ML021580390
| ML021580390 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 02/04/2003 |
| From: | Donohew J NRC/NRR/DLPM/LPD4 |
| To: | Overbeck G Arizona Public Service Co |
| Donohew J N, NRR/DLPM,415-1307 | |
| References | |
| TAC MB4076 | |
| Download: ML021580390 (10) | |
Text
February 4, 2003 Mr. Gregg R. Overbeck Senior Vice President, Nuclear Arizona Public Service Company P. O. Box 52034 Phoenix, AZ 85072-2034
SUBJECT:
PALO VERDE NUCLEAR GENERATING STATION, UNIT 2 -
SUMMARY
OF CONFERENCE CALLS ON UNIT 2 REFUELING OUTAGE STEAM GENERATOR TUBE INSPECTION (TAC NO. MB4076)
Dear Mr. Overbeck:
In its letter of February 26, 2002, the Nuclear Regulatory Commission (NRC) staff identified the importance of inservice inspections of steam generator (SG) tubes in assuring the integrity of the tubes, and stated that a teleconference had been set up with your staff to discuss the results of the SG tube inspections that were conducted during the March/April 2002 refueling outage of Palo Verde Nuclear Generating Station, Unit 2, after about 75 percent of the tubes had been inspected. A list of discussion points for the teleconference was enclosed with the letter.
The discussion with your staff on the results of the SG tube inspection was to allow the NRC staff to collect information on Unit 2 SG tube degradation earlier than would be reported within 12 months of the inspection, in accordance with Technical Specification 5.6.8, "Steam Generator Tube Inspection Report." The teleconference is not part of any licensing action being conducted by the NRC staff for the unit, and the subject TAC is not fee billable to the Unit 2 license.
On April 3, 2002, a teleconference on the results of the SG tube inspection being then conducted at Unit 2 was held between your staff and the NRC staff. A second teleconference was held on December 6, 2002, to clarify several discussion items from the first teleconference.
Enclosed is a summary of the information provided by your staff in the two calls. The summary was reviewed by your staff for technical accuracy, and its comments were incorporated in the enclosed summary of the two calls.
Gregg R. Overbeck This closes out the staffs work for subject TAC No. MB4076. If you have any questions on this letter, 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. STN 50-529
Enclosure:
Summary of Teleconferences Held on April 3 and December 6, 2002 cc w/encl: See next page
Gregg R. Overbeck This closes out the staffs work for subject TAC No. MB4076. If you have any questions on this letter, 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. STN 50-529
Enclosure:
Summary of Teleconferences Held on April 3 and December 6, 2002 cc w/encl: See next page DISTRIBUTION:
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LLund JTsao KKarwoski CKhan MMurphy CMarschall, RIV ACCESSION NO: ML021580390 NRR-106 OFFICE PDIV-2/PM PDIV-1/LA EMCB/SC PDIV-2/SC NAME JDonohew:eh MMcAllister LLund SDembek DATE 1/30/03 12/13/02 2/3/03 2/4/03 OFFICIAL RECORD COPY DOCUMENT NAME: C:\\ORPCheckout\\FileNET\\ML021580390.wpd
April 2002 Palo Verde Generating Station, Units 1, 2, and 3 cc:
Mr. Steve Olea Arizona Corporation Commission 1200 W. Washington Street Phoenix, AZ 85007 Douglas Kent Porter Senior Counsel Southern California Edison Company Law Department, Generation Resources P.O. Box 800 Rosemead, CA 91770 Senior Resident Inspector U.S. Nuclear Regulatory Commission P. O. Box 40 Buckeye, AZ 85326 Regional Administrator, Region IV U.S. Nuclear Regulatory Commission Harris Tower & Pavillion 611 Ryan Plaza Drive, Suite 400 Arlington, TX 76011-8064 Chairman Maricopa County Board of Supervisors 301 W. Jefferson, 10th Floor Phoenix, AZ 85003 Mr. Aubrey V. Godwin, Director Arizona Radiation Regulatory Agency 4814 South 40 Street Phoenix, AZ 85040 Mr. Craig K. Seaman, Director Regulatory Affairs/Nuclear Assurance Palo Verde Nuclear Generating Station P.O. Box 52034 Phoenix, AZ 85072-2034 Mr. Hector R. Puente Vice President, Power Generation El Paso Electric Company 2702 N. Third Street, Suite 3040 Phoenix, AZ 85004 Mr. David Summers Public Service Company of New Mexico 414 Silver SW, #1206 Albuquerque, NM 87102 Mr. Jarlath Curran Southern California Edison Company 5000 Pacific Coast Hwy Bldg DIN San Clemente, CA 92672 Mr. Robert Henry Salt River Project 6504 East Thomas Road Scottsdale, AZ 85251 Terry Bassham, Esq.
General Counsel El Paso Electric Company 123 W. Mills El Paso, TX 79901 Mr. John Schumann Los Angeles Department of Water & Power Southern California Public Power Authority P.O. Box 51111, Room 1255-C Los Angeles, CA 90051-0100 Brian Almon Public Utility Commission William B. Travis Building P. O. Box 13326 1701 North Congress Avenue Austin, TX 78701-3326
SUMMARY
OF CONFERENCE CALLS REGARDING MARCH 2002 STEAM GENERATOR TUBE INSPECTION RESULTS ARIZONA PUBLIC SERVICE COMPANY PALO VERDE NUCLEAR GENERATING STATION, UNIT 2 DOCKET NO. STN 50-529 In its letter of February 26, 2002, the Nuclear Regulatory Commission (NRC) staff identified the importance of inservice inspections of steam generator (SG) tubes in assuring the integrity of the tubes, and stated that a teleconference had been set up with the licensees staff to discuss the results of the SG tube inspections that were to be conducted during the March/April 2002 refueling outage of Palo Verde Nuclear Generating Station, Unit 2, after about 75 percent of the tubes had been inspected. A list of discussion points for the teleconference was enclosed with the letter.
On April 3, 2002, the NRC staff conducted a teleconference with representatives of Arizona Public Service Company (the licensee), to discuss the preliminary results of the SG tube inspection during the then ongoing refueling outage 10 at Palo Verde Nuclear Generating Station, Unit 2 (Palo Verde). The NRC staff conducted a second teleconference on December 6, 2002, to clarify several discussion items from the first teleconference. The unit has two SGs, which are numbered SGs 21 and 22.
The following preliminary information on the Unit 2 SGs came from the licensee in the phone call. Attachments 1 through 6 were provided by the licensee in e-mails to the NRC staff to support the call held on April 3, 2002.
The licensee inspected the following in the SGs:
All in-service tubes, full length, using a bobbin probe.
The Alternative Repair Criteria (ARC) region plus buffer sample using a plus point probe.
The top of the tubesheet region of all hot leg tubes using a plus point probe.
Row 1 through 5 tubes using a mid-range and high frequency plus point probe.
All bobbin indications at tube support intersections using a plus point probe.
Lower hot leg dents, manufacturing buff marks, and bulge indications using a plus point probe.
Previous indications (I-codes) using a plus point probe.
A sample of 20 percent bobbin indications detected on the top of tubesheet on cold leg using a plus point probe.
Visual inspection of tube plugs.
Internal visual inspection of 39 Combustion Engineering mechanical rolled plugs to address the Prairie Island tube plug issue.
The licensee's expansion criteria for the above inspection activities were as follows:
1.
If axial indications were detected in the ARC region, inspect five tube expansion zones in all directions. Additional regions may be specified.
2.
If axial indications were detected in the short radius U-bends, inspect 100 percent of adjacent row. If geometry anomalies were detected in the short radius U-bend, expansion inspection will be considered.
3.
Rotating pancake coil inspection of any bobbin indications that exceed the Palo Verde plugging criteria.
4.
Rotating pancake coil inspection of all I-codes and bobbin indications using a rotating pancake coil probe.
5.
Rotating pancake coil inspection of all apex anomalies in rows 6 to 18 tubes.
6.
If manufacturing burnish marks, dents, and bulges were detected, inspect 100 percent of critical size locations below elevation of detected stress corrosion cracking flaws.
7.
If circumferential cracks were detected in cold leg tubes, inspect 100 percent of the top of tubesheet on the cold leg side. If C-3 condition occurs in the hot leg rotating pancake coil inspection, expand inspection to 100 percent of cold leg tubes.
8.
If mixed mode indications were detected, inspect a five tube buffer zone.
9.
Rotating pancake coil inspection of tubes where loose parts were present.
In both SGs, the licensee stated it detected circumferential indications at the top of the tubesheet, axial indications in the ARC region and lower elevations, wear indications at batwings, volumetric indications, and loose parts. The licensee discussed two types of indications of significance.
The first type of indication was an axial stress corrosion crack initiated from the outside diameter (axial ODSCC) of the tube. One axial ODSCC indication was detected at the 02H tube support intersection in a tube in row 11 column 50 in SG 21. The average depth and length were 82.9 percent through-wall and 0.67 inch, respectively. The licensee performed condition monitoring of this indication and found that it exceeded the pressure testing screening criteria. This indication will be in-situ pressure tested and plugged. A similar axial ODSCC indication was identified at the 03H support in tube row 107 column 152. The indication had an average depth and length of 78 percent and 0.34 inches, respectively. The indication will also be in-situ pressure tested and plugged. These two tubes were pressure tested subsequent to this phone call, and passed testing with no leakage.
The second type of indication discussed with the licensee was an axial indication at the dented 02H tube support intersection in a tube in row 69 column 124 in SG 22. This indication was attributed to primary water stress corrosion cracking (PWSCC) and was the first time this type of flaw has been found at Unit 2 despite a plus point sampling program that has been in place since 1998. The indication was not present in the last outage inspection. The initial evaluation indicated an average depth and length of the indication were 66.5 percent throughwall and 0.27 inches, respectively. The condition monitoring assessment of this indication showed that it was not within the pressure testing screening criteria; however, in-situ pressure testing was being considered. Following the April 3, 2002, conference call, this indication was re-inspected and re-sized utilizing a calibration standard and analysis techniques better suited for detailed flaw profiling (i.e., length and depth sizing). The licensee concluded that the flaw was 45 percent throughwall and 0.2 inches long and did not require in-situ pressure testing. The tube with this indication was plugged.
As a result of finding the PWSCC indication at the dented 02H tube support intersection, the licensee expanded its inspection to all recordable dented intersections at the 01H, 02H, and 03H intersections using a plus point probe. No further PWSCC indications were found by the licensee as a result of the expanded inspection.
The licensee stated it detected boric acid residues on 7 Westinghouse Alloy 690 ribbed plugs and 1 Babcock and Wilcox Alloy 690 rolled plugs. The Alloy 690 plugs were installed to replace the Alloy 600 plugs in 1991. The licensee stated that there was no evidence of operational leakage during Cycle 10 and there is low likelihood of through-wall degradation in the plugged tubes. The licensee did not detect cracks in the affected Alloy 690 plugs. The licensee stated that potential leakage may be caused by the improper plug installation and the Alloy 690 plugs were designed as leak limiting, not leak tight. In response to the recent tube severance event at Three Mile Island, Unit 1, the licensee stated it will remove these plugs and examine the affected tubes for possible swelling and the diode effect.
The licensee stated it detected 25 wear indications that exceeded the technical specification limit of 40 percent throughwall. The affected tubes will be plugged. As of the phone call, the licensee plans to plug about 325 tubes. Both of the Unit 2 SGs are scheduled to be replaced during the next refueling outage scheduled for late next year.
The following information was provided by the licensee to support the call, and is given in attachments (ADAMS Accession No. ML023440013) to this summary, as indicated below:
1.
Steam Generator Tube Inspection Discussion Points - Briefing Paper 2.
Palo Verde Nuclear Generating Station (PVNGS) Administrative Plugging Criteria 3.
Preliminary In Situ Screening 4.
Unit 2 Refueling 10 (U2R10) Axial and Circumferential (Circ) Indications 5.
U2R10 Steam Generator Eddy Current Testing (ECT) Status Report 6.
Assessment of Steam Generator Tube Degradation Mechanisms provides the licensees responses to the list of discussion points for the teleconference that were enclosed with the NRC staffs letter of February 26, 2002. contains corrections marked on two of the pages sent to the NRC staff to support the April 3, 2002, teleconference. The error was corrected by the licensee in the December 6, 2002, teleconference. The error resulted from the fact that the in-situ screening data was preliminary (i.e., not quality assurance checked) at the time of the April 3, 2002, teleconference.
By the December 6, 2002, teleconference the data had been quality assurance checked and the error had been determined.
Attachments: As listed above Principal Contributor: John Tsao Date: February 4, 2003