality Control (QC), each with over thirty years of experience with weld processes and inspections, concluded that the most apparent cause of the weld defect that led to the leak was inadequate root penetration in the weld. This conclusion was reached based on the characteristics of the failed weld after consideration of High Cycle Fatigue (HCF), Intergranular Stress Corrosion Cracking (ICSCC), possible imposed stress from work conducted in the course of the subject outage, improper weld fusion, original weld defect caused by slag or porosity at the root, or inadequate root penetration.
At the time of the performance of the subject weld some years ago, it was permissible to use a welding rod with a diameter of 1/8 inch in such welds, and this practice may have contributed to the suspected inadequate root penetration. Applicable welding procedures were revised in 2008 to specify that the root pass of all socket welds be performed using filler material with a maximum diameter of 3/32 of an inch to provide proper root penetration.
A subsurface or root defect resulting from inadequate root penetration most likely propagated over time through the wall, and eventually caused the leak. The actual cause of the weld failure that led to the observed leak has not yet been fully determined. The section of piping in which the leak was located will be sent to an appropriate vendor (Altran) for inspection and expert determination of the most probable cause of the through-wall leak.
When that evaluation of the apparent cause has been completed, this report will be revised to disclose the final results of the analysis.
define the reactor coolant pressure boundary. During plant life, the joint and valve interfaces can produce varying amounts of reactor coolant leakage through either normal operational wear or mechanical deterioration. Limits on RCS operational leakage are required to ensure appropriate action is taken before the integrity of the reactor coolant pressure boundary is compromised. The TS delineate the limits on the specific types of leakage. The unidentified leakage flow limit allows time for corrective action to be taken before the reactor coolant pressure boundary can be compromised significantly. The five gallons per minute (gpm) limit is a small fraction of the calculated flow from a critical crack in the primary system piping. A critical crack is one large enough to propagate rapidly, ultimately leading to failure of the affected component. As discussed in the FSAR, crack behavior from experimental programs shows that leakage rates of over a hundred gallons per minute will precede crack instability.
In this event, a small leak was identified and investigated as a result of a RPV Pressure Test walk-down. This leak was determined to meet the TS definition of pressure boundary leakage due to its location in a portion of the RCS piping which could not be isolated from the reactor coolant pressure boundary. At the time it was discovered and corrective action taken, the leak was not unstable and would not have resulted in catastrophic failure of the line. However, a worst-case instantaneous and complete severing of the line due to the presence of such a leak would not result in a significant loss of reactor coolant or present any challenge to core cooling. In addition, even if the inventory loss were completely water as compared to steam or a steam-water mix, the break would still be bounded by both the Loss of Coolant Accident analysis and the Feedwater Line break analysis. This hypothetical leak would be significantly less than the rated capacity of the High Pressure Coolant Injection, HPCI (EIIS Code BJ) system, which is sized to provide adequate coolant make-up for pipe breaks up to four inches, and approximates the rated capacity of the Reactor Core Isolation Cooling, RCIC (EIIS Code BN) system. Consequently, either system would have been capable of indefinitely maintaining normal reactor water level. Additionally, a leak of several hundred gallons per minute (gpm) would be adequately accommodated by the feedwater system (EIIS Code SJ), which has a flow rate capacity margin at rated conditions of at least 10 percent. Therefore, any one of three diverse and independent high pressure injection systems could have provided sufficient make-up flow to maintain water level well above the top of the active fuel. Based upon the preceding considerations, it is concluded that this event had no adverse impact on nuclear safety. This analysis is applicable to all operating conditions under which the subject leak might have propagated to line failure.
NRC. FORM 368A 1142010)
2. DOCKET
Previous Similar Events:
Non-isolable ASME Class-1 pressure boundary leaks were discovered during three previous refueling outages; one each in Unit 2 piping in years 2005 and 2007, and one in Unit 1 piping in 2008. All three leaks were identified during the RPV System Leakage Tests at the end of refueling outages. The three leaks occurred on non-isolable 1" stainless steel instrumentation piping associated with the main steam system. In each of these instances, the plant had to be returned to cold shutdown in order to perform the repairs. In each case, it was apparent that the leak, although small in magnitude, had existed for some period of time during the preceding run cycle. Upon completion of the failure analysis for the affected pipe elbow this section will be updated to determine if there were actually any identified previous similarities.
The piping leak discovered on Unit 2 in the Spring of 2005, occurred in the 1" stainless steel instrumentation piping associated with the 4" steam supply to the RCIC system. The failed component was shipped to a vendor (Altran) for failure analysis. High Cycle Fatigue (HCF) was determined to be the predominant failure mechanism. The failed piping section was replaced with the identical material and original weld geometry.
The second piping leak discovered on Unit 2 in the Spring of 2007, occurred in 1" stainless steel instrumentation piping associated with the main steam flow-measurement manifold, on WIC FORM 366A (104010) this failure. The failed piping section was replaced with the same material using the original weld geometry.
NRC FORM 356,A 00-20101