05000445/LER-2002-002
| Event date: | |
|---|---|
| Report date: | |
| Reporting criterion: | 10 CFR 50.73(a)(2)(ii)(A), Seriously Degraded |
| Initial Reporting | |
| 4452002002R01 - NRC Website | |
I. DESCRIPTION OF REPORTABLE EVENT
A. REPORTABLE EVENT CLASSIFICATION
The subject event is reportable pursuant to the requirements of CPSES TS 5.6.10, specifically 10CFR50.73(a)(2)(ii)(A).
B. PLANT OPERATING CONDITIONS PRIOR TO THE EVENT
On October 6, 2002, CPSES Unit 1 was in Mode 6, Refueling, during its ninth refueling outage.
C. STATUS OF STRUCTURES, SYSTEMS, OR COMPONENTS THAT WERE
INOPERABLE AT THE START OF THE EVENT AND THAT CONTRIBUTED TO
THE EVENT
Not Applicable — There were no structures, systems, or components that were inoperable at the start of the event which contributed to this event.
D. NARRATIVE SUMMARY OF THE EVENT, INCLUDING DATES AND
APPROXIMATE TIMES
On September 28, 2002, CPSES Unit 1 began its ninth refueling outage.
CPSES Technical Specification (TS) 5.5.9, "Steam Generator (SG) Tube Surveillance Program", requires that the results of each Steam Generator (EIIS: (AB)(SG)) tube inspection be classified as Category C-3 if more than 1 percent of the total tubes inspected are defective.
Additionally, if the results of the SG tube sample inspections are classified as Category C-3, then prompt NRC notification is required in accordance with TS 5.5.9 Table 5.5-2 and TS 5.6.10.c. During this ninth refueling outage, results of 3 SG inspections went into Category C- 3 at separate times.
Two separate notifications were identified on the following dates and times:
1. On October 6, 2002, at 4:50 p.m., CPSES made notification of an event pursuant to the requirements of 10CFR50.72(b)(3)(ii)(A). The notification stated that analysis of eddy current testing data on SG 1-2 indicated that greater than 1 percent of the total tubes inspected in SG 1-2 were defective (Refer to NRC event number 39251).
Facility Name (1) COMANCHE PEAK STEAM ELECTRIC STATION UNIT 1 LER Number (6) 02 M 02 M 01 Docket Year Sequential Revision Number Number Page(3) 2. On October 6, 2002, at 9:30 p.m., CPSES made notification of an event pursuant to the requirements of 10CFR50.72(b)(3)(ii)(A). The notification stated that analysis of eddy current testing data on SGs 1-3 and 1-4 indicated that greater than 1 percent of the total tubes inspected in SGs 1-3 and 1-4 were defective (Refer to NRC event number 39251).
E. THE METHOD OF DISCOVERY OF EACH COMPONENT OR SYSTEM FAILURE,
OR PROCEDURAL OR PERSONNEL ERROR
The defective tubes were found during scheduled eddy current testing of the CPSES Unit 1 SG tubing.
II. COMPONENT OR SYSTEM FAILURES
A. FAILURE MODE, MECHANISM, AND EFFECTS OF EACH FAILED COMPONENT
TXU Energy believes that the predominant degradation mechanism was ODSCC. Additional degradation mechanisms identified, to a very limited extent, ( Water Stress Corrosion Cracking (PWSCC) and wear.
B. DURATION OF SAFETY SYSTEM TRAIN INOPERABILITY
Not Applicable — No safety system train was rendered inoperable.
C. SAFETY CONSEQUENCES AND IMPLICATIONS
The ODSCC associated with the hot leg expansion transition was found to be the predominant degradation mechanism seen during the CPSES IRFO9 inspection. A total of 667 tubes were repaired (plugged or sleeved) for this mode of degradation. SG 1-1 had 31 tubes affected; SG 1-2 had 186 tubes affected, SG 1-3 had 216 tubes affected, and SG 1-4 had 234 tubes affected.
The total plugs and sleeves installed to date remain well below the 10 percent tube plugging allowance provided by the accident analysis described in CPSES FSAR Chapters 4 and 15.
Eight tubes with ODSCC associated with the hot leg expansion transition were in situ pressure tested with no leakage or achieving the burst point.
However, during the in situ pressure testing on SG 1-02, tube R41 C71, leakage exceeded the pump capacity at 2.6 gallons per minute (GPM) and 2070 psig. Limited pump capacity prevented reaching the Structural Integrity Performance Criterion of NEI 97-06, "Steam Generator Program Guidelines," therefore meeting this criterion is indeterminate. Due to the inaccessability of tube R41 C71 for removal, two tubes with similar indications to tube R41 C71 were removed and sent to the vendor (Westinghouse) for failure analysis after successful in situ pressure testing was completed. It should be noted that 10 additional tubes with defects similar in nature to tube R41 C71 were also in situ pressure tested with satisfactory results. Actual SG tube leakage prior to the ninth refueling outage was well within the allowed CPSES TS limit of 150 gpd and there were no measurable offsite radiological consequences.
The condition of the tubes at the end of cycle (EOC) 9 for this damage mechanism meets the NRC accepted integrity levels. The number of indications for EOC 9 increased but the voltage amplitude distribution was equivalent to the results at the EOC 7 and EOC 8. Therefore, the structural and leakage integrity condition of the CPSES Unit 1 SGs is not significantly different from previous cycles and continues to meet the established regulations, codes, and standards, with the exception of tube R41 C71 as discussed above.
Based on the aforementioned, it was concluded that the event had no impact on the health and safety of the public Supplemental Information:
Primary to secondary leakage was identified at the end of the cycle and the observation of dripping water from tube R41 C71 during shutdown indicated that a 100% through wall (TW) degradation was present. Subsequent visual examination of the inner diameter surface of R41 C71 clearly shows 2 collinear axial cracks at the elevation in question. The upper 100%TW tip of the lower crack is at the same elevation or slightly below the lower 100%TW tip of the upper crack. A non-degraded ligament is clearly visible between the 2 cracks. Based on burst testing results performed as part of the original F* alternate repair criterion development, it was concluded that collinear axial cracks act independently of each other with regard to burst capability.
Changes were made to the bobbin reporting criteria for the 1RFO9 inspection designed to identify the early precursor signal for tube R41 C71. Therefore, if indications similar to R41 C71 were present in the CPSES SGs, they would have been reported in the bobbin reanalysis program. Also, all freespan differential signals (FSD) reported in the U-bend region of the CPSES SGs at 1RFO9 were Plus PointTM (+Pt) inspected. Therefore, it is not reasonable to assume that an indication similar to R41 C71 in the prior refueling outage (1RF08) is currently present in the CPSES Unit 1 SGs.
FactIny Name (1)
COMANCHE PEAK STEAM ELECTRIC STATION UNIT I
LER Number (6) 02 ri 02 M 01 Docket Page(3) Year Sequential Revision Number Number The maximum observed in situ test pressure for this tube was 2150 psi, with a measured leak rate of 2.6 GPM. The estimated 100%TW length to provide 2.6 GPM at a differential pressure of 2150 psi is 0.50 to 0.55". Based on the in situ testing results for R41 C71, the leak rate was projected for the CPSES Unit 1 Steam Line Break (SLB) differential pressure of 2350 psi with Power Operated Relief Valve (PORV) availability using the methodology applied to axial ODSCC indications at tube support plate (TSP) intersections that is part of the alternate repair criterion methodology. The projected leak rate is 5.1 GPM. This evaluation uses the elevated temperature tube material property values to estimate volumetric flow and then adjusts these values to room temperature conditions to provide an evaluation bases consistent with the offsite dose leakage limit. The offsite dose leakage limit for Comanche Peak Unit 1 is 27 GPM. Thus, while this indication would have provided leakage in excess of the NEI 97-06 performance criterion, doses at the site boundary would not have exceeded the licensing basis.
III. CAUSE OF THE EVENT
TXU Energy believes that the predominant damage mechanism (ODSCC) was caused by the temperature, chemistry, and residual stress effects on the tubing material (Inconel 600 MA).
IV. CORRECTIVE ACTIONS
TXU Energy believes that it has repaired the known defective tubes by plugging or sleeving as required by CPSES Technical Specifications.
V. PREVIOUS SIMILAR EVENTS
There have been three other previous events regarding SG inspections that went into Category C-3 at CPSES, which occurred during the SG tube inspections for the sixth, seventh, and eighth refueling outages. Corrective actions taken for the previous events would not have prevented this event.
VI. ADDITIONAL INFORMATION
The following information meets the requirements of the Special Report as defined in CPSES Technical Specification 5.6.10.a. Total tubes plugged and/or sleeved during this outage (this includes some previously plugged tubes which were recovered by sleeving):
CPSES UNIT 1 STEAM GENERATOR 1 48 tubes were plugged in this steam generator 0 tubes were sleeved in this steam generator 0 tubes were designated as an F* (as defined in CPSES TS ) tube.
CPSES UNIT 1 STEAM GENERATOR 2 18 tubes were plugged in this steam generator 213 tubes were sleeved in this steam generator 0 tubes were designated as an F* (as defined in CPSES TS ) tube.
CPSES UNIT 1 STEAM GENERATOR 3 23 tubes were plugged in the steam generator 250 tubes were sleeved in this steam generator 0 tubes were designated as an F* (as defined in CPSES TS ) tube.
CPSES UNIT 1 STEAM GENERATOR 4 12 tubes were plugged in this steam generator 273 tubes were sleeved in this steam generator 0 tubes were designated as an F* (as defined in CPSES TS ) tube.