L-02-014, Request for Additional Information Related to Technical Specifications Change - Steam Generator Inspection Frequency Revision for Spring 2003 Refueling Outage
| ML021960109 | |
| Person / Time | |
|---|---|
| Site: | Farley  |
| Issue date: | 07/11/2002 |
| From: | Dennis Morey Southern Nuclear Operating Co |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| NEL-02-0149 | |
| Download: ML021960109 (7) | |
Text
Dave Morey Southern Nuclear Vice President Operating Company Farley Project P.O. Box 1295 Birmingham, Alabama 35201 Tel 205.992.5131 July 11, 2002 SOUTHERN Docket No.: 50-348 COM PANY Energy to Serve Your World' NEL-02-0149 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 Joseph M. Farley Nuclear Plant, Unit 1 Request for Additional Information Related to Technical Specifications Change Steam Generator Inspection Frequency Revision for the Spring 2003 Refueling Outage Ladies and Gentlemen:
By letter dated March 4, 2002, Southern Nuclear Operating Company (SNC) submitted a one-time Technical Specifications change revising steam generator inspection frequencies for Unit 1. On June 14, 2002, a phone call was held between members of your staff and SNC personnel concerning the proposed change. As a result of the phone call, SNC received a request for additional information (RAI) by e-mail dated June 17, 2002 from Ms. Cheryl Khan of your staff. Enclosed are the NRC questions and the SNC responses to the RAI.
Mr. D. N. Morey states he is Vice President of Southern Nuclear Operating Company and is authorized to execute this oath on behalf of Southern Nuclear Operating Company, and to the best of his knowledge and belief, the facts set forth in this letter are true.
Respectfully submitted, Southern Nuclear Operating Company Dave Morey Sworn to aj bscrib d before me this Itf^_ day of - 2002.
- Notary Public My commission expires.:
>0
July 11, 2002 Page 2 U. S. Nuclear Regulatory Commission MJA/sl: Supplemental Response for Steam Generator Inspection.doc
Enclosure:
Request for Additional Information Related to Technical Specifications Change cc: Southern Nuclear Operating Company Mr. D. E. Grissette, General Manager - Farley U. S. Nuclear Regulatory Commission, Washington, D. C.
Mr. F. Rinaldi, Licensing Project Manager - Farley U. S. Nuclear Regulatory Commission, Region II Mr. L. A. Reyes, Regional Administrator Mr. T. P. Johnson, Senior Resident Inspector - Farley Alabama Department of Public Health Dr. D. E. Williamson, State Health Officer
ENCLOSURE Joseph M. Farley Nuclear Plant, Unit 1 Request for Additional Information Related to Technical Specifications Change Steam Generator Inspection Frequency Revision for the Spring 2003 Refueling Outage NRC Question No. 1 The submittal, dated March 4, 2002, states that during the Unit 1 Fall 2001 refueling outage, 100% of the tubing was inspected full-length with a bobbin coil probe, and a 20% sample of the hot leg top-of tubesheet (TTS) transition and the low row U-bends were inspected with the +Point rotating probe.
- a. State whether each of these inspections (i.e., full-length, hot leg TTS and low row U bends) were performed in all three steam generators.
- b. Which rows were inspected as part of the low row U-bend inspection?
- c. Were any additional +Point inspections performed (e.g., +Point inspection of bobbin signals)? If so, briefly describe the conditions under which a +Point inspection would be required and how many of this type of +Point inspection were performed during the Fall 2001 inspection.
SNC Response
- a. 100% of the tubing was inspected full-length with a bobbin coil probe in the three (3) replacement steam generators (SGs). A 20% sample of the hot leg top-of-tubesheet (TTS) transitions were inspected in the three SGs with the +Point rotating probe. 100%
of the low row U-bends were inspected with the +Point rotating probe in all three SGs.
- b. The low row U-bend inspection was performed on rows 1 and 2 of the three replacement SGs.
- c. Additional +Point inspections were performed on possible bobbin indication locations not cleared by a historical review of the pre-service inspection results. New or pre existing signals that exhibited significant change in magnitude were inspected with the
+Point probes. In the three (3) SGs, a total of thirty-seven (37) indications were inspected with the +Point probe.
NRC Question No. 2 The submittal states that the Fall 2001 inspection results showed no degraded or defective tubes.
Utilizing the Technical Specification definition of degraded and defective would imply that no tubes contained defects greater than 20% throughwall.
- a. Were any defects (i.e., service induced degradation) less than 20% throughwall identified? If so, please list all indications that were identified and sizing estimates, if appropriate.
- b. Were any results identified that were not attributed to service induced degradation and were left in-service (e.g., dents, manufacturing burnish marks, etc.)? If so, please list the number and type of results identified. In addition, briefly describe the actions taken that led to your decision to leave them in service (e.g., history review, supplemental eddy current inspection, etc.).
SNC Response
- a. No service induced defects < 20% through wall were detected or sized.
- b. The following 1RI 7 results not attributed to service induced degradation were left in service.
1R17 Results Summary SR1l Condition SGA
-SignalsI SGB SGC BLG Bulge - diameter increase 1 0 1 DNG Free Span Dings 2 0 3 DNT Dents (TSP and baffle plate) 0 1 1 FSD Freespan signal unchanged from PSI 6 3 9 NQS Indication not confirmed by RPC exam 18 10 7 OXP Expansion transition anomaly within the tubesheet 0 0 10 PLP Possible Loose Part detected by RPC exam 0 0 2 Our decision to leave the above signals in service is primarily based on either previously identifying signal during preservice inspections or the signal does not exhibit flaw like characteristics. Historical review of these bobbin signals can confirm their existence in the as-built preservice inspection records. If such a signal is unchanged from its baseline appearance, the possible flaw is re-categorized as a non-flaw (FSD) as shown above. If the signal appears to have changed or not to have been present in the baseline (PSI) records, the signal is +Point tested.
If no degradation is found, the +Point result is reported as "NDF" (no degradation found) and the bobbin result re-stated as "NQS" (non-quantifiable signal). Tubes with signals classified in this fashion are not designated to be plugged.
Signals that are indicative of diameter reduction in TSPs are reported as dents (DNT). In freespan sections the term "ding" (DNG) is used. A "bulge" (BLG) is a random local diameter increase, producing a signal about the size of a typical dent or ding. All of these signals were found in the pre-service inspection and are not indicative of tube degradation. If the signal reported as DNG, DNT, or BLG exhibits change beyond that associated with repeatability of bobbin testing, it is reported as a distorted signal, e.g., DNI, and a +Point examination is required to determine the condition underlying the change. Upon +Point examination, the interference that masks the location for the purpose of bobbin examination is eliminated; the presence of significant flaws, if any, is then verifiable. Only tubes with confirmed "plug on detection" flaws or those with non-cracks properly sized greater than 40% throughwall depth need be plugged.
OXP signals are flaw free manufacturing expansion anomalies within the tubesheet.
Detection of a possible loose part (PLP) by bobbin probe or by +Point probe requires that the extent of contact and wear, if any, be bounded by +Point testing. Visual inspection of the location is recommended and removal of the part, if possible, is required. A PLP (possible loose part) indication is sometimes a false indicator. Agglomerated sludge, i.e., sludge rocks, has been shown to produce a similar signal. Thus, depending on the timing of sludge removal operations, visual examination may not identify the source of the signal. In the absence of wear detected or confirmed by +Point examination, and in conjunction with an assessment that a loose part confirmed to be present poses no threat to tube integrity during the operating interval until the next inspection, tubes with PLP signals are not required to be plugged. As explained in our question 4 response, the above PLP signals were confirmed to not be the result of a loose part.
2
NRC Question No. 3 The submittal states that one of the steam generator design improvements is an increased number and type of external shell penetrations which provide for better secondary side access for sludge and foreign object removal capabilities. Do you intend to utilize these penetrations to perform sludge lancing of the steam generators during the Spring 2003 refueling outage?
SNC Response Sludge lancing of the top of the tube sheet is currently planned for Farley 1R18 in Spring 2003. The penetrations required for sludge lancing will be used in the process. However, the use of secondary side cleaning techniques is evaluated after every outage and could change in the future. The increased number and type of external shell penetrations provides for additional inspection flexibility and enhanced cleaning capability.
NRC Question No. 4 The submittal states that "no foreign objects detrimental to the steam generator tubing were identified,"
and that "minor debris was removed from the steam generators as part of the inspection."
- a. Please describe what debris was removed from the steam generators and how you determined that they were not detrimental to the steam generator tubing.
- b. Were any "possible loose parts" indications identified as part of the eddy current inspection?
If so, describe whether loose parts were identified on the secondary side, and describe the inspections and findings, if any, on surrounding steam generator tubes.
SNC Response
- a. Thirteen (13) small pieces of non-metallic material resembling flexitallic gasket-like material were removed from SG A. Total length of the thirteen (13) pieces was approximately 5 inches. One (1) metal shaving approximately 1/16 inch long and one (1) piece of wire approximately 3/4 inch long were removed from SG B. One (1) nail (1.25 inches long) and two (2) pieces of flexitallic gasket like material (each approximately 1 inch long), were removed from SG C.
Inspections performed included: 1) eddy current inspections of all tubes; 2) FOSAR of regions most likely to experience high levels of wear should an object be present in the SG; and 3) inspections of the material removed via sludge lance from the SGs.
The eddy current inspection program included both a 100% bobbin coil inspection (which is very good at detecting volumetric indications) and a 20% plus-point inspection of the hot leg tubes near the top of the tubesheet. From this data, it has been determined that there are no indications of either a loose object or indications of any tube wear.
- b. PLP signals indicative of possible loose parts/foreign objects were reported only in SG C at the top of the tubesheet on the hot leg (HL) side of tubes 11/82 and 12/82. Visual examination did not confirm an object at this location. The detection of the PLP signals was accomplished in the +Point top of tubesheet inspection program (+/- 3 inches). The immediate neighbors of these two (2) tubes were all examined with +Point, effectively bounding the extension of the signals' source. A summary of the examination results follows.
3
+Point Results for Tubes Surrounding SG C PLP Location Row# Column # 81 Column # 82 Column # 83 9 NDD NDD 10 NDD NDD NDD 11 NDD PLP NDD 12 NDD PLP NDD 13 NDD NDD NDD 14 NDD NDD 15 NDD NDD -
NRC Question No. 5 The submittal states that there have been no reported instances of antivibration bar (AVB) wear in replacement steam generators with the Westinghouse advanced AVB design that was incorporated in the Farley steam generators. How many plants have steam generators in operation with the Westinghouse advanced AVB design? How many of these have completed at least one inservice inspection of their steam generators?
SNC Response Eleven (11) of the plants with advanced design AVB control have had at least one (1) inservice inspection. The table that follows is a list of all Westinghouse plants equipped with advanced design AVB design; i.e., close tolerance U-bend fitup, Type 405 stainless steel AVBs, and a rectangular section AVB. Alloy 690TT tubing either in replacement SGs or in original equipment SGs, as in Sizewell B, is the norm for these units. The Indian Point 2 SGs were built with square section chrome-plated Inconel AVBs and Alloy 600TT tubing, but tightness control was emphasized in their U-bend assembly. Except for the plants whose SGs were replaced in 2001 (Farley 2, Kewaunee, ANO 2, and Shearon Harris) and Indian Point 2, the plants listed have been inspected at least once. None of the eleven (11) plants have reported detecting AVB wear in their first ISI (usually 100% bobbin inspection). The plants operating for various longer terms have not reported AVB wear in subsequent inspections.
Westinghouse SGs (6-1-02) with Improved AVB Design Plant Commercial. Replacement Date Model Tubes Tube AVB Operation Alloy Alloy COOK 2 7/1/78 3/1/89 54F 3592 690TT 405 FARLEY 1 12/1/77 5/24/00 54F 3592 690TT 405 FARLEY 2 7/1/81 5/8/01 54F 3592 690TT 405 INDIAN 8/1/74 7/1/00 44F 3214 600TT 600 POINT 2 INDIAN 8/1/76 6/1/89 44F 3214 690TT 405 POINT 3 KEWAUNEE 6/1/74 12/5/01 54F 3592 690TT 405 MIHAMA 1 11/28/70 4/3/96 35F 2918 690TT 405 NORTH 6/1/78 4/1/93 54F 3592 690TT 405 ANNA 1 NORTH 12/1/80 6/1/95 54F 3592 690TT 405 ANNA 2 ANO 2 11/1/80 9/15/01 Delta 109 10637 690TT 405 KORI 1 4/29/78 7/1/98 Delta 60 4934 690TT 405 4
POINT 10/1/72 3/1/97 Delta 47 3499 690TT 405 BEACH 2 SHEARON 5/1/87 10/1/01 Delta75 6307 690TT 405 HARRIS SOUTH 8/25/88 5/1/00 Delta 94 7585 690TT 405 TEXAS 1 SUMMER 1/1/84 12/1/94 Delta75 6307 690TT 405 SIZEWELL B 2/1/95 Original in Service F 5626 690TT 405 5