CPSES-200402318, (CPSES) Units 1 and 2, Response to NRC Generic Letter 2004-01; Requirements for Steam Generator Tube Inspections
| ML042940371 | |
| Person / Time | |
|---|---|
| Site: | Comanche Peak  |
| Issue date: | 10/14/2004 |
| From: | Madden F TXU Generation Co, LP, TXU Power |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| CPSES-200402318, GL-04-001, TXX-04182 | |
| Download: ML042940371 (8) | |
Text
.l
- h TXU 4"'
Power TXU Power Comanche Peak Steam Electric Station P. O. Box 1002 (EO1)
Glen Rose, TX 76043 Tel: 254 897 5209 Fax: 254 897 6652 mike.blevins~txu.com Mike Blevins Senior Vice President &
Chief Nuclear Officer Ref: GL 2004-01 CPSES-200402318 Log#
TXX-04182 October 14, 2004 U. S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555
SUBJECT:
COMANCHE PEAK STEAM ELECTRIC STATION (CPSES)
UNITS 1 AND 2 - DOCKET NOS. 50-445 AND 50-446 RESPONSE TO NRC GENERIC LETTER 2004-01; "REQUIREMENTS FOR STEAM GENERATOR TUBE INSPECTIONS" Gentlemen:
By means of the Attachment to this letter, TXU Generation Company LP (TXU Power) submits its response to the Nuclear Regulatory Commission's request for information pursuant to Generic Letter 2004-01; "Requirements For Steam Generator Tube Inspections."
Should you have any questions, please contact Mr. Bob Kidwell at (254) 897-5310.
This communication contains no new or revised licensing basis commitments.
A' I /
A member of the STARS (Strategic Teaming and Resource Sharing) Alliance Callaway
- Comanche Peak
- Diablo Canyon
- Palo Verde
- South Texas Project
- Wolf Creek
TXX-041 82 Page 2 of 2 Sincerely, TXU Generation Company LP By:
TXU Generation Management Company LLC Its General Partner Mike Blevins By. A 2Z i/ ;7 Fred W. Madden Director, Regulatory Affairs RJK Attachment c -
B. S. Mallett, Region IV W. D. Johnson, Region IV M. C. Thadani, NRR Resident Inspectors, CPSES
Attachment to TXX-04182 Response to NRC Generic Letter 2004-01 "Requirements for Steam Generator Tube Inspections"
Attachment to TXX-04182 Page 2 of 6 In accordance with the instructions provided within the Generic Letter, within 60 days of the date of this generic letter, addressees are requested to provide the following information to the NRC.
- 1. Addressees should provide a description of the SG tube inspections performed at their plant during the last inspection. In addition, if they are not using SG tube inspection methods whose capabilities are consistent with the NRC 's position, addressees should provide an assessment of how the tube inspections performed at their plant meet the inspection requirements of the TS in conjunction with Criteria IXandXI of I OCFR Part 50, Appendix B, and corrective action taken in accordance with Appendix B, Criterion XVI. This assessment should also address whether tie tube inspection practices are capable of detectingflaws of any type that may potentially be present along the length of the tube required to be inspected and that may exceed the applicable tube repair criteria.
CPSES Response to Question 1:
Steam Generator tube Inservice Inspection (ISI) performed at CPSES is consistent with the NRC's position regarding tube inspections. TXU Power uses tube inspection methods that are capable of detecting flaw types that may be present. Prior to each inspection a degradation assessment, which includes operating experience, is performed to identify degradation mechanisms that may be present, and a technique validation assessment is performed to verify that the eddy current techniques are capable of detecting those flaw types identified in the degradation assessment.
CPSES Unit 1 has four (4) Westinghouse Model D4 steam generators. The tubing material in each of the steam generators is Inconel Alloy 600. To reduce the residual tensile stresses in the Model D4 tubing, Row I and Row 2 U-bends have been stress relieved using an in situ thermal process, and the hot and cold legs of all active tubes have been shotpeened within the tubesheet region.
CPSES Unit 2 has four (4) Westinghouse Model D5 steam generators. The tubing material in each of the steam generators is Inconel Alloy 600, thermally treated in the factory to reduce the residual tensile stresses.
Attachment to TXX-04182 Page 3 of 6 CPSES Response to Question 1 (cont.):
During the last scheduled SG ISI on each unit, TXU Power performed the following:
- CPSES Unit 1. April 2004 The lRFI0 inspection scope exceeded both the Technical Specification minimum requirements as well as the recommendations of EPRI TR-1003138, "PWR Steam Generator Examination Guidelines," Revision 6. The inspection scope was developed to specifically address the areas identified by the degradation assessment (including expansion criteria), those areas expected to be affected based on industry experience, and site specific lessons learned from previous outages. The IRF10 ISI for all four Unit 1 SGs included:
- 1.
100% full length bobbin inspection (except U-Bend region in Rows 1 and 2)
- 2.
100% Hot Leg 'TS +Point inspection from 3 inches above to 3 inches belowl for hard rolled expanded tubes and from 3 inches above to Hot Leg tube end for WEXTEX expanded tubes
- 3.
20% Cold Leg ITS +Point ins ection from 3 inches above to 3 inches below2 for hard rolled expanded tubes
- 4.
100% Row I through 21 U-Bend +Point inspection4
- 5.
20% Row 22 U-Bend +Point inspection
- 6.
25% +Point inspection of tubes expanded at Cold Leg baffles B (C2) and D (C3)
- 7.
+Point inspection of dents, regardless of voltage, at AVB locations
- 8.
Rotating probe inspection of mixed residuals > 1.5 volts (by bobbin) and Hot Leg dented intersections > 5 volts (by bobbin) according to the requirements of GL 95-05 1Conservatively bounds the F* criterion of 1.47 inches (includes NDE measurement uncertainty).
2 Conservatively bounds the F* criterion of 1.47 inches (includes NDE measurement uncertainty).
3 Cold Leg TI'S inspection was expanded an additional 20% in SG 1 based on the observation of a volumetric signal. No additional degradation was reported.
4 Includes expansion to Rows 11 -21 due to indications of oblique PWSCC in Row 10 in SGs I and 2.
Although indications were observed in Row 13, no further expansion was required as this row was bounded by the critical area redefinition.
Attachment to TXX-04182 Page 4 of 6
- CPSES Unit 1 April 2004 (cont.)
- 9.
Rotating probe inspection of preheater baffle plate indications and freespan bobbin coil indications for flaw confirmation and characterization
- 10.
100% +Point inspection of all dented intersections at the H3 TSP > 2 volts
- 11.
20% +Point inspection of freespan dings > 2 volts and < 5 volts between TSH and H3 TSP
- 12.
100% +Point inspection of freespan dings > 5 volts
- 13.
20% +Point freespan paired ding inspection between the top two TSPs (Hot Leg and Cold Leg)
- 14.
+Point inspection of tubes selected for installation of Alloy 800 sleeves in the region of the roll joint (TTS +3.0 inches to -10.0 inches)
- 15.
Inspection of tubes deplugged during lRF 0 consistent with the above plan
- 16.
100% +Point inspection of sleeves installed in SGs 2, 3 and 4 during IRF09 (weld to expansion in tubesheet)5
- 17.
Baseline +Point inspection of all Alloy 800 sleeves installed during IRFIO
- 18.
Special Interest +Point inspections for possible bobbin flaw indications
- 19.
100% tube plug visual inspection
- 20.
Secondary side video inspection including a limited scope TFS in-bundle inspection and FOSAR at TTS and cold leg baffle plate B 5 Excludes 60 sleeves that were found partially collapsed. All tubes with partially collapsed sleeves were plugged.
Attachment to TXX-04 182 Page 5 of 6
- CPSES Unit 2, October 2003 The 2RF07 inspection scope exceeded both the Technical Specification minimum requirements as well as the recommendations of EPRI 1003138, "PWR Steam Generator Examination Guidelines," Revision 6. The inspection scope was developed to specifically address the areas identified by the degradation assessment (including expansion criteria), those areas expected to be affected based on industry experience and site specific lessons learned from previous outages. Additionally, tubes in SGs 1 and 4, which were identified as possibly having elevated residual stress (NRC IN 2002-21 Supplement 1), were included in the full length bobbin program (items I and 2 below) and ITS +Point program (items 4 or 5 below). The 2RF07 ISI for Unit 2 SGs 1 and 4, unless otherwise noted, included:
- 1.
75% full length bobbin inspection in SG I (except U-Bend regions of Rows I and 2)6
- 2.
55% full length bobbin inspection in SG 4 (except U-Bend regions of Rows 1 and 2)
- 3.
50% Row I and 2 U-Bend +Point inspection
- 4.
44% Hot Leg TITS +Point inspection from 3 inches above to 9 inches below 7
- 5.
6% Hot Leg TI'S +Point inspection from 3 inches above to Hot Leg tube end8
- 6.
50% +Point inspection of the expanded baffle plate intersections
- 7.
100% +Point inspection of all dented TSP intersections > 5 volts at the H3 TSP
- 8.
50% +Point inspection of > 5 volt dings in the Hot Legs
- 9.
Special Interest +Point inspections for possible bobbin flaw indications
- 10.
100% tube plug visual inspection
- 11.
Secondary side video inspection including a limited scope TIS in-bundle inspection and FOSAR at TTS and cold leg baffle plate B in all four SGs 6 Includes 20% expansion due to a repairable indication in tube R47C56.
7 The inspection extent of -9 inches conservatively bounds the limiting distance for partial length RPC inspection of the tubesheet for the Unit 2 Model 5 Steam Generators (referred to as the H* distance).
A License Amendment Request for implementation of He criterion is still under development.
8 Represents the Technical Specification required inspection scope (i.e., 12% / 2 SG = 6%).
Attachment to TXX-04182 Page 6 of 6
- 2. If addressees conclude that full compliance with the TS in conjunction with Criteria IX, Xl and XVI of 10 CFR Part 50, Appendix B, requires corrective action, they should discuss their proposed corrective actions (e.g., changing inspection practices consistent with the NRC's position or submitting a TS amendment request with the associated safety basis for limiting the inspections) to achieve full compliance. If addressees choose to change their TS, the staff has included in the Attachment suggested changes to the TS definitionsfor a tube inspection andfor plugging limits to show what may be acceptable to the staff in cases where the tubes are expandedfor thefull depth of the tube sheet and where the extent of the inspection in the tube sheet region is limited CPSES Response to Question 2:
Steam Generator tube inspections performed at CPSES are consistent with the NRC's position regarding tube inspections. Therefore this question does not apply.
- 3. For plants where SG tube inspections have not been or are not being performed consistent with the NRC's position on the requirements in the TS in conjunction with Criteria IX, XI, and XVI of IO CFR Part 50, Appendix B, the licensee should submit a safety assessment (i.e., ajustificationfor continued operation based on maintaining tube structural and leakage integrity) that addresses any differences between the licensee's inspection practices and those calledfor by the NRC's position. Safety assessments should be submittedfor all areas of the tube required to be inspected by the TS, where flaws are not being used, and should include the basis for not employing such inspection techniques. The assessment should include an evaluation of (J) whether the inspection practices rely on an acceptance standard (e.g., cracks located at least a minimum distance of x below the top of tube sheet, even if these cracks cause complete severance of the tube) which is differentfrom the TS acceptance standards (i.e., the tube plugging limits or repair criteria), and (2) whether the safety assessment constitutes a change to the "method of evaluation " (as defined in lOCRF5O.59) for establishing the structural and leakage integrity of the joint. If the safety assessment constitutes a change to the method of evaluation under 10 CFR 50.59, the licensee should determine whether a license amendment is necessary pursuant to that regulation.
CPSES Response to Question 3:
Steam Generator tube inspections performed at CPSES are consistent with the NRC's position regarding tube inspections. Therefore this question does not apply.