ML030640628
| ML030640628 | |
| Person / Time | |
|---|---|
| Site: | Callaway  |
| Issue date: | 03/05/2003 |
| From: | Donohew J NRC/NRR/DLPM/LPD4 |
| To: | Randolph G Union Electric Co |
| Donohew J N, NRR/DLPM,415-1307 | |
| References | |
| TAC MB6643 | |
| Download: ML030640628 (8) | |
Text
March 5, 2003 Mr. Garry L. Randolph Vice President and Chief Nuclear Officer Union Electric Company P.O. Box 620 Fulton, MO 65251
SUBJECT:
CALLAWAY PLANT -
SUMMARY
OF CONFERENCE CALL WITH UNION ELECTRIC COMPANY REGARDING THE 2002 STEAM GENERATOR INSPECTIONS (TAC NO. MB6643)
Dear Mr. Randolph:
In a call with your staff before Refueling Outage 12, I identified the importance of inservice inspections of steam generator (SG) tubes in assuring the integrity of the tubes, and requested that a teleconference be held with your staff to discuss the results of the SG tube inspections, that would be conducted during the October 2002 refueling outage of the Callaway Plant, after about 75 percent of the tubes had been inspected.
The discussion with your staff on the SG tube inspection results was to allow the NRC staff to collect information on any SG tube degradation found earlier than would be typically reported within 12 months of the inspection, in accordance with Technical Specification (TS) 5.6.8, "Steam Generator Tube Inspection Report." The teleconference is not part of any licensing action and the subject TAC is not fee billable to the Callaway license.
On November 5, 2002, a teleconference on the results of the SG tube inspection being then conducted at Callaway was held between your staff and the NRC staff. Enclosed is a summary of the information provided by your staff. The summary has been reviewed by your staff for technical accuracy and their comments were incorporated in the enclosed summary. This closes out the subject TAC. If you have any questions, please contact me at 301-415-1307, or through the Internet at jnd@nrc.gov.
Sincerely,
/RA/
Jack Donohew, Senior Project Manager, Section 2 Project Directorate IV Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket No. 50-483
Enclosure:
Summary of Teleconferences Held on November 5 and 15, 2002 cc w/encl: See next page
ML030640628 NRR-106 OFFICE PDIV-2/PM PDIV-2/LA EMCB/SC PDIV-2/SC NAME JDonohew EPeyton LLund RGramm for SDembek DATE 2/24/2003 2/24/03 2/27/03 3/5/03 DOCUMENT NAME:G:\\PDIV-2\\Callaway\\Letter-SummaryofSGtubeInspectionCall-2002.cw.wpd
Callaway Plant, Unit 1 cc:
Professional Nuclear Consulting, Inc.
19041 Raines Drive Derwood, MD 20855 John ONeill, Esq.
Shaw, Pittman, Potts & Trowbridge 2300 N. Street, N.W.
Washington, D.C. 20037 Mr. Mark A. Reidmeyer, Regional Regulatory Affairs Supervisor Regulatory Affairs AmerenUE P.O. Box 620 Fulton, MO 65251 U.S. Nuclear Regulatory Commission Resident Inspector Office 8201 NRC Road Steedman, MO 65077-1302 Mr. J. V. Laux, Manager Quality Assurance AmerenUE P.O. Box 620 Fulton, MO 65251 Manager - Electric Department Missouri Public Service Commission 301 W. High P.O. Box 360 Jefferson City, MO 65102 Regional Administrator, Region IV U.S. Nuclear Regulatory Commission 611 Ryan Plaza Drive, Suite 400 Arlington, TX 76011-4005 Mr. Ronald A. Kucera, Deputy Director for Public Policy Department of Natural Resources 205 Jefferson Street Jefferson City, MO 65101 Mr. Rick A. Muench President and Chief Executive Officer Wolf Creek Nuclear Operating Corporation P,O. Box 411 Burlington, KA 66839 Mr. Dan I. Bolef, President Kay Drey, Representative Board of Directors Coalition for the Environment 6267 Delmar Boulevard University City, MO 63130 Mr. Lee Fritz Presiding Commissioner Callaway County Court House 10 East Fifth Street Fulton, MO 65151 Mr. David E. Shafer Superintendent Licensing Regulatory Affairs AmerenUE Post Office Box 66149, MC 470 St. Louis, MO 63166-6149 Mr. John D. Blosser, Manager Regulatory Affairs AmerenUE P.O. Box 620 Fulton, MO 65251 Mr. Scott Clardy, Director Section for Environmental Public Health P.O. Box 570 Jefferson City, Missouri 65102-0570
SUMMARY
OF TELECONFERENCES HELD ON NOVEMBER 5 AND 15, 2002 REGARDING STEAM GENERATOR TUBE INSPECTION RESULTS UNION ELECTRIC COMPANY CALLAWAY PLANT, UNIT 1 DOCKET NO. 50-483 On November 5, 2002, the NRC staff participated in a conference call with Union Electric Company (the licensee) representatives regarding the then ongoing steam generator (SG) tube inspection activities at Callaway. The activities were during Refueling Outage 12. At the time of the call, the licensee had completed approximately 70 percent of the eddy current data analysis, and the information provided was subject to change. On November 5, 2002, the licensee provided the following information regarding the ongoing steam generator inspection activities:
The licensee stated that primary-to-secondary leakage did not exist prior to the refueling outage, and, therefore, it did not conduct any secondary side pressure tests.
The licensee stated that the SG inspection scope consisted of:
Full length bobbin examination of 100 percent of the inservice tubes in SGs A and D.
Rotating probe (equipped with a plus-point coil) examination of 100 percent of the tubes from 2-inches above to "X"-inches below the top of the hot-leg tubesheet in all four steam generators. The distance "X" is variable depending on the tubes radial location within the steam generator. This examination would include the expansion transition.
Rotating probe (equipped with a high frequency plus-point coil) examination of the U-bend region of 100 percent of the Row 1 and 2 tubes in SG C. Rows 1 through 10 are Alloy 600 thermally treated tubing. Rows 11 and higher are Alloy 600 mill-annealed tubing.
Ultrasonic testing of 100 percent of the Electrosleeves in SG A.
Rotating probe examination of 100 percent of the laser welded sleeves in SG C.
Rotating probe (equipped with a plus-point coil) examination of 20 percent of the dings greater than 2 volts (as measured by the bobbin probe).
- 2 -
The staff noted that the licensees practice of performing bobbin inspection of only two-out-of-the-four SGs each outage is different than that which is performed by other licensees with Alloy 600 mill-annealed SG tubing. The licensee indicated that their inspection plan is based on their operating experience (i.e., the types of degradation they have observed at specific locations along the length of the tube). The licensee indicated that wear has been identified at tube-to-antivibration bar intersections and wear has been identified at various locations due to loose parts. These wear indications were identified with the bobbin probe and the licensees condition monitoring and operational assessment supports their inspection scheme. The licensees inspection scope complies with the technical specification requirements.
The licensee stated that the SG tube degradation that had been identified at the time of the call was:
Antivibration Bar Wear (AVB) - Three (3) tubes in SG A and one (1) tube in SG D contain AVB wear that exceeds 40 percent through wall. The tube with the deepest AVB wear scar was 52 percent through wall, which was a 14 percent through wall increase since the last inspection of that tube (2 cycles of operation). These four (4) tubes will be plugged.
Axial, circumferential and volumetric indications were identified near the top-of-tubesheet on the hot leg side of the SG. The majority of the indications were determined to have initiated from the inside surface of the tube (primary water stress corrosion cracking [PWSCC]), with only a handful initiating from the tube outside.
Approximately 35 axial indications were identified near the expansion transition region. The voltage distributions were similar to those identified during the previous inspection of the SGs. Sizing of the flaws had not been completed at the time of the call, however, the licensee indicated that the flaws appeared to be very small. All tubes with axial flaws will be plugged.
Approximately 26 circumferential indications were identified in the expansion transition region and approximately 12 were identified below the expansion transition region. The maximum distance a circumferential flaw was found below the top of the tubesheet was approximately 11 inches. Sizing of the flaws had not been completed at the time of the call, however, the licensee indicated that the majority of the flaws extended 110 to 120 degrees circumferentially. One flaw, located within the tubesheet region, appeared to extend 360 degrees circumferentially. All tubes with circumferential flaws will be plugged.
Several volumetric flaws were identified near the top of the tubesheet. Three very low voltage (approximately 0.2 volts) volumetric indications were adjacent to one another, and the licensee speculated they could potentially be from wear due to loose parts. One volumetric indication was identified in a Row 9 tube (a thermally treated tube) which was 0.14 volts. The licensee did not see any sign of loose parts near these indications based on the eddy current data. The licensee plugs-on-detection all volumetric indications identified near the top of the tubesheet.
- 3 -
The Electrosleeves had not been inspected at the time of the call.
The licensee plugs on detection all crack-like indications and all volumetric indications located near the top of the tubesheet. The licensee plans to stabilize and plug all circumferential indications. All AVB wear indications greater than or equal to 40 percent through wall will be plugged. The licensee does not plan to sleeve any tubes this outage.
The licensee stated that it performs a lookback of previous inspection data under certain circumstances, and the lookback for this refueling outage was the following:
When a freespan signal is identified in the bobbin data, the licensee reviews previous inspection data to determine if that signal was previously reported at least 2 cycles before. If it was (i.e., the licensee previously identified the signal and determined it was not indicative of service-induced degradation), the licensee compares the current outage data to the previous outage data to determine if the signal has changed. If the signal has changed, that tube is further inspected with a rotating probe to determine if the signal is now indicative of service induced degradation. If the signal was not previously reported, the licensee reviews the inspection data from at least the 6th outage prior to the current outage to determine if the signal was present, but not identified, at that time. If the signal was not present or has changed, that tube is further inspected with a rotating probe to determine if the signal is indicative of service induced degradation.
The licensee reviews previous inspection data of all locations where service induced degradation is identified during the current outage. This effort is ongoing at Callaway.
The licensee stated that there were no new degradation modes identified at Callaway this refueling outage.
The licensee stated they were aware of the recent inspection findings (i.e., ODSCC in thermally treated steam generator tubing) at Seabrook. The licensee included Seabrook eddy current data in Callaways site-specific performance demonstration database which is utilized for training eddy current analysts.
The licensee explained that the only inspection techniques and probes that are utilized at Callaway are the eddy current bobbin probe, a rotating probe with a mid-frequency plus point coil, a rotating probe with a high frequency plus point coil, a rotating probe with a mag-bias plus point coil, and ultrasonic testing for Electrosleeves.
The licensee stated that in-situ pressure testing had not been performed at the time of the call. The licensee stated they use both voltage and flaw sizes to determine whether in-situ pressure testing is required. The licensee had twelve potential candidates for in-situ pressure testing, however, many of them may be eliminated from the candidate list once flaw sizing has been completed.
The licensee stated that it does not plan to pull any tubes.
- 4 -
The licensee notified the staff that SG A entered a C-3 category (i.e., more than 10 percent of the total tubes inspected are degraded or more than 1 percent are defective) due to the number of indications identified at the top of the tubesheet. The licensee stated that it will follow the Callaway Technical Specifications for the C-3 category.
The licensee stated that it expected to complete eddy current testing late on Thursday, November 7, 2002, and expected to complete in-situ pressure tests and tube plugging by Saturday, November 9, 2002.
The NRC staff did not identify any issues requiring followup, but requested that the licensee contact the NRC if the remaining inspections identified any of the following: (1) any significant degradation, (2) a degradation mode or location other than that discussed during the conference call, or (3) a failure of or an incomplete in-situ pressure test; or an Electrosleeve with service induced degradation. The licensee did not contact the NRC for any of these three items.
The status of its SG tube inspection in Refueling Outage 12 at the time of the call with the NRC staff was provided by the licensee in an e-mail to support the call, and is given in the attached table.
In a later call on November 15, 2002, the licensee notified the NRC of the final number of SG tubes plugged during the outage, which was greater than the number provided in the call on November 5, 2002. The total for each SG is as follows:
Steam Generator A - 91 tubes plugged Steam Generator B - 5 tubes plugged Steam Generator C - 19 tubes plugged Steam Generator D - 9 tubes plugged
Attachment:
Table: Refuel 12 Steam Generator Maintenance Principal Contributor: Cheryl Khan Date: March 5, 2003
[Table:] Refuel 12 Steam Generator Maintenance Steam Generator Channel Head Scope
(# of tests)
Acquired Analyzed Percent Complete Pluggable Indications*
Hot Leg RPC 5431 5316 4803 88.4 49 Cold Leg Bobbin 5068 4109 3008 59.4 3
Hot Leg RPC 5568 4027 3816 68.5 2
Hot Leg RPC 5449 5430 3461 63.5 10 Steam Generator D
Hot Leg RPC 5528 5512 3581 64.8 2
Cold Leg Bobbin 5164 4715 3313 64.2 5
Total 32208 29109 21982 68.3 71
- All indications have not necessarily been through the resolution process. Number of indications may actually decrease RF12 Eddy Current Update November 5, 2002 0500