NOC-AE-07002143, 1RE13 Inservice Inspection Summary Report for Steam Generator Tubing
| ML071140087 | |
| Person / Time | |
|---|---|
| Site: | South Texas  |
| Issue date: | 04/16/2007 |
| From: | Jenewein B South Texas |
| To: | Document Control Desk, NRC/NRR/ADRO |
| References | |
| G25, NOC-AE-07002143 | |
| Download: ML071140087 (34) | |
Text
4 Nuclear Operating Company South Tews Pro/ed Electric GeneradnSStation PO Box 289 Wadsworth. Texas 77483 _
April 16, 2007 NOC-AE-07002143 File No.: G25 10CFR50.55a U. S. Nuclear Regulatory Commission Attention: Document Control Desk One White Flint North 11555 Rockville Pike Rockville, MD 20852-2738 South Texas Project Unit 1 Docket No. STN 50-498 1 RE1 3 Inservice Inspection Summary Report for Steam Generator Tubinq Four copies of the summary report describing the results of the steam generator tube inservice inspection performed during refueling outage 1RE13 are enclosed. The summary report satisfies the reporting requirements of ASME Section XI, Article IWA-6230, and Section 6.9.1.7 of the South Texas Project Technical Specifications.
There are no commitments in this letter.
If there are any questions regarding this report, please contact either Mr. P. L. Walker at (361) 972-8392 or me at (361) 972-7431.
Pon Jenewein ager, ting/Programs PLW
Enclosure:
1 RE13 Inservice Inspection Summary Report for Steam Generator Tubing of the South Texas Project Electric Generating Station Unit 1 STI: 32142228 A0j4"7
NOC-AE-07002143 Page 2 of 2 cc:
(paper copy) (electronic copy)
Regional Administrator, Region IV A. H. Gutterman, Esquire U. S. Nuclear Regulatory Commission Morgan, Lewis & Bockius LLP 611 Ryan Plaza Drive, Suite 400 Arlington, Texas 76011-8064 Mohan C. Thadani U. S. Nuclear Regulatory Commission Richard A. Ratliff Steve Winn Bureau of Radiation Control Christine Jacobs Texas Department of State Health Services Eddy Daniels 1100 West 49th Street Marty Ryan Austin, TX 78756-3189 NRG South Texas LP Senior Resident Inspector J. J. Nesrsta U. S. Nuclear Regulatory Commission R. K. Temple P.O. Box 289, Mail Code: MN116 Kevin Polio Wadsworth, TX 77483 City Public Service C. M. Canady Jon C. Wood City of Austin Cox Smith Matthews Electric Utility Department 721 Barton Springs Road C. Kirksey Austin, TX 78704 City of Austin
Attachment NOC-AE-07002141 Page 1 of 7 1RE13 INSPECTION
SUMMARY
REPORT FOR STEAM GENERATOR TUBING of the SOUTH TEXAS PROJECT ELECTRIC GENERATING STATION UNIT 1 USNRC DOCKET NO.: 50-498 OPERATING LICENSE NO.: NPF-76 COMMERCIAL OPERATION DATE: August 25, 1988 Prepared By:
D. A. Stuhler Date Test Engineer Approved By: -7 C. . You ier Date Supervisor, Test Engineering
Attachment NOC-AE-07002143 Page 2 of 8 SOUTH TEXAS PROJECT UNIT 1 1RE13 INSPECTION
SUMMARY
REPORT FOR STEAM GENERATOR TUBING Introduction This summary report describes the inspection of steam generator tubing at South Texas Project (STP) Unit 1 performed during refueling outage 1 RE1 3 in October 2006.
Steam generator eddy current inspection, sludge lancing, and Foreign Object Search and Retrieval (FOSAR) were conducted in steam generators 1 A, 1 B, 1C, and 1 D.
Because of wire remnants and wall thinning found during 1RE12, a more aggressive inspection scope was developed for steam generator 1D. The wire remnants originated from a feedwater heater cable stabilizer and migrated into the steam generator during cycle 11.
This report provides the information required by STP Technical Specification 6.8.3.o for maintaining steam generator tube integrity and the reporting requirements of Technical Specification 6.9.1.7.
Scope of Examinations The inservice inspection program, "2006 Outage Plan for the In-service Inspection of Steam Generator Tubing at the South Texas Project Electric Generating Station, Unit 1,"
(ISI Outage Plan) identified the steam generator tube areas to be examined by eddy current (EC) testing and the procedures expected to be used during the inservice inspection. A Degradation Assessment written prior to the outage established the scope of eddy current inspections.
EPRI guidelines require that all steam generators undergo a 50% general purpose EC bobbin inspection during the outage nearest the midpoint of the operative sequential period. Similarly, 20% examinations (+Point) of regions potentially susceptible to stress corrosion cracking should also be performed during the outage nearest the midpoint of the sequential operating period. For STP Unit 1, the operative sequential period is 144 EFPM beginning with refueling outage 1RE10, the first inservice inspection for the current steam generators. A more extensive eddy current and visual inspection of steam generator 1 D was developed to support the planned cycle 3 inspection interval for the Unit 1 steam generators. This additional effort focused on potential wear at the top of the tubesheet and the flow distribution baffle related to the inventory of stabilizer wire remnants remaining in steam generator 1D. The 1RE13 inspection scope is outlined below:
Steam Generators 1A, 1 B, and 1C
- Inspect three peripheral rows with 100% bobbin coil full length.
- Full length bobbin coil inspection of 50% of remaining tubes, other than three peripheral rows.,
+Point inspection of three peripheral rows from 3 inches into tube sheet to 6 inches above top of tube sheet to aid in loose parts detection.
+Point inspection of 20% of hot leg tubes, from full 16 inches into tube sheet to 6 inches above top of tube sheet.
+Point inspection of all previously identified dents and dings > 5 volts.
Attachment NOC-AE-07002143 Page 3 of 8
- +Point inspection of 20% of first two rows of U-bend looking for outer diameter stress corrosion cracking (ODSCC).
" +Point inspection of all tube bulges in tubesheet as identified in pre-service inspection.
" +Point inspection of all known unretrieved possible loose parts as identified by previous eddy current inspections, if possible.
- +Point inspection of all unretrieved visually observed loose parts as identified by previous secondary side inspections.
- +Point as required to bound potential loose parts identified by eddy current or loose parts identified by secondary side visual inspections with two clean surrounding tubes.
- Standard secondary side video probe inspection including visual inspection of loose parts previously left in place and possible loose parts as identified by eddy current during 1 RE1 3 and previous outages, if possible.
" Sludge lancing.
- Upper steam drum inspection (SG 1C only).
- Feedring inspection (SG 1C only).
- Inspection of the ninth tube support plate (SG 1A only).
- Tube scale profiling (SG 1C only).
- Inspection of all installed plugs.
Steam Generator 1 D
- 100% bobbin coil full length inspection.
- Conduct 100% top of tube sheet +Point, full depth tube sheet -3 inches to +6 inches.
- Conduct 20% of hot leg +Point inspection of tubesheet (hot leg only) from -16 inches to +6 inches at top of tube sheet.
- +Point inspection of all previously identified dents and dings > 5 volts.
- +Point inspection of 20% of first two rows of U-bend looking for ODSCC.
- +Point inspection of all tube bulges and over expansions in tubesheet as identified in pre-service inspection.
- +Point inspection of all tubes surrounding known unretrieved possible loose parts as identified by previous eddy current inspections.
- +Point inspection of all tubes surrounding unretrieved visually observed loose parts as identified by previous secondary side inspections.
- +Point inspection of all tube wear left in service during previous outages.
- +Point as required to bound potential loose parts identified by bobbin inspection or loose parts identified by as-left secondary side visual inspections with two clean surrounding tubes.
Attachment NOC-AE-07002143 Page 4 of 8
- Enhanced secondary side video probe inspection by inserting the video probe down every row to inspect for loose parts and associated wear.
- 100% hot leg and 20% cold leg +Point inspection of flow distribution baffle (FDB) from -3 inches to + 6 inches.
Summary of Examinations All steam generators were sludge lanced and the top of the tubesheet visually inspected for foreign objects. A small number of small foreign objects were observed at the top of the tubesheet in the steam generator 1A, 1B, and 1C tube bundles; fragments of flexitallic gaskets, machining remnants, wire bristles, weld slag, pieces of tube scale, and sludge rocks account for most of the material observed. Four pieces of stabilizer wire were found in SG 1C. Except for benign objects, such as sludge rocks and fiber bristles, all identified foreign objects were removed. No degradation was identified in any of these steam generators based on the 1 RE1 3 inspection results. Due to the known inventory of stabilizer wire in SG 1 D, visual inspection of the top of the tubesheet included 100% foreign object mapping of both the hot leg and cold leg, with attempted retrieval of all identified items from the top of the tubesheet. Visual inspection of the flow distribution baffle was also performed to identify the source of eddy current potential loose part (PLP) signals.
The following table is a summary of eddy current inspections performed during 1 RE1 3:
Attachment NOC-AE-07002143 Page 5 of 8 STEAM GENERATOR EC INSPECTIONS PERFORMED DURING 1RE13 SG Program Tubes Inspected Hot Leg Cold Leg 1A Bobbin Straight Leg 4330 384
+Point Top of Tubesheet 2064 662 Low Row U-bend bobbin 155 -
+Point Row 1 and Row 2 U-bends 31
+Point FDB (-3 inches to + 6 inches) - -
Special Interest 13 14
+Point of Prior Dents and Dings > 5 volts 28 51 PLPs Inspected 88 -
PLP Calls 0 0 1B Bobbin Straight Leg 4328 384
+Point Top of Tubesheet 2048 659 Low Row U-bend bobbin 154 -
+Point Row 1 and Row 2 U-bends 31
+Point FDB (-3 inches to + 6 inches) - -
Special Interest 10 10
+Point of Prior Dents and Dings > 5 volts 1 -
PLPs Inspected 38 16 PLP Calls 3 3 1C Bobbin Straight Leg 4328 384
+Point Top of Tubesheet 2046 662 Low Row U-bend bobbin 155 -
+Point Row 1 and Row 2 U-bends 31
+Point FDB (-3 inches to + 6 inches) - -
Special Interest 2 1
+Point of Prior Dents and Dings > 5 volts 6 PLPs Inspected 58 14 PLP Calls 6 0 1D Bobbin Straight Leg 7575 386
+Point Top of Tubesheet 7575 7575 Low Row U-bend bobbin 155 -
+Point Row 1 and Row 2 U-bends 31 -
+Point FDB (-3 inches to + 6 inches) 5424 1468 Special Interest 17 6
+Point of Prior Dents and Dings > 5 volts - -
PLPs Inspected 6830 1468 PLP Calls 348 134
Attachment NOC-AE-07002143 Page 6 of 8 Examination Results and Corrective Measures There were no axial or circumferential crack-like indications, corrosion mechanisms, or mechanical wear observed at the anti-vibration bar intersections in any of the steam generators.
A total of ten volumetric indications (one in SG 1 B, and nine in SG 1 D) were detected during the MRPC inspection for resolution of I-codes. Three of the indications were known prior to 1 RE13 and no change was noted during the current inspection. Of these three indications, one location at 09C (R10 C50) in SG 1B was a pre-service call and did not change, and two locations at TSH (R84 C22 and R84 C24) were identified during 1RE12 as stabilizer wire wear and did not change. Seven additional volumetric indications were identified during 1 RE1 3. Five were associated with stabilizer wire wear at the top of the tubesheet, while two were associated with PLP calls at the flow distribution baffle. Four tubes in the SG 1 D cold leg were identified with wear at the top of the tubesheet: one tube (R117 C49) required plugging due to a wear depth of 44%;
and the remaining three tubes (R2 C138, R99 C35, and R1 16 C48) had wear depths of
< 20% and remain in service. One location (R2 C138) was found with two wear scars less than two inches apart. These wear scars measured 8% and 9% respectively. The observed wear was related to the known inventory of stabilizer wire.
In addition to the top of tubesheet indications, two tubes were identified with volumetric indications at the hot leg flow distribution baffle to tube intersections. The through-wall depth of the volumetric indications was 23% and 25%. Since it was not possible to clearly determine the source of the volumetric signals, these locations (R28 C8 and R71 C27) were plugged. None of the top of tubesheet or flow distribution baffle indications challenged the tube integrity limits, and no tube leakage was observed during Cycle 13 operation; therefore, the Condition Monitoring requirements were satisfied.
Due to the number of PLPs being called during the FDB inspection and the potential for additional wear sites, the +Point inspection scope was increased to 100% of the hot leg and 20% of the cold leg intersections. Additional PLP indications were identified, but there were no additional volumetric indications. During the in-bundle top of tubesheet inspection of SG 1D, a total of 227 foreign objects were identified following sludge lancing. The majority of the foreign objects were characterized as fine wire associated with the feedwater heater stabilizer released during Cycle 11. Of the foreign objects identified during top of the tubesheet mapping, five known stabilizer wires were left in place. For those loose parts/foreign objects not removed, wear assessments were performed to support the assessment of SG 1 D for operation until 1 RE1 4.
Indications The following table lists the number of indications which includes all data, including the supplementary inspection program of the Flow Distribution Baffle.
Attachment NOC-AE-07002143 Page 7 of 8
SUMMARY
OF EDDY CURRENT INDICATIONS SOUTH TEXAS UNIT 1 1 RE13 INDICATION COUNT- FINAL DATA INDICATION CONDITION S/G 1A S/G 1B S/G 1C S/G 1D ADS Absolute Drift Signal 0 0 0 1 DNG Freespan Ding 543 17 262 145 DNI Distorted DNG/DNT Indication 0 0 0 0 DNS Distorted Dent Indication - Cleared 44 14 29 69 DNT Dent 0 1 0 0 DSS DSI History Cleared 0 0 0 1 DTI Distorted Tubesheet Indication 0 0 0 0 DTS Distorted TS Indication - Cleared 0 0 0 3 INF Indication Not Found 0 0 7 127 INR Indication Not Reportable 30 13 27 107 MBI Possible Indication at MBM 0 0 0 0 MBM Manufacturing Buff Marks 140 118 144 296 MBS Manufacturing Burnish Signal 0 1 0 2 NDD No Detectable Degradation 7336 7467 7399 30529 NDF No Degradation Found 10 13 2 17 NQI Potential Bobbin Flaw Signal 0 1 0 0 NQS Not Cleared by +Point 56 31 40 72 PLP Possible Loose Part 0 6 6 482 PVN Permeability Variation 0 0 0 4 RBD Retest - Bad Data 78 32 55 53 RIC Retest - Incomplete 26 4 9 112 RND Retest- No Data 0 0 0 1 RRT Retest - Restricted Tube 0 1 0 0 SVI Single Volumetric Indication 0 1 0 9 VOL Volumetric Indication 0 1 0 9 No flaw was found during the 1RE13 inservice inspection that met the requirement for "Active" degradation.
The only degradation identified during the 1 RE1 3 inspections was loose parts wear in SG 1 D. Wear indications at the top of the tubesheet were sized using a qualified eddy
Attachment NOC-AE-07002143 Page 8 of 8 current technique. The technique is reported to result in a conservative measurement for large volume flaws.
Tube Plugging As a result of the 1RE13 inspection efforts, three tubes in SG 1D were removed from service by plugging. The locations plugged were R28C8, R71 C27, and R117C49. No stabilization was required. No plugging was needed for active degradation mechanisms.
No tubes exceeded the structural integrity requirements. No primary-to-secondary leakage was observed during Cycle 13 operation and none is predicted during the next three cycles of operation for SG 1A, 1 B, and 1C, and one cycle of operation for SG 1 D.
Inservice inspection results confirm that the Unit 1 steam generators meet all industry and regulatory structural and leakage integrity guidance.
The total number of tubes plugged per steam generator to date is as follows:
Steam Generator 1A 33 0.44%
Steam Generator 1 B 40 0.53%
Steam Generator 1C 26 0.34%
Steam Generator 1D 13 0.17%
Condition Monitoring Results None of the observed indications exceeded the screening thresholds for in situ testing.
No tubes were pulled or subjected to in-situ pressure testing.
Based on the inspections performed, engineering analysis of the inspection results obtained during 1RE13, and that no corrosion-induced flaws were detected, tube degradation large enough to challenge structural integrity requirements is not expected during the planned operating intervals for the Unit 1 steam generators. Therefore, based on the 1 RE13 inspection results, the operating interval between inspections for SG 1A, 1 B, and 1C is three cycles. Based on the extensive eddy current and top of tubesheet in-bundle visual inspection efforts performed during 1 RE1 3, the operational assessment supports the expectation that tube integrity in SG 1 D will be satisfactorily maintained during the Cycle 14 operating interval.
Attachment NOC-AE-07002141 Page 1 of 7 IRE13 INSPECTION
SUMMARY
REPORT FOR STEAM GENERATOR TUBING of the SOUTH TEXAS PROJECT ELECTRIC GENERATING STATION UNIT 1 USNRC DOCKET NO.: 50-498 OPERATING LICENSE NO.: NPF-76 COMMERCIAL OPERATION DATE: August 25, 1988
,ý/*// /2e*.,7 '7 Prepared By: /
D. A. Stuhler Date Test Engineer Approved By: -7 C. i Youn#r Date Supervisor, Test Engineering
Attachment NOC-AE-07002143 Page 2 of 8 SOUTH TEXAS PROJECT UNIT 1 1RE13 INSPECTION
SUMMARY
REPORT FOR STEAM GENERATOR TUBING Introduction This summary report describes the inspection of steam generator tubing at South Texas Project (STP) Unit 1 performed during refueling outage 1 RE1 3 in October 2006.
Steam generator eddy current inspection, sludge lancing, and Foreign Object Search and Retrieval (FOSAR) were conducted in steam generators 1A, 1 B, 1C, and 1 D.
Because of wire remnants and wall thinning found during 1RE12, a more aggressive inspection scope was developed for steam generator 1D. The wire remnants originated from a feedwater heater cable stabilizer and migrated into the steam generator during cycle 11.
This report provides the information required by STP Technical Specification 6.8.3.0 for maintaining steam generator tube integrity and the reporting requirements of Technical Specification 6.9.1.7.
Scope of Examinations The inservice inspection program, "2006 Outage Plan for the In-service Inspection of Steam Generator Tubing at the South Texas Project Electric Generating Station, Unit 1,"
(ISI Outage Plan) identified the steam generator tube areas to be examined by eddy current (EC) testing and the procedures expected to be used during the inservice inspection. A Degradation Assessment written prior to the outage established the scope of eddy current inspections.
EPRI guidelines require that all steam generators undergo a 50% general purpose EC bobbin inspection during the outage nearest the midpoint of the operative sequential period. Similarly, 20% examinations (+Point) of regions potentially susceptible to stress corrosion cracking should also be performed during the outage nearest the midpoint of the sequential operating period. For STP Unit 1, the operative sequential period is 144 EFPM beginning with refueling outage 1RE10, the first inservice inspection for the current steam generators. A more extensive eddy current and visual inspection of steam generator 1D was developed to support the planned cycle 3 inspection interval for the Unit 1 steam generators. This additional effort focused on potential wear at the top of the tubesheet and the flow distribution baffle related to the inventory of stabilizer wire remnants remaining in steam generator 1D. The 1RE13 inspection scope is outlined below:
Steam Generators 1A, 1 B, and 1C
" Inspect three peripheral rows with 100% bobbin coil full length.
" Full length bobbin coil inspection of 50% of remaining tubes, other than three peripheral rows.
" +Point inspection of three peripheral rows from 3 inches into tube sheet to 6 inches above top of tube sheet to aid in loose parts detection.
" +Point inspection of 20% of hot leg tubes, from full 16 inches into tube sheet to 6 inches above top of tube sheet.
- +Point inspection of all previously identified dents and dings > 5 volts.
Attachment NOC-AE-07002143 Page 3 of 8
" +Point inspection of 20% of first two rows of U-bend looking for outer diameter stress corrosion cracking (ODSCC).
- +Point inspection of all tube bulges in tubesheet as identified in pre-service inspection.
- +Point inspection of all known unretrieved possible loose parts as identified by previous eddy current inspections, if possible.
- +Point inspection of all unretrieved visually observed loose parts as identified by previous secondary side inspections.
" +Point as required to bound potential loose parts identified by eddy current or loose parts identified by secondary side visual inspections with two clean surrounding tubes.
- Standard secondary side video probe inspection including visual inspection of loose parts previously left in place and possible loose parts as identified by eddy current during 1 RE1 3 and previous outages, if possible.
- Sludge lancing.
- Upper steam drum inspection (SG 1C only).
- Feedring inspection (SG 1C only).
- Inspection of the ninth tube support plate (SG 1A only).
- Tube scale profiling (SG 1C only).
- Inspection of all installed plugs.
Steam Generator 1 D
- 100% bobbin coil full length inspection.
- Conduct 100% top of tube sheet +Point, full depth tube sheet -3 inches to +6 inches.
0 Conduct 20% of hot leg +Point inspection of tubesheet (hot leg only) from -16 inches to +6 inches at top of tube sheet.
0 +Point inspection of all previously identified dents and dings > 5 volts.
- +Point inspection of 20% of first two rows of U-bend looking for ODSCC.
- +Point inspection of all tube bulges and over expansions in tubesheet as identified in pre-service inspection.
- +Point inspection of all tubes surrounding known unretrieved possible loose parts as identified by previous eddy current inspections.
- +Point inspection of all tubes surrounding unretrieved visually observed loose parts as identified by previous secondary side inspections.
- +Point inspection of all tube wear left in service during previous outages.
- +Point as required to bound potential loose parts identified by bobbin inspection or loose parts identified by as-left secondary side visual inspections with two clean surrounding tubes.
Attachment NOC-AE-07002143 Page 4 of 8
- Enhanced secondary side video probe inspection by inserting the video probe down every row to inspect for loose parts and associated wear.
- 100% hot leg and 20% cold leg +Point inspection of flow distribution baffle (FDB) from -3 inches to + 6 inches.
Summary of Examinations All steam generators were sludge lanced and the top of the tubesheet visually inspected for foreign objects. A small number of small foreign objects were observed at the top of the tubesheet in the steam generator 1A, 1B, and 1C tube bundles; fragments of flexitallic gaskets, machining remnants, wire bristles, weld slag, pieces of tube scale, and sludge rocks account for most of the material observed. Four pieces of stabilizer wire were found in SG 1 C. Except for benign objects, such as sludge rocks and fiber bristles, all identified foreign objects were removed. No degradation was identified in any of these steam generators based on the 1RE13 inspection results. Due to the known inventory of stabilizer wire in SG 1 D, visual inspection of the top of the tubesheet included 100% foreign object mapping of both the hot leg and cold leg, with attempted retrieval of all identified items from the top of the tubesheet. Visual inspection of the flow distribution baffle was also performed to identify the source of eddy current potential loose part (PLP) signals.
The following table is a summary of eddy current inspections performed during 1 RE1 3:
Attachment NOC-AE-07002143 Page 5 of 8 STEAM GENERATOR EC INSPECTIONS PERFORMED DURING 1RE13 SG Program Tubes Inspected Hot Leg Cold Leg 1A Bobbin Straight Leg 4330 384
+Point Top of Tubesheet 2064 662 Low Row U-bend bobbin 155
+Point Row 1 and Row 2 U-bends 31
+Point FDB (-3 inches to + 6 inches)
Special Interest 13 14
+Point of Prior Dents and Dings > 5 volts 28 51 PLPs Inspected 88 PLP Calls 0 0 1B Bobbin Straight Leg 4328 384
+Point Top of Tubesheet 2048 659 Low Row U-bend bobbin 154
+Point Row 1 and Row 2 U-bends 31
+Point FDB (-3 inches to + 6 inches)
Special Interest 10 10
+Point of Prior Dents and Dings > 5 volts 1 PLPs Inspected 38 16 PLP Calls 3 3 1C Bobbin Straight Leg 4328 384
+Point Top of Tubesheet 2046 662 Low Row U-bend bobbin 155
+Point Row 1 and Row 2 U-bends 31
+Point FDB (-3 inches to + 6 inches)
Special Interest 2 1
+Point of Prior Dents and Dings > 5 volts 6 PLPs Inspected 58 14 PLP Calls 6 0 1D Bobbin Straight Leg 7575 386
+Point Top of Tubesheet 7575 7575 Low Row U-bend bobbin 155
+Point Row 1 and Row 2 U-bends 31
+Point FDB (-3 inches to + 6 inches) 5424 1468 Special Interest 17 6
+Point of Prior Dents and Dings > 5 volts PLPs Inspected 6830 1468 PLP Calls 348 134
Attachment NOC-AE-07002143 Page 6 of 8 Examination Results and Corrective Measures There were no axial or circumferential crack-like indications, corrosion mechanisms, or mechanical wear observed at the anti-vibration bar intersections in any of the steam generators.
A total of ten volumetric indications (one in SG 1 B, and nine in SG 1 D) were detected during the MRPC inspection for resolution of I-codes. Three of the indications were known prior to 1 RE1 3 and no change was noted during the current inspection. Of these three indications, one location at 09C (R10 C50) in SG 1 B was a pre-service call and did not change, and two locations at TSH (R84 C22 and R84 C24) were identified during 1RE12 as stabilizer wire wear and did not change. Seven additional volumetric indications were identified during 1RE13. Five were associated with stabilizer wire wear at the top of the tubesheet, while two were associated with PLP calls at the flow distribution baffle. Four tubes in the SG 1 D cold leg were identified with wear at the top of the tubesheet: one tube (Ri 17 C49) required plugging due to a wear depth of 44%;
and the remaining three tubes (R2 C138, R99 C35, and R1 16 C48) had wear depths of
< 20% and remain in service. One location (R2 C138) was found with two wear scars less than two inches apart. These wear scars measured 8% and 9% respectively. The observed wear was related to the known inventory of stabilizer wire.
In addition to the top of tubesheet indications, two tubes were identified with volumetric indications at the hot leg flow distribution baffle to tube intersections. The through-wall depth of the volumetric indications was 23% and 25%. Since it was not possible to clearly determine the source of the volumetric signals, these locations (R28 C8 and R71 C27) were plugged. None of the top of tubesheet or flow distribution baffle indications challenged the tube integrity limits, and no tube leakage was observed during Cycle 13 operation; therefore, the Condition Monitoring requirements were satisfied.
Due to the number of PLPs being called during the FDB inspection and the potential for additional wear sites, the +Point inspection scope was increased to 100% of the hot leg and 20% of the cold leg intersections. Additional PLP indications were identified, but there were no additional volumetric indications. During the in-bundle top of tubesheet inspection of SG 1D, a total of 227 foreign objects were identified following sludge lancing. The majority of the foreign objects were characterized as fine wire associated with the feedwater heater stabilizer released during Cycle 11. Of the foreign objects identified during top of the tubesheet mapping, five known stabilizer wires were left in place. For those loose parts/foreign objects not removed, wear assessments were performed to support the assessment of SG 1D for operation until 1 RE14.
Indications The following table lists the number of indications which includes all data, including the supplementary inspection program of the Flow Distribution Baffle.
Attachment NOC-AE-07002143 Page 7 of 8
SUMMARY
OF EDDY CURRENT INDICATIONS SOUTH TEXAS UNIT 1 1 RE1 3 INDICATION COUNT - FINAL DATA INDICATION CONDITION S/G1A S/G1B S/G1C S/G1D ADS Absolute Drift Signal 0 0 0 1 DNG Freespan Ding 543 17 262 145 DNI Distorted DNG/DNT Indication 0 0 0 0 DNS Distorted Dent Indication - Cleared 44 14 29 69 DNT Dent 0 1 0 0 DSS DSI History Cleared 0 0 0 1 DTI Distorted Tubesheet Indication 0 0 0 0 DTS Distorted TS Indication - Cleared 0 0 0 3 INF Indication Not Found 0 0 7 127 INR Indication Not Reportable 30 13 27 107 MBI Possible Indication at MBM 0 0 0 0 MBM Manufacturing Buff Marks 140 118 144 296 MBS Manufacturing Burnish Signal 0 1 0 2 NDD No Detectable Degradation 7336 7467 7399 30529 NDF No Degradation Found 10 13 2 17 NQI Potential Bobbin Flaw Signal 0 1 0 0 NQS Not Cleared by +Point 56 31 40 72 PLP Possible Loose Part 0 6 6 482 PVN Permeability Variation 0 0 0 4 RBD Retest - Bad Data 78 32 55 53 RIC Retest - Incomplete 26 4 9 112 RND Retest- No Data 0 0 0 1 RRT Retest - Restricted Tube 0 1 0 0 SVI Single Volumetric Indication 0 1 0 9 VOL Volumetric Indication 0 1 0 9 No flaw was found during the 1 RE13 inservice inspection that met the requirement for "Active" degradation.
The only degradation identified during the 1 RE13 inspections was loose parts wear in SG 1 D. Wear indications at the top of the tubesheet were sized using a qualified eddy
Attachment NOC-AE-07002143 Page 8 of 8 current technique. The technique is reported to result in a conservative measurement for large volume flaws.
Tube Plugging As a result of the 1RE13 inspection efforts, three tubes in SG 1D were removed from service by plugging. The locations plugged were R28C8, R71 C27, and R117C49. No stabilization was required. No plugging was needed for active degradation mechanisms.
No tubes exceeded the structural integrity requirements. No primary-to-secondary leakage was observed during Cycle 13 operation and none is predicted during the next three cycles of operation for SG 1A, 1B, and 1C, and one cycle of operation for SG 1D.
Inservice inspection results confirm that the Unit 1 steam generators meet all industry and regulatory structural and leakage integrity guidance.
The total number of tubes plugged per steam generator to date is as follows:
Steam Generator 1A 33 0.44%
Steam Generator 1 B 40 0.53%
Steam Generator 1C 26 0.34%
Steam Generator 1D 13 0.17%
Condition Monitoring Results None of the observed indications exceeded the screening thresholds for in situ testing.
No tubes were pulled or subjected to in-situ pressure testing.
Based on the inspections performed, engineering analysis of the inspection results obtained during 1RE13, and that no corrosion-induced flaws were detected, tube degradation large enough to challenge structural integrity requirements is not expected during the planned operating intervals for the Unit 1 steam generators. Therefore, based on the 1 RE1 3 inspection results, the operating interval between inspections for SG 1A, 1B, and 1C is three cycles. Based on the extensive eddy current and top of tubesheet in-bundle visual inspection efforts performed during 1 RE13, the operational assessment supports the expectation that tube integrity in SG 1 D will be satisfactorily maintained during the Cycle 14 operating interval.
Attachment NOC-AE-07002141 Page 1 of 7 IRE13 INSPECTION
SUMMARY
REPORT FOR STEAM GENERATOR TUBING of the SOUTH TEXAS PROJECT ELECTRIC GENERATING STATION UNIT 1 USNRC DOCKET NO.: 50-498 OPERATING LICENSE NO.: NPF-76 COMMERCIAL OPERATION DATE: August 25, 1988 Prepared By: cýlu.2ee)
D. A. Stuhler Date Test Engineer Approved By: A -7 C Youn er Date Supervisor, Test Engineering
Attachment NOC-AE-07002143 Page 2 of 8 SOUTH TEXAS PROJECT UNIT 1 1RE13 INSPECTION
SUMMARY
REPORT FOR STEAM GENERATOR TUBING Introduction This summary report describes the inspection of steam generator tubing at South Texas Project (STP) Unit 1 performed during refueling outage 1 RE13 in October 2006.
Steam generator eddy current inspection, sludge lancing, and Foreign Object Search and Retrieval (FOSAR) were conducted in steam generators 1A, 11B, 1C, and 1D.
Because of wire remnants and wall thinning found during 1RE12, a more aggressive inspection scope was developed for steam generator 1 D. The wire remnants originated from a feedwater heater cable stabilizer and migrated into the steam generator during cycle 11.
This report provides the information required by STP Technical Specification 6.8.3.0 for maintaining steam generator tube integrity and the reporting requirements of Technical Specification 6.9.1.7.
Scope of Examinations The inservice inspection program, "2006 Outage Plan for the In-service Inspection of Steam Generator Tubing at the South Texas Project Electric Generating Station, Unit 1,"
(ISI Outage Plan) identified the steam generator tube areas to be examined by eddy current (EC) testing and the procedures expected to be used during the inservice inspection. A Degradation Assessment written prior to the outage established the scope of eddy current inspections.
EPRI guidelines require that all steam generators undergo a 50% general purpose EC bobbin inspection during the outage nearest the midpoint of the operative sequential period. Similarly, 20% examinations (+Point) of regions potentially susceptible to stress corrosion cracking should also be performed during the outage nearest the midpoint of the sequential operating period. For STP Unit 1, the operative sequential period is 144 EFPM beginning with refueling outage 1RE10, the first inservice inspection for the current steam generators. A more extensive eddy current and visual inspection of steam generator 1 D was developed to support the planned cycle 3 inspection interval for the Unit 1 steam generators. This additional effort focused on potential wear at the top of the tubesheet and the flow distribution baffle related to the inventory of stabilizer wire remnants remaining in steam generator 1D. The 1RE13 inspection scope is outlined below:
Steam Generators 1A, 1 B, and 1C
- Inspect three peripheral rows with 100% bobbin coil full length.
- Full length bobbin coil inspection of 50% of remaining tubes, other than three peripheral rows.
+Point inspection of three peripheral rows from 3 inches into tube sheet to 6 inches above top of tube sheet to aid in loose parts detection.
+Point inspection of 20% of hot leg tubes, from full 16 inches into tube sheet to 6 inches above top of tube sheet.
+Point inspection of all previously identified dents and dings > 5 volts.
Attachment NOC-AE-07002143 Page 3 of 8
" +Point inspection of 20% of first two rows of U-bend looking for outer diameter stress corrosion cracking (ODSCC).
" +Point inspection of all tube bulges in tubesheet as identified in pre-service inspection.
" +Point inspection of all known unretrieved possible loose parts as identified by previous eddy current inspections, if possible.
- +Point inspection of all unretrieved visually observed loose parts as identified by previous secondary side inspections.
" +Point as required to bound potential loose parts identified by eddy current or loose parts identified by secondary side visual inspections with two clean surrounding tubes.
- Standard secondary side video probe inspection including visual inspection of loose parts previously left in place and possible loose parts as identified by eddy current during 1 RE1 3 and previous outages, if possible.
- Sludge lancing.
" Upper steam drum inspection (SG 1C only).
" Feedring inspection (SG 1C only).
" Inspection of the ninth tube support plate (SG 1A only).
" Tube scale profiling (SG 1C only).
" Inspection of all installed plugs.
Steam Generator 1 D
- 100% bobbin coil full length inspection.
0 Conduct 100% top of tube sheet +Point, full depth tube sheet -3 inches to +6 inches.
0 Conduct 20% of hot leg +Point inspection of tubesheet (hot leg only) from -16 inches to +6 inches at top of tube sheet.
- +Point inspection of all previously identified dents and dings > 5 volts.
- +Point inspection of 20% of first two rows of U-bend looking for ODSCC.
- +Point inspection of all tube bulges and over expansions in tubesheet as identified in pre-service inspection.
- +Point inspection of all tubes surrounding known unretrieved possible loose parts as identified by previous eddy current inspections.
- +Point inspection of all tubes surrounding unretrieved visually observed loose parts as identified by previous secondary side inspections.
0 +Point inspection of all tube wear left in service during previous outages.
0 +Point as required to bound potential loose parts identified by bobbin inspection or loose parts identified by as-left secondary side visual inspections with two clean surrounding tubes.
Attachment NOC-AE-07002143 Page 4 of 8 0 Enhanced secondary side video probe inspection by inserting the video probe down every row to inspect for loose parts and associated wear.
- 100% hot leg and 20% cold leg +Point inspection of flow distribution baffle (FDB) from -3 inches to + 6 inches.
Summary of Examinations All steam generators were sludge lanced and the top of the tubesheet visually inspected for foreign objects. A small number of small foreign objects were observed at the top of the tubesheet in the steam generator 1A, 1B, and 1C tube bundles; fragments of flexitallic gaskets, machining remnants, wire bristles, weld slag, pieces of tube scale, and sludge rocks account for most of the material observed. Four pieces of stabilizer wire were found in SG 1C. Except for benign objects, such as sludge rocks and fiber bristles, all identified foreign objects were removed. No degradation was identified in any of these steam generators based on the 1 RE1 3 inspection results. Due to the known inventory of stabilizer wire in SG 1D, visual inspection of the top of the tubesheet included 100% foreign object mapping of both the hot leg and cold leg, with attempted retrieval of all identified items from the top of the tubesheet. Visual inspection of the flow distribution baffle was also performed to identify the source of eddy current potential loose part (PLP) signals.
The following table is a summary of eddy current inspections performed during 1 RE1 3:
Attachment NOC-AE-07002143 Page 5 of 8 STEAM GENERATOR EC INSPECTIONS PERFORMED DURING 1RE13 Program Tubes Inspected SG Hot Leg Cold Leg 1A Bobbin Straight Leg 4330 384
+Point Top of Tubesheet 2064 662 Low Row U-bend bobbin 155 -
+Point Row 1 and Row 2 U-bends 31
+Point FDB (-3 inches to + 6 inches) - -
Special Interest 13 14
+Point of Prior Dents and Dings > 5 volts 28 51 PLPs Inspected 88 -
PLP Calls 0 0 1B Bobbin Straight Leg 4328 384
+Point Top of Tubesheet 2048 659 Low Row U-bend bobbin 154
+Point Row 1 and Row 2 U-bends 31
+Point FDB (-3 inches to + 6 inches) _ _
Special Interest 10 10
+Point of Prior Dents and Dings > 5 volts 1 PLPs Inspected 38 16 PLP Calls 3 3 1C Bobbin Straight Leg 4328 384
+Point Top of Tubesheet 2046 662 Low Row U-bend bobbin 155
+Point Row 1 and Row 2 U-bends 31
+Point FDB (-3 inches to + 6 inches) -
Special Interest 2 1
+Point of Prior Dents and Dings > 5 volts 6 PLPs Inspected 58 14 PLP Calls 6 0 1D Bobbin Straight Leg 7575 386
+Point Top of Tubesheet 7575 7575 Low Row U-bend bobbin 155
+Point Row 1 and Row 2 U-bends 31
+Point FDB (-3 inches to + 6 inches) 5424 1468 Special Interest 17 6
+Point of Prior Dents and Dings > 5 volts PLPs Inspected 6830 1468 PLP Calls 348 134
Attachment NOC-AE-07002143 Page 6 of 8 Examination Results and Corrective Measures There were no axial or circumferential crack-like indications, corrosion mechanisms, or mechanical wear observed at the anti-vibration bar intersections in any of the steam generators.
A total of ten volumetric indications (one in SG 1 B, and nine in SG 1 D) were detected during the MRPC inspection for resolution of I-codes. Three of the indications were known prior to 1 RE1 3 and no change was noted during the current inspection. Of these three indications, one location at 09C (R10 C50) in SG 1 B was a pre-service call and did not change, and two locations at TSH (R84 C22 and R84 C24) were identified during 1RE12 as stabilizer wire wear and did not change. Seven additional volumetric indications were identified during 1 RE13. Five were associated with stabilizer wire wear at the top of the tubesheet, while two were associated with PLP calls at the flow distribution baffle. Four tubes in the SG 1D cold leg were identified with wear at the top of the tubesheet: one tube (R117 C49) required plugging due to a wear depth of 44%;
and the remaining three tubes (R2 C138, R99 C35, and R1 16 C48) had wear depths of
< 20% and remain in service. One location (R2 C138) was found with two wear scars less than two inches apart. These wear scars measured 8% and 9% respectively. The observed wear was related to the known inventory of stabilizer wire.
In addition to the top of tubesheet indications, two tubes were identified with volumetric indications at the hot leg flow distribution baffle to tube intersections. The through-wall depth of the volumetric indications was 23% and 25%. Since it was not possible to clearly determine the source of the volumetric signals, these locations (R28 C8 and R71 C27) were plugged. None of the top of tubesheet or flow distribution baffle indications challenged the tube integrity limits, and no tube leakage was observed during Cycle 13 operation; therefore, the Condition Monitoring requirements were satisfied.
Due to the number of PLPs being called during the FDB inspection and the potential for additional wear sites, the +Point inspection scope was increased to 100% of the hot leg and 20% of the cold leg intersections. Additional PLP indications were identified, but there were no additional volumetric indications. During the in-bundle top of tubesheet inspection of SG 1D, a total of 227 foreign objects were identified following sludge lancing. The majority of the foreign objects were characterized as fine wire associated with the feedwater heater stabilizer released during Cycle 11. Of the foreign objects identified during top of the tubesheet mapping, five known stabilizer wires were left in place. For those loose parts/foreign objects not removed, wear assessments were performed to support the assessment of SG 1 D for operation until 1 RE1 4.
Indications The following table lists the number of indications which includes all data, including the supplementary inspection program of the Flow Distribution Baffle.
Attachment NOC-AE-07002143 Page 7 of 8
SUMMARY
OF EDDY CURRENT INDICATIONS SOUTH TEXAS UNIT 1 1 RE13 INDICATION COUNT - FINAL DATA INDICATION CONDITION S/GlA S/G1B S/G1C S/G 1D ADS Absolute Drift Signal 0 0 0 1 DNG Freespan Ding 543 17 262 145 DNI Distorted DNG/DNT Indication 0 0 0 0 DNS Distorted Dent Indication - Cleared 44 14 29 69 DNT Dent 0 1 0 0 DSS DSI History Cleared 0 0 0 1 DTI Distorted Tubesheet Indication 0 0 0 0 DTS Distorted TS Indication - Cleared 0 0 0 3 INF Indication Not Found 0 0 7 127 INR Indication Not Reportable 30 13 27 107 MBI Possible Indication at MBM 0 0 0 0 MBM Manufacturing Buff Marks 140 118 144 296 MBS Manufacturing Burnish Signal 0 1 0 2 NDD No Detectable Degradation 7336 7467 7399 30529 NDF No Degradation Found 10 13 2 17 NOI Potential Bobbin Flaw Signal 0 1 0 0 NOS Not Cleared by +Point 56 31 40 72 PLP Possible Loose Part 0 6 6 482 PVN Permeability Variation 0 0 0 4 RBD Retest - Bad Data 78 32 55 53 RIC Retest - Incomplete 26 4 9 112 RND Retest- No Data 0 0 0 1 RRT Retest - Restricted Tube 0 1 0 0 SVI Single Volumetric Indication 0 1 0 9 VOL Volumetric Indication 0 1 0 9 No flaw was found during the 1RE13 inservice inspection that met the requirement for "Active" degradation.
The only degradation identified during the 1 RE13 inspections was loose parts wear in SG 1D. Wear indications at the top of the tubesheet were sized using a qualified eddy
Attachment NOC-AE-07002143 Page 8 of 8 current technique. The technique is reported to result in a conservative measurement for large volume flaws.
Tube Pluqqing As a result of the 1RE13 inspection efforts, three tubes in SG 1D were removed from service by plugging. The locations plugged were R28C8, R71 C27, and Ri 17C49. No stabilization was required. No plugging was needed for active degradation mechanisms.
No tubes exceeded the structural integrity requirements. No primary-to-secondary leakage was observed during Cycle 13 operation and none is predicted during the next three cycles of operation for SG 1A, 1B, and 1C, and one cycle of operation for SG 1 D.
Inservice inspection results confirm that the Unit 1 steam generators meet all industry and regulatory structural and leakage integrity guidance.
The total number of tubes plugged per steam generator to date is as follows:
Steam Generator 1A 33 0.44%
Steam Generator 1 B 40 0.53%
Steam Generator 1C 26 0.34%
Steam Generator 1D 13 0.17%
Condition Monitoring Results None of the observed indications exceeded the screening thresholds for in situ testing.
No tubes were pulled or subjected to in-situ pressure testing.
Based on the inspections performed, engineering analysis of the inspection results obtained during 1RE13, and that no corrosion-induced flaws were detected, tube degradation large enough to challenge structural integrity requirements is not expected during the planned operating intervals for the Unit 1 steam generators. Therefore, based on the 1 RE13 inspection results, the operating interval between inspections for SG 1A, 1 B, and 1C is three cycles. Based on the extensive eddy current and top of tubesheet in-bundle visual inspection efforts performed during 1 RE1 3, the operational assessment supports the expectation that tube integrity in SG 1D will be satisfactorily maintained during the Cycle 14 operating interval.
Attachment NOC-AE-07002141 Page 1 of 7 IRE13 INSPECTION
SUMMARY
REPORT FOR STEAM GENERATOR TUBING of the SOUTH TEXAS PROJECT ELECTRIC GENERATING STATION UNIT 1 USNRC DOCKET NO.: 50-498 OPERATING LICENSE NO.: NPF-76 COMMERCIAL OPERATION DATE: August 25, 1988 Prepared By: -- / ~ ~-~7i~2L I/,//ý -2 e)e D. A. Stuhler Date Test Engineer Approved By:
C. f. You*er Date Supervisor, Test Engineering
Attachment NOC-AE-07002143 Page 2 of 8 SOUTH TEXAS PROJECT UNIT 1 IRE13 INSPECTION
SUMMARY
REPORT FOR STEAM GENERATOR TUBING Introduction This summary report describes the inspection of steam generator tubing at South Texas Project (STP) Unit 1 performed during refueling outage 1 RE1 3 in October 2006.
Steam generator eddy current inspection, sludge lancing, and Foreign Object Search and Retrieval (FOSAR) were conducted in steam generators 1A, 1B, 1C, and 1D.
Because of wire remnants and wall thinning found during 1RE12, a more aggressive inspection scope was developed for steam generator 1 D. The wire remnants originated from a feedwater heater cable stabilizer and migrated into the steam generator during cycle 11.
This report provides the information required by STP Technical Specification 6.8.3.o for maintaining steam generator tube integrity and the reporting requirements of Technical Specification 6.9.1.7.
Scope of Examinations The inservice inspection program, "2006 Outage Plan for the In-service Inspection of Steam Generator Tubing at the South Texas Project Electric Generating Station, Unit 1,"
(ISI Outage Plan) identified the steam generator tube areas to be examined by eddy current (EC) testing and the procedures expected to be used during the inservice inspection. A Degradation Assessment written prior to the outage established the scope of eddy current inspections.
EPRI guidelines require that all steam generators undergo a 50% general purpose EC bobbin inspection during the outage nearest the midpoint of the operative sequential period. Similarly, 20% examinations (+Point) of regions potentially susceptible to stress corrosion cracking should also be performed during the outage nearest the midpoint of the sequential operating period. For STP Unit 1, the operative sequential period is 144 EFPM beginning with refueling outage 1RE10, the first inservice inspection for the current steam generators. A more extensive eddy current and visual inspection of steam generator 1D was developed to support the planned cycle 3 inspection interval for the Unit 1 steam generators. This additional effort focused on potential wear at the top of the tubesheet and the flow distribution baffle related to the inventory of stabilizer wire remnants remaining in steam generator 1D. The 1RE13 inspection scope is outlined below:
Steam Generators 1A, 1B, and 1C
" Inspect three peripheral rows with 100% bobbin coil full length.
" Full length bobbin coil inspection of 50% of remaining tubes, other than three peripheral rows.
" +Point inspection of three peripheral rows from 3 inches into tube sheet to 6 inches above top of tube sheet to aid in loose parts detection.
" +Point inspection of 20% of hot leg tubes, from full 16 inches into tube sheet to 6 inches above top of tube sheet.
" +Point inspection of all previously identified dents and dings > 5 volts.
Attachment NOC-AE-07002143 Page 3 of 8
- +Point inspection of 20% of first two rows of U-bend looking for outer diameter stress corrosion cracking (ODSCC).
- +Point inspection of all tube bulges in tubesheet as identified in pre-service inspection.
" +Point inspection of all known unretrieved possible loose parts as identified by previous eddy current inspections, if possible.
" +Point inspection of all unretrieved visually observed loose parts as identified by previous secondary side inspections.
" +Point as required to bound potential loose parts identified by eddy current or loose parts identified by secondary side visual inspections with two clean surrounding tubes.
" Standard secondary side video probe inspection including visual inspection of loose parts previously left in place and possible loose parts as identified by eddy current during 1 RE1 3 and previous outages, if possible.
- Sludge lancing.
- Upper steam drum inspection (SG 1C only).
- Feedring inspection (SG 10 only).
- Inspection of the ninth tube support plate (SG 1A only).
- Tube scale profiling (SG 1C only).
- Inspection of all installed plugs.
Steam Generator 1 D
- 100% bobbin coil full length inspection.
- Conduct 100% top of tube sheet +Point, full depth tube sheet -3 inches to +6 inches.
- Conduct 20% of hot leg +Point inspection of tubesheet (hot leg only) from -16 inches to +6 inches at top of tube sheet.
0 +Point inspection of all previously identified dents and dings > 5 volts.
- +Point inspection of 20% of first two rows of U-bend looking for ODSCC.
- +Point inspection of all tube bulges and over expansions in tubesheet as identified in pre-service inspection.
0 +Point inspection of all tubes surrounding known unretrieved possible loose parts as identified by previous eddy current inspections.
- +Point inspection of all tubes surrounding unretrieved visually observed loose parts as identified by previous secondary side inspections.
a +Point inspection of all tube wear left in service during previous outages.
- +Point as required to bound potential loose parts identified by bobbin inspection or loose parts identified by as-left secondary side visual inspections with two clean surrounding tubes.
Attachment NOC-AE-07002143 Page 4 of 8
- Enhanced secondary side video probe inspection by inserting the video probe down every row to inspect for loose parts and associated wear.
- 100% hot leg and 20% cold leg +Point inspection of flow distribution baffle (FDB) from -3 inches to + 6 inches.
Summary of Examinations All steam generators were sludge lanced and the top of the tubesheet visually inspected for foreign objects. A small number of small foreign objects were observed at the top of the tubesheet in the steam generator 1A, 1B, and 1C tube bundles; fragments of flexitallic gaskets, machining -remnants, wire bristles, weld slag, pieces of tube scale, and sludge rocks account for most of the material observed. Four pieces of stabilizer wire were found in SG 1 C. Except for benign objects, such as sludge rocks and fiber bristles, all identified foreign objects were removed. No degradation was identified in any of these steam generators based on the 1 RE1 3 inspection results. Due to the known inventory of stabilizer wire in SG 1D, visual inspection of the top of the tubesheet included 100% foreign object mapping of both the hot leg and cold leg, with attempted retrieval of all identified items from the top of the tubesheet. Visual inspection of the flow distribution baffle was also performed to identify the source of eddy current potential loose part (PLP) signals.
The following table is a summary of eddy current inspections performed during 1 RE1 3:
Attachment NOC-AE-07002143 Page 5 of 8 STEAM GENERATOR EC INSPECTIONS PERFORMED DURING 1RE13 SG Program Tubes Inspected Hot Leg Cold Leg 1A Bobbin Straight Leg 4330 384
+Point Top of Tubesheet 2064 662 Low Row U-bend bobbin 155
+Point Row 1 and Row 2 U-bends 31
+Point FDB (-3 inches to + 6 inches)
Special Interest 13 14
+Point of Prior Dents and Dings > 5 volts 28 51 PLPs Inspected 88 PLP Calls 0 0 1B Bobbin Straight Leg 4328 384
+Point Top of Tubesheet 2048 659 Low Row U-bend bobbin 154
+Point Row 1 and Row 2 U-bends 31
+Point FDB (-3 inches to + 6 inches) ___
Special Interest 10 10
+Point of Prior Dents and Dings > 5 volts 1 PLPs Inspected 38 16 PLP Calls 3 3 1C Bobbin Straight Leg 4328 384
+Point Top of Tubesheet 2046 662 Low Row U-bend bobbin 155
+Point Row 1 and Row 2 U-bends 31
+Point FDB (-3 inches to + 6 inches)
Special Interest 2 1
+Point of Prior Dents and Dings > 5 volts 6 PLPs Inspected 58 14 PLP Calls 6 0 1D Bobbin Straight Leg 7575 386
+Point Top of Tubesheet 7575 7575 Low Row U-bend bobbin 155
+Point Row 1 and Row 2 U-bends 31
+Point FDB (-3 inches to + 6 inches) 5424 1468 Special Interest 17 6
+Point of Prior Dents and Dings > 5 volts PLPs Inspected 6830 1468 PLP Calls 348 134
Attachment NOC-AE-07002143 Page 6 of 8 Examination Results and Corrective Measures There were no axial or circumferential crack-like indications, corrosion mechanisms, or mechanical wear observed at the anti-vibration bar intersections in any of the steam generators.
A total of ten volumetric indications (one in SG 1 B, and nine in SG 1 D) were detected during the MRPC inspection for resolution of I-codes. Three of the indications were known prior to 1 RE1 3 and no change was noted during the current inspection. Of these three indications, one location at 09C (R10 C50) in SG 1 B was a pre-service call and did not change, and two locations at TSH (R84 C22 and R84 C24) were identified during 1RE12 as stabilizer wire wear and did not change. Seven additional volumetric indications were identified during 1 RE1 3. Five were associated with stabilizer wire wear at the top of the tubesheet, while two were associated with PLP calls at the flow distribution baffle. Four tubes in the SG 1D cold leg were identified with wear at the top of the tubesheet: one tube (R1 17 C49) required plugging due to a wear depth of 44%;
and the remaining three tubes (R2 C138, R99 C35, and R1 16 C48) had wear depths of
< 20% and remain in service. One location (R2 C138) was found with two wear scars less than two inches apart. These wear scars measured 8% and 9% respectively. The observed wear was related to the known inventory of stabilizer wire.
In addition to the top of tubesheet indications, two tubes were identified with volumetric indications at the hot leg flow distribution baffle to tube intersections. The through-wall depth of the volumetric indications was 23% and 25%. Since it was not possible to clearly determine the source of the volumetric signals, these locations (R28 C8 and R71 C27) were plugged. None of the top of tubesheet or flow distribution baffle indications challenged the tube integrity limits, and no tube leakage was observed during Cycle 13 operation; therefore, the Condition Monitoring requirements were satisfied.
Due to the number of PLPs being called during the FDB inspection and the potential for additional wear sites, the +Point inspection scope was increased to 100% of the hot leg and 20% of the cold leg intersections. Additional PLP indications were identified, but there were no additional volumetric indications. During the in-bundle top of tubesheet inspection of SG 1D, a total of 227 foreign objects were identified following sludge lancing. The majority of the foreign objects were characterized as fine wire associated with the feedwater heater stabilizer released during Cycle 11. Of the foreign objects identified during top of the tubesheet mapping, five known stabilizer wires were left in place. For those loose parts/foreign objects not removed, wear assessments were performed to support the assessment of SG 1D for operation until 1 RE1 4.
Indications The following table lists the number of indications which includes all data, including the supplementary inspection program of the Flow Distribution Baffle.
Attachment NOC-AE-07002143 Page 7 of 8
SUMMARY
OF EDDY CURRENT INDICATIONS SOUTH TEXAS UNIT 1 1 RE13 INDICATIONCOUNT- FINAL DATA INDICATION CONDITION S/G 1A S/G 1B S/G 1C S/G 1D ADS Absolute Drift Signal 0 0 0 1 DNG Freespan Ding 543 17 262 145 DNI Distorted DNG/DNT Indication 0 0 0 0 DNS Distorted Dent Indication - Cleared 44 14 29 69 DNT Dent 0 1 0 0 DSS DSI History Cleared 0 0 0 1 DTI Distorted Tubesheet Indication 0 0 0 0 DTS Distorted TS Indication - Cleared 0 0 0 3 INF Indication Not Found 0 0 7 127 INR Indication Not Reportable 30 13 27 107 MBI Possible Indication at MBM 0 0 0 0 MBM Manufacturing Buff Marks 140 118 144 296 MBS Manufacturing Burnish Signal 0 1 0 2 NDD No Detectable Degradation 7336 7467 7399 30529 NDF No Degradation Found 10 13 2 17 NOI Potential Bobbin Flaw Signal 0 1 0 0 NOS Not Cleared by +Point 56 31 40 72 PLP Possible Loose Part 0 6 6 482 PVN Permeability Variation 0 0 0 4 RBD Retest - Bad Data 78 32 55 53 RIC Retest - Incomplete 26 4 9 112 RND Retest- No Data 0 0 0 1 RRT Retest - Restricted Tube 0 1 0 0 SVI Single Volumetric Indication 0 1 0 9 VOL Volumetric Indication 0 1 0 9 No flaw was found during the 1 RE1 3 inservice inspection that met the requirement for "Active" degradation.
The only degradation identified during the 1 RE13. inspections was loose parts wear in SG 1 D. Wear indications at the top of the tubesheet were sized using a qualified eddy
Attachment NOC-AE-07002143 Page 8 of 8 current technique. The technique is reported to result in a conservative measurement for large volume flaws.
Tube Plugging As a result of the 1RE13 inspection efforts, three tubes in SG 1D were removed from service by plugging. The locations plugged were R28C8, R71 C27, and Ri 17C49. No stabilization was required. No plugging was needed for active degradation mechanisms.
No tubes exceeded the structural integrity requirements. No primary-to-secondary leakage was observed during Cycle 13 operation and none is predicted during the next three cycles of operation for SG 1A, 1 B, and 1C, and one cycle of operation for SG 1D.
Inservice inspection results confirm that the Unit 1 steam generators meet all industry and regulatory structural and leakage integrity guidance.
The total number of tubes plugged per steam generator to date is as follows:
Steam Generator 1A 33 0.44%
Steam Generator 1 B 40 0.53%
Steam Generator 1C 26 0.34%
Steam Generator 1D 13 0.17%
Condition Monitoring Results None of the observed indications exceeded the screening thresholds for in situ testing.
No tubes were pulled or subjected to in-situ pressure testing.
Based on the inspections performed, engineering analysis of the inspection results obtained during 1RE13, and that no corrosion-induced flaws were detected, tube degradation large enough to challenge structural integrity requirements is not expected during the planned operating intervals for the Unit 1 steam generators. Therefore, based on the 1RE13 inspection results, the operating interval between inspections for SG 1A, 1B, and 1C is three cycles. Based on the extensive eddy current and top of tubesheet in-bundle visual inspection efforts performed during 1 RE1 3, the operational assessment supports the expectation that tube integrity in SG 1D will be satisfactorily maintained during the Cycle 14 operating interval.