Text

Steam Generator Eddy Current Inspection Report Refueling Outage 13, April 2007
	ML072120524
Person / Time
Site:	Byron
Issue date:	06/07/2007
From:	; Exelon Generation Co
To:	; Office of Nuclear Reactor Regulation
References
	Download: ML072120524 (48)
	v • d • e

Exelon Generation Company, LLC BYRON STATION UNIT 2 4450 North German Church Road Byron, Illinois 61010 COMMERCIAL OPERATION: August 21, 1987 BYRON STATION UNIT 2 STEAM GENERATOR EDDY CURRENT INSPECTION REPORT REFUELING OUTAGE 13 April 2007 Exelon Generation Company, LLC 200 Exelon Way Kennett Square, PA 19348 Mailing Address 4300 Winfield Road Warrenville, IL 60555 Documentation Completed Date:

June 07, 2007 Page 1 of 38

TABLE OF CONTENTS

1.0 INTRODUCTION

.3 2.0

SUMMARY

3 3.0 CERTIFICATIONS 4

3.1 Procedures/Examinations/Equipment 4

3.2 Personnel 5

4.0 EXAMINATION TECHNIQUE AND EXAMINATION SCOPE 7

4.1 SG Tube Examination Techniques 7

4.2 SG Tube Inspection Scope 8

4.3 Recording of Examination Data 9

4.4 Witness and Verification of Examination 9

5.0 EXAMINATION RESULTS 10 5.1 Indications Found 10 5.2 Other SG Inspection Results 12 6.0 RESULTS OF CONDITION MONITORING 14 6.1 AVB Wear 15 6.2 Pre-Heater Baffle/TSP Wear 15 6.3 Foreign Object Wear 15 6.4 Primary-to-Secondary Leakage Assessment 15 7.0 REPAIR

SUMMARY

16 8.0 DOCUMENTATION 17 9.0 FIGURES/TABLES/ATTACHMENTS 17 Page 2 of 38

Exelon Generation Company, LLC BYRON STATION UNIT 2 4450 North German Church Road Byron, Illinois 61010 COMMERCIAL OPERATION: August 21, 1987 BYRON STATION UNIT 2 STEAM GENERATOR EDDY CURRENT INSPECTION REPORT REFUELING OUTAGE 13 April 2007 Exelon Generation Company, LLC 200 Exelon Way Kennett Square, PA 19348 Mailing Address 4300 Winfield Road Warrenville, IL 60555 Documentation Completed Date:

June 07, 2007 Page 1 of 38

TABLE OF CONTENTS

1.0 INTRODUCTION

.3 2.0

SUMMARY

3 3.0 CERTIFICATIONS 4

3.1 Procedures/Examinations/Equipment 4

3.2 Personnel 5

4.0 EXAMINATION TECHNIQUE AND EXAMINATION SCOPE 7

4.1 SG Tube Examination Techniques 7

4.2 SG Tube Inspection Scope 8

4.3 Recording of Examination Data 9

4.4 Witness and Verification of Examination 9

5.0 EXAMINATION RESULTS 10 5.1 Indications Found 10 5.2 Other SG Inspection Results 12 6.0 RESULTS OF CONDITION MONITORING 14 6.1 AVB Wear 15 6.2 Pre-Heater Baffle/TSP Wear 15 6.3 Foreign Object Wear 15 6.4 Primary-to-Secondary Leakage Assessment 15 7.0 REPAIR

SUMMARY

16 8.0 DOCUMENTATION 17 9.0 FIGURES/TABLES/ATTACHMENTS 17 Page 2 of 38

1.0 INTRODUCTION

Byron Station, Unit 2 operates with four Westinghouse Model D-5 recirculating steam generators (SGs) in the four loop pressurized water reactor system. The steam generators contain thermally treated Alloy-600 U-tubes that have a nominal outside diameter of 0.750 inches and a nominal thickness of 0.043 inches. The tubes are hydraulically expanded into the full depth of the tubesheet. The tubes are supported by stainless steel quatref oil support plates (TSPs) and chrome plated AIloy-600 anti-vibration bars (AVBs). See Figure A.1 for a diagram of the D-5 steam generator configuration.

In accordance with Byron Station Technical Specification (TS) 3.4.19, Steam Generator (SG) Tube Integrity, TS 5.5.9, Steam Generator (SG) Program, and American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel (B&PV) Code Section XI 2001 Edition through the 2003 Addenda, IWB 2500-1, Examination Category B-Q, Item Bi 6.20, SG eddy current examinations were performed during the Byron Station, Unit 2 Refueling Outage 13.

The inspections were performed consistent with the Electric Power Research Institute (EPRI) PWR Steam Generator Examination Guidelines: Revision 6, applicable interim guidance and Nuclear Energy Institute (NEI) 97-06, Steam Generator Program Guidelines, Revision 2. The field inspection activities were conducted from April 6 through April 13, 2007, by Westinghouse Electric Company LLC. The following tube inspections were performed during this outage (TS 5.6.9.a).

o 100% Full Length Bobbin Coil in all four SGs, excluding the row 1 and row 2 U-bend region where a 25% plus-point inspection was performed in each SG o

30% Hot Leg Top of Tubesheet Plus-Point (+3 inches to 17 inches) Plus-Point in all four SGs o

30% PIus-Point of Bulges ~18 volts and Overexpansions ~1.5 mils located within 17 inches of the top of the hot leg tubesheet in all four SGs o

100% Hot Leg Top of Tubesheet (+3 inches to 17 inches) Plus-Point of Tubes with Potentially High Residual Stress in all four SGs o

25% Plus-Point of the Row 1 and Row 2 U-Bend Regions o

25% Plus-Point of the Hot Leg Dents/Dings >5.0 volts in all four SGs o

50% Plus-Point of the Hot Leg Dent/Dings 3.0-5.0 volts in all four SGs o

25% Plus-Point of the Pre-heater baffle expansions contained in two SGs o

100% Visual Inspection of Previously Installed Welded Tube Plugs in all four SGs o

100% Visual Inspection of Previously Installed Mechanical Tube Plugs in all four SGs o

100% Visual Inspection of Newly Installed Tube Plugs in all SGs 2.0

SUMMARY

The guidance in Revision 6 of the EPRI PWR Steam Generator Examination Guidelines (i.e., EPRI Guidelines and applicable interim guidance) was used during this inspection. A degradation assessment was performed prior to each inspection to ensure the proper EPRI Appendix H, Performance Demonstration for Eddy Current Examination, qualified inspection techniques were used to detect any existing and potential modes of degradation. Each technique was evaluated to ensure that the detection and sizing capabilities are applicable to the Byron Station, Unit 2 site-specific condition in accordance with Section 6.3.2 of the EPRI Guidelines. All data analysts were qualified to Appendix G, Page 3 of 38

Qualification of Nondestructive Examination Personnel for Analysis of Nondestructive Examination Data, of the EPRI Guidelines (i.e., Qualified Data Analyst (QDA)). All data analyst and acquisition personnel satisfactorily completed site specific performance training and testing. An independent QDA process control review was employed to randomly sample the data to ensure that the analysis resolution process was properly performed and that the field calls were properly reported. An analysis feedback process was implemented that required the data analysts to reviewtheir missed calls and overcalls on a daily basis.

The modes of tube degradation found during the current inspection were anti-vibration bar (AVB) wear, pre-heater support plate wear and foreign object wear. Pursuant to EPRI Guideline Section 3.5, Inspection Results Categories, the results of the inspection were classified as inspection category C-i for SGs C/D and C-2 for SGs A/B.

There were no scanning limitations during the examinations.

As a result of the current eddy current inspections and response to conditions found, a total of seventeen (17) tubes were repaired by tube plugging. Table 2.1 provides the tube plugging levels for each SG. Table 2.2 provides the total number of tubes plugged in the current outage by degradation mode.

Equivalent Tube TABLE 2.1 Pluqciinq Level (TS 5.6.9.f & TS 5.6.9.h)

SCA SGB SGC SGD TOTAL Tubes Previously Plugged 144 123 57 25 349 Tubes Plugged in Cycle 13 2

4 ii 0

17 Total Tubes Plugged 146 127 68 25 366 Total Tubes Sleeved 0

0 0

Total Tubes Plugged (%)

3.19%

2.78%

1.49%

0.55%

2.00%

Each SG contains 4570 Tubes TABLE 2.2 Tubes Plugged During Cycle 13 (TS 5.6.9.e)

Mode of Degradation SG A SO B SO C SG D Total Anti-Vibration Bar Wear 2

1 0

0 3

Pre-Heater Support Plate Wear 0

0 0

Foreign Object Wear 0

2 1

0 3

Preventively Plugged 0

1 10 0

11 Cycle 13 Plugging Totals 2

4 11 0

17 3.0 CERTIFICATIONS 3.1 Procedures/Examinations/Equipment 3.1.1 The examination and evaluation procedures used during the eddy current inspection were approved by personnel qualified to Level Ill in accordance with the 1984 Edition of the American Society for Nondestructive Testing (ASNT) Recommended Practice SNT-TC-1A, Personnel Qualification and Certification in Nondestructive Testing and the 1991 and 1995 Editions of the American National Standards Institute (ANSI)/ASNT CP-1 89, ASNT Standard for Qualification and Certification of Nondestructive Testing Page 4 of 38

Personnel. Exelon Generation Company, LLC (EGC) procedure ER-AP-335-039, Multifrequency Eddy Current Data Acquisition of Steam Generator Tubing, Revision 4 and EGC procedure ER-AP-335-040, Evaluation of Eddy Current Data for Steam Generator Tubing, Revision 3, were used for data acquisition and analysis.

3.1.2 The examinations, equipment, procedures and personnel were in compliance with the following requirements: the EGO and Westinghouse Quality Assurance Programs for Inservice Inspection; Byron Station Technical Specification 5.5.9; 2001 Edition through the 2003 Addenda of the ASME B&PV Code Section Xl, Rules for Inservice Inspection of Nuclear Power Plant Components; 2001 Edition through the 2003 Addenda of the ASME B&PV Code Section V, Nondestructive Examination; Revision 6 of the EPRI PWR SG Examination Guidelines; and NEI 97-06, Steam Generator Program Guidelines, Revision 2.

3.1.3 Certification packages for examiners, data analysts, and equipment are available at Byron Station. Table A.1 and Table A.2 contained in Attachment A lists all personnel who performed, supervised, or evaluated the data during the current inspection.

3.1.4 RID Tech Incorporated Model TC7700 Remote Data Acquisition Units (RDAUs) with ANSER Version 8.4.3, Revision 213 software was used to acquire the eddy current data. Analysis was performed with Westinghouse ANSER Version 8.4.3, Revision 238 computer software.

3.1.5 The bobbin coil examinations were performed with a 0.610 inch diameter bobbin coil eddy current probe. A 0.590 inch diameter probe was used for Row 1 through Row 4 where there was difficulty traversing the tight radius U-bend region.

3.1.6 The top of tubesheet, tubesheet region, baffle plate expansion, and special interest rotating coil examinations were performed with a 0.610 inch diameter three coil rotating plus-point probe that contained a plus-point coil, a 0.115 inch diameter pancake coil and a 0.080 inch diameter pancake coil.

3.1.7 The rotating coil examinations in the U-Bend region were performed with a 0.580 inch diameter rotating plus-point probe.

3.2 Personnel 3.2.1 The personnel who performed the SG eddy current inspection data acquisition were qualified to Level II in accordance with the 1984 Edition of the ASNT Recommended Practice SNT-TC-1A, Personnel Qualification and Certification in Nondestructive Testing or the 1995 Edition of ANSI/ASNT CP-189, ASNT Standard for Qualification and Certification of Nondestructive Testing Personnel. A list of certified eddy current personnel who performed data acquisition for the examination are contained in Table A.1 of Attachment A.

Page 5 of 38

3.2.2 The personnel who performed the SG eddy current data analysis were qualified to a minimum of Level II, with special analysis training (i.e.,

Level IIA) in accordance with the 1984 Edition of the ASNT Recommended Practice SNT-TC-1A, Personnel Qualification and Certification in Nondestructive Testing or the 1995 Edition of ANSI/ASNT OP-i 89, ASNT Standard for Qualification and Certification of Nondestructive Testing Personnel.

A list of certified eddy current personnel who performed data analysis for the examination are contained in Table A.2 of Attachment A 3.2.3 All SG eddy current data analysts were qualified in accordance with EPRI Appendix G for QDAs.

In addition, all data analysts were trained and tested in accordance with a site specific performance demonstration program in both the bobbin coil and plus-point inspection data analysis.

Resolution analysts were also trained and tested specifically for the performance of data resolution. All analysts were required to achieve a minimum probability of detection of 80% with a 90% minimum confidence level on practical examinations and a minimum score of 80% on the written test prior to analyzing data.

3.2.4 All SG eddy current data acquisition personnel were trained and tested in accordance with a site specific performance demonstration program.

The data acquisition operators were required to achieve a written test score of 80% or greater prior to acquiring data.

3.2.5 The SG eddy current analysis was subject to two independent analyses.

Primary analysis of all data was performed by personnel from Westinghouse Electric Company, NDE Technologies Incorporated, and Wiltec. Secondary analysis was performed by personnel from Young Technology Services and Infineddy, LLC. Discrepancies between the two parties required Level III concurrence between both parties for the final resolution.

3.2.6 Two independent SG eddy current Level Ill QDAs who were not part of the resolution team were employed to serve as a process control reviewer, in accordance with EPRI Guidelines, Section 6.3.3. The Independent Level III QDA randomly sampled the data to ensure the resolution process was properly performed and that the field calls were properly reported. The Independent Level III QDA also provided data acquisition oversight to ensure that the data collection process was in compliance with appropriate procedures, that all essential variables were set in accordance with the applicable Examination Technique Specification Sheet (ETSS) and to provide a data quality check of acquired data. The Independent Level III QDA reported directly to the EGC Nondestructive Examination Level III.

3.2.7 Personnel from Westinghouse Electric Company, Young Technology Services and Hudson Global Resources performed data acquisition.

3.2.8 Real time data quality verifications were performed by personnel qualified as data analysts.

Page 6 of 38

4.0 EXAMINATION TECHNIQUE AND EXAMINATION SCOPE All eddy current examination techniques used are qualified in accordance with Appendix H of the EPRI PWR SG Examination Guidelines. Each examination technique was evaluated to be applicable to the tubing and conditions of the Byron, Unit 2 SGs.

4.1 SG Tube Examination Techniques (TS 5.6.9.c) 4.1.1 The bobbin coil examinations were performed with a 0.610 inch diameter bobbin coil eddy current probe described in Section 3.1.5. For low row U-Bend regions in Rows 4 and lower, a 0.590 inch diameter bobbin probe was utilized where there was difficulty traversing the U-bend region. The nominal probe inspection speed was 40 inches per second for the 0.610 inch diameter probe and 24 inches per second for the 0.590 inch diameter probe. Sufficient sampling rates were used to maintain a minimum of 30 samples per inch. The bobbin coil probes were operated at frequencies of 550 kHz, 300 kHz, 130 kHz, and 20 kHz operating in the differential and absolute test modes. In addition, suppression mixes were used to enhance the inspection. These mixes were as follows: 550/1 30 kHz differential mix, a 300/i 30 kHz absolute mix, and a 550/300/130 kHz differential mix.

4.1.2 The plus-point examinations at top of tubesheet and pre-heater baffle plate expansion transition regions, and special interest locations were performed with a 0.610 inch diameter three coil plus-point eddy current probe described in Section 3.i.6. The nominal probe speed was 0.8 inches per second and 0.1 inches per second for dents and dings. A sampling rate was used to maintain a minimum of 30 samples per inch in the circumferential direction and 25 samples per inch in the axial direction. For dents and dings, a sampling rate was used to maintain a minimum of 30 samples per inch in the circumferential direction and 30 samples per inch in the axial direction. The rotating probes were operated at frequencies of 300 kHz, 200 kHz, 100 kHz and 20 kHz.

In addition to the four base frequencies, three process channels were used to display circumferential indications in the positive trace.

4.1.3 The plus-point examinations in the U-bend regions were performed with a 0.580 inch diameter plus-point probe described in Section 3.1.7. The nominal probe speed was 0.4 inches per second. A sampling rate was used to maintain a minimum of 30 samples per inch in the circumferential direction and 30 samples per inch in the axial direction. The plus-point probe was operated at frequencies of 400 kHz, 300 kHz, 150 kHz, and 20 kHz for Rows 1 and 2. For U-bend rows greater than row 2, the plus-point probe was operated at frequencies at 400kHz, 300 kHz, 100 kHz and 20 kHz. In addition to the four base frequencies, three process channels were used to display circumferential indications in the positive trace.

4.1.4 The eddy current calibration standards used for the bobbin coil and plus-point inspections met the requirements of Section 6.2.7 of the EPRI PWR Steam Generator Examination Guidelines, Revision 6 and Sections V and XI of the ASME B&PV Code, 2001 Edition through the 2003 Addenda.

4.1.5 The SG eddy current examination techniques used during this inspection were equivalent to the EPRI Appendix H techniques listed in Table 4.1.

Page 7 of 38

Each Examination Technique Specification Sheet (ETSS) was evaluated and determined to be applicable to the site conditions.

Table 4.1 EPRI Appendix H Techniques EPRI ETSS Probe Description ETSS Revision 96004.3 10 Bobbin Anti-Vibration Bar/Pre-Heater Baffle Plate Wear 96005.2 9

Bobbin Free Span Pitting 96007.1 11 Bobbin Tube Support Plate (TSP) Outer Diameter Stress Corrosion Cracking (ODSCC) 96043.2 1

Bobbin Single Land Pre-Heater Support Wear 96511.1 16 Plus-Point Low Row U-bend Primary Water Stress Corrosion Cracking (PWSCC) 96703.1 17 Plus-Point DentlDing Axial PWSCC 96910.1 10 PIus-Point TSP Tapered Wear Flaw Sizing 21409.1 5

Plus-Point Sludge Pile/Crevice/Expansion Transition Axial ODSCC 21410.1 6

Plus-Point Expansion Transition/DentlDing Circumferential ODSCC 20510.1 7

Plus-Point Expansion Transition/Tubesheet (TS) Bulge-Overexpansion Dent/Ding Circumferential PWSCC 20511.1 8

Plus-Point Expansion Transition/IS Bulge-Overexpansion Axial PWSCC 21998.1 4

Plus-Point Foreign Object Wear/Free Span Volumetric Indications 22401.1 4

PIus-Point Dent/Ding Axial PWSCC 4.2 SG Tube Inspection Scope (TS 5.6.9.a) 4.2.1 100% of the tubes in all SG5 were inspected full length, tube end to tube end, with a bobbin coil probe described in Section 4.1.1 above, with the exception of the Row 1 and Row 2 U-bend region were a 25% sample was performed with a rotating coil probe as described in Section 4.1.3.

4.2.2 30% of the tubes in all SGs were inspected at the hot leg top of tubesheet expansion transition region (+3 inches to 17 inches) with a plus-point probe described in Section 4.1.2. In addition, all tubes (40) that were identified with potentially high residual stress were inspected at hot leg top of tubesheet expansion transition region (+3 inches to 17 inches) with a plus-point probe described in Section 4.1.2.

4.2.3 30% of the tubes in all SGs that contained bulges ~18 volts and overexpansion >1.5 mils located within the hot leg tubesheet to depths of 17 inches below the top of the hot leg tubesheet were inspected with a plus-point probe described in Section 4.1.2. Tubes containing bulges and overexpansions within the initial sample were inspected from the top of the hot leg tubesheet +3 inches to 17 inches below the top of the tubesheet.

4.2.4 25% of the tubes in all SGs were inspected in the Row 1 and Row 2 U-bend regions with a plus-point described in Section 4.1.3.

4.2.5 25% of the dents and dings that are >5.0 volts and 50% of the dents and dings 3.0-5.0 volts in all SGs were inspected with a plus-point probe Page 8 of 38

described in Section 4.1.2. The number of tubes examined are included in the special interest diagnostic examinations described in Section 4.2.7.

4.2.6 25% of the total number of pre-heater baffle plate expansion transitions

(+1-2 inches) contained in SGs 2B and 2C were inspected with a plus-point probe at baffle plates 02C and 030 described in Section 4.1.2.

Additional pre-heater baffle plate expansion transitions were inspected with a plus-point probe as described in Section 4.1.2 in SGs 2A, 2B, and 20 at pre-heater baffle plate TSP 020 in the outer peripheral tubes near the flow block, as this is a location where foreign objects may collect due to the area flow conditions. This location was visually inspected in SG 2D.

4.2.7 Diagnostic examinations were conducted on the following types of indications and conditions using a rotating probe described in Section 4.1.2 and 4.1.3:

o Non-quantifiable indications that were detected by the bobbin coil examination o

Hot leg dents and dings described in Section 4.2.5.

o Tubes in the vicinity of potential foreign objects in order to determine the extent of tubes potentially affected by the objects.

o A sample of selected AVB wear indications o

All expansion transitions and bulges that are significantly outside the top of tubesheet o

Diagnostic examinations were also performed in the 40 tubes that were identified with potentially high residual stress in the areas of hot leg dents and dings 3-volts or greater and areas of tube wear.

A total of 783 tubes were inspected as a result of these diagnostic examinations.

4.2.8 Attachment B contains tube sheet maps indicating the tube inspections that were performed during Refueling Outage 13.

4.3 Recording of Examination Data The raw eddy current data and analysis results were recorded on optical disks.

The data was then loaded into the Westinghouse Eddy Current Data Management System, ST Max, version 1.19.03. This system was used to track the proper examination of all tubes and it was also used to generate the final eddy current report summaries.

4.4 Witness and Verification of Examination Eddy current inspections were witnessed and/or verified by the Authorized Nuclear Inservice Inspectors, Mr. Jeff Hendricks and Mr. Lee Malabanan, of the Hartford Steam Boiler of CT of Hartford Connecticut, Chicago Branch, 2443 Warrenville Road, Suite 500, Lisle, Illinois 60532-9871.

Page 9 of 38

The Refueling Outage 13 ASME Form NIS-1, Owners Report for Inservice Inspections, is contained in Attachment D.

The Refueling Outage 13 ASME Form NIS-2, Owners Report for Repair/Replacement Activity for steam generator mechanical tube plugging activities is contained in Attachment E.

5.0 EXAMINATION RESULTS 5.1 Indications Found (TS 5.6.9.b) 5.1.1 Anti-Vibration Bar (AVB) Wear Tube degradation was found during the Refueling Outage 13 bobbin coil examination in the U-bend region due to fretting of the Anti-Vibration Bars on the tube. A total of 838 indications in 487 tubes were reported. The EPRI Appendix H bobbin coil examination technique 96004.3 was utilized in this inspection for the depth sizing of AVB wear. Three (3) indications in two tubes exceeded the 40% TW repair limit and were subsequently plugged. The largest indication found was 42% through wall (TW) and was found in tube R40-C18 in SG 2B. Tube R46-C61 contained a 36% TW and a 33% TW flaw at two different AVB locations and was preventatively plugged. (Table 5.1.1 provides a summary of AVB Wear degradation. Attachment C provides a listing of all tube flaws containing measurable through wall depth and inservice indications, including AVB wear.

Table 5.1.1 Refueling Outage 13 AVB Wear Summary SGA SGB SGC SGD Tubes*

Ind.

Tubes*

Ind.

Tubes*

md.

Tubes*

md.

<20%TW 73 87 106 133 105 136 65 82 20-39%TW 65 93 113 175 52 68 45 61

>=40%TW 1

1 1

2 0

0 0

0 TOTAL*

102 181 170 310 129 204 86 143

Tubes may contain multiple inaications and may be identified in multiple size categories.

5.1.2 Foreign Object Wear Tube degradation was found that was attributed to foreign object wear during the Refueling Outage 13 inspection. Six indications of foreign object wear were found in five tubes. The indications ranged from 12% TW to 31% TW as measured by the EPRI Appendix H plus point qualified examination technique 21998.1.

Table 5.1.2 provides a summary of the tubes that contained foreign object wear during Refueling Outage 13.

Page 10 of 38

Table 5.1.2 Refueling Outage 13 Foreign Object Wear Summary SG Row Column Depth Location Comment 2A 45 67 19%/(7%)*

TSP 02C+2.85 No Change from Refueling Outage 11 2A 45 67 21%/(7%)*

TSP 02C+1.17 No Change from Refueling Outage 11 2B 25 ii 19%

TSP 07H+0.68 2B 27 11 12%

TSP 07H+0.76 2C 33 65 27%

TSP 08H+0.69 2D 24 65 31%/(i 1 %)*

TSP 02C+i.00 No Change from Refueling Outage 11

Sizing method conservatively changed from ETSS 96910.1 to 21998.1 during the current refueling outage. Depths in () indicate the prior 96910.1 sizing for comparison to previous inspection data. No change in size was noted, since the object that caused the flaw was removed.

Three of the indications did not change from the previous inspection because the foreign objects were removed during Refueling Outage 11.

These indications were contained in tube R45-C67 in the 2A SG and tube R24-C65 in the 2D SG. These indications were previously sized with examination technique 96910.1 due to the wear-like characteristics of the flaws. During the current outage, these flaws were sized with the more conservative examination technique 21998.1 developed for volumetric flaws, which tend to oversize flaws of larger volumetric material loss.

Two tubes (R25-Ci 1 and R27-C1 1 in the 2B SG) were preventatively plugged and stabilized because foreign object retrieval could not be performed due to lack of access to the affected location.

One tube (R33-C65) was plugged and stabilized, along with two other adjacent tubes that contained possible loose part (PLP) signals with no detectable degradation (R33-54 and R34-C64) located at the 8th TSP. The location of this foreign object can only be accessed from an existing inspection port. Removal of the inspection port was considered, however, to do so would entail significant unplanned dose to build scaffold and remove the object. Other schedule impacts would have also occurred since the removal activities could not be performed prior to hot leg plugging and moving the manipulators and inspection equipment to the cold leg channel head. As a result, these tubes were plugged and stabilized.

Additionally, the foreign object is adjacent to two tubes that were plugged during Refueling Outages 2 and 7 that were not stabilized due to what was believed at the time to be pitting degradation at TSP 08H. Consequently, 8 additional tubes were preventatively plugged and stabilized to completely surround (box-in) these two non-stabilized plugged tubes.

Removal of the inspection port and inspection in the area of the foreign object is currently planned during the next refueling outage when the activities can be planned and scheduled.

5.1.3 Pre-Heater Wear Sixteen (16) tubes were found that contained indications of pre-heater baffle plate/TSP wear. The depth of the pre-heater wear ranged from 5% 1W to 39% 1W as measured by the EPRI Appendix H qualified bobbin coil examination technique 96043.2 for single land quatrefoil wear, 96004.3 for drilled hole baffle plate wear and 96910.1 for tapered wear. No tubes were plugged as a result of pre-heater baffle Page ii of 38

plate/TSP wear. Table 5.1.3 below provides a summary of tubes that contain pre-heater baffle plate/TSP wear.

TABLE 5.1.3 Refueling Outage 13 Pre-heater Baftle Plate/TSP Wear Summary

Support NDE Support ETSS Sizing SO Row Column Location Depth Wear Type Technique 2B 15 91 060 7%

Drifled Baffle 96004.3 2B 47 75 02C 13%

Drilled Baffle 96004.3 20 48 35 02C 5%

Drilled Baffle 96004.3 2B 46 50 07C 20%

Single Land 96043.2 2B 48 50 07C 39%

Single Land 96043.2 2B 48 53 07C 29%

Single Land 96043.2 2B 48 54 070 30%

Single Land 96043.2 2B 48 55 07C 37%

Single Land 96043.2 2B 48 59 07C 33%

Single Land 96043.2 2B 49 52 07C 26%

Single Land 96043.2 2B 49 63 07C 33%

Single Land 96043.2 2C 49 70 07C 35%

Single Land 96043.2 2D 49 67 07C 35%

Single Land 96043.2 2D 49 69 07C 35%

Single Land 96043.2 20 49 73 070 22%

Tapered 96910.1 2D 48 63 07C 20%

Tapered 96910.1 5.2 Other SG Inspection Results 5.2.1 Hot Leg Tubesheet Eddy Current Results (TS 5.6.9.j~:During Refueling Outage 13, 30% of the hot leg tubesheet region from 3 inches above the hot leg tubesheet to 17 inches below the top of the hot leg tubesheet were inspected with a three-coil rotating probe, which included a plus-point coil.

Additionally, 30% of the bulges (18 volts and greater) and overexpansions (1.5 mils and greater) that were contained in the upper 17 inches of the hot leg tubesheet were also inspected with a three-coil rotating probe, which included a plus-point coil. No indication of degradation was found as a result of these inspections.

5.2.2 Inspection of Tubes that Potentially Contain Higher Residual Stress: Forty tubes were previously found in the Byron Unit 2 SG as a result of a special screening to identify tubes that potentially could contain higher residual stress. This screening was performed in response to a fabrication anomaly that was found at another plant containing thermally treated Alloy 600 tubing that resulted in higher residual stress in certain tubes. Several of these tubes at the other plant developed stress corrosion cracking in tubes that contained higher residual stress resulting from the fabrication anomaly.

As a result, the following inspections were performed on the 40 tubes in Page 12 of 38

the Byron Station Unit 2 SGs that potentially could contain higher residual stress:

o Full Length bobbin coil inspection o

Hot Leg Top of tubesheet (+3 inches to 17 inches below the hot leg top of tubesheet) with a rotating three coil plus-point probe o

All hot leg dents and dings 3.0 volts and greater with a rotating three coil plus-point probe o

All areas of wear with a three coil plus-point probe As a result of these inspections, no indication of stress corrosion cracking was found.

5.2.3 Visual Inspection of Installed Tube Plugs All previously installed welded plugs and previously installed mechanical plugs were visually inspected for signs of degradation and leakage. A total of 25 welded plugs and 737 mechanical plugs were visually inspected. In addition, all plugs installed during this outage (i.e., 34 mechanical plugs in 17 tubes) were also visually inspected and the installation parameters were reviewed for acceptable installation. No anomalies were found.

5.2.4 Preventative Tube Plugging Eleven (11) tubes were preventatively plugged that did not contain tube flaws or service induced degradation.

Tube R37-C95 in SG 2B was preventatively plugged and stabilized due to a large 139.4 volt bulge located at the top of the hot leg tubesheet (TSH+0.08). Plus-point inspection was performed on this tube prior to tube plugging and no tube degradation was found.

Tubes R33-C64 and R34-C65 in SG 2C were preventatively plugged and stabilized because they contained a possible loose part signal (PLP) with no degradation located at the top edge of hot leg TSP 08H. This location was adjacent to tube R33-C65 that contained a 27% TW flaw at the top edge of hot leg TSP 08H as described in Section 5.1.2. This tube was also plugged and stabilized. The affected and surrounding tubes were inspected with the plus-point probe and no additional degradation was found. The possible loose part was also located adjacent to two tubes that were historically plugged but not stabilized. Consequently, as described in Section 5.1.2, eight additional tubes that did not contain degradation were preventively plugged and stabilized to box-in the non-stabilized plugged tubes.

5.2.5 Attachments C contains tube lists with axial elevations of all tube flaws that contain measurable through wall depth and inservice indications that were found during the Refueling Outage 13 eddy current inspection (TS 5.6.9.d).

5.2.6 A visual inspection of the secondary side moisture separator regions of all four SGs was performed during the Refueling Outage 13 in accordance with Westinghouse procedure MRS-SSP-1323-CBEICDE, Model D-5 SG Steam Drum and Auxiliary Feedwater Nozzle/Piping Inspection at Byron Station, Unit 2, and Braidwood Station, Unit 2, Revision 0. This was a follow-up inspection as a result of the SG 2B Refueling Outage 12 inspection where erosion was found on the moisture Page 13 of 38

separator tangential nozzles, downcomer barrels and swirl vanes. The results of the previous Refueling Outage 12 SG 2B secondary side moisture separator region inspection were previously provided to the NRC Staff in EGC Letters dated September 8, 2006 (ML062560349) and January 16, 2007 (MLO7O1 70225).

During the Refueling Outage 13 visual inspection areas of erosion was found in the primary moisture separator components in each of the four SGs inspected. The extent of the erosion was similar to the previous Refueling Outage 12 inspection results. Additional ultrasonic thickness measurements were taken of the eroded areas in each of the SGs. This was the second inspection of SG 2B and the first inspection of the other three SGs. Continued erosion of the components was identified in SG 2B, while no indications of through wall erosion were identified. Similar extent of erosion was found in the other three SGs. An analysis was performed that determined that significant margin remained in the eroded areas prior to the erosion penetrating through wall and affecting SG performance or possibly generating loose parts. The erosion in the affected areas was not projected to penetrate through wall or produce loose parts over the next two operating cycles until the next inspection is currently planned. Monitoring of the condition is planned over subsequent operating cycles in order to monitor the degradation growth rate and take corrective actions if they become necessary.

6.0 RESULTS OF CONDITION MONITORING (TS 5.6.9.g)

A condition monitoring assessment was performed for each inservice degradation mechanism found during the Refueling Outage 13 inspection. The condition monitoring assessment was performed in accordance with 15 5.5.9.a and NEI 97-06 using the EPRI Steam Generator Integrity Assessment Guidelines, Revision 2. For each identified degradation mechanism, the as-found condition was compared to the appropriate performance criteria for tube structural integrity, accident induced leakage and operational leakage as defined in 15 5.5.9.b. For each damage mechanism a tube structural limit was determined to ensure that SG tube integrity would be maintained over the full range of normal operating conditions and design basis accidents. This includes retaining a safety factor of 3.0 against burst under normal steady state full power operation primary to secondary pressure differential and a safety factor of 1.4 against burst under the limiting design basis accident pressure differential. Satisfying the structural limit ensures that the SG tube integrity performance criteria for structural integrity, accident induced leakage and operational leakage will be maintained.

The as-found condition of each degradation mechanism found during Refueling Outage 13 was shown to meet the appropriate limiting structural integrity performance parameter with a probability of 0.95 at 50% confidence, including consideration of relevant uncertainties.

No tube pulls or in-situ pressure testing was performed during Refueling Outage 13.

Sections 6.1 through 6.3 provide a summary of the condition monitoring assessment for each degradation mechanism. Section 6.4 provides a primary to secondary leakage assessment as required by IS 5.6.9.k and TS 5.6.9.1.

Page i4of 38

6.1 AVB Wear The largest AVB wear indication found during the Refueling Outage 13 inspection was 42% 1W as measured by the EPRI Appendix H qualified technique 96004.3, Revision 10. Considering technique and analyst uncertainties, the largest AVB wear indication found is corrected to 49.2% TW with a 0.95 probability at 50% confidence. This is well below the AVB wear structural limit of 71.4% TW.

6.2 Pre-Heater Baffle/TSP Wear The largest pre-heater baffle plate drilled hole baffle wear indication found during the Refueling Outage 13 inspection was 13% 1W as measured by the EPRI Appendix H qualified technique 96004.3, Revision 10. Considering technique and analyst uncertainties, the largest baffle plate wear indication found is corrected to 21.4% TW with a 0.95 probability at 50% confidence. This is well below the 0.75-inch baffle plate wear structural limit of 65.6% 1W.

The largest single land TSP quatrefoil wear indication found during the Refueling Outage 13 inspection was 39% TW as measured by the EPRI Appendix H qualified technique 96043.2, Revision 1. Considering technique and analyst uncertainties, the largest single land TSP wear indication found is corrected to 43.7% 1W with a 0.95 probability at 50% confidence. This is well below the 1.12 inch TSP wear structural limit of 60.7% 1W.

The largest TSP tapered wear indication found during the Refueling Outage 13 inspection was 22% 1W as measured by the EPRI Appendix H qualified technique 96910~1,Revision 10. Considering technique and analyst uncertainties, the largest tapered TSP wear indication found is corrected to 38.8% 1W with a 0.95 probability at 50% confidence. This is well below the 1.12 inch TSP wear structural limit of 60.7% TW.

6.3 Foreign Object Wear The largest foreign object wear indication found during the Refueling Outage 13 inspection was 31 % TW as measured by the EPRI Appendix H qualified technique 21998.1, Revision 4. Considering technique and analyst uncertainties, the largest baffle plate wear indication found is corrected to 49.02% 1W with a 0.95 probability at 50% confidence. This is well below the 58.1% 1W freespan uniform wall thinning of unlimited length structural limit.

6.4 Primary-to-Secondary Leakage Assessment (IS 5.6.9.k and TS 5.6.9.1)

Byron Station Unit 2 did not observe any operational primary to secondary leakage greater than three gallons per day over the cycle preceding the inspection. The SG tube inspections did not find any potential sources of tube leakage. Chemistry sampling of the Steam Jet Air Ejector and liquid SG blowdown sample locations did not detect any SG operational leakage that was above the detection threshold. Therefore, it was determined that there was no quantifiable SG operational leakage.

Page 15 of 38

In accordance with IS 5.5.9.c, for Unit 2 during Refueling Outage 13 and the subsequent operating cycle, tube flaws located below 17 inches from the top of the hot leg tubesheet (i.e., lowermost 4-inches) do not require inspection, plugging or repair. The calculated accident leakage rate from flaws or postulated flaws in the lowermost 4-inches is 2 times the maximum operational primary to secondary leakage rate. Since Byron Station Unit 2 did not observe any measurable SG primary to secondary operational leakage, the calculated accident leakage rate from flaws in the lowermost 4-inches of the hot leg tubesheet would also not be quantifiable.

7.0 REPAIR

SUMMARY

(TS 5.6.9.i)

Repairs were conducted in accordance with ASME Section Xl, 2001 Edition through the 2003 Addenda. All tube plugging was performed by Westinghouse using Alloy 690 mechanical tube plugging process in accordance with ASME Section Xl IWA-4713, Heat Exchanger Tube Plugging by Expansion. All repairs were performed in accordance with approved Westinghouse procedures. Table 7.1 depicts the repairs conducted during Refueling Outage 13. Table 7.2 lists the tube locations that were repaired in Refueling Outage 13.

TABLE 7.1 Summary of Refueling Outage 13 Tube Plugging REPAIRS PERFORMED SGA SGB SGC SGD TOTAL Tubes Plugged*

2 4

11 0

17 Tubes Stabilized 0

3 11 0

14

Includes number of tubes stabilized and piugged.

Page 16 of 38

TABLE 7.2 SG Tubes Repaired During Refueling Outage 13 T

Stabilizer SG Row Col Repair Leg Indication Location 36%

AV3+0.00 2A 47 61 Plug None AV4-0.15 2

2A 41 87 Plug None 40%

26%

18%

AV2+0.12 AV3-0.03 AV4+0.00 3

2B 25 11 Hot 19%

07H+0.68 4

2B 27 11 Plug Hot 12%

07H+0.76 5

2B 40 18 Plug None 17%

42%

40%

AV1 +0.00 AV2+0.00 AV3+0.00 2B 37 95 Plug Hot TSH+0.08 7

20 33 64 Plug Hot PLP 08H+0.77 8

20 32 65 Plug Hot Note 2 9

20 33 65 Plug Hot 27%

08H+0.69 10 20 34 65 Plug Hot PLP 08H+0.72 11 2C 35 65 Plug Hot Note 2 12 20 32 66 Plug Hot Note 2 13 20 35 66 Plug Hot Note 2 14 20 32 67 Plug Hot Note 2 15 20 33 67 Plug Hot Note 2 16 20 34 67 Plug Hot Note 2 17 20 35 67 Plug Hot Note 2 PLP Possible Loose Part signal Note 1: Tube was preventatively plugged due to a 139.4-volt bulge at the top of the hot leg expansion transition. There was no degradation associated with this bulge.

Note 2: Tube was preventatively plugged and stabilized to surround two tubes that were previously plugged with no stabilizer that is adjacent to a foreign object.

8.0 DOCUMENTATION All original optical disks have been provided to EGO and are maintained at Byron Station.

The final data sheets and pertinent tube sheet plots are contained in the Westinghouse Final Outage Reports for Byron Station, Unit 2, Refueling Outage 13 Steam Generator Inspection. The report is also maintained at Byron Station.

9.0 FIGURES/TABLES/ATTACHMENTS Attachment A Table A.1 Data Acquisition Personnel Certification List Table A.2 Data Analysis Personnel Certification List Figure A.1 Westinghouse Model D-5 Tube Support Configuration Page 17 of 38

Attachment B Attachment B.1 Hot Leg Bobbin Coil Inspection Scope Attachment B.2 Cold Leg Bobbin Coil Inspection Scope Attachment B.3 Hot Leg Top of Tubesheet Plus-Point Inspection Scope Attachment B.4 Row 1 and Row 2 Plus-Point Inspection Scope Attachment B.5 Baffle Plate Expansion Plus-Point Inspection Scope Attachment B.6 Special Interest Plus-Point Inspection Scope, Including Hot Leg Dents and Dings Attachment C Attachment C.1 2A Steam Generator Inservice Indications.2 2B Steam Generator Inservice Indications Attachment C.3 20 Steam Generator Inservice Indications.4 2D Steam Generator Inservice Indications Attachment D ASME Form NIS-1, Owners Report for Inservice Inspections Attachment E ASME Form NIS-2, Owners Report for Repair/Replacement Activity for 2A SG Tube Plugging ASME Form NIS-2, Owners Report for Repair/Replacement Activity for 2B SG Tube Plugging ASME Form NIS-2, Owners Report for Repair/Replacement Activity for 20 SG Tube Plugging Page 18 of 38

ATTACHMENT A PERSONNEL CERTIFICATIONS WESTINGHOUSE MODEL D-5 TUBE SUPPORT CONFIGURATION Page 19 of 38

TABLE A.1 DATA ACQUISITION PERSONNEL CERTIFICATIONS No.

Name Company Level QDA 1

Bradley, GD Westinghouse II No 2

Dillard, WE Westinghouse II No 3

Evering, DP Westinghouse II No 4

Gallant, GJ Westinghouse II No 5

Glenn, WD Westinghouse II No 6

Mains, PJ Westinghouse II No 7

Mantich, SM Hudson I

No 8

Ostler, E Young Technology IlA QDA 9

Scott, AW Westinghouse II No 10 Smith, AO Westinghouse II No 11 Tedrick, JE Westinghouse II No 12 Thompson, KW Westinghouse II No 13 Vernon, DP Westinghouse II No Page 20 of 38

TABLE A.2 DATA ANALYSIS PERSONNEL CERTIFICATIONS No, Name Company Level QDA 1

Anderson, DA NDE Technology lIA QDA 2

Beehner, SJ Westinghouse Ill QDA 3

Black, CR NDE Technology lIlA QDA 4

Bowler, S Young Technology IIA QDA 5

Bowser, GC Westinghouse Ill QDA 6

Brown, ME*

NDE Technology lIlA QDA 7

Calender, Dom Young Technology IlA QDA 8

Calender, Doug Young Technology lIlA QDA 9

Chapmon, G Young Technology IlA QDA 10 Chevalier, WD Young Technology IIA QDA 11 Childers, JE Wiltec lIlA QDA 12 Drumm, AL NDE Technology lIlA QDA 13 Dye, JE NDE Technology lIA QDA 14 Gomez, A Young Technology lIA QDA 15 Grant, BM NDE Technology lIlA QDA 16 Gray, W Young Technology lIlA QDA 17 Haynes, WA NDE Technology lIlA QDA 18 Hover, L Young Technology lIlA QDA 19 lngenthron, JP Infineddy IIA QDA 20 Jerina, FJ NDE Technology lIlA QDA 21 Kirshberger, G Young Technology IlA QDA 22 Knox, P Young Technology IlA QDA 23 Lewis, CL NDE Technology IlA QDA 24 Lewis, DA NDE Technology lIlA QDA 25 Lohner, ET NDE Technology lIlA QDA 26 Mast, MS*

NDE Technology lIlA QDA 27 McLeod, EJ NDE Technology IIA QDA 28 Newsom, C Young Technology IlA QDA 29 Owens, S Young Technology lIA QDA 30 Popovich, RA Westinghouse Ill QDA 31 Richmond, MA NDE Technology lIlA QDA 32 Schmitz, KJ NDE Technology lIlA QDA 33 Siegel, RA NDE Technology lIlA QDA 34 Skirpan, JR NDE Technology IIA QDA 35 Stewart, KP Young Technology lIA QDA 36 Stocklin, PK Young Technology IIA QDA 37 Stokke, TF NDE Technology lIlA QDA 38 Sum raIl, W Young Technology lIlA QDA 39 Taylor, SH Westinghouse Ill QDA 40 Thompson, KA NDE Technology lIA QDA 41 Tobin, RJ Westinghouse III QDA 42 Webb, JF Young Technology lIlA QDA 43 Wrubleski, AJ NDE Technology lIlA QDA 44 Yaklich, DJ Westinghouse Ill QDA 45 Zevchak, JJ NDE Technology IIA QDA

Independent Qualified Data Analyst Page 21 of 38

FIGURE A.1 Westinghouse Model D-5 Tube Support Configuration 07C IJ5C 04C 03C

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Itlanway Page 22 of 38

ATTACHMENT B INSPECTION SCOPE Page 23 of 38

ATTACHMENT B.1 Hot Leg Bobbin Coil Inspection Scope Page 24 of 38

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Attachment B,6 Special Interest Plus-Point Inspection Scope Including Hot Leg Dents and Dings Page 29 of 38

ML072120524

Contents

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1.0 INTRODUCTION

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1.0 INTRODUCTION

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