ML091950409
| ML091950409 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 09/16/2009 |
| From: | Cotton K Plant Licensing Branch II |
| To: | Heacock D Virginia Electric & Power Co (VEPCO) |
| Cotton K, NRR/DLPM, 301-415-1438 | |
| References | |
| TAC ME0981 | |
| Download: ML091950409 (5) | |
Text
UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 September 16, 2009 Mr. David A. Heacock President and Chief Nuclear Officer Virginia Electric and Power Company Innsbrook Technical Center 5000 Dominion Boulevard Glen Allen, VA 23060-6711
SUBJECT:
SURRY POWER STATION, UNIT NO.1 -
SUMMARY
OF CONFERENCE CALLS REGARDING THE SPRING 2009 STEAM GENERATOR INSPECTIONS (TAC NO. ME0981)
Dear Mr. Heacock:
On April 29, 2009, and May 1, 2009, the Nuclear Regulatory Commission (NRC) staff participated in a conference call with Virginia Electric and Power Company representatives regarding the ongoing steam generator tube inspection activities at Surry Power Station, Unit NO.1. The summary of the conference calls is enclosed.
If you have any questions or concerns please feel free to call me at 301-415-1438.
Sincerely,
~
Karen Cotton, Project Manager Plant Licensing Branch 11-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-280
Enclosure:
Summary of Conference Call cc wi encl: Distribution via Listserv
SUMMARY
OF CONFERENCE CALLS WITH SURRY POWER STATION, UNIT NO.1 REGARDING THE SPRING 2009 STEAM GENERATOR TUBE INSPECTION RESULTS DOCKET NO. 50-280 On April 29, 2009, and May 1, 2009, the Nuclear Regulatory Commission (NRC) staff participated in a conference call with Virginia Electric and Power Company (the licensee) representatives regarding the ongoing steam generator (SG) tube inspection activities at Surry Power Station, Unit NO.1 (Surry 1).
Surry 1 has three Westinghouse model 51 F steam generators (A, B, and C) that were installed in 1981. Each SG nominally contains 3,342 thermally treated Alloy 600 tubes. Each tube has a nominal outside diameter of 0.875 inches and a nominal wall thickness of 0.050 inches. The tubes were hydraulically expanded at both ends for the full length of the tubesheet and are supported by a number of stainless steel tube support plates. The U-bends of the tubes installed in rows 1 through 8 were thermally stress-relieved after bending.
Prior to the 2009 outage, the NRC staff had requested a conference call with Surry 1 representatives to discuss the general results of their 2009 SG tube inspections (Agency-wide Documents Access Management (ADAMS) Accession No. ML090900804). This general conference call was not conducted since two conference calls were held to discuss several specific inspection findings. A summary of these calls is below.
April 29, 2009, Conference Call During the 2009 outage, tube inspections were planned for SGs A and C.
In SG A, an axial indication attributed to primary water stress corrosion cracking was identified.
The indication was initially detected with a rotating probe (since the rotating probe examination was performed before the bobbin probe examination); however, the indication was also detected with the bobbin coil probe (with application of a turbo mix).
The indication is in the tube located in row 9, column 69, and it is partially above and partially below the top of the tubesheet on the hot-leg side of the SG. The indication was estimated to be approximately 0.64 inches long and 0.32 inches above the top of the tubesheet. Portions of the indication were estimated to be 1OO-percent through-wall. The indication was located in a tube with potentially elevated residual stress, such as, a tier 1 tube.
Based on operating experience at another plant, the eddy current data, prior to 2009, from all of the tubes was reviewed to determine whether any of the tubes may have potentially higher residual stresses than other tubes. These tubes are identified based on the presence/size of any offset in the eddy current data between the straight part of the tube and the U-bend region. The tubes are classified as tier 1 tubes jf there is an offset in the eddy current data in the transition from the U-bend region to the hot-leg and the cold-leg portion of the tube. The tubes are classified as Enclosure
- 2 tier 2 tubes if there is an offset in the transition from the U-bend region to either the hot-leg or cold-leg. There are 19 tubes in SG A, 22 tubes in SG B, and 3 tubes in SG C with a tier 1 offset.
There are 33 tubes in SG A, 23 tubes in SG B, and 24 tubes in SG C with a tier 2 offset.
Based on the 2009 inspection findings, such as, an axial indication near the top of the tubesheet in a tier 1 tube, the scope of inspection was expanded. The expansion included performing a rotating probe inspection of 100 percent of the tier 1 tubes and 20 percent of the tier 2 tubes in all three SGs. The rotating probe inspections of the tier 1 tubes were performed at: the hot-leg at the top of the tubesheet region, all locations where there were non-quantifiable signals (including those with history), bUlges, dents, manufacturing burnishing marks, and tube support plate elevations.
In total, approximately 58 percent of the tubes were inspected with a rotating probe at the top of the tubesheet in SGs A and C. In addition, approximately 110 tubes were inspected in SG B as a result of the finding of the axial indication in SG A.
There was no primary-to-secondary leakage detected, above the threshold of detection, during the cycle prior to the 2009 outage.
Prior rotating probe inspections at the top of the tubesheet focused on the sludge pile region, that is, a trapezoidal shaped area near the center of the tube bundle. Based on a review of the 2006 bobbin coil data, the licensee concluded that an indication was present, but that it would not have been expected to be identified during the inspection.
Given the estimated size of this indication, the tube with the axial indication near the top of the tubesheet was scheduled to be in-situ pressure tested. A bladder was going to be used for pressures above the main steam line break differential pressure, which is above the pressure associated with accident induced leakage testing for the structural integrity test.
Based on the information provided during the conference call, the NRC staff observed the following:
The indications detected in the tubes with potentially elevated residual stresses, that is, the tubes with an eddy current offset, initiated from the outside diameter whereas the indication detected at Surry 1 initiated from the inside diameter of the tube.
Crack-like flaws detected near the top of the tubesheet at other plants with thermally treated Alloy 600 tubing have not been preferentially observed in tubes with an eddy current offset.
The number of tubes with crack-like indications is small. As a result, it may not be unusual to find only one tube with an indication in a 60-percent sample.
The stresses at the top of the tubesheet may be more a function of the expansion process rather than a result of non-optimal tube processing, as evidenced by the eddy current offset.
The bobbin coil will not detect circumferential cracking.
- 3 Given the limited rotating probe scope in SG B, there may be some advantage to review the SG B bobbin coil eddy current data from the previous outage. This review may provide additional confidence that a similar indication does not exist in SG B.
At the end of the call, the licensee indicated they would discuss whether the 2006 and 2009 eddy current data from the tube in row 9, column 69 could be sent to the NRC staff for review. This data was subsequently provided to the NRC staff. The licensee also indicated they would evaluate the need to re-evaluate the prior outage bobbin coil data for SG B and would inform the NRC staff of the results of the in-situ pressure test. The licensee subsequently informed the staff that the tube passed the in-situ pressure test with no leakage at the accident induced leakage pressure. In addition, no leakage was observed during the structural integrity test since a bladder was used at this test pressure. The licensee also indicated it would evaluate what the size of the flaw in the tube at row 9, column 69 would have been in 2006 given the industry growth data for flaws in this region of the tube bundle. The licensee subsequently provided an assessment which indicated that the flaw may have been 30-percent through-wall during the 2006 outage. This assessment was based on a 95th percentile growth rate of 20-percent through-wall per year. This assessment was not reviewed by the NRC staff.
May 1, 2009 Conference Call Initially, tube inspections were only planned for SGs A and C in the 2009 outage. Based on finding crack-like indications near the tube ends in these two SGs, the inspection was expanded to include the tube ends in SG B.
During the inspections performed in SG B, a large number of tubes were identified as having large permeability variations near the tube end. These indications were dispersed throughout the tube bundle. These permeability variations were large enough to affect the ability to inspect the tubes.
This was the first time the tube ends were inspected with a probe sensitive to tube degradation.
As a result of this finding, the licensee used magnetically biased probes to reduce the size of the permeability variations. The probe reduced the magnitude of the permeability variations in half, but the size of these signals was still too large that it could compromise the inspection of these locations. The licensee consulted with industry eddy current experts and they have not identified any way to eliminate the permeability variations.
Similar permeability variations were not seen in the other two SGs in which 100 percent of the hot leg tube ends and 20 percent of the cold-leg tube ends were inspected with a rotating probe. The inspections in these two SGs resulted in identifying five tubes in SG C and approximately seven tubes in SG A that would require plugging due to circumferential indications, that is, flaw signals, near the tube-end that exceeded the 94-degree circumferential extent criterion.
At the time of the call, the licensee was considering an emergency technical specification amendment that would rely, in part, on taking credit for the tube being held in place by the interference fit between the tube and the tubesheet. An emergency technical specification amendment was subsequently submitted and approved by the NRC staff on May 7,2009 (ADAMS Accession No. ML091260386).
The staff did not identify any issues that required follow-up action at this time; however, the staff asked to be notified in the event that any unusual conditions were detected during the remainder of the outage.
ML091950409 OFFICE NRRlLPL2-1/PM NRRlLPL2-1/LA NRRlDCI NRRlLPL2-1/BC NAME KCotton:prb MOBrien KKarwoski MWonq DATE 7/20/09 7/20/09 8/14/09 9/16/09