ML11305A077
| ML11305A077 | |
| Person / Time | |
|---|---|
| Site: | Robinson  |
| Issue date: | 10/26/2011 |
| From: | Rogalski R Progress Energy Carolinas |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| Download: ML11305A077 (7) | |
Text
TS 5.6.8 rProgress Energy Serial: RNP-RA/1 1-0068 OCT 2 6 2011f United States Nuclear Regulatory Commission ATTN: Document Control Desk 11555 Rockville Pike Rockville, Maryland 20852 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT NO. 2 DOCKET NO. 50-261/RENEWED LICENSE NO. DPR-23 RESPONSE TO NRC REQUEST FOR ADDITIONAL INFORMATION REGARDING H. B. ROBINSON STEAM GENERATOR TUBE REPORT DATED JANUARY 13,2011 Ladies and Gentlemen:
By letter dated August 5, 2011, the NRC requested that Carolina Power and Light Company (CP&L), now doing business as Progress Energy.Carolinas, Inc. (PEC), respond by August 22, 2011 to a request for additional information (RAI) regarding the H. B. Robinson Steam Generator Tube Report submitted on January 13, 2011. In an e-mail dated August 12, 2011, the respond by date was extended to October 31, 2011. The attachment to this letter provides the RAI response for the H. B. Robinson Steam Electric Plant, Unit No. 2.This document contains no new Regulatory Commitments.
If you have any questions concerning this matter, please contact me at (843) 857-1626.Sincerely, Richard J. Rogalski Supervisor
-Licensing/Regulatory Programs RJR/rjr Attachment c: V. M. McCree, NRC, Region II B. L. Mozafari, NRC, NRR NRC Resident Inspector Progress Energy Carolinas, Inc.Robinson Nuclear Plant 3581 West Entrance Road Hartsville, SC 29550 United States Nuclear Regulatory Commission Attachment to Serial: RNP-RA/1 1-0068 Page 1 of 6 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT NO. 2 RESPONSE TO NRC REQUEST FOR ADDITIONAL INFORMATION REGARDING H. B. ROBINSON STEAM GENERATOR TUBE REPORT DATED JANUARY 13,2011 NRC Ouestion 1 Provide the cumulative effective full power years that the current steam generators (SG) had operated at the time refueling outages 25 and 26 commenced.
Response: The first steam generator inservice inspection (ISI) was completed in RO 10 at the cumulative exposure of 9.0 effective full power years.At the start of R025 the cumulative exposure was 27.3 effective full power years or 18.3 effective full power years since completion of the first steam generator ISI.At the start of R026 the cumulative exposure was 28.6 effective full power years or 19.6 effective full power years since completion of the first steam generator ISI.Cumulative EFPY Since EFPM Cycle/RO Start End EOC EFPY Completion of Completion of S/G ISI Interval first SG ISI first SG ISI C25 05/13/07 09/26/08 27.3 18.3 219.4 R025 09/26/08 11/07/08 Third ISI interval 60 C26 11/07/08 03/28/10 28.6 19.6 235.3 EFPM (270 EFPM R026 03/28/10 07/19/10 total)NRC Question 2 On page 12 of 14 of your letter dated January 13, 2011, a table provides the depth of wear indications at the antivibration bar.* Discuss why the two different techniques (Z-22899 and Z-8652) provide significantly different sizing estimates.
- Identify which analysis is the analysis of record.Response: In the previous RNP outages the sizing of anti-vibration bar (AVB) wear was performed according to the EPRI ETSS 96004.1 bobbin technique.
The standard used during these previous measurements was Z-8652, which was designed for flow baffle wear. For R026 a new standard was manufactured with notches more appropriate for AVB wear. To determine actual growth since R024 both Z-8652 and Z-22899 standards were run together on the seven previous AVB wear calls.
United States Nuclear Regulatory Commission Attachment to Serial: RNP-RA/1 1-0068 Page 2 of 6 The Z-22899 standard (or equivalent replacement) will be used in future outages for the analysis of record.NRC Question 3 During the 2007 SG tube inspections, a pin-hole was found in one of the structures that hold the moisture separators in place. It was uncertain if the pinhole was due to fabrication or erosion.* Discuss whether this area was inspected during RFO 26." If so, discuss the results of this inspection and any other secondary side inspections.
Response: A pin-hole was identified during R024 in the SG-B moisture separator structure referred to as a PAGODA. It is believed that these holes originated from pre-existing holes drilled through the pipe wall during original installation.
During inspections in R026 similar holes were identified in the PAGODA supports for steam generators A and C. The pin-hole in SG-B PAGODA was ultrasonically tested during R026 and found to be unchanged from R024. The holes in the PAGODA support pipes were evaluated by the original equipment manufacturer and determined to not adversely affect structural integrity and therefore are acceptable.
RO26 secondary side maintenance included the following activities:
High Volume Bundle Flush (HVBF) on SG-A, SG-B and SG-C This activity involves the installation of temporary fixtures that are used to deliver approximately 1000 gpm of water through the upper steam drum swirl vanes which then cascades over the tube bundle for the removal of loose deposits.
A limited visual inspection of the region above the upper support plate (6th support) was performed before and after the HVBF to assess the effectiveness of the operation.
Results: Although all three steam generators were flushed with water only SG-B was inspected for assessing the results of the HVBF. The amount of loose sludge was reduced by the HVBF." Visual inspection above the 6 th support plate on SG-B only.This activity included visual inspections before and after the HVBF in the upper tube bundle area above the 6 th support plate.Results: There was soft sludge located on top of the support plate and some loose scale.* Tubesheet cleaning on SG-A, SG-B and SG-C.This activity is a high pressure water lancing used to remove sludge deposits from the top of tubesheet region.
United States Nuclear Regulatory Commission Attachment to Serial: RNP-RA/1 1-0068 Page 3 of 6 Results: Steam Generator Sludge Removed, lbs A 106 B 108 C 94 Total 308* Top of tube sheet, tubelane and annulus visual inspections with foreign object search and retrieval on SG-A, SG-B and SG-C. This activity includes visual inspection, object classification and foreign object removal to the extent possible in the top of tube sheet region of the steam generators.
Results: All objects identified were evaluated to be acceptable for 2 cycles of operation or removed. The single Priority 1 part that was not removed is a legacy part from RO-24 located in SG-A. The four adjacent tubes were inspected with RPC and no wear was identified.
Since no wear occurred over two full cycles of operation, it was determined to be acceptable for two additional cycles.* Steam drum inspections on SG-A and SG-B This activity included visual inspections on all accessible areas of the primary and secondary separators, mid deck, feedring, feedring support structures and J-nozzles.
In addition to visual inspections a UT inspection was performed on accessible areas of the feedwater ring in S/G B.Results: No anomalous conditions were identified.
All UT dimensions taken were within acceptable limits of the Steam Drum Inspection procedure.
NRC Ouestion 4 It appears that two tubes had the bottom of the expansion transition located greater than 1.0 inch from the top of the tubesheet.
- Clarify the location of the bottom of the expansion transition for these two tubes.It is the staff's understanding that most plants with thermally treated Alloy 600 tube material have plugged such tubes since the current H* analysis only supports a tube with a bottom of the expansion transition located approximately 1.0 inch from the top of the tubesheet and since the tube-to-tubesheet weld is potentially susceptible to cracking and no qualified examination exists for inspecting these welds." Clarify whether these tubes were plugged." If not plugged, discuss any plans to plug these tubes in a future outage.
United States Nuclear Regulatory Commission Attachment to Serial: RNP-RA/1 1-0068 Page 4 of 6 NRC Question 5 Confirm that the bottom of the expansion transition for the tube in SG A at row 20, column 35 and the tube in SG B in row 11, column 70 are located between 0.96 and 1.0 inch from the top of the tubesheet.
If the bottom of the expansion transition is located greater than 1.0 inch from the top of the tubesheet, address the previous question for these two tubes.NRC Question 6 Clarify the following statement: "HBRSEP inspected the tube ends (16 total) not fully expanded with the tubesheet to at least 0.5 inches from the top of the tubesheet." Is this statement implying that there are only 16 tubes in which the bottom of the expansion transition is located greater than 0.5 inches from the top of the tubesheet?
Response to Questions 4, 5, & 6: Robinson has two tubes that are not completely expanded and as such do not have a determined bottom of transition expansion (BET): SG A: R1C47 SG B: R25C10 During the approval process for the H* temporary technical specification the NRC indicated that they would approve the submittal if RNP agreed to inspects all tube portions within the tubesheet for tubes with BET further than 0.5 inches below the top of tube sheet. The 0.5 inch dimension was chosen as a conservative option, future inspections will perform inspections as specified by the applicable technical specification SER.Robinson has 14 tubes that have a BET below 0.5" from the top of the tubesheet.
Those tubes are listed below. The value in column "BET" is the distance in inches from the top of the tubesheet to the BET. Note that this does not include the two tubes discussed above.SG A SG B SG C R C BET H/C R C BET H/C R C BET H/C 20 35 1.08 C 11 70 1.12 H 17 12 0.66 H 42 43 0.59 H 1 59 0.84 C 1 87 0.64 C 6 18 0.54 C 10 22 0.79 C 3 84 0.58 H H 18 74 0.77 H 27 44 0.58 C 12 40 0.56 H 12 4 0.52 H 19 42 0.52 All tube ends with BET greater than 0.5" below the top of the tubesheet were inspected with RPC through the tubesheet to the tube end. No degradation was detected in any of these tubes.
United States Nuclear Regulatory Commission Attachment to Serial: RNP-RA/1 1-0068 Page 5 of 6 There is no plan to plug these tubes. When the alternate repair criteria technology is accepted by the NRC for permanent technical specification change, Robinson Engineering will assess the need to plug these tubes.NRC Ouestion 7 The table on page 4 and the discussion on page 13 of your letter dated January 13, 2011, implies that only 32 tubes have been plugged in your SGs at the commencement of refueling outage 26.The NRC staff was under the impression that 60 tubes had been plugged in your SGs (which includes 28 tubes plugged prior to the SGs being placed in operation).
- Confirm the total number of tubes plugged. If 60 tubes have been plugged, recalculate the plugging percentage for the SGs.Response: The statement in the transmittal is correct. Prior to refueling outage 26, March 28, 2010, there were a total of 32 tubes with plugs.NRC Ouestion 8 It was indicated that seven tubes were plugged in steam generator (SG) B and five tubes were plugged in SG C during RFO 26. In reviewing the information on pages 9 through 12 of your letter dated January 13, 2011, the NRC staff only identified six tubes in SG B that were plugged (five stabilized and plugged and one plugged) and four tubes in SG C that were plugged (two stabilized and plugged and two plugged).* Identify the additional tubes plugged and provide the reason for plugging those tubes.Response: The tables on pages 9 through 12 of the report dated January 13, 2011, list indications with% depth through wall depth.A tube in steam generator B at row 37 column 30 was plugged due to the presence of an aggressive foreign object which had caused damage to tubes in column 30 at rows; 35, 36, 38, 39 and 40. The additional tube plugged in steam generator B is is not listed in this table because no wear indications were measured.
Subsequent to the plugging and stabilizing efforts this aggressive loose part was removed from the steam generator.
A tube in steam generator C at row 38 column 62 was plugged due to a wear indication at an anti Vibration bar. The wear depth of this scar was determined to be 39% through wall using standard Z-22899. As shown in the table on page 12 of the referenced report, the wear depth when measured with standard Z-8652 shows no change from the previous wear depth.
United States Nuclear Regulatory Commission Attachment to Serial: RNP-RA/1 1-0068 Page 6 of 6 NRC Question 9 The number of tubes with bulges, over expansions, or dents in the tubesheet region that were inspected to a depth of 17.28 inches below the top of tubesheet was provided in the table on page 4.* Discuss what percentage of the total population of these indications were inspected (e.g., 50% of all bulges, over expansions, or dents within the hot-leg tubesheet region were inspected from 4-inches above to 17.28 inches below the top of the tubesheet with a rotating probe).Response: The refueling outage 26 inspection scope for the tubes with bulges, over expansions, or dents in the tubesheet region included approximately 50% of these indications.
These tube segments were inspected to a depth of 17.28 inches below the top of tubesheet.
The tubes selected for this sample include all the tubes that were not inspected in RF024.NRC Question 10 Discuss whether the tube in row 1, column 67 in SG B (with an "indication not recordable" at the sixth cold leg tube support plate) was inspected with a rotating probe to confirm the absence of degradation.
Provide any insights on why an indication detected since 2002 was no longer present during the refueling outage 26 (2010) inspection.
Response: The indications in SG B, Row 1, Col 67 at the Cold Leg 6th Tube Support Plate was inspected with a rotating probe during RF026 (2010) at Robinson.
These indications were first identified in RFO21 (2002) as 7% and 10% wear at the top, and bottom of the tube support. Each outage since then, the indications were re-examined to check for growth.In RF022 (2004) the wear was recorded as 2% and 4% wear. Then as 24% and 25% wear in RF024 (2007). In RF026 (2010) the indications were seen again, but determined to be a false indications because the indications did not behave as a flaw. As a result, the indications were classified as INRs (Indication Not Recordable).
Although these are indications that have been called flaws in previous inspections, due to changes in flaw definition, flaw calling criteria, or an improvements in analyst techniques, they are now deemed to not be a flaw, just an observable indication.
Review of the current data suggests that these are most likely deposits at the Tube Support Interfaces, creating false flaw responses.
The current data on these indications was reviewed by two Resolution Analysts (Eddy Current Level Ills), an Independent Resolution Analyst (Eddy Current Level III), as well as the PGN Eddy Current Level III.