ML17313A688
| ML17313A688 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 11/25/1998 |
| From: | Fields M NRC (Affiliation Not Assigned) |
| To: | James M. Levine ARIZONA PUBLIC SERVICE CO. (FORMERLY ARIZONA NUCLEAR |
| References | |
| TAC-MA0681, TAC-MA681, NUDOCS 9811300109 | |
| Download: ML17313A688 (12) | |
Text
November.25, lgg8 Mr. James M. Levine Senior Vice President, Nuclear Arizona Public Service Company Post Office Box.53999 Phoenix, Arizona 85072-3999
SUBJECT:
REVIEW OF THE STEAM GENERATOR EDDY CURRENT INSPECTIONS AT PALO VERDE NUCLEAR GENERATING STATION UNIT2 (TAC NO. MA0681)
Dear Mr. Levine:
In letters dated October 2 and October 30, 1997, the NRC staff requested additional information from Arizona Public Service Company (APS) regarding steam generator eddy current inspection results at Palo Verde Nuclear Generating Station Unit 2 obtained during the 1997 refueling outage.
Specifically, the staff focused on inspection results from the U-bend region in the low row tubes and from support regions in tubes located in the batwing-stay cylinder region.
The staff also requested the licensee consider the impact of the Unit 2 inspection results on the operability of Palo Verde Units 1 and 3. APS responded to our requests for additional information in a letter dated November 18, 1997, and provided further information in letters dated January 25, February 6, and May 7, 1998. The NRC staff has reviewed your responses and has concluded that APS has demonstrated acceptable structural and leakage integrity of the low row U-bend tubes through its condition monitoring and operational assessments at all three Palo Verde units.
A summary of our review is enclosed.
Ifyou have any questions, please contact me at (301) 415-3062.
Sincerely, Original Signed By Mel B. Fields, Project Manager Project Directorate IV-2 Division of Reactor Projects - III/IV Office of Nuclear Reactor Regulation BSJJILJt Docket Nos. STN 50-528, STN 50-529 and STN 50-530
Enclosure:
Unit 2 Steam Generator Inspection Results ccw/encl: See next page DOCUMENT NAME: PV2-SG.LTR t;Docket File PUBLIC EAdensam MFields EPeyton OGC, 015B18 ACRS, TWFN PDIV-2 Reading WBateman PGwynn, RIV PHarrell, RIV TSullivan OFC PDIV-2/P NAME M
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Mr. James M. Levine November 25, 1998 cc w/encl:
Mr. Steve Olea Arizona Corporation Commission 1200 W. Washington Street Phoenix, Arizona 85007 Mr. David Summers Public Service Company of New Mexico 414 Silver SW, ¹1206 Albuquerque, New Mexico 87102 Douglas Kent Porter Senior Counsel Southern California Edison Company Law Department, Generation Resources P.O. Box 800
- Rosemead, California 91770 Senior Resident Inspector USNRC P. O. Box 40 Buckeye, Arizona 85326 Regional Administrator, Region IV U. S. Nuclear Regulatory Commission Harris Tower 8 Pavillion 611 Ryan Plaza Drive, Suite 400 Arlington, Texas 76011-8064 Chairman, Board of Supervisors ATTN: Chairman 301 W. Jefferson, 10th Floor Phoenix, Arizona 85003 Mr. Jarlath Curran Southern California Edison Company 14300 Mesa Road, Drop D41-SONGS San Clemente, California 92672, Mr. Robert Henry Salt River Project 6504 East Thomas Road Scottsdale, Arizona 85251 Te'rry Bassham, Esq.
General Counsel El Paso Electric Company 123 W. Mills El Paso, Texas 79901 Mr. John Schumann Los Angeles Department of Water 8 Power Southern California Public Power Authority P.O. Box 51111, Room 1255-C Los Angeles, California 90051 Mr. Aubrey V. Godwin, Director Arizona Radiation Regulatory Agency 4814 South 40 Street Phoenix, Arizona 85040 Ms. Angela K. Krainik, Manager Nuclear Licensing Arizona Public Service Company P.O. Box 52034 Phoenix, Arizona 85072-2034 Mr. John C. Horne, Vice President Power Supply Palo Verde Services 2025 N. Third Street, Suite 220 Phoenix, Arizona 85004
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N ERGNE N
- 2 AND 1.0 NT Arizona Public Service Company (APS), the licensee for the Palo Verde Nuclear Generating Station (PVNGS), Units 1, 2 and 3, conducted steam generator (SG) tube eddy current inspections for Unit 2 during its Cycle 7 refueling outage in September 1997.
Each PVNGS unit has two Combustion Engineering (CE) System-80 SGs with stainless steel eggcrate supports and a full-depth, explosive tubesheet expansion.
Two SG tube integrity issues emerged from the Unit 2 Cycle 7 refueling outage SG inspection results:
(1) a throughwall indication in the U-bend of a row 1 tube, and (2) degradation attributed to wear in the batwing-stay cylinder area.
In letters dated October 2 and October 30, 1997, the NRC staff requested additional information from APS regarding steam generator eddy current inspection results from this outage.
Specifically, the staff focused on inspection results from the U-bend region in the low row tubes and from support regions in tubes located in the batwing-stay cylinder region.
In addition, the staff requested APS provide the basis for dispositioning the indications as due to geometry in the previous outage.
The staff also requested the licensee consider the impact of the Unit 2 inspection results on the operability of Palo Verde Units 1 and 3. APS responded to our requests for additional information in a letter dated November 18, 1997, and provided further information in letters dated January 25, February 6, and May 7, 1998. These issues are discussed below in more detail.
20 V
A E
NRE 21
-B During Unit 2 Cycle 7 operation, APS tracked a 1-2 gallons per day primary-to-secondary leak in SG ¹21. After shutting down for the refueling outage, the licensee performed a secondary side pressurization test and identified a positive leakage source at tube R1 C56: a low row, tight radius tube.
The licensee used the Plus Point eddy current probe technique to inspect 100 percent of the row 1 and 2 U-bends.
APS then expanded its inspection scope to include 100 percent of rows 3 and 4 U-bends.
The licensee reported 3 U-bend indications in SG ¹21, one of which was throughwall (tube R1C56), and attributed these indications to primary water stress corrosion cracking (PWSCC). Two of the three indications, including the throughwall indication, had been identified during the previous outage with a Plus Point probe and were dispositioned as due to a geometry effect and thus were not repaired.
No indications were reported in SG ¹22.
C 2.2 D
-t li Through its bobbin coil eddy current inspections, APS identified 54 pluggable tube indications caused by wear in the batwing-stay cylinder region at Unit 2. APS used an Electric Power
. Research Institute (EPRI) Appendix H-qualified technique to size the wear indications; the largest of the batwing wear indications was sized at a depth of 70 percent throughwall (tube R36C87).
The deep wear degradation was not entirely unexpected given the recent SG shroud modifications that caused an increase in the flow rates and subsequent increase in wear rates in this region of the SG.
In a letter dated October 2, 1997, the staff requested the licensee provide the basis for its decision to notin situ pressure test or pull tube R36C87.
The licensee initiallystated the EPRI sizing technique for wear had an associated eddy current uncertainty with respect to depth of 3-4 percent; thus the defect measured at 70 percent throughwall would be less than the structural limitof 78 percent throughwall ~ However, in developing its response to the staff's request for additional information, APS identified three areas potentially impacting the measurement technique for batwing wear that are not currently addressed in the EPRI qualification. These are (1) wear scar geometry on calibration standards, (2) development of amplitude curves, and (3) effect of the tube support plate signal.
Based on an assessment of these issues, APS concluded that the depth-sizing technique for wear is valid only for depths up to about 50 percent throughwall. A reassessment of the sizing technique led the licensee to the conclusion that the indication in tube R36C87 could have been as deep as 93 percent throughwall.
In the October 2 letter, the staff also requested APS provide the basis for concluding that Unit 2 is safe to operate for a full cycle, and the basis for concluding Units 1 and
'3 are safe to continue operating given similar batwing-stay cylinder wear and current uncertainty with respect to the validity of past sizing ofwear degradation using the EPRI technique.
3.0 31 N
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'n With respect to the U-bend indications, the licensee performed in situ pressure testing of tube R1 C56; the tube with the throughwall indication. The licensee could not demonstrate by the test that structural integrity requirements were met (i.e., 3 times normal operating delta pressure, or 4400 psig when corrected for operating temperature) because leakage through the indication exceeded the test pump's capacity. The maximum test pressure achieved was 3550 psig. Therefore, the licensee relied on a combination of eddy current results, in situ pressure test results, and engineering evaluations to determine that the throughwall length of the
. indication was no longer than 0.32 inches, which is below the critical throughwall crack size of 0.63 inches.
Based on this, the licensee concluded that Regulatory Guide 1.121 structural integrity requirements were met. Leakage through the indication at main steam line break pressure was measured at 0.49 gpm or 0.74 gpm with a temperature correction. This is below the unit's allowable leakage limitof 6 gpm and is therefore acceptable.
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1 ii With respe'ct to the wear degradation in the batwing-stay cylinder region, APS concluded that the most limiting indication located in tube R36C87 could have been as deep as 93 percent throughwall. APS stated that burst and leak rate testing performed by CE indicated that tubes with batwing wear defects95-100 percent throughwall do not burst at normal operating or under accident conditions. The licensee also stated that testing performed by CE under accident conditions demonstrated that the leakage through such indications would be, less than 4 gpm, which is less than the licensee's allowable leak rate limitof 6 gpm. (The staff did not review the CE burst and leak rate test results.) Thus, the licensee concluded that even ifthe wear degradation in tube R36C87 was as deep as 93 percent throughwall, the degradation would not have represented a significant safety issue for Unit 2 during the past operating cycle.
3.2 V
i With respect to the U-bend indications, the licensee inspected 1'00 percent of rows 1 through 4 U-bends using the Plus Point probe. APS plugged ail tubes with similar geometric-like U-bend indications and added these types of indications to the administrative plugging criteria. Based
. on the acceptable condition monitoring results as discussed in the preceding section, the expanded inspection scope, and the implementation of a modiTied plugging criteria, the licensee concluded that Unit 2 was safe to operate for a complete cycle.
With respect to the wear degradation in the batwing-stay cylinder region, the licensee performed an interim operational assessment to support startup.
APS assumed a worst case condition to justify operating for at least 10.6 months, The licensee used the largest in-service flaw of 19 percent throughwall (the plugging limitin the batwing-stay cylinder region is 20 percent throughwall) plus 5 percent to account for eddy current measurement uncertainty. APS then "grew" the flaw using a growth rate of nondetectable degradation to 93 percent throughwall over 16.5 months.
Using these inputs and a structural limitof 78 percent throughwall, the licensee justified Unit 2 operation through September 1, 1998 (a 10.6 month operating cycle).
APS also preventatively plugged nearly the entire susceptible tube population in the batwing-stay cylinder area.
APS completed a more detailed flinai operational assessment that supports a full 18-month cycle of operation for Unit 2 and notified the staff of its conclusions in a letter dated May 7, 1998. The final operational assessment is maintained at the PVNGS.
4.0 D
With respect to the U-bend indications, the licensee reexamined the most recent Plus Point inspection results of the row 1 and 2 U-bends in the Units 1 and 3 steam generators.
APS found two similar geometric-like indications in Unit 1 SG ¹12. The indications are located in the apex (like the U-bend indications in Unit 2), have two consecutive cycle of Plus Point inspection results indicating no change, and are much smaller than the R1C56 precursor indication in Unit
- 2. Based on the acceptable condition monitoring assessment for Unit 2, the licensee concluded that the U-bend indications in Unit 1 would not compromise SG tube integrity. No such indications were identified in Unit 3. Thus, APS concluded Units 1 and 3 were both safe to continue operating.
1 0,
With respect to the wear degradation in the batwing-stay cylinder region, APS concluded that the issue was not relevant to Unit 1 because the SG shroud modifications that cause an increase in the flow rates and subsequent increase in wear rates were not implemented at Unit
- 1. The licensee stated that the last tube plugged in Unit 1 for batwing-stay cylinder wear was 2 cycles ago for a 24 percent throughwall wear indication. APS used the EPRI sizing technique discussed earlier, but believes it is a valid technique as long as the depths are less than about 50 percent throughwall. For Unit 3, APS performed an interim operational assessment using the same assumptions discussed above for Unit 2. APS justified Unit 3 operation through February 15, 1998 (a 10.6 month operating cycle). The licensee had also preventatively plugged nearly the entire susceptible tube population in the batwing-stay cylinder area dunng the previous cycle. APS completed a more detailed final operational assessment that supports a full 18 month cycle of operation for Unit 3 and notified the staff of its conclusions in a letter dated February 6, 1998. The final operational assessment is maintained at PVNGS.
5.0 With respect to the U-bend indications, the staff concludes that APS has demonstrated acceptable structural and leakage integrity of the low row U-bend tubes through its condition monitoring and operational assessments at all three Palo Verde units. The staffs review of the eddy current examinations supported the licensee's dispositioning of the indications as due to a geometry effect in the previous outage.
However, the staff notes that the eddy current examination was not optimized to detect crackiike indications. The licensee informed the staff that the Unit 2 findings will be incorporated into the SG eddy current examination procedure and analyst training program for future SG inspections.
Additionally, the licensee plans to manufacture calibration standards with inner diameter notches to improve the characterization of PWSCC flaws. These improvements should enhance the stress corrosion cracking detection capabilities of the eddy current technique.
With respect to the wear degradation in the batwing-stay cylinder region, the staff concludes that even with the worst case assumptions of the condition of tube R36C87, there did not appear to be a safety significant issue with respect to structural and leakage integrity over the past operating cycle at Unit 2. Regarding the operational assessments, the staff concludes Unit 1 is safe to continue operating given the shroud modifications that cause high wear degradation rates was not implemented at Unit 1. For PVNGS Units 2 and 3, the staff finds reasonable the licensee's conclusions that both units are safe to operate for a full cycle. The assumptions used for the interim operational assessments performed for Units 2 and 3 appear to be very conservative in nature, and the licensee preventatively plugged nearly the entire susceptible tube population in the batwing-stay cylinder area.
Thus, the staff does not plan to review the details of APS'inal operational assessments.
With respect to problems identified with the EPRI Appendix H-qualified sizing technique, the staff notes that licensees must fullyqualify eddy current sizing techniques before using such techniques to justify leaving degraded SG tubes in service or before using such techniques as a basis for condition monitoring and operational assessments.
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