U.S. Operating Experience 

with Thermally Treated Alloy 

600 Steam Generator Tubes 

Through December 2013

Office of Nuclear Reactor Regulation

NUREG-2188

 
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U.S. Operating Experience 

with Thermally Treated Alloy 

600 Steam Generator Tubes 

Through December 2013 

Manuscript Completed: September 2015

Date Published: February 2016

Prepared by:

K. J. Karwoski

Office of Nuclear Reactor Regulation

NUREG-2188

iii

ABSTRACT

Steam generators placed in service in the 1960s and 1970s primarily had mill-annealed 

Alloy 600 tubes. Over time, this material proved to be susceptible to stress corrosion cracking 

in the highly pure primary and secondary water chemistry environments of pressurized-water 

reactors. The corrosion ultimately led to the replacement of steam generators at many facilities, 

with the first U.S. replacement occurring in 1980. Many of the steam generators placed into 

service in the 1980s used tubes fabricated from thermally treated Alloy 600. This tube material 

was thought to be less susceptible to corrosion. NUREG-1771, “U.S. Operating Experience 

with Thermally Treated Alloy 600 Steam Generator Tubes,” documented the operating 

experience associated with thermally treated Alloy 600 steam generator tubes as of 

December 2001. This document builds upon the information in NUREG-1771 and summarizes 

the operating experience with thermally treated Alloy 600 tubes through December 2013, with 

some information from 2014 included.

CONTENTS

ABSTRACT...............................................................................................................................iii

CONTENTS............................................................................................................................... v

LIST OF FIGURES ...................................................................................................................vii

LIST OF TABLES......................................................................................................................ix

EXECUTIVE SUMMARY .........................................................................................................xiii

ACKNOWLEDGMENTS...........................................................................................................xv

ABBREVIATIONS AND ACRONYMS ....................................................................................xvii

1 INTRODUCTION................................................................................................................. 1-1

1.1 Safety Significance....................................................................................................... 1-1

1.2 General Steam Generator Design ................................................................................ 1-2

1.3 Steam Generator Program ........................................................................................... 1-5

1.3.1 Regulatory Requirements ................................................................................... 1-5

1.3.2 Steam Generator Tube Inspections .................................................................... 1-9

1.3.3 Tube Plugging/Repair Limits............................................................................. 1-11

1.3.4 Tube Plugging and Repair................................................................................ 1-13

1.4 Mill-Annealed Alloy 600 Steam Generator Operating Experience............................... 1-14

1.5 Thermally Treated Alloy 600 Tubes ............................................................................ 1-15

1.6 Thermally Treated Alloy 690 Tubes ............................................................................ 1-16

1.7 TSTF-449................................................................................................................... 1-16

1.8 TSTF-510................................................................................................................... 1-19

2 STEAM GENERATOR DESIGNS IN UNITS WITH THERMALLY TREATED ALLOY 

600 TUBES......................................................................................................................... 2-1

2.1 Introduction .................................................................................................................. 2-1

2.2 Model D5 Steam Generators ........................................................................................ 2-1

2.3 Model F Steam Generators .......................................................................................... 2-2

2.4 Replacement Steam Generators .................................................................................. 2-3

3 THERMALLY TREATED ALLOY 600 STEAM GENERATOR TUBE OPERATING 

EXPERIENCE..................................................................................................................... 3-1

3.1 Data Gathering Methods and Introduction .................................................................... 3-1

3.2 Model D5 Steam Generator Operating Experience....................................................... 3-1

3.2.1 Braidwood 2 ....................................................................................................... 3-1

3.2.2 Byron 2............................................................................................................. 3-21

3.2.3 Catawba 2 ........................................................................................................ 3-42

3.2.4 Comanche Peak 2............................................................................................ 3-55

3.3 Model F Steam Generator Operating Experience ....................................................... 3-64

3.3.1 Callaway........................................................................................................... 3-64

3.3.2 Millstone 3 ........................................................................................................ 3-66

3.3.3 Seabrook.......................................................................................................... 3-83

3.3.4 Vogtle 1 ............................................................................................................ 3-98

3.3.5 Vogtle 2 .......................................................................................................... 3-115

3.3.6 Wolf Creek...................................................................................................... 3-127

3.4 Replacement Model Steam Generator Operating Experience .................................. 3-142

3.4.1 Indian Point 2 ................................................................................................. 3-142

3.4.2 Point Beach 1 ................................................................................................. 3-147
3.4.3 Robinson 2 ..................................................................................................... 3-159

3.4.4 Salem 1 .......................................................................................................... 3-168

3.4.5 Surry 1............................................................................................................ 3-176

3.4.6 Surry 2............................................................................................................ 3-193

3.4.7 Turkey Point 3 ................................................................................................ 3-208

3.4.8 Turkey Point 4 ................................................................................................ 3-214

4 SUMMARY.......................................................................................................................... 4-1

4.1 Model D5 Summary...................................................................................................... 4-1

4.2 Model F Summary ........................................................................................................ 4-2

4.3 Replacement Model Summary ..................................................................................... 4-3

4.4 Overall Summary.......................................................................................................... 4-3

4.4.1 Forced outages and unplanned inspections........................................................ 4-3

4.4.2 Tubes removed for laboratory examination......................................................... 4-5

4.4.3 Corrosion of tubes .............................................................................................. 4-7

4.4.4 Degradation in steam generator channel head ................................................. 4-10

4.4.5 Degradation of steam generator secondary-side internals ................................ 4-12

4.4.6 Tube wear ........................................................................................................ 4-13

4.4.7 Selected findings .............................................................................................. 4-14

4.4.8 Summary and observations .............................................................................. 4-16

APPENDIX A: BIBLIOGRAPHY............................................................................................A-1
LIST OF FIGURES

Figure 1-1: Typical Pressurized Water Reactor Power Plant............................................ 1-35

Figure 1-2: Typical PWR Recirculating Steam Generator without a Preheater................. 1-36

Figure 1-3: Typical PWR Once-Through Steam Generator .............................................. 1-37

Figure 1-4: U-Bend Features............................................................................................ 1-38

Figure 1-5: Typical PWR Recirculating Steam Generator with a Preheater...................... 1-39

Figure 1-6: Typical Steam Generator Channel Head in a Recirculating Steam 

Generator ...................................................................................................... 1-40

Figure 1-7: Partial and Full Depth Expansions ................................................................. 1-41

Figure 1-8: Typical Tubesheet Joint – Full Depth Expansion............................................ 1-42

Figure 1-9: Combustion Engineering Steam Generator.................................................... 1-43

Figure 1-10: Typical Tube Support Configurations ............................................................. 1-44

Figure 1-11: Illustration of H* Distance............................................................................... 1-45

Figure 1-12: Alloy 800 Tubesheet Sleeve .......................................................................... 1-46

Figure 1-13: Alloy 800 Tube Support Sleeve...................................................................... 1-47

Figure 1-14: Steam Generator Tube Degradation Mechanisms ......................................... 1-48

Figure 1-15: Number of Units with Thermally Treated Alloy 600 Steam Generator Tubes 

as a Function of Year..................................................................................... 1-49

Figure 2-1: Westinghouse Model D5 Steam Generator Tube Support Locations ............... 2-6

Figure 2-2: Westinghouse Model D5 Steam Generator Tubesheet Map ............................ 2-7

Figure 2-3: Preheater Region of Westinghouse Model D5 Steam Generator ..................... 2-8

Figure 2-4: Westinghouse Model F Steam Generator Tube Support Locations.................. 2-9

Figure 2-5: Westinghouse Model F Steam Generator Tubesheet Map............................. 2-10

Figure 2-6: Westinghouse Model 44F Steam Generator Tube Support Locations............ 2-11

Figure 2-7: Westinghouse Model 44F Steam Generator Tubesheet Map......................... 2-12

Figure 2-8: Westinghouse Model 51F Steam Generator Tube Support Locations............ 2-13

Figure 2-9: Westinghouse Model 51F Steam Generator Tubesheet Map......................... 2-14

Figure 4-1: Model D5: Causes of Tube Plugging (12/2013)............................................. 4-55

Figure 4-2a: Model D5: Cumulative Plugging per Year (12/2013) ..................................... 4-56

Figure 4-2b: Model D5: Plugging per Year (12/2013)........................................................ 4-57

Figure 4-3: Model D5: Cumulative Plugging per Refueling Outage (12/2013) ................. 4-58

Figure 4-4: Model D5: Causes of Tube Plugging per Year (12/2013) .............................. 4-59

Figure 4-5: Model F: Causes of Tube Plugging (12/2013)............................................... 4-60

Figure 4-6a: Model F: Cumulative Plugging per Year (12/2013)........................................ 4-61

Figure 4-6b: Model F: Plugging per Year (12/2013) .......................................................... 4-62

Figure 4-7: Model F: Cumulative Plugging per Refueling Outage (12/2013).................... 4-63

Figure 4-8: Model F: Causes of Tube Plugging per Year (12/2013)................................. 4-64

Figure 4-9: Replacement Models: Causes of Tube Plugging (12/2013)........................... 4-65

Figure 4-10a: Replacement Models: Cumulative Plugging per Year (12/2013) ................... 4-66

Figure 4-10b: Replacement Models: Plugging per Year (12/2013)...................................... 4-67

Figure 4-11: Replacement Models: Cumulative Plugging per Refueling Outage 

(12/2013) ....................................................................................................... 4-68

Figure 4-12: Replacement Models: Causes of Tube Plugging per Year (12/2013)............ 4-69

Figure 4-13: Number of Thermally Treated Alloy 600 Tubes in Service per Year 

(12/2013) ....................................................................................................... 4-70

Figure 4-14: All Models: Tubes Plugged Per Grouping/Model (12/2013)........................... 4-71

Figure 4-15: All Models: Causes of Tube Plugging (12/2013) ........................................... 4-72

Figure 4-16: All Models: Number of Tubes Plugged per Year (12/2013) ........................... 4-73

Figure 4-17: All Models: Percentage of Tubes Plugged per Year (12/2013)...................... 4-74

Figure 4-18: All Models: Causes of Tube Plugging per Year (12/2013)............................. 4-75

ix

LIST OF TABLES

Table 1-1: Unit Listing by PWR Vendor (12/2014) ............................................................. 1-24

Table 1-2: Unit Listing by Tube Material (12/2014)............................................................. 1-25

Table 1-3: Unit Listing by Tube Expansion Type and Material (12/2014) ........................... 1-26

Table 1-4: Unit Listing by Tube Support Plate Material (12/2014) ...................................... 1-27

Table 1-5: History of H* Amendments (Part 1)................................................................... 1-28

Table 1-5: History of H* Amendments (Part 2)................................................................... 1-29

Table 1-6: Units with Replacement Steam Generators Part 1 (12/2014)............................ 1-30

Table 1-6: Units with Replacement Steam Generators Part 2 (12/2014)............................ 1-31

Table 1-6: Units with Replacement Steam Generators Part 3 (12/2014)............................ 1-32

Table 1-7: Units with Thermally Treated Alloy 600 Tubes (12/2014).................................. 1-33

Table 1-8: Age of Steam Generators at Units with Thermally Treated Alloy 600 

Tubes (12/2013) ............................................................................................... 1-34

Table 2-1: Steam Generator Design Information for Units with Thermally Treated Alloy 

600 Tubes........................................................................................................... 2-5

Table 3-1: Braidwood 2: Summary of Bobbin Inspections and Tube Plugging ................ 3-222

Table 3-2: Braidwood 2: Causes of Tube Plugging ......................................................... 3-223

Table 3-3: Braidwood 2: Tubes Plugged for Indications Other Than AVB Wear.............. 3-224

Table 3-4: Byron 2: Summary of Bobbin Inspections and Tube Plugging........................ 3-228

Table 3-5: Byron 2: Causes of Tube Plugging................................................................. 3-229

Table 3-6: Byron 2: Tubes Plugged for Indications Other Than AVB Wear ..................... 3-230

Table 3-7: Catawba 2: Summary of Bobbin Inspections and Tube Plugging ................... 3-236

Table 3-8: Catawba 2: Causes of Tube Plugging............................................................ 3-237

Table 3-9: Catawba 2: Tubes Plugged for Indications Other Than AVB Wear................. 3-238

Table 3-10: Comanche Peak 2: Summary of Bobbin Inspections and Tube Plugging....... 3-249

Table 3-11: Comanche Peak 2: Causes of Tube Plugging................................................ 3-250

Table 3-12: Comanche Peak 2: Tubes Plugged for Indications Other Than AVB Wear .... 3-251

Table 3-13: Callaway: Summary of Bobbin Inspections and Tube Plugging (Thermally 

Treated Tubes Only)....................................................................................... 3-253

Table 3-14: Callaway: Causes of Tube Plugging (Thermally Treated Tubes Only) ........... 3-254

Table 3-15: Callaway: Tubes Plugged for Indications Other Than AVB Wear (Thermally 

Treated Tubes Only)....................................................................................... 3-255

Table 3-16: Millstone 3: Summary of Bobbin Inspections and Tube Plugging ................... 3-257

Table 3-17: Millstone 3: Causes of Tube Plugging............................................................ 3-258

Table 3-18: Millstone 3: Tubes Plugged for Indications Other Than AVB Wear................. 3-259

Table 3-19: Seabrook: Summary of Bobbin Inspections and Tube Plugging..................... 3-263

Table 3-20: Seabrook: Causes of Tube Plugging.............................................................. 3-264

Table 3-21: Seabrook: Tubes Plugged for Indications Other Than AVB Wear .................. 3-265

Table 3-22: Vogtle 1: Summary of Bobbin Inspections and Tube Plugging ....................... 3-268

Table 3-23: Vogtle 1: Causes of Tube Plugging................................................................ 3-269

Table 3-24: Vogtle 1: Tubes Plugged for Indications Other Than AVB Wear .................... 3-270

Table 3-25: Vogtle 2: Summary of Bobbin Inspections and Tube Plugging ....................... 3-273

Table 3-26: Vogtle 2: Causes of Tube Plugging................................................................ 3-274

Table 3-27: Vogtle 2: Tubes Plugged for Indications Other Than AVB Wear .................... 3-275

Table 3-28: Wolf Creek: Summary of Bobbin Inspections and Tube Pugging ................... 3-276

Table 3-29: Wolf Creek: Causes of Tube Plugging ........................................................... 3-277

Table 3-30: Wolf Creek: Tubes Plugged for Indications Other Than AVB Wear................ 3-278

Table 3-31: Indian Point 2: Summary of Bobbin Inspections and Tube Plugging .............. 3-280

Table 3-32: Indian Point 2 Causes of Tube Plugging ......................................................... 3-281
x

Table 3-33: Indian Point 2: Tubes Plugged for Indications Other Than AVB Wear............ 3-282

Table 3-34: Point Beach 1: Summary of Bobbin Inspections and Tube Plugging.............. 3-283

Table 3-35: Point Beach 1: Causes of Tube Plugging....................................................... 3-284

Table 3-36: Point Beach 1: Tubes Plugged for Indications Other Than AVB Wear ........... 3-285

Table 3-37: Robinson 2: Summary of Bobbin Inspections and Tube Plugging .................. 3-286

Table 3-38: Robinson 2: Causes of Tube Plugging........................................................... 3-287

Table 3-39: Robinson 2: Tubes Plugged for Indications Other Than AVB Wear................ 3-288

Table 3-40: Salem 1: Summary of Bobbin Inspections and Tube Plugging ....................... 3-291

Table 3-41: Salem 1: Causes of Tube Plugging................................................................ 3-292

Table 3-42: Salem 1: Tubes Plugged for Indications Other Than AVB Wear..................... 3-293

Table 3-43: Surry 1: Summary of Bobbin Inspections and Tube Plugging......................... 3-295

Table 3-44: Surry 1: Causes of Tube Plugging ................................................................. 3-296

Table 3-45: Surry 1: Tubes Plugged for Indications Other Than AVB Wear...................... 3-297

Table 3-46: Surry 2: Summary of Bobbin Inspections and Tube Plugging......................... 3-301

Table 3-47: Surry 2: Causes of Tube Plugging ................................................................. 3-302

Table 3-48: Surry 2: Tubes Plugged for Indications Other Than AVB Wear...................... 3-303

Table 3-49: Turkey Point 3: Summary of Bobbin Inspections and Tube Plugging ............. 3-306

Table 3-50: Turkey Point 3: Causes of Tube Plugging...................................................... 3-307

Table 3-51: Turkey Point 3: Tubes Plugged for Indications Other Than AVB Wear........... 3-308

Table 3-52: Turkey Point 4: Summary of Bobbin Inspections and Tube Plugging ............. 3-312

Table 3-53: Turkey Point 4: Causes of Tube Plugging...................................................... 3-313

Table 3-54: Turkey Point 4: Tubes Plugged for Indications Other Than AVB Wear........... 3-314

Table 4-1: Model D5: Total Number and Percentage of Tubes Plugged (12/2013) ........... 4-18

Table 4-2: Model D5: Number of Tubes Plugged as a Function of Mechanism 

(Detailed) (12/2013).......................................................................................... 4-19

Table 4-3: Model D5: Cumulative Plugging per Year ........................................................ 4-20

Table 4-4: Model D5: Plugging per Year........................................................................... 4-21

Table 4-5: Model D5: Cumulative Plugging per RFO (12/2013) ........................................ 4-22

Table 4-6: Model D5: Number of Tubes Plugged as a Function of Mechanism per Year 

(Detailed).......................................................................................................... 4-23

Table 4-7: Model D5: Number of Tubes Plugged as a Function of Mechanism per Year 

(Summary)........................................................................................................ 4-24

Table 4-8: Model D5: Percentage of Tubes Plugged as a Function of Mechanism per 

Year.................................................................................................................. 4-25

Table 4-9: Model F: Total Number and Percentage of Tubes Plugged (12/2013).............. 4-26

Table 4-10: Model F: Number of Tubes Plugged as a Function of Mechanism (Detailed) 

(12/2013) .......................................................................................................... 4-27

Table 4-11: Model F: Cumulative Plugging per Year........................................................... 4-28

Table 4-12: Model F: Plugging per Year ............................................................................. 4-29

Table 4-13: Model F: Cumulative Plugging per RFO (12/2013)........................................... 4-30

Table 4-14: Model F: Number of Tubes Plugged as a Function of Mechanism per Year 

(Detailed).......................................................................................................... 4-31

Table 4-15: Model F: Number of Tubes Plugged as a Function of Mechanism per Year..... 4-32

Table 4-16: Model F: Percentage of Tubes Plugged as a Function of Mechanism .....................

per Year............................................................................................................ 4-33

Table 4-17: Replacement Models: Total Number and Percentage of Tubes Plugged 

(12/2013) .......................................................................................................... 4-34

Table 4-18: Replacement Models: Number of Tubes Plugged as a Function of Mechanism 

(Detailed) (12/2013) ......................................................................................... 4-35

Table 4-19: Replacement Models: Cumulative Plugging per Year ...................................... 4-36

Table 4-20: Replacement Models: Plugging per Year......................................................... 4-37
xi

Table 4-21: Replacement Models: Cumulative Plugging Per RFO (12/2013)...................... 4-38

Table 4-22: Replacement Models: Number of Tubes Plugged as a Function of 

Mechanism per Year (Detailed) ........................................................................ 4-39

Table 4-23: Replacement Models: Number of Tubes Plugged as a Function of 

Mechanism per Year (Summary) ...................................................................... 4-40

Table 4-24: Replacement Models: Percentage of Tubes Plugged as a Function of 

Mechanism per Year (Summary) ...................................................................... 4-41

Table 4-25: Cracking in Thermally Treated Alloy 600 Tubes (12/2013)................................ 4-42

Table 4-26: Tube End Cracking in Thermally Treated Alloy 600 Tubes (12/2013) ............... 4-43

Table 4-27: Non Tube-End Cracking in Thermally Treated Alloy 600 Tubes (Sorted by 

Plant) (12/2013)................................................................................................ 4-44

Table 4-28: Non Tube-End Cracking in Thermally Treated Alloy 600 Tubes (Sorted by 

Location) (12/2013)........................................................................................... 4-45

Table 4-29: Wear at the AVBs (12/2013) ............................................................................. 4-46

Table 4-30: All Models: Total Number and Percentage of Tubes Plugged (12/2013).......... 4-47

Table 4-31: All Models: Number of Tubes Plugged as a Function of Mechanism 

(Detailed) (12/2013).......................................................................................... 4-48

Table 4-32: All Models: Number of Tubes Plugged as a Function of Mechanism 

(Summary) (12/2013)........................................................................................ 4-49

Table 4-33: All Models: Plugging per Year.......................................................................... 4-50

Table 4-34: All Models: Number of Tubes Plugged as a Function of Mechanism per 

Year (Detailed).................................................................................................. 4-52

Table 4-35: All Models: Number of Tubes Plugged as a Function of Mechanism per 

Year (Summary) ............................................................................................... 4-53

Table 4-36: All Models: Percentage of Tubes Plugged as a Function of Mechanism per 

Year (Summary) ............................................................................................... 4-54

xiii

EXECUTIVE SUMMARY

The susceptibility of steam generator tubes to degradation is affected by various factors, 

including the steam generator design, the operating environment (temperature and water 

chemistry), and operating and residual stresses. Two of the most important factors affecting the 

susceptibility of a tube to degradation are the tube material and the tube’s heat treatment.

Alloy 600 tubes installed in U.S. nuclear steam generators placed in service in the 1960s and 

1970s were typically only mill-annealed (passed through a furnace at a high temperature). 

Operating experience has shown that mill-annealed Alloy 600 is susceptible to degradation in 

the steam generator operating environment. The degradation includes pitting, wear, thinning, 

wastage, and stress corrosion cracking.

The extensive tube degradation at pressurized-water reactors (PWRs) with mill-annealed 

Alloy 600 steam generator tubes resulted in numerous tube leaks, about nine tube ruptures, 

many midcycle steam generator tube inspections, and the replacement of steam generators at 

numerous units. In addition, extensive tube degradation contributed to the permanent shutdown 

of other units: Haddam Neck Plant; Maine Yankee; Trojan Nuclear; Zion, Units 1 and 2; and 

San Onofre Nuclear Generating Station, Unit 1.

As mill-annealed Alloy 600 steam generator tubes began exhibiting degradation in the early 

1970s, the industry pursued improvements in the design of future steam generators to reduce 

the likelihood of corrosion. In the late 1970s, some mill-annealed Alloy 600 tubes were 

subjected to high temperatures for 10 to 15 hours to relieve fabrication stresses and to improve 

the tubes’ microstructure. This thermal treatment process was first used on tubes installed in 

replacement steam generators put into service in the early 1980s. Thermally treated Alloy 600 

is used in the steam generators at 17 units. At another unit, Callaway Plant, its original steam 

generators had thermally treated Alloy 600 tubes in the first 10 rows and mill-annealed Alloy 600 

tubes in the remaining rows. The original steam generators at Callaway were replaced in 2005 

because of degradation occurring in the mill annealed Alloy 600 tubes. The replacement steam 

generators at Callaway have thermally treated Alloy 690 tubes. Thermally treated Alloy 600 is 

used in about 26 percent of the operating PWRs (17 of 65).

The operating experience of units with mill-annealed Alloy 600 steam generator tubes is well 

documented. NUREG-1771, “U.S. Operating Experience with Thermally Treated Alloy 600 

Steam Generator Tubes,” was published in 2003 and summarized the operating experience with 

thermally treated Alloy 600 tubes as of December 2001. Section 3 of this report offers a 

detailed summary of the steam generator operating experience at each unit with thermally 

treated Alloy 600 steam generator tubes from December 2001 through December 2013, with 

some information from 2014 included. Section 4 of this report summarizes the overall operating 

experience with thermally treated Alloy 600 steam generator tubes since they were put in 

service. There is some information from early 2014 included in Section 3; however, it is typically 

not included in the tables and graphs contained within Section 4.

A review of operating experience identified only eight unplanned outages because of steam 

generator issues in units with thermally treated Alloy 600 tubes: three unplanned outages were 

because of primary-to-secondary leakage, and five were because of indications that a loose part 

may be present in a steam generator.
xiv

Of the 281,262 thermally treated Alloy 600 tubes placed in service at 18 units between 1980 

and 2013, only 2,734 tubes (1.0 percent) have been plugged. All together, these 18 units have 

operated for about 468 calendar years (as of December 2013). On the average each of these 

units has commercially operated for approximately 26 calendar years (as of December 2013). 

The dominant degradation mode for thermally treated Alloy 600 tubes is wear at tube supports. 

Of the approximately 2,700 tubes plugged, approximately 42 percent of the tubes were plugged 

because of wear at a support structure (e.g., an anti-vibration bar). Wear can also occur 

because of a tube interacting with loose parts.

Far fewer tubes have been plugged in the steam generators with second-generation tube 

materials (i.e., thermally treated alloy 600) than in earlier steam generators with comparable 

operating times. Improvements in the design and operation of the second-generation steam 

generators appear to have increased the resistance of the tubes to degradation, as evidenced 

by the general lack of any significant amounts of degradation. The increased corrosion 

resistance of the tubes is largely because of the thermal treatment process that has superseded 

the mill annealing process used in earlier steam generator designs. The relatively good 

operating experience with thermally treated Alloy 600 steam generator tubes can also be 

attributed to several factors besides the heat treatment: hydraulic expansion of the tubes into 

the tubesheet, the quatrefoil design of the openings in the tube support plates, and the stainless 

steel material used to fabricate the plates.

During the writing of this report, one noteworthy event occurred in a unit with thermally treated 

Alloy 600 steam generator tubes. In the spring of 2014, H.B. Robinson Steam Electric Plant, 

Unit 2, had an unplanned outage attributed to primary-to-secondary leakage. The maximum 

primary-to-secondary leakage rate observed before the shutdown of the unit was 142 liters per 

day (37.5 gallons per day). The primary-to-secondary leak was attributed to wear from a loose 

part introduced during maintenance. As a result, the total number of unplanned outages (as of 

December 2013) because of steam generator issues in units with thermally treated Alloy 600 

tubes is nine.
xv

ACKNOWLEDGMENTS

The author thanks Alan Huynh and Andrew Johnson for their assistance in compiling, 

summarizing, and graphing the information contained within this report. In addition, the author 

recognizes Thomas Morgan (former U.S. Nuclear Regulatory Commission employee) who 

compiled information and provided written analyses for this report.

xvii

ABBREVIATIONS AND ACRONYMS

ADAMS Agencywide Documents Access and Management System

ADI absolute drift indication

ADS absolute drift signal

ASCA Advanced Scale Conditioning Agent

ASTM American Society for Testing and Materials

AVB anti-vibration bar

BPC cold-leg flow distribution baffle (baffle plate cold)

BPH hot-leg flow distribution baffle (baffle plate hot)

CECIL Consolidated Edison Combined Inspection and Lance

CFR Code of Federal Regulations

CL cold-leg

CLP confirmed loose part

CM condition monitoring

DNT dent

ECT eddy current testing

EFPY effective full-power year

EPRI Electric Power Research Institute

FBC cold-leg flow distribution baffle

FBH hot-leg flow distribution baffle (flow baffle hot)

FDB flow distribution baffle

FOSAR foreign object search and retrieval

FS freespan

gpd gallons per day

gpm gallons per minute

HL hot-leg

iARC interim alternate repair criteria

ID inside diameter

IN Information Notice

kHz kilohertz

kPa kilopascals

ksi kilopound per square inch

lb pound

LCO limiting condition(s) of operation

lpd liters per day

lpm liters per minute

MAI multiple axial indication

MBM manufacturing burnishing mark

MCI multiple circumferential indications

mm millimeters

NDF no degradation found

NQI non-quantifiable indication

NRC Nuclear Regulatory Commission

OD outside diameter

ODI outside diameter indication

ODSCC outside diameter stress corrosion cracking

PLP possible loose part

PPC pressure pulse cleaning

psi pounds per square inch

psig pounds per square inch gauge (pressure relative to atmospheric pressure)
xviii

PWR pressurized-water reactor

PWSCC primary water stress corrosion cracking

RAI request for additional information

RCS reactor coolant systems

RFO refueling outage

RIS regulatory issue summary

RPC rotating pancake coil

SAI single axial indication

SCC stress corrosion cracking

SCI single circumferential indication

SG steam generator

SGOG Steam Generator Owners Group

STS standard technical specifications

TAC technical assignment control

TEC tube-end cold

TEH tube-end hot

TS technical specification

TSC tubesheet cold

TSH tubesheet hot

TSP tube support plate

TSTF Technical Specification Task Force

TT thermally treated

UBIB upper bundle in bundle

UEC ultrasonic energy cleaning

UT ultrasonic testing

UTEC ultrasonic test eddy current

VOL volumetric
1-1

1 INTRODUCTION

1.1 Safety Significance

In pressurized-water reactors (PWRs), the primary coolant removes the heat generated from the 

reactor core. Each primary coolant loop in U.S. PWR designs has one reactor coolant pump 

and one vertically mounted steam generator. Each unit contains two to four reactor coolant 

loops. The hot primary coolant enters and leaves the steam generator through nozzles in the 

hemispherical head(s) of the steam generator. The steam generator tubes supply the primary 

means for the transfer of heat from the primary system water to the water on the secondary side 

of the steam generator. This heat transfer boils the water on the secondary side of the steam 

generator. The primary coolant then returns to the reactor core through the reactor coolant 

pump, where it is reheated and the cycle is repeated.

Feedwater (secondary coolant) is pumped into the secondary or shell side of the steam 

generator, where it boils into steam. The steam exits the steam generator through an outlet 

nozzle and flows to the turbine generator, where it spins the turbine, generating electricity. After 

exiting the turbine, the steam is condensed into water and pumped back to the steam generator, 

where the cycle repeats. Figure 1-1 depicts the basic design of a PWR power plant with 

recirculating steam generators.

Steam generator tubes constitute well over 50 percent of the surface area of the primary 

pressure boundary in a PWR. This portion of the pressure boundary is an important element in 

the defense in depth against release of radioactive material from the reactor into the 

environment. Unlike other parts of the reactor coolant pressure boundary, the barrier to fission 

product release supplied by the steam generator tubes is not reinforced by the reactor 

containment. That is, fission products released through leaking or ruptured steam generator 

tubes can escape directly into the environment through the secondary side of the steam 

generator. Consequently, the integrity of the steam generator tubes must be ensured with high 

confidence.

In the event of primary-to-secondary leakage during normal operation or postulated accidents—

such as the rupture of the main steam line or feed line—leakage of reactor coolant through the 

tubes could contaminate the flow in these lines. In addition, leakage of primary coolant through 

openings in the steam generator tubes could deplete the inventory of water available for the 

long-term cooling of the core in the event of an accident.

Because of the potential consequences of primary-to-secondary leakage, regulatory limits exist 

on the amount of primary-to-secondary leakage permitted during normal operation. In addition, 

PWRs are designed such that operators can rapidly and effectively respond to 

primary-to-secondary leakage during power operation. For postulated accidents, 

primary-to-secondary leakage is assumed to exist and is assessed in evaluating the radiological 

consequences of postulated accidents such as a feedwater or steam line breaks.

Although limits exist for the amount of primary-to-secondary leakage during normal operation, it 

is possible for a tube to rupture during normal operation. Leakage from a ruptured tube can 

result in primary-to-secondary leak rates in the range of 378.5 to 2,650 liters per minute (lpm) 

(100 to 700 gallons per minute (gpm)) depending on the severity of the tube rupture and the 

capacity of the safety injection/charging system pumps. The design of PWRs allows operators 

to respond rapidly and effectively to the accidental rupture of one steam generator tube during 
1-2

power operation. Although PWR designs consider the rupture of a tube during normal power 

operation, they do not account for a tube rupture concurrent with a postulated accident.

1.2 General Steam Generator Design

As of December 2014, the United States had 65 operating PWR units. The three major 

designers were Westinghouse, Combustion Engineering, and Babcock and Wilcox. The 

number of steam generators at each unit ranges between two and four. These steam 

generators are of two basic designs: recirculating or once-through. Westinghouse and 

Combustion Engineering used recirculating steam generators in their PWR designs while 

Babcock and Wilcox used once-through steam generators. Figure 1-2 depicts a typical 

recirculating steam generator and Figure 1-3 depicts a typical once-through steam generator. 

Recirculating steam generators have tubes that are in the shape of a “U” and are used at 

59 PWRs. Once-through steam generators have straight tubes and are used at six PWRs. 

A listing of units by PWR vendor type is included in Table 1-1.

Recirculating steam generators are designed with an evaporator section and a steam drum 

section. The steam drum section is the upper part of the steam generator containing the 

moisture separators. The evaporator section, sometimes called the “tube bundle,” is an inverted 

U-tube heat exchanger containing the tubes. Figure 1-4 shows typical nomenclature used for 

the U-bend region of a tube. The evaporator section may have a preheater region depending 

on the model. The preheater, which is a series of baffle plates around a portion of the cold-leg 

side of the steam generator, enhances heat transfer to the incoming feedwater. Figure 1-2 

depicts a typical recirculating steam generator without a preheater, and Figure 1-5 depicts one 

with a preheater. No moisture separating equipment exists in a once-through steam generator 

because the steam becomes superheated as it rises on the secondary side of the once-through 

steam generator.

Because all steam generators in units with thermally treated Alloy 600 tubes are recirculating 

steam generators, the following discussion focuses on the design and operation of recirculating 

steam generators.

The recirculating steam generators in the United States are vertical shell and U-tube heat 

exchangers with integral moisture-separating equipment (Figures 1-2 and 1-5). Heat is 

transferred from the hot primary coolant to the water on the secondary side of the steam 

generator as the primary coolant flows through the inverted U-tubes. The primary coolant 

enters and leaves the steam generators through nozzles in the hemispherical bottom head of 

the steam generator. Heat transfer from the primary system to the water on the secondary side 

of the steam generator is accomplished primarily through the steam generator U-tubes.

The main components of the primary side of a recirculating steam generator are the channel 

head, the divider plate, the tubesheet, and the tubes. The channel head is the region where the 

primary coolant enters and exits the steam generator (Figure 1-6). The primary coolant exits 

the steam generator after it flows through the tubes. A plate in the channel head below the 

tubesheet, called a “divider plate,” separates the inlet and outlet primary coolant and directs the 

flow through the tubes. The tubesheet is a thick low alloy steel (typically SA-508, Class 2a) 

plate, typically 53 to 61 cm (21 to 24 in.) thick, which serves as the attachment point for the 

tubes. About 6.35 mm (0.25 in.) of corrosion resistant cladding is typically deposited on the 

primary face of the tubesheet.
1-3

The tubes in operating steam generators in the United States are one of three types: 

mill-annealed Alloy 600, thermally treated Alloy 600, or thermally treated Alloy 690. Early steam 

generator designs used tubes fabricated from Alloy 600, which was typically mill annealed by 

passing the tubes through a furnace to enhance the material’s resistance to corrosion. The next 

generation of steam generators used thermally treated Alloy 600 tubing. The thermal treatment 

process further improved the tubes’ resistance to corrosion. The third generation uses thermally 

treated Alloy 690 tubing. This tubing is regarded as more resistant to corrosion than the other 

tubing material and is the material of choice for steam generators in the United States. A listing 

of operating units by tube material is included in Table 1-2.

The number of tubes in each steam generator varies from unit to unit. The number of tubes can 

vary from about 3,200 tubes to 15,700 tubes. For units with thermally treated Alloy 600 tubes, 

the number of tubes in a steam generator varies from approximately 3,200 to nearly 5,700 per 

steam generator. 

The tubes are expanded into the tubesheet for either a portion of the tubesheet (partial depth 

expansion) or for the entire thickness of the tubesheet (full-depth expansion). Figure 1-7 

depicts partial and full depth tube expansions in the tubesheet region. The preference is to use 

full-depth tube expansions such that no crevice exists between the tube and the tubesheet. 

A crevice in this region can result in the concentration of chemical impurities between the tube 

and the tubesheet and can lead to corrosion of the tubes. As of December 2014, all 

recirculating steam generators have tubes that were expanded for the full depth of the 

tubesheet (i.e., full-depth tube expansions). Some once-through steam generators have tubes 

that were only partially expanded into the tubesheets.

Several methods have been used to expand the tube into the tubesheet. Early steam 

generators had tubes that were expanded by mechanical rolling. Subsequent steam generators 

had tubes expanded into the tubesheet by explosive means using either the Westinghouse 

explosive tube expansion method (commonly referred to as WEXTEX expansions) or the 

Combustion Engineering explansion process. The preferred method for expanding the tubes 

into the steam generators is by hydraulic means. Using a hydraulic technique to expand the 

tubes in the tubesheet is expected to result in less stress at the expansion transition and 

therefore limit the susceptibility of this location to stress-corrosion cracking when compared to 

tubes that were expanded with other methods (e.g., mechanical rolling). The tubes in all units 

with thermally treated Alloy 600 tubes were expanded into the tubesheet by hydraulic means. 

A listing of the units by tube material and method of expansion (including whether it is a full or 

partial depth expansion) is included in Table 1-3.

The tube-to-tubesheet joint consists of the tube, which is expanded against the wall in one of 

the holes in the tubesheet; the tube-to-tubesheet weld at the tube end; and the tubesheet. The 

joint in steam generators with thermally treated Alloy 600 tubing was designed as a welded joint 

and not as a friction or expansion joint. That is, the weld forms the boundary between the 

primary and secondary sides of the plant. It was designed to transmit the entire end-cap 

pressure load (i.e., axial force because of the difference in primary and secondary side 

pressure) during normal operating and design basis accident conditions from the tube to the 

tubesheet with no credit taken for the friction developed between the hydraulically expanded 

tube and the tubesheet.

In steam generators with thermally treated Alloy 600 tubing, the tubes are installed into the 

tubesheet, tack expanded into the bottom of the tubesheet for about 2.54 centimeters (cm) (1 

inch (1-in.)) above the bottom of the tubesheet, welded to the bottom or primary face of the 
1-4

tubesheet, and then hydraulically expanded for the full depth of the tubesheet. The tack 

expansion facilitates the welding of the tube to the tubesheet. The transition from the expanded 

portion of tube within the tubesheet to the unexpanded portion of the tube at the top of the 

tubesheet is referred to as the expansion transition region of the tube. Figure 1-8 depicts a 

typical tube-to-tubesheet joint.

All of the tubes in steam generators in Westinghouse-designed PWRs are U-shaped, while the 

larger radius tubes in some Combustion Engineering designed PWRs have two 90-degree 

bends (sometimes referred to as square bends). Figure 1-9 depicts a recirculating steam 

generator with both U-shaped and square bend tubes. Although the steam generators at some 

Combustion Engineering designed PWRs have square bends, all tubes are typically referred to 

as “U-tubes.” For the steam generators with tubes that have two 90-degree bends, most of the 

tubes are square bends rather than U-shaped. The U-shaped tubes in these steam generators 

are in the lower row tubes (i.e., tubes with smaller bend radii). All of the units with thermally 

treated Alloy 600 tubes are Westinghouse designed PWRs with Westinghouse designed steam 

generators and have U-shaped tubes.

The tubes are supported above the tubesheet both in the straight (vertical) portion of the tube 

and in the U-bend (including square bend) region of the tube. Plates support the tubes in the 

straight span (or the vertical section) of the tubes in some recirculating and in all once-through 

steam generators. In the straight span of the other recirculating steam generators, a lattice grid 

(sometimes referred to as “egg crate”) supports the tubes. The tube supports in the straight 

span are at a number of fixed axial locations along the length of the tube. In the bent region of 

the tube, various shaped bars and plates support the tubes. All of the units with thermally 

treated Alloy 600 tubes have tubes supported by tube support plates along the straight portion 

of the tube and with V-shaped bars in the U-bend region of the tube. These V-shaped bars are 

called “anti-vibration bars.”

In the horizontal tube support plates, which support the straight (or vertical) section of the tube, 

there are openings through which the tubes pass. Figure 1-10 depicts the various types of 

openings used for most tube supports. In early steam generator designs, these openings in the 

horizontal tube supports tended to be circular holes (and they were typically referred to as 

“drilled-hole tube support plates”). Because the crevice between the tube and the drilled hole in 

the tube support plate can result in concentration of chemical impurities that can lead to 

corrosion, more advanced designs changed these openings to various shaped holes to limit the 

crevice and improve the flow through the opening so as to reduce the potential for concentrating 

chemical impurities. These openings are created by a broaching process and typically are 

trefoil or quatrefoil holes. A trefoil hole has three lands that are in close proximity to the tube 

and a quatrefoil hole has four lands.

Early tube support plates and lattice grid supports were fabricated from carbon steel. Because

of corrosion of the carbon steel and the resultant denting of the tubes, the tube support material 

in most subsequent steam generator designs was changed to stainless steel. Denting is the 

plastic deformation (constriction or mechanical deformation) of the steam generator tubes and 

can be caused by the buildup of corrosion product between the tube and the tube support plate 

in the crevice between the hole in the support plate and the tube. Denting can result in 

increased susceptibility of the tube to cracking because of increased stresses at the dented 

location. The corrosion resistance of the stainless steel tube supports is expected to eliminate 

the potential for tube denting. With the exception of Beaver Valley Power Station, Unit 2 (with 

mill-annealed Alloy 600 tubes), and Davis-Besse Nuclear Power Station (once-through steam 

generators), all other operating steam generators have stainless steel tube supports. All steam 
1-5

generators with thermally treated Alloy 600 tubes have tube support plates that were 

constructed from stainless steel. Table 1-4 lists the units by tube support material and the 

shape of most of the tube support openings (since some units have a mixture of the type of 

openings used in the plates).

1.3 Steam Generator Program

1.3.1 Regulatory Requirements

Steam generator tubes constitute a substantial portion of the reactor coolant pressure boundary 

and also play a role in fission product containment. As a result, their integrity is important to the 

safe operation of a PWR. For ensuring steam generator tube integrity, the U.S. Nuclear 

Regulatory Commission (NRC) uses a regulatory framework that is largely performance based. 

In the 1990s, NRC staff, with external stakeholder involvement, began efforts to improve the 

steam generator regulatory framework. Because of these efforts, the NRC and industry 

developed modified generic technical specifications for addressing steam generator tube 

integrity. The generic changes to the standard technical specifications (STS) were submitted by 

the Technical Specification Task Force (TSTF) and are designated TSTF-449, “Steam 

Generator Tube Integrity.” The NRC reviewed and approved Revision 4 to TSTF-449. As of 

September 2007, all PWR units in the United States had adopted technical specification 

requirements modeled after TSTF-449. However, licensees of all PWR units had been 

voluntarily putting similar “requirements” into place since the 2000 timeframe. Section 1.7 

reflects most of the steam generator inspection, repair, and reporting requirements included in 

TSTF-449. Because all the units have technical specifications modeled after TSTF-449, the 

steam generator tube inspection, repair, and reporting requirements are similar at all PWR units.

The technical specifications require developing a steam generator program to ensure that units 

maintain steam generator tube integrity for the operating interval between tube inspections. The 

technical specifications define what constitutes tube integrity through the establishment of 

performance criteria, and the specifications require monitoring primary-to-secondary leakage, 

inspecting tubes periodically, assessing the condition of the tubes relative to the performance 

criteria, and defining criteria for plugging tubes.

The requirements in TSTF-449 are largely performance based; however, they are 

supplemented with some prescriptive requirements. The framework recognizes that there are 

three combinations of tube materials and heat treatments used in the United States and that the 

operating experience depends, in part, on the type of material used. Because the approach is 

performance-based, it can readily accommodate new or unexpected degradation mechanisms 

and advances in nondestructive examination technology. The program, however, is not 

intended to address certain forms of degradation that must be prevented by design such as 

rapidly propagating degradation (e.g., high cycle fatigue). This approach includes programmatic 

elements to ensure that tubes are adequately monitored and maintained relative to the 

structural and leakage performance criteria.

The technical specifications are performance-based because they do not specify the details of 

how to achieve the performance criteria. There are three steam generator performance criteria: 

structural integrity, accident-induced leakage, and operational leakage. Steam generator tube 

integrity is maintained when all three of these criteria are met, and steam generators can be 

operated only when tube integrity is maintained. The structural and accident-induced leakage 
1-6

performance criteria were based on the design and licensing basis of the plants. The NRC 

based its operational leakage performance criterion on engineering judgment that considered 

the need to avoid unnecessary unit shutdowns while limiting the frequency of exceeding the 

structural integrity performance criterion.

The structural integrity performance criterion requires that margins against tube burst and 

collapse be maintained during normal operations, transients, and design-basis accidents, 

including a combination of accidents. The NRC developed these criteria considering design 

codes such as that of the American Society of Mechanical Engineers Boiler and Pressure 

Vessel Code.

The NRC has approved some exceptions to the standard structural integrity performance 

criteria (Section 1.7) on a unit-specific basis. These exceptions relate to tube repair criteria 

carried out in units with mill-annealed Alloy 600 tubes. These exceptions generally have 

involved adopting a probabilistic criterion for demonstrating tube integrity during accident 

conditions (e.g., the probability of tube burst, given a steam line break, shall not exceed 1×10-2

).

The accident-induced leakage performance criterion requires limiting the amount of 

primary-to-secondary leakage that would occur during a design-basis accident, other than a 

tube rupture, to that which was evaluated as part of the unit’s licensing basis. Demonstrating 

compliance with the accident-induced leakage performance criterion, therefore, requires a 

calculation of the amount of leakage expected during various design-basis accidents. The 

calculated amount of leakage must be less than that assumed in the accident analyses. 

Typically, units were designed assuming that primary-to-secondary leakage during postulated 

accidents would be less than 3.79 lpm (1 gpm). These particular licensing basis analyses were 

performed to demonstrate that the radiological consequences associated with these 

design-basis accidents meet the limits in (1) Title 10 of the Code of Federal Regulations

(10 CFR) Part 100, “Reactor Site Criteria,” for offsite doses, and (2) General Design 

Criterion 19, “Control Room,” in Appendix A, “General Design Criteria for Nuclear Power 

Plants,” to 10 CFR Part 50, “Domestic Licensing of Production and Utilization Facilities,” for 

control room operator doses; or (3) some fraction thereof, as appropriate to the accident; or 

(4) the NRC-approved licensing bases. The accident-induced leakage performance criterion is 

also intended to ensure that the amount of leakage caused by specific severe accident 

scenarios will remain at a level that will not increase risk.

The NRC has also approved exceptions to the accident-induced leakage performance criteria 

on a unit-specific basis. These exceptions are associated with tube repair criteria put into place 

in units with mill-annealed Alloy 600 tubes. These exceptions generally have allowed more 

accident-induced leakage during steam-line break accidents, provided the risk associated with 

such leakage during specific severe accident scenarios remains acceptable.

The operational leakage performance criterion requires limiting primary-to-secondary leakage to 

a specific value. The limit is unit-specific, but it is no greater than 568 liters per day (lpd)

(150 gallons per day (gpd)) through any one steam generator. Although this criterion does not 

ensure tube integrity, it has been effective in limiting the frequency of tube ruptures and 

providing an indirect indicator of tube structural and accident-induced leakage integrity. This

criterion is important, because it can be monitored while the unit is operating.

The technical specifications require that licensees monitor primary-to-secondary leakage during 

operation. This specification is performance based, because it does not prescribe how to 

monitor for this leakage. A related requirement is that licensees must monitor leakage at least 
1-7

every 72 hours. From a practical standpoint, licensees generally monitor for 

primary-to-secondary leakage continuously by monitoring various streams (the steam generator 

blowdown, each main steam line, and the condenser air ejector exhaust) and supplement this 

continuous sampling through periodically sampling and analyzing the steam generator 

secondary water for the presence of, or increases in, radioactivity. Most, if not all, units have 

leakage monitoring programs that are modeled after the Electric Power Research Institute’s 

“PWR [Pressurized-Water Reactor] Primary-to-Secondary Leak Guidelines.” In addition, the 

technical specifications limit the specific activity of the secondary coolant (typically to 

0.1 microcurie per gram of dose equivalent iodine-131). The specific activity is used in 

determining the radiological consequences of primary-to-secondary leakage.

The steam generator inspection requirements in the technical specifications contain both 

performance-based and prescriptive elements. From a performance-based perspective, 

licensees are required to assess the types and locations of flaws to which their tubes may be 

susceptible, and the inspection method, scope, and the interval between inspections must be 

sufficient to maintain tube integrity until the next inspection. The tubes are inspected with the 

intent of detecting mechanical or corrosive damage to the tubes from manufacturing or 

in-service conditions. The inspections also offer a means of characterizing the nature and 

cause of any steam generator tube degradation so that corrective measures can be taken. 

In addition to this performance-based aspect of the inspection requirements, prescriptive 

inspection requirements also exist. The NRC established these prescriptive requirements to 

ensure sufficient monitoring of the condition of the tubes. These requirements reflect the 

improvement in steam generator performance for the various combinations of tube material and 

heat treatment. In addition, the NRC based these prescriptive inspection requirements on 

qualitative engineering considerations and experience. 

There have been some modifications to the standard inspection requirements at some units. 

These modifications generally involve specifying inspection requirements associated with tube 

repair criteria and tube repair methods. For example, many of the units with mill-annealed and 

thermally treated Alloy 600 tubes have adopted requirements that limit the extent of inspection 

in the tubesheet region (e.g., in these recirculating steam generators, only the uppermost 

portion of the tube in the tubesheet is examined, rather than the whole length of the tube in the 

tubesheet).

For a performance-based approach to be effective, licensees must periodically verify that they 

are satisfying the performance criteria. As a result, the technical specifications require an 

assessment to confirm that the tubes have adequate structural and leakage integrity. The 

licensee must perform this assessment during each outage in which the steam generator tubes 

are inspected, plugged, or repaired.

The periodic assessment of the inspection results is a critical element of the performance-based 

strategy. It requires an assessment of whether the tubes exhibited adequate structural and 

leakage (accident-induced) integrity during the prior operating interval. This type of assessment 

is referred to as condition monitoring. In addition to the condition monitoring assessment, the 

condition of the tubes is projected from the current inspection to the next inspection to ensure 

that the tubes will retain adequate integrity for the next operating interval. This type of 

assessment is referred to as an operational assessment. It takes place because of the 

performance-based framework of the technical specifications and because the technical 

specifications specify the maximum amount of time that is permitted between inspections. 

In the event that the condition monitoring assessment indicates that tube integrity was not 
1-8

maintained, it would indicate the need for corrective action. Corrective actions could include 

more frequent steam generator tube inspections. Exceeding a performance criterion would 

require reporting to the NRC, under 10 CFR 50.72, “Immediate Notification Requirements for 

Operating Nuclear Power Reactors,” or 10 CFR 50.73, “Licensee Event Report System.” 

The repair criterion (also referred to as the plugging limit or repair limit) in the technical 

specifications is prescriptive. At a minimum, all units have a depth-based tube repair criterion 

that requires tubes with flaws that exceed a specific depth to be removed from service. This 

criterion is consistent with the performance criteria; however, it may be necessary to remove 

flawed tubes from service even before they exceed the plugging/repair limit. This may be 

necessary because the criterion was developed with specific assumptions on flaw orientation, 

the potential for flaw growth during the next operating interval, and uncertainties in measuring 

the size of the flaw. Plugging tubes before they exceed the plugging/repair limit may be

necessary in instances where longer cycle lengths (than those assumed in the development of 

the depth-based plugging limit) are anticipated, where the growth rate of the flaws is higher than 

assumed, or the uncertainties in measuring the size of the flaw are greater.

Several units have alternatives to the depth-based repair criterion. These alternatives are only 

in place in units with mill-annealed and thermally treated Alloy 600 tubes. These include 

alternatives that allow tubes to remain in service if all flaws are in the lower portion of the tube 

within the tubesheet (at units with mill annealed Alloy 600 tubes and thermally treated Alloy 600 

tubes) and voltage-based repair criteria for flaws at tube support plates (at Beaver Valley 2,

which has mill annealed Alloy 600 tubes).

While adopting and carrying out the TSTF-449 requirements, a number of issues related to the 

implementation of the accident-induced leakage performance criterion and the tube inspection 

requirements were identified. As a result, NRC staff clarified its position on these issues in 

Regulatory Issue Summaries 2007-20, “Implementation of Primary-to-Secondary Leakage 

Performance Criteria,” dated August 23, 2007; and 2009-04, “Steam Generator Tube Inspection 

Requirements,” dated April 3, 2009.

Regulatory Issue Summary 2007-20 clarified the following issues:

• Potential primary-to-secondary leakage for all design-basis accidents should not exceed 

the value assumed in the accident analyses.

• Accident-induced leakage includes leakage existing before the accident occurred.

• The temperature at which the volumetric primary-to-secondary flow rate (i.e., leak rate) 

is evaluated should be consistent with the temperature assumed in the accident 

analyses.

• The assumptions about the pre- and post-accident leakage rate must be satisfied.

• The normal operating primary-to-secondary leak rate may need to be kept well below the 

normal operating primary-to-secondary leak rate limit to ensure the unit does not exceed 

the accident-induced leakage performance criterion.

• The term “most limiting accident” should be clearly defined (e.g., most limiting, since it 

produces the largest leak rate, or most limiting, since it is the closest to the regulatory 

limit on radiological doses).
1-9

• In the event that a primary-to-secondary leak rate is not assumed for each steam 

generator, licensees should institute appropriate controls to ensure the unit does not 

exceed the accident-induced primary-to-secondary leak rate for all steam generators.

• Exceptions (increases) to the risk-informed 3.79 lpm (1 gpm) limit on accident-induced 

leakage are evaluated on a case-by-case basis.

Regulatory Issue Summary 2009-04 clarified the following issues:

• In the event that a new potential degradation mechanism is identified after the first 

inspection in the sequential period, a prorated sample for the remaining portion of the 

sequential period is appropriate for this potentially new degradation mechanism, rather 

than inspecting all the tubes; however, the scope of inspections should be sufficient to 

ensure tube integrity.

• The starting point for the second and subsequent sequential periods shall be after the 

accumulation of the effective full-power months listed in the technical specifications 

(e.g., the starting point for the 90 effective full-power month period is 120 effective 

full-power months after the completion of the first in-service inspection).

• The inspection nearest the midpoint of the period can either be before or after the 

midpoint; however, the inspection at the end of the period must take place during an 

outage before the end of the period. 

Because of some of these issues, the industry proposed modifications to the generic steam 

generator technical specifications requirements contained in TSTF-449. These new 

requirements were contained in TSTF-510, Revision 2, “Revision to Steam Generator Program 

Inspection Frequencies and Tube Sample Selection,” which the NRC reviewed and approved. 

The modifications contained in TSTF-510 included editorial corrections as well as changes and 

clarifications intended to improve internal consistency, consistency with carrying out industry 

documents, and usability without changing the intent of the TSTF-449 requirements. One of the 

more significant changes was the revision to the inspection frequencies for when 100 percent of 

the tubes must be inspected. Section 1.8 reflects the main steam generator inspection, repair, 

and reporting requirements included in TSTF-510.

Of the units with thermally treated Alloy 600 steam generator tubes, only Catawba Nuclear 

Station, Unit 2, and Point Beach Nuclear Plant, Unit 1, have not applied to modify their technical 

specifications based on TSTF-510 as of December 2014. The reviews for Indian Point Nuclear 

Generating Unit 2 and Salem Nuclear Generating Station, Unit 1, were on-going as of 

December 2014, and all other units with thermally treated Alloy 600 had adopted technical 

specifications based on TSTF-510.

1.3.2 Steam Generator Tube Inspections

Eddy current testing (ECT) is the primary means for inspecting steam generator tubes. This 

method involves inserting a test coil inside the tube (i.e., the primary side of the tube) and 

pushing and pulling the coil so that it traverses the tube length. The test coil is then “excited” by 

alternating current, thereby creating a magnetic field that induces eddy currents in the tube wall. 

Disturbances of the eddy currents caused by flaws in the tube wall (such as cracks, holes, 

thinned regions, and other defects) produce corresponding changes in the electrical impedance 

as seen at the test coil terminals. Instruments translate these changes in test coil impedance 
1-10

into an output that the data analyst can monitor. The observed phase angle response of this 

output signal can determine the depth of certain types of flaws. Tube specimens with artificially 

induced flaws of known depth calibrate the test equipment. Geometric discontinuities (such as 

the expansion transition and dents) and support structures (such as the tubesheet and tube 

support plates) also produce eddy current signals, making it very difficult to discriminate flaw 

signals at these locations. NUREG/CR-6365, “Steam Generator Tube Failures” contains a 

discussion of some of the basic principles of ECT.

Bobbin coil eddy current probes are routinely used to inspect steam generator tubes. The 

bobbin coil probe permits a rapid screening of the tube for axially oriented and volumetric forms 

of degradation; however, it has several limitations:

• a general inability to permit characterization of identified degradation (e.g., axial, 

circumferential, or volumetric; single or multiple axial indications)

• relative insensitivity to detecting circumferentially oriented tube degradation

• limited capability to detect degradation in regions with geometric discontinuities 

(e.g., expansion transitions, U-bends, and dents) and deposits

Because of the bobbin coil’s limitations, inspectors use additional probes. Inspections of steam 

generator tubes generally employ both a bobbin coil probe and an extra probe, such as a 

rotating probe, or an array probe (array probes also have bobbin coils associated with the 

probe). Other types of probes are occasionally used for further characterizing eddy current 

signals (e.g., a Ghent probe which uses transmit-receive technology). The bobbin coil probe 

can be pulled through a tube at speeds exceeding 1.02 m (40 in.) per second. Typical rotating 

probes are pulled through the tubes at much lower speeds (e.g., 2.54 cm (1 in. per second) and 

the speed of an array probe is between that of a rotating probe and a bobbin probe.

Rotating probes generally contain one to three specialized test coils. The coils used in the 

rotating probe head during an inspection will depend on many factors including optimizing the 

coils for detecting the forms of degradation to which a tube may potentially be susceptible. The 

coils used on a rotating probe may include (1) a pancake coil that is sensitive to both axially and 

circumferentially oriented degradation, (2) an axially wound coil that is sensitive to 

circumferentially oriented degradation, (3) a circumferentially wound coil that is sensitive to 

axially oriented degradation, and (4) a plus-point coil that reduces the effects of geometry 

variations in the tube and is sensitive to both axially and circumferentially oriented degradation.

Each of the above-mentioned test coils can be designed and driven at specific frequencies to 

ensure an optimal inspection of the tubing. In general, lower frequencies are better for detecting 

degradation initiating from the outside diameter of the tube, while higher frequencies are better 

for detecting degradation initiating from the inside diameter of the tube. The advantages of the 

rotating probes are that they are sensitive to circumferentially oriented degradation (which the 

bobbin coil probe is not), can better characterize the defect, and are less sensitive to geometric 

discontinuities. The major disadvantage of the rotating probes is their slow inspection speed 

(2.54 cm, or 1 in. per second). Because of this slow inspection speed, rotating probes are only 

used at specific locations (e.g., U-bends, sleeves, expansion transitions, dents, locations where 

there is a bobbin coil probe indication, locations where a more sensitive inspection is needed, 

and locations susceptible to circumferential cracking).
1-11

In addition to bobbin and rotating probes, an array probe is also used at some units. The array 

probe has many of the advantages of the rotating probes, but operates at much higher speeds 

than a rotating probe.

1.3.3 Tube Plugging/Repair Limits

A limit on the size of a flaw in a tube is specified in the unit’s technical specification. This limit is 

typically referred to as the plugging/repair limit. The typical steam generator tube 

plugging/repair limit is based on the minimum tube wall thickness needed to ensure structural 

margins are maintained consistent with Regulatory Guide 1.121, “Bases for Plugging Degraded 

PWR Steam Generator Tubes.” Margins must be maintained during both normal operating and 

postulated accident conditions. The plugging/repair limit allows for eddy current measurement 

error and incremental degradation that may occur before the next in-service inspection of the 

tube. The plugging/repair limit is conservatively established according to an assumed mode of 

degradation in which the walls are uniformly thinned over a significant axial length of tubing. 

These limits do not consider other structural margins associated with flaws, such as 

small-volume thinning and pitting, and they do not consider the external structural constraints 

against gross tube failure that may be supplied by support structures, such as the tubesheet 

and tube support plates.

Because of its conservative basis, the depth-based plugging/repair limit tends to be overly 

restrictive for highly localized flaws (such as stress corrosion cracks) and flaws within the 

tubesheet. As a result, the industry has developed, and the NRC has approved, various 

alternative plugging/repair limits for specific forms of steam generator tube degradation.

All units have a depth-based plugging/repair limit that is applicable to all forms of steam 

generator tube degradation. The depth-based plugging/repair limit varies from unit to unit, but is 

typically 40 percent of the tube wall thickness. That is, tubes with flaws with depths greater than 

or equal to 40 percent of the tube wall thickness must be plugged (or repaired, if the NRC has 

approved a repair method for that unit). For operating units with thermally treated Alloy 600 

steam generator tubes, only Robinson 2 does not have the standard 40-percent depth-based 

plugging/repair limit in their technical specifications. Robinson 2 has a depth-based 

plugging/repair limit of 47-percent throughwall.

Alternatives to the depth-based plugging/repair limit have been approved for some units. These 

alternatives have usually been developed in response to finding steam generator tube 

degradation attributed to corrosion processes. Several different alternate repair criteria (or 

plugging/repair limits) have been approved for units with mill-annealed Alloy 600 steam 

generator tubes; however, industry did not pursue alternates for units with thermally treated 

Alloy 600 steam generator tubes until the early 2000s.

Until the fall of 2004, no instances of stress corrosion cracking affecting the region of the tube 

contained within the tubesheet had been reported in the United States at units with thermally 

treated Alloy 600 tubing. As a result, most units were not inspecting the entire portion of the 

tube within the tubesheet region with eddy current test probes capable of reliably detecting 

stress corrosion cracking. Rather, probes capable of detecting stress corrosion cracking were 

only being used in a region extending from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of 

the tubesheet. This region includes the tube-expansion transition, which contains significant 

residual stress, and which is considered a likely location to develop stress corrosion cracking. 

In addition, it is difficult to detect wear in this region with a bobbin coil.
1-12

In the fall of 2004, crack-like indications were found in tubes in the tubesheet region at one unit 

with thermally treated alloy 600 tubing. The crack-like indications were found in bulges (or 

over-expansions) in the tubesheet region and also near the tube end.

Given the detection of these cracks and subsequent cracks detected at other units with 

thermally treated Alloy 600 tubes, the U.S. industry extended the eddy current inspection region 

to the bottom of the tubesheet. The industry also sought an approach to relax the tube 

inspection requirements and plugging/repair limits for a portion of the tube within the tubesheet. 

The basis for this relaxation was that the interference friction fit between the tube and the 

tubesheet would ensure tube integrity provided that there was at least a minimum engagement 

distance of sound (unflawed) material between the tube and the tubesheet. That is, the friction 

between the tube and the tubesheet would hold the tube in place and limit leakage to 

acceptable levels. As a result, reliance on the tube-to-tubesheet weld to supply this function 

would no longer be needed. The minimum engagement distance is referred to as the H* 

(pronounced H-star) distance. The “H” reflects that the tube was hydraulically expanded into 

the tubesheet. Figure 1-11 graphically depicts the H* distance in the tube-to-tubesheet joint.

From about 2004 through 2012, the industry submitted various requests to limit the extent of 

tube inspections in the tubesheet region thereby allowing flaws that may be in the region not 

required to be inspected to remain in service. Because of technical issues identified during the 

review of these submittals, NRC staff did not give permanent approval initially for an 

H* amendment. Rather, NRC staff permitted implementation for a short period of time (typically 

one fuel cycle), which considered, in part, the state of degradation in the steam generator and 

the technical merits of the proposal. In the 2008-2009 timeframe, NRC staff questioned the 

overall validity of H*. As a result, amendments approved at that time relied on the orientation of 

the flaws (axial or circumferential), the size (e.g., circumferential extent) of the flaws, and the 

location of the flaws within the tubesheet. These criteria were referred to as the “interim 

alternate repair criteria” (iARC). After the industry addressed NRC staff technical concerns, 

NRC staff approved its first permanent H* amendment in 2012. A summary of the 

H* amendments approved at all units with thermally treated Alloy 600 tubing is supplied in Table 

1-5. All units with thermally treated Alloy 600 tubes except for Point Beach 1 currently have H* 

approved on a permanent basis.

With the adoption of H*, the plant’s technical specifications were modified. Specifically, for the 

permanent H* amendments, the tube plugging/repair limits were modified to require that the 

following alternate tube repair criteria shall be applied as an alternate to the depth-based 

plugging/repair limit:

Tubes with service-induced flaws located greater than x inches below the top of the 

tubesheet do not require plugging. Tubes with service-induced flaws located in the 

portion of the tube from the top of the tubesheet to x inches below the top of the 

tubesheet shall be plugged on detection.

The “x” is the H* distance in Table 1-5, and is unit-specific. 

In addition, the tube inspection requirements in the technical specifications were modified to 

indicate:

Portions of the tube below x inches below the top of the tubesheet are excluded from 

this requirement.
1-13

Lastly, the reporting requirements in the technical specifications were modified as part of the 

permanent H* amendments to include the following reporting requirements:

• The primary-to-secondary leakage rate observed in each steam generator (if it is not 

practical to assign the leakage to an individual steam generator, the entire 

primary-to-secondary leakage should be conservatively assumed to be from one steam 

generator) during the cycle preceding the inspection that is the subject of the report.

• The calculated accident-induced leakage rate from the portion of the tubes below 

x inches from the top of the tubesheet for the most limiting accident in the most limiting 

steam generator. In addition, if the calculated accident-induced leakage rate from the 

most limiting accident is less than y times the maximum operational 

primary-to-secondary leakage rate, the report should describe how it was determined.

• The results of monitoring for tube axial displacement (slippage). If slippage is 

discovered, the implications of the discovery and corrective action shall be provided.

The “y” is the leakage factor in Table 1-5 and is unit-specific.

For implementation of H*, the tubes are monitored to make sure they are not moving within the 

tubesheet (since a tube may be severed beneath the H* distance because of a 360-degree, 

100-percent throughwall circumferential flaw). Tubes are monitored for slippage through review 

of the bobbin coil data. Several units will consider a tube potentially severed if the bobbin signal 

is greater than 50 volts and has a phase angle between 25 and 50 degrees.

1.3.4 Tube Plugging and Repair

The technical specifications set plugging/repair limits for the maximum allowable wall 

degradation beyond which the tubes must be removed from service by plugging or repaired by 

methods such as sleeving. The plugging technique involves installing plugs at the tube inlet and 

outlet. After plugging, the tube no longer functions as the boundary between the primary and 

secondary coolant systems. All units are permitted to take tubes out of service by tube 

plugging.

To prolong the life of severely degraded steam generator tubes, some units, with prior NRC 

approval, have repaired tubes with flaws by sleeving. A sleeve is a pipe of shorter length 

(typically a few feet) and smaller diameter than the tube into which it is inserted. The sleeve is 

positioned to span the flawed portion of the original (parent) tube and the ends of the sleeve are 

secured to the parent tube forming a new pressure boundary. The sleeve and its attachment 

joints form a new pressure boundary; thereby, removing the flawed region from the pressure 

boundary. There are at least two joints in a sleeve: one at the top of the sleeve and the other at 

the bottom of the sleeve. Sleeves vary in length and are typically attached to the parent tube 

either by welding or expansion (e.g., hydraulic expansion). A variety of sleeve designs have 

been used, but the only sleeves currently in service (December 2014) are leak limiting Alloy 800 

sleeves with hydraulic expansions. Alloy 800 is a nickel-iron-chromium alloy with a relatively 

low nickel content when compared to Alloy 600 and Alloy 690.

After sleeving, the repaired tube may remain in service. Although a number of units have 

repaired steam generator tubes by sleeving in the past, only Callaway had installed sleeves in 

thermally treated Alloy 600 steam generator tubes. This sleeving was in their original steam 

generators. Of the units with thermally treated Alloy 600 tubes, none are authorized to repair 
1-14

their tubes by sleeving. In fact, only Beaver Valley 2, with mill-annealed Alloy 600 steam 

generator tubes, is authorized to repair tubes by sleeving. Figure 1-12 depicts a leak limiting 

Alloy 800 sleeve used to repair tubes with flaws in the tubesheet region or with flaws at/near the 

top of the tubesheet. Figure 1-13 depicts a leak limiting Alloy 800 sleeve used to repair tubes 

with flaws near a horizontal tube support.

1.4 Mill-Annealed Alloy 600 Steam Generator Operating Experience

A variety of steam generator designs exist in the United States. A number of factors can affect 

the susceptibility of steam generator tubes to degradation, including the operating environment 

(temperature and water chemistry), the tube material and its heat treatment, and operating and 

residual stresses. One of the most important factors is the tube material and its heat treatment. 

Early steam generator designs used tubes fabricated from Alloy 600, which were typically 

mill-annealed by passing the tubes through a furnace at a temperature high enough to 

recrystallize the material and dissolve the carbon. The carbon content and the mill annealing 

temperature are important parameters for controlling the mechanical and corrosion properties of 

Alloy 600. As discussed in NUREG/CR-6365, the purpose of the mill annealing is to dissolve all 

the carbides, enlarge the grain size, and then cover the grain boundaries with carbides during 

slow cooling in air. Alloy 600 with insufficient carbides at the grain boundaries is more 

susceptible to primary water stress corrosion cracking. Undissolved intragranular carbides are 

undesirable because they supply nucleation sites for the dissolved carbon and prevent 

precipitation of the carbides on the grain boundaries. Undissolved carbides also prevent the 

grains from growing. The smaller grains have a much larger grain boundary area per unit of 

volume, and the carbides do not properly cover the boundaries.

Tubes installed in U.S. nuclear steam generators placed in service in the 1960s and 1970s were 

usually only mill-annealed. The annealing temperature depended on the manufacturer’s 

practice at the time. Over 30 years of operating experience has shown mill-annealed Alloy 600 

is susceptible to various forms of degradation in the steam generator operating environment. 

The types of degradation affecting mill-annealed Alloy 600 steam generator tubes include 

pitting, wear, thinning, wastage, and stress corrosion cracking. The orientation of the stress 

corrosion cracking can be axial, circumferential, or volumetric. Degradation, of one form or 

another, has been observed on virtually every portion of the tube. Figure 1-14 illustrates most 

of the forms of degradation experienced. Although this figure represents a steam generator with 

U-shaped tubes, once-through steam generators (with straight tubes) have also experienced 

many of the same types of degradation.

The extensive tube degradation at PWRs with mill-annealed Alloy 600 steam-generator tubes 

resulted in numerous primary-to-secondary leaks, about nine domestic tube ruptures, many 

midcycle steam generator tube inspections, and the replacement of steam generators at many 

units. In addition, extensive tube degradation has contributed to the shutdown of other units. 

Haddam Neck, Maine Yankee, Trojan, Zion 1, Zion 2, and San Onofre 1 permanently ceased 

operation with significant amounts of tube degradation. As of December 2014, 59 units in the 

United States had replaced their original mill-annealed Alloy 600 steam generators. With one 

exception (Palisades Nuclear Plant), the replacement steam generators typically had more 

advanced tube materials. A listing of the units that replaced their steam generators is provided 

in Table 1-6. This table also supplies the model and tube material of the replacement steam 

generator. Of the 59 units that have replaced steam generators, four have subsequently 

permanently ceased operation: Crystal River Nuclear Generating Plant, Unit 3; Kewaunee
1-15

Power Station, and San Onofre, Units 2 and 3. Operating experience for units with 

mill-annealed Alloy 600 steam generator tubes is well documented.

1.5 Thermally Treated Alloy 600 Tubes

As mill-annealed Alloy 600 steam generator tubes began exhibiting degradation in the early 

1970s, improvements in the design of future steam generators were pursued to limit the 

likelihood of corrosion. Mill-annealed Alloy 600 tubes are generally resistant to chloride stress 

corrosion cracking, but are susceptible to caustic stress corrosion cracking. The tube material 

and its heat treatment were of particular importance in these improved designs. The first major 

advance in limiting the corrosion susceptibility of the steam generator tubes was using a 

thermal-treatment process to improve the tube’s microstructure and thereby its corrosion 

resistance.

In the late 1970s, some mill-annealed Alloy 600 tubes were subjected to this thermal-treatment 

process to relieve fabrication stresses and to further improve the tube’s microstructure. In this 

process, the tubes were subjected to high temperatures (about 705 degrees Celsius, or 

1,301 degrees Fahrenheit) for 10 to 15 hours. This process promotes carbide precipitation at 

the grain boundaries and diffusion of chromium to the regions adjacent to the grain boundaries. 

Alloy 600 with insufficient carbides at the grain boundaries is more susceptible to primary water 

stress corrosion cracking, and chromium depletion at the grain boundaries makes the material 

more susceptible to outside-diameter stress corrosion cracking.

This thermal treatment process was first used on tubes installed in replacement steam 

generators placed into service in the early 1980s. Thermally treated Alloy 600 is used in 

17 units. Another unit, Callaway, had steam generators in which only the first 10 rows had 

thermally treated Alloy 600 tubes and the remaining rows had mill-annealed Alloy 600 tubes; 

however, these steam generators were replaced in 2005 with steam generators containing 

thermally treated Alloy 690 tubes. Steam generators at other units (e.g., in the original steam 

generators at South Texas Project, Unit 2) had some thermally treated tubes; however, the 

number of these tubes at these units is insignificant and are not discussed in this report. 

Thermally treated Alloy 600 is considered to be highly resistant but not immune to primary water 

stress corrosion cracking compared to mill-annealed Alloy 600 tubes.

Steam generators with thermally treated Alloy 600 tubes were first placed in service in 1980. 

Figure 1-15 is a graph of the deployment of steam generators with thermally treated Alloy 600 

tubes. All units with thermally treated Alloy 600 steam generator tubes are 

Westinghouse-designed PWR units with Westinghouse-designed steam generators.

Table 1-7 lists all the units with thermally treated Alloy 600 tubes as of December 2014. The 

table reveals two populations of units with thermally treated Alloy 600 tubes: (1) units that 

replaced their original steam generators (containing mill-annealed tubes) with ones containing 

thermally treated Alloy 600 tubes, and (2) units whose original steam generators were initially 

fabricated with thermally treated Alloy 600 tubes. All of the latter units have Westinghouse 

model D5 and F steam generators.

In addition to the advanced tubing material, steam generators with thermally treated Alloy 600 

tubes have other features to increase the tubes’ resistance to degradation. One design 

improvement was to expand the tubes into the tubesheet by hydraulic means rather than by roll 

expansion or explosive expansion methods. Hydraulic expansion reduces the residual stresses 
1-16

at the expansion transition region, reducing the potential for stress corrosion cracking. In

addition, the expansion process (as with all full-depth expansion processes) closes the crevice 

between the tube and the tubesheet hole, which is a region where dryout can concentrate 

chemicals if the crevice remains open. Another design improvement in these newer steam 

generators is using stainless steel tube supports rather than carbon steel tube supports. 

Stainless steel is less susceptible to corrosion than the carbon steel used for the tube support 

plates in earlier designs. The carbon steel plates corroded and formed magnetite, which filled 

the crevice between the tubes and the tube support plates, denting the tubes. Denting is the 

constricting or mechanical deformation of a tube. Another design improvement was the use of 

quatrefoil holes rather than round holes. The quatrefoil holes promote high-velocity flow along 

the tube, sweeping impurities away from the support plate locations. The quatrefoil hole design 

also limits the contact between the tube and the support plate to four narrow lands, minimizing 

local dryout and chemical concentration.

Table 1-8 indicates the number of calendar years that steam generators with thermally treated 

Alloy 600 tubes have been in service. This table also includes the number of years the original 

steam generators with mill-annealed Alloy 600 tubes were in service for units that replaced their 

steam generators with ones containing thermally treated Alloy 600 tubes. Several units that 

replaced their steam generators in the early 1980s have operated over three times as long with 

their replacement steam generators. This table clearly illustrates the improvements made in the 

design and operation of early replacement steam generators. The average age of steam 

generators with thermally treated Alloy 600 tubes is about 26 years as of December 2013.

Although thermally treated Alloy 600 is no longer the material of choice for new or replacement 

steam generators, it is used in a number of units and has been in service for over 30 years. The 

operating experience with thermally treated Alloy 600 could offer insights into the behavior of 

newer steam generator materials such as thermally treated Alloy 690, which is the preferred 

material for tubes in new and replacement steam generators. NUREG-1771, “U.S. Operating 

Experience with Thermally Treated Alloy 600 Steam Generator Tubes,” documents the 

operating experience associated with thermally treated Alloy 600 as of December 2001. 

Sections 3 and 4, below, summarizes the operating experience with thermally treated Alloy 600 

tubes through December 2013, with some information from 2014 included.

1.6 Thermally Treated Alloy 690 Tubes

The operating experience with thermally treated Alloy 690 tubes through December 2004 was 

summarized in NUREG-1841, “U.S. Operating Experience with Thermally Treated Alloy 690 

Steam Generator Tubes.” As of December 2014, no corrosion related degradation has been 

detected in thermally treated Alloy 690 tubes.

Of the 65 operating PWRs in December 2014, about 3 percent have mill-annealed Alloy 600 

steam generator tubes (Beaver Valley 2 and Palisades), about 26 percent have thermally 

treated Alloy 600 steam generator tubes, and about 71 percent have thermally treated Alloy 690 

steam generator tubes.

1.7 TSTF-449

The following represents most of the technical and reporting requirements that a unit would 

incorporate into its technical specifications when it adopts TSTF-449.
1-17

Steam Generator Program

A Steam Generator (SG) Program shall be established and implemented to ensure that SG tube 

integrity is maintained. In addition, the Steam Generator Program shall include the following 

provisions:

a. Provisions for condition monitoring assessments. Condition monitoring assessment means

an evaluation of the “as found” condition of the tubing with respect to the performance 

criteria for structural integrity and accident-induced leakage. The “as found” condition refers 

to the condition of the tubing during an SG inspection outage, as determined from the 

inservice inspection results or by other means, prior to the plugging [or repair] of tubes. 

Condition monitoring assessments shall be conducted during each outage during which the 

SG tubes are inspected, plugged, [or repaired] to confirm that the performance criteria are 

being met.

b. Performance criteria for SG tube integrity. SG tube integrity shall be maintained by meeting 

the performance criteria for tube structural integrity, accident-induced leakage, and 

operational LEAKAGE.

1. Structural integrity performance criterion: All in-service steam generator tubes shall 

retain structural integrity over the full range of normal operating conditions (including 

startup, operation in the power range, hot standby, and cool down and all anticipated 

transients included in the design specification) 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 applied to the design-basis accident primary-to-secondary pressure 

differentials. Apart from the above requirements, additional loading conditions 

associated with the design-basis accidents, or combination of accidents in 

accordance with the design and licensing basis, shall also be evaluated to determine 

if the associated loads contribute significantly to burst or collapse. In the 

assessment of tube integrity, those loads that do significantly affect burst or collapse 

shall be determined and assessed in combination with the loads due to pressure with 

a safety factor of 1.2 on the combined primary loads and 1.0 on axial secondary 

loads.

2. Accident induced leakage performance criterion: The primary to secondary accident 

induced leakage rate for any design basis accident, other than a SG tube rupture, 

shall not exceed the leakage rate assumed in the accident analysis in terms of total 

leakage rate for all SGs and leakage rate for an individual SG. Leakage is not to 

exceed [1 gpm] per SG [,except for specific types of degradation at specific locations 

as described in paragraph c of the Steam Generator Program].

3. The operational LEAKAGE performance criterion is specified in LCO a.b.cd, “RCS 

Operational LEAKAGE.”

c. Provisions for SG tube repair criteria. Tubes found by inservice inspection to contain flaws 

with a depth equal to or exceeding [40%] of the nominal tube wall thickness shall be plugged 

[or repaired].

[The following alternate tube repair criteria may be applied as an alternative to the 

40-percent depth-based criteria:]
1-18

d. Provisions for SG tube inspections. Periodic SG tube inspections shall be performed. The 

number and portions of the tubes inspected and methods of inspection shall be performed 

with the objective of detecting flaws of any type (e.g., volumetric flaws, axial and 

circumferential cracks) that may be present along the length of the tube, from the 

tube-to-tubesheet weld at the tube inlet to the tube-to-tubesheet weld at the tube outlet, and 

that may satisfy the applicable tube repair criteria. The tube-to-tubesheet weld is not part of 

the tube. In addition to meeting the requirements of d.1, d.2, and d.3 below, the inspection 

scope, inspection methods, and inspection intervals shall be such as to ensure that SG tube 

integrity is maintained until the next SG inspection. An assessment of degradation shall be 

performed to determine the type and location of flaws to which the tubes may be susceptible 

and, based on this assessment, to determine which inspection methods need to be used 

and at what locations.

1. Inspect 100% of the tubes in each SG during the first refueling outage following SG 

replacement.

2. For units with mill-annealed Alloy 600 tubes: Inspect 100% of the tubes at sequential 

periods of 60 effective full power months. The first sequential period shall be considered 

to begin after the first inservice inspection of the SGs. No SG shall operate for more 

than 24 effective full-power months or one refueling outage (whichever is less) without 

being inspected.

For units with thermally treated Alloy 600 tubes: Inspect 100% of the tubes at sequential 

periods of 120, 90, and, thereafter, 60 effective full-power months. The first sequential 

period shall be considered to begin after the first in-service inspection of the SGs. In 

addition, inspect 50% of the tubes by the refueling outage nearest the midpoint of the 

period and the remaining 50% by the refueling outage nearest the end of the period. No 

SG shall operate for more than 48 effective full power months or two refueling outages 

(whichever is less) without being inspected.

For units with thermally treated Alloy 690 tubes: Inspect 100% of the tubes at sequential 

periods of 144, 108, 72, and, thereafter, 60 effective full power months. The first 

sequential period shall be considered to begin after the first inservice inspection of the 

SGs. In addition, inspect 50% of the tubes by the refueling outage nearest the midpoint 

of the period and the remaining 50% by the refueling outage nearest the end of the 

period. No SG shall operate for more than 72 effective full power months or three 

refueling outages (whichever is less) without being inspected.

3. If crack indications are found in any SG tube, then the next inspection for each SG for 

the degradation mechanism that caused the crack indication shall not exceed 24 

effective full power months or one refueling outage (whichever is less). If definitive 

information, such as from examination of a pulled tube, diagnostic non-destructive 

testing, or engineering evaluation indicates that a crack-like indication is not associated 

with a crack(s), then the indication need not be treated as a crack.

e. Provisions for monitoring operational primary-to-secondary LEAKAGE.

f. [Provisions for SG tube repair methods. Steam generator tube repair methods shall provide

the means to reestablish the RCS pressure boundary integrity of SG tubes without removing 
1-19

the tube from service. For the purposes of these Specifications, tube plugging is not a 

repair. All acceptable tube repair methods are listed below.]

Steam Generator Tube Inspection Report

A report shall be submitted within 180 days after the initial entry into MODE 4 following

completion of an inspection performed in accordance with the Specification x.y.z, Steam 

Generator (SG) Program. The report shall include:

a. the scope of inspections performed on each SG,

b. active degradation mechanisms found,

c. nondestructive examination techniques utilized for each degradation mechanism,

d. location, orientation (if linear), and measured sizes (if available) of service-induced 

indications,

e. number of tubes plugged [or repaired] during the inspection outage for each active 

degradation mechanism,

f. total number and percentage of tubes plugged [or repaired] to date,

g. the results of condition monitoring, including the results of tube pulls and in-situ testing,

[h. the effective plugging percentage for all plugging [and tube repairs] in each SG, and]

[i. repair method utilized and the number of tubes repaired by each repair method.]

1.8 TSTF-510

The following represents most of the technical and reporting requirements that a unit would 

incorporate into its technical specifications when it adopts TSTF-510.

Steam Generator (SG) Program

A Steam Generator Program shall be established and implemented to ensure that SG tube 

integrity is maintained. In addition, the Steam Generator Program shall include the following:

a. Provisions for condition monitoring assessments. Condition monitoring assessment 

means an evaluation of the “as found” condition of the tubing with respect to the 

performance criteria for structural integrity and accident induced leakage. The “as 

found” condition refers to the condition of the tubing during an SG inspection outage, as 

determined from the inservice inspection results or by other means, prior to the plugging 

[or repair] of tubes. Condition monitoring assessments shall be conducted during each 

outage during which the SG tubes are inspected, plugged, [or repaired] to confirm that 

the performance criteria are being met.
1-20

b. Performance criteria for SG tube integrity. SG tube integrity shall be maintained by 

meeting the performance criteria for tube structural integrity, accident induced leakage, 

and operational LEAKAGE.

1. Structural integrity performance criterion: All in-service steam generator tubes 

shall retain structural integrity over the full range of normal operating conditions 

(including startup, operation in the power range, hot standby, and cool down), all 

anticipated transients included in the design specification, 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 applied to the design basis 

accident primary-to-secondary pressure differentials. Apart from the above 

requirements, additional loading conditions associated with the design basis 

accidents, or combination of accidents in accordance with the design and 

licensing basis, shall also be evaluated to determine if the associated loads 

contribute significantly to burst or collapse. In the assessment of tube integrity, 

those loads that do significantly affect burst or collapse shall be determined and 

assessed in combination with the loads due to pressure with a safety factor of 1.2 

on the combined primary loads and 1.0 on axial secondary loads.

2. Accident-induced leakage performance criterion: The primary to secondary 

accident induced leakage rate for any design basis accident, other than a SG 

tube rupture, shall not exceed the leakage rate assumed in the accident analysis 

in terms of total leakage rate for all SGs and leakage rate for an individual SG. 

Leakage is not to exceed [1 gpm] per SG [, except for specific types of 

degradation at specific locations as described in paragraph c of the Steam 

Generator Program].

3. The operational LEAKAGE performance criterion is specified in LCO a.b.cd, 

“RCS Operational LEAKAGE.”

c. Provisions for SG tube plugging [or repair] criteria. Tubes found by inservice inspection 

to contain flaws with a depth equal to or exceeding [40%] of the nominal tube wall 

thickness shall be plugged [or repaired].

[The following alternate tube plugging [or repair] criteria may be applied as an alternative 

to the 40% depth based criteria:]

d. Provisions for SG tube inspections. Periodic SG tube inspections shall be performed. 

The number and portions of the tubes inspected and methods of inspection shall be 

performed with the objective of detecting flaws of any type (e.g., volumetric flaws, axial 

and circumferential cracks) that may be present along the length of the tube, from the 

tube-to-tubesheet weld at the tube inlet to the tube-to-tubesheet weld at the tube outlet, 

and that may satisfy the applicable tube plugging [or repair] criteria. The 

tube-to-tubesheet weld is not part of the tube. In addition to meeting the requirements of 

d.1, d.2, and d.3 below, the inspection scope, inspection methods, and inspection 

intervals shall be such as to ensure that SG tube integrity is maintained until the next SG 

inspection. A degradation assessment shall be performed to determine the type and 

location of flaws to which the tubes may be susceptible and, based on this assessment, 

to determine which inspection methods need to be employed and at what locations.
1-21

1. Inspect 100% of the tubes in each SG during the first refueling outage following 

SG installation.

2. For units with mill annealed Alloy 600 tubes: After the first refueling outage 

following SG installation, inspect each steam generator at least every 24 effective 

full power months or at least every refueling outage (whichever results in more 

frequent inspections). In addition, inspect 100% of the tubes at sequential 

periods of 60 effective full-power months beginning after the first refueling outage 

inspection following SG installation. Each 60 effective full power month 

inspection period may be extended up to 3 effective full power months to include 

a SG inspection outage in an inspection period and the subsequent inspection 

period begins at the conclusion of the included SG inspection outage. If a 

degradation assessment indicates the potential for a type of degradation to occur 

at a location not previously inspected with a technique capable of detecting this 

type of degradation at this location and that may satisfy the applicable tube 

plugging criteria, the minimum number of locations inspected with such a capable 

inspection technique during the remainder of the inspection period may be 

prorated. The fraction of locations to be inspected for this potential type of 

degradation at this location at the end of the inspection period shall be no less 

than the ratio of the number of times the SG is scheduled to be inspected in the 

inspection period after the determination that a new form of degradation could 

potentially be occurring at this location divided by the total number of times the 

SG is scheduled to be inspected in the inspection period.

For units with thermally treated Alloy 600 tubes: After the first refueling outage 

following SG installation, inspect each SG at least every 48 effective full power 

months or at least every other refueling outage (whichever results in more 

frequent inspections). In addition, the minimum number of tubes inspected at 

each scheduled inspection shall be the number of tubes in all SGs divided by the 

number of SG inspection outages scheduled in each inspection period as defined 

in a, b, and c below. If a degradation assessment indicates the potential for a 

type of degradation to occur at a location not previously inspected with a 

technique capable of detecting this type of degradation at this location and that 

may satisfy the applicable tube-plugging criteria, the minimum number of 

locations inspected with such a capable inspection technique during the 

remainder of the inspection period may be prorated. The fraction of locations to 

be inspected for this potential type of degradation at this location at the end of 

the inspection period shall be no less than the ratio of the number of times the 

SG is scheduled to be inspected in the inspection period after the determination 

that a new form of degradation could potentially be occurring at this location 

divided by the total number of times the SG is scheduled to be inspected in the 

inspection period. Each inspection period defined below may be extended up to 

3 effective full power months to include a SG inspection outage in an inspection 

period and the subsequent inspection period begins at the conclusion of the 

included SG inspection outage.

a) After the first refueling outage following SG installation, inspect 100% of the 

tubes during the next 120 effective full power months. This constitutes the 

first inspection period;
1-22

b) During the next 96 effective full power months, inspect 100% of the tubes. 

This constitutes the second inspection period; and

c) During the remaining life of the SGs, inspect 100% of the tubes every 72 

effective full power months. This constitutes the third and subsequent 

inspection periods.

For units with thermally treated Alloy 690 tubes: After the first refueling outage 

following SG installation, inspect each SG at least every 72 effective full power 

months or at least every third refueling outage (whichever results in more 

frequent inspections). In addition, the minimum number of tubes inspected at 

each scheduled inspection shall be the number of tubes in all SGs divided by the 

number of SG inspection outages scheduled in each inspection period as defined 

in a, b, c and d below. If a degradation assessment indicates the potential for a 

type of degradation to occur at a location not previously inspected with a 

technique capable of detecting this type of degradation at this location and that 

may satisfy the applicable tube plugging criteria, the minimum number of 

locations inspected with such a capable inspection technique during the 

remainder of the inspection period may be prorated. The fraction of locations to 

be inspected for this potential type of degradation at this location at the end of 

the inspection period shall be no less than the ratio of the number of times the 

SG is scheduled to be inspected in the inspection period after the determination 

that a new form of degradation could potentially be occurring at this location 

divided by the total number of times the SG is scheduled to be inspected in the 

inspection period. Each inspection period defined below may be extended up to 

3 effective full power months to include a SG inspection outage in an inspection 

period and the subsequent inspection period begins at the conclusion of the 

included SG inspection outage.

a) After the first refueling outage following SG installation, inspect 100% of 

the tubes during the next 144 effective full power months. This 

constitutes the first inspection period;

b) During the next 120 effective full power months, inspect 100% of the 

tubes. This constitutes the second inspection period;

c) During the next 96 effective full power months, inspect 100% of the tubes. 

This constitutes the third inspection period; and

d) During the remaining life of the SGs, inspect 100% of the tubes every 72 

effective full power months. This constitutes the fourth and subsequent 

inspection periods.

3. If crack indications are found in any SG tube, then the next inspection for each 

affected and potentially affected SG for the degradation mechanism that caused 

the crack indication shall not exceed 24 effective full power months or one 

refueling outage (whichever results in more frequent inspections). If definitive 

information, such as from examination of a pulled tube, diagnostic non-
1-23

destructive testing, or engineering evaluation indicates that a crack-like indication 

is not associated with a crack(s), then the indication need not be treated as a 

crack.

e. Provisions for monitoring operational primary-to-secondary LEAKAGE.

f. [Provisions for SG tube repair methods. Steam generator tube repair methods shall 

provide the means to reestablish the RCS pressure boundary integrity of SG tubes 

without removing the tube from service. For the purposes of these Specifications, tube 

plugging is not a repair. All acceptable tube repair methods are listed below.]

Steam Generator Tube Inspection Report

A report shall be submitted within 180 days after the initial entry into MODE 4 following

completion of an inspection performed in accordance with the Specification x.y.z, “Steam 

Generator (SG) Program.” The report shall include:

a. The scope of inspections performed on each SG,

b. Degradation mechanisms found,

c. Nondestructive examination techniques utilized for each degradation mechanism,

d. Location, orientation (if linear), and measured sizes (if available) of service induced 

indications,

e. Number of tubes plugged [or repaired] during the inspection outage for each degradation 

mechanism,

f. The number and percentage of tubes plugged [or repaired] to date, and the effective 

plugging percentage in each steam generator,

g. The results of condition monitoring, including the results of tube pulls and in-situ testing,

[h. Repair method utilized and the number of tubes repaired by each repair method.]
1-24

Table 1-1: Unit Listing by PWR Vendor (12/2014)

Babcock and Wilcox – 6 units

Arkansas Nuclear One - 1

Davis-Besse

Oconee 1

Oconee 2

Oconee 3

Three Mile Island 1

Combustion Engineering – 12 units

Arkansas Nuclear One - 2

Calvert Cliffs 1

Calvert Cliffs 2

Fort Calhoun

Millstone 2

Palisades

Palo Verde 1

Palo Verde 2

Palo Verde 3

St. Lucie 1

St. Lucie 2

Waterford 3

Westinghouse – 47 units

Beaver Valley 1

Beaver Valley 2

Braidwood 1

Braidwood 2

Byron 1

Byron 2

Callaway

Catawba 1

Catawba 2

Comanche Peak 1

Comanche Peak 2

Cook 1

Cook 2

Diablo Canyon 1

Diablo Canyon 2

Farley 1

Farley 2

Ginna

Harris

Indian Point 2

Indian Point 3

McGuire 1

McGuire 2

Millstone 3

North Anna 1

North Anna 2

Point Beach 1

Point Beach 2

Prairie Island 1

Prairie Island 2

Robinson 2

Salem 1

Salem 2

Seabrook

Sequoyah 1

Sequoyah 2

South Texas Project 1

South Texas Project 2

Summer

Surry 1

Surry 2

Turkey Point 3

Turkey Point 4

Vogtle 1

Vogtle 2

Watts Bar 1

Wolf Creek
1-25

Table 1-2: Unit Listing by Tube Material (12/2014)

Mill-Annealed Alloy 600 – 2 units

Beaver Valley 2 Palisades 

Thermally Treated Alloy 600 – 17 units

Braidwood 2

Byron 2

Catawba 2

Comanche Peak 2

Indian Point 2

Millstone 3

Point Beach 1

Robinson 2

Salem 1

Seabrook

Surry 1

Surry 2

Turkey Point 3

Turkey Point 4

Vogtle 1

Vogtle 2

Wolf Creek

Thermally Treated Alloy 690 – 46 units

Arkansas Nuclear One - 1

Arkansas Nuclear One - 2

Beaver Valley 1

Braidwood 1

Byron 1

Callaway

Calvert Cliffs 1

Calvert Cliffs 2

Catawba 1

Comanche Peak 1

Cook 1

Cook 2

Davis-Besse

Diablo Canyon 1

Diablo Canyon 2

Farley 1

Farley 2

Fort Calhoun

Ginna

Harris

Indian Point 3

McGuire 1

McGuire 2

Millstone 2

North Anna 1

North Anna 2

Oconee 1

Oconee 2

Oconee 3

Palo Verde 1

Palo Verde 2

Palo Verde 3

Point Beach 2

Prairie Island 1

Prairie Island 2

Salem 2

Sequoyah 1

Sequoyah 2

South Texas Project 1

South Texas Project 2

St. Lucie 1

St. Lucie 2

Summer

Three Mile Island 1

Waterford 3

Watts Bar 1
1-26

Table 1-3: Unit Listing by Tube Expansion Type and Material (12/2014)

EXPANSION TYPE -

TUBE MATERIAL

UNIT NAME

Full-Depth Hardroll -

Mill Annealed Alloy 600

Beaver Valley 2

Full Depth Explosive -

Mill Annealed Alloy 600

Palisades

Full-Depth Hydraulic -

Thermally Treated 

Alloy 600

Braidwood 2

Byron 2

Catawba 2

Comanche Peak 2

Indian Point 2

Millstone 3

Point Beach 1

Robinson 2

Salem 1

Seabrook

Surry 1

Surry 2

Turkey Point 3

Turkey Point 4

Vogtle 1

Vogtle 2

Wolf Creek

Partial-Depth Hydraulic -

Thermally Treated 

Alloy 690

Davis-Besse

Oconee 1

Oconee 2

Oconee 3

Full-Depth Hydraulic -

Thermally Treated 

Alloy 690

Arkansas Nuclear One - 1

Arkansas Nuclear One - 2

Beaver Valley 1

Braidwood 1

Byron 1

Callaway

Calvert Cliffs 1

Calvert Cliffs 2

Catawba 1

Comanche Peak 1

Cook 1

Cook 2

Diablo Canyon 1

Diablo Canyon 2

Farley 1

Farley 2

Fort Calhoun

Ginna

Harris

Indian Point 3

McGuire 1

McGuire 2

Millstone 2

North Anna 1

North Anna 2

Palo Verde 1

Palo Verde 2

Palo Verde 3

Point Beach 2

Prairie Island 1

Prairie Island 2

Salem 2

Sequoyah 1

Sequoyah 2

South Texas Project 1

South Texas Project 2

St. Lucie 1

St. Lucie 2

Summer

Three Mile Island 1

Waterford 3

Watts Bar 1
1-27

Table 1-4: Unit Listing by Tube Support Plate Material (12/2014)

Carbon Steel

Beaver Valley 2 (D) Davis-Besse (?)

Stainless Steel

Arkansas Nuclear One – 1 (T)

Arkansas Nuclear One - 2 (T)

Beaver Valley 1 (Q)

Braidwood 1 (L)

Braidwood 2 (Q)

Byron 1 (L)

Byron 2 (Q)

Callaway (T)

Calvert Cliffs 1 (L)

Calvert Cliffs 2 (L)

Catawba 1 (L)

Catawba 2 (Q)

Comanche Peak 1 (T)

Comanche Peak 2 (Q)

Cook 1 (L)

Cook 2 (Q)

Diablo Canyon 1 (T)

Diablo Canyon 2 (T)

Farley 1 (Q)

Farley 2 (Q)

Fort Calhoun (T)

Ginna (L)

Harris (T)

Indian Point 2 (Q)

Indian Point 3 (Q)

McGuire 1 (L)

McGuire 2 (L)

Millstone 2 (L)

Millstone 3 (Q)

North Anna 1 (Q)

North Anna 2 (Q)

Oconee 1 (T)

Oconee 2 (T)

Oconee 3 (T)

Palisades (L)

Palo Verde 1 (L)

Palo Verde 2 (L)

Palo Verde 3 (L)

Point Beach 1 (Q)

Point Beach 2 (T)

Prairie Island 1 (Q)

Prairie Island 2 (Q)

Robinson 2 (Q)

Salem 1 (Q)

Salem 2 (T)

Seabrook (Q)

Sequoyah 1 (L)

Sequoyah 2 (L)

South Texas Project 1 (T)

South Texas Project 2 (T)

St. Lucie 1 (L)

St. Lucie 2 (T)

Summer (T)

Surry 1 (Q)

Surry 2 (Q)

Three Mile Island 1 (T)

Turkey Point 3 (Q)

Turkey Point 4 (Q)

Vogtle 1 (Q)

Vogtle 2 (Q)

Waterford 3 (T)

Watts Bar 1 (L)

Wolf Creek (Q)

NOTES:

D=Drilled Hole L=Lattice T=Trifoil

Q=Quatrefoil ?=design not readily available

In some units, there is a combination of tube support “opening” configurations. For example, Babcock and Wilcox 

International and AREVA once-through steam generators primarily have broached tube support plate openings; 

however, the uppermost tube support plate has some drilled holes primarily in the periphery of the tube bundle.
1-28

Table 1-5: History of H* Amendments (Part 1)

Unit

Refueling 

Outage

Applies 

to HotLeg (HL)

or ColdLeg (CL)

Reporting 

RequirementsH* 

Distance

Leakage 

Factor

Amendmen

t Date

Amendment 

Accession 

Number Notes

Braidwood 2 11 HL N 17 in. 2 04/25/05

ML05117014

9

Braidwood 2 12 HL N 17 in. 2 10/24/06

ML06278050

7

Braidwood 2 13 HL/CL Y iARC1 2.5 04/18/08

ML08092088

9

Braidwood 2 14 HL/CL Y 16.95 in. 3.11 10/16/09

ML09252051

2

Braidwood 2 15 HL/CL Y 16.95 in. 3.11 04/13/11

ML11084058

0

Braidwood 2 ≥16 HL/CL Y 14.01 in. 3.11 10/05/12

ML12262A36

0

Byron 2 12 HL N 17 in. 2 09/19/05

ML05223001

9

Byron 2 13 HL Y 17 in. 2

03/30/07 

05/09/07

ML07081035

4 

ML07121055

5

Byron 2 14 HL/CL Y iARC1 2.5 10/01/08

ML08234086

2

Byron 2 15 HL/CL Y 16.95 in. 3.11 10/16/09

ML09252051

2

Byron 2 16 HL/CL Y 16.95 in. 3.11 04/13/11

ML11084058

0

Byron 2 ≥17 HL/CL Y 14.01 in. 3.11 10/05/12

ML12262A36

0

Callaway Replaced steam generators

Catawba 2 14 HL/CL N 17 in. 2 03/31/06

ML06076001

1

ML06076011

1

Catawba 2 15 HL/CL N 17 in. 2 10/31/07

ML07282001

3

Catawba 2 16 HL/CL Y iARC1 2.5 04/13/09

ML09103008

8

Catawba 2 17 HL/CL Y 20 in. 3.27 09/27/10

ML10264053

7

Catawba 2 ≥18 HL/CL Y 14.01 in. 3.27 03/12/12

ML12054A69

2

Comanche Peak 2 11 HL/CL Y 16.95 in. 3.16 10/09/09

ML09274007

6

Comanche Peak 2 12 HL/CL Y 16.95 in. 3.16 04/16/11

ML11077032

2

Comanche Peak 2 ≥13 HL/CL Y 14.01 in. 3.16 10/18/12

ML12263A03

6

Indian Point 2 ≥22 HL/CL Y 18.9 in. 1.75

09/05/14 

09/30/14

ML14198A16

1 

ML14252A67

9

Millstone 3 12 HL/CL Y iARC1 2.5

09/30/08 

11/21/08

ML08232129

2 

ML08281014

7

Millstone 3 13 HL/CL Y 13.1 in. 2.49 05/03/10

ML10077035

8

Millstone 3 14 HL/CL Y 15.2 in. 2.49 10/07/11

ML11258051

7

Millstone 3 ≥15 HL/CL Y 15.2 in. 2.49 12/06/12

ML12299A49

8

Point Beach 1 30 HL N 17 in. 2 04/04/07

ML07080070

5

Point Beach 1 31 HL/CL Y iARC1 2.5 10/07/08

ML08254088

3

Robinson 2 24, 25 HL/CL Y 17 in. 2 04/09/07

ML07106025

9

No inspections in refueling outage 

(RFO) 25

Robinson 2 26, 27 HL/CL Y 17.28 in. 1.82 05/07/10

ML10099040

5 No inspections in RFO 27

Robinson 2 ≥28 HL/CL Y 18.11 in. 1.87 08/29/13

ML13198A36

7

Salem 1 18, 19 HL/CL Y 17 in. 2 03/27/07

ML07079008

1 No inspections in RFO 19

Salem 1 20, 21 HL/CL Y 13.1 in. 2.16 03/29/10

ML10057045

2 No inspections in RFO 21

Salem 1 ≥22 HL/CL Y 15.21 in. 2.16 03/27/13

ML13072A10

5

1 iARC refers to interim alternate repair criteria (iARC) which had acceptance limits based on the size, orientation, and spacing of indications located greater than 17 

in. from the top of the tubesheet.

2 The numbering for the refueling outages in this document differs than the numbering in the plant technical specifications.
1-29

Table 1-5: History of H* Amendments (Part 2)

Unit Refueling 

Outage

Applies to 

HL or CL

Reporting 

Requirements

H* 

Distance

Leakage 

Factor

Amendment 

Date

Amendment 

Accession 

Number

Notes

Seabrook 11, 12 HL N 17 in. 2 09/29/2006 ML062630457 No inspections in RFO 12

Seabrook 13, 14 HL/CL Y 13.1 in. 2.5 10/13/2009 ML092460184 Limited inspections in RFO 

14

Seabrook ≥15 HL/CL Y 15.21 in. 2.49 09/10/2012 ML12178A537

Surry 1 22 HL/CL Y iARC1 2.5 04/08/09 

04/16/09

ML090860735 

ML091040065

Surry 1 22 Y 4.7 05/07/2009 ML091260386

Addressed permeability 

variations in bottom 1 in. of 

tube in steam generator B 

only, 20 gallon per day 

leakage limit

Surry 1 23 HL/CL Y 16.7 in. 2.03 11/05/2009 ML092960484

Surry 1 ≥24 HL/CL Y 17.89 in. 1.8 04/17/2012 ML120730304 

ML12109A270

Surry 2 21 HL/CL Y iARC1 2.5 05/16/2008 ML081340106

Surry 2 22 HL/CL Y 16.7 in. 2.03 11/05/2009 ML092960484

Surry 2 23 HL/CL Y 17.74 in. 2.03 05/20/11 

06/29/11

ML11090A000 

ML111810163

Surry 2 ≥24 HL/CL Y 17.89 in. 1.8 04/17/2012 ML120730304 

ML12109A270

Turkey Point 3 22, 232 HL N 17 in. 2 11/01/2006 ML062990193 No inspections in RFO 23

Turkey Point 3 24, 252 HL/CL Y 17.28 in. 1.82 10/30/2009 ML092990489 No inspections in RFO 25

Turkey Point 3 ≥262 HL/CL Y 18.11 in. 1.82 11/05/2012 ML12292A342

Turkey Point 4 22, 232 HL N 17 in. 2 11/01/2006 ML062990193 No inspections in RFO 23

Turkey Point 4 24, 252 HL/CL Y 17.28 in. 1.82 10/30/2009 ML092990489 No inspections in RFO 25

Turkey Point 4 ≥262 HL/CL Y 18.11 in. 1.82 11/05/2012 ML12292A342

Vogtle 1 13 HL N 17 in. 2 09/12/2006 ML062260302

Vogtle 1 14 HL/CL Y iARC1 2.5 04/09/2008 ML080950232

Vogtle 1 15 HL/CL Y 13.1 in. 2.48 09/24/2009 ML092170782

Vogtle 1 16 HL/CL Y 15.2 in. 2.48 03/14/2011 ML110660264

Vogtle 1 ≥17 HL/CL Y 15.2 in. 2.48 09/10/2012 ML12216A056

Vogtle 2 11 HL N 17 in. 2 09/21/2005 ML052630014

Vogtle 2 12 HL N 17 in. 2 09/12/2006 ML062260302

Vogtle 2 13 HL/CL Y iARC1 2.5 09/16/2008 ML082530038

Vogtle 2 14 HL/CL Y 13.1 in. 2.48 09/24/2009 ML092170782

Vogtle 2 15 HL/CL Y 15.2 in. 2.48 03/14/2011 ML110660264

Vogtle 2 ≥16 HL/CL Y 15.2 in. 2.48 09/10/2012 ML12216A056

Wolf Creek 14 HL N 17 in. 2 04/28/2005 ML051230044

Wolf Creek 15 HL N 17 in. 2 10/10/2006 ML062580016

Wolf Creek 16 HL/CL Y iARC1 2.5 04/04/2008 ML080840003

Wolf Creek 17 HL/CL Y 13.1 in. 2.5 10/19/2009 ML092750606

Wolf Creek 18 HL/CL Y 15.2 in. 2.5 04/06/2011 ML110840590

Wolf Creek ≥19 HL/CL Y 15.21 in. 2.5 12/11/2012 ML12300A309

1 iARC refers to interim alternate repair criteria (iARC) which had acceptance limits based on the size, orientation, and spacing of indications located greater 

than 17 in. from the top of the tubesheet.

2 The numbering for the refueling outages in this document differs than the numbering in the plant technical specifications.
1-30

Table 1-6: Units with Replacement Steam Generators Part 1 (12/2014)

Unit Name

No. of

Loops

SG Manufacturer/Model1

Completion 

Date Tube Material Original Replacement 2

Surry 2 3 W/51 W/51F 9/80 600 TT

Surry 1 3 W/51 W/51F 7/81 600 TT

Turkey Point 3 3 W/44 W/44F 4/82 600 TT

Turkey Point 4 3 W/44 W/44F 5/83 600 TT

Point Beach 1 2 W/44 W/44F 3/84 600 TT

Robinson 2 3 W/44 W/44F 10/84 600 TT

Cook 2 4 W/51 W/54F 3/89 690 TT

Indian Point 3 4 W/44 W/44F 6/89 690 TT

Palisades 2 CE CE 3/91 600 MA

Millstone 2 2 CE-67 BWI 1/93 690 TT

North Anna 1 3 W/51 W/54F 4/93 690 TT

Summer 3 W/D3 W/D75 12/94 690 TT

North Anna 2 3 W/51 W/54F 5/95 690 TT

Ginna 2 W/44 BWI 6/96 690 TT

Catawba 1 4 W/D3 BWI 9/96 690 TT

Point Beach 2 2 W/44 W/D47 12/96 690 TT

McGuire 1 4 W/D2 BWI 5/97 690 TT

Salem 1 4 W/51 W/F 7/97 600 TT

McGuire 2 4 W/D3 BWI 12/97 690 TT

St. Lucie 1 2 CE-67 BWI 1/98 690 TT

Byron 1 4 W/D4 BWI 1/98 690 TT

Braidwood 1 4 W/D4 BWI 11/98 690 TT

South Texas Project 1 4 W/E W/D94 5/00 690 TT

Farley 1 3 W/51 W/54F 5/00 690 TT

Cook 1 4 W/51 BWI 12/00 690 TT

Arkansas Nuclear One 2 2 CE/2815 W/D109 12/00 690 TT
1-31

Table 1-6: Units with Replacement Steam Generators Part 2 (12/2014)

Unit Name

No. of

Loops

SG Manufacturer/Model1

Completion 

Date Tube Material Original Replacement 2

Indian Point 2 4 W/44 W/44F 12/00 600 TT

Farley 2 3 W/51 W/54F 5/01 690 TT

Kewaunee3 2 W/51 W/54F 12/01 690 TT

Harris 3 W/D4 W/D75 12/01 690 TT

Calvert Cliffs 1 2 CE BWI 6/02 690TT

South Texas 2 4 W/E W/Delta 94 12/02 690TT

Calvert Cliffs 2 2 CE BWI 5/03 690TT

Sequoyah 1 4 W/51 ABB/Doosan 6/03 690TT

Palo Verde 2 2 CE 80 ABB/Ansaldo 12/03 690TT

Oconee 1 2 B&W BWI 1/04 690TT

Oconee 2 2 B&W BWI 6/04 690TT

Prairie Island 1 2 W/51 Areva 11/04 690TT

Oconee 3 2 B&W BWI 12/04 690TT

Callaway 4 W/F Areva 11/05 690TT

Arkansas Nuclear One 1 2 B&W Areva 12/05 690TT

Palo Verde 1 2 CE 80 ABB/Ansaldo 12/05 690TT

Beaver Valley 1 3 W/51 W/54F 4/06 690TT

Watts Bar 1 4 W/D3 ABB/Doosan 11/06 690TT

Fort Calhoun 2 CE Mitsubishi 12/06 690TT

Comanche Peak 1 4 W/D4 W/D76 4/07 690TT

St. Lucie 2 2 CE Areva 1/08 690TT

Palo Verde 3 2 CE ABB/Ansaldo 1/08 690TT

Diablo Canyon 2 4 W/51 W/D54 4/08 690TT

Salem 2 4 W/51 Areva 5/08 690TT
1-32

Table 1-6: Units with Replacement Steam Generators Part 3 (12/2014)

Unit Name

No. of

Loops

SG Manufacturer/Model1

Completion 

Date Tube Material Original Replacement 2

Diablo Canyon 1 4 W/51 W/D54 3/09 690TT

TMI-1 2 B&W Areva 1/10 690TT

San Onofre 23 2 CE Mitsubishi 4/10 690TT

San Onofre 33 2 CE Mitsubishi 2/11 690TT

Sequoyah 2 4 W/51 W/Doosan 1/13 690TT

Waterford 2 CE W/Delta 110 1/13 690TT

Crystal River 33, 4 2 B&W BWI 2009-13 690TT

Prairie Island 2 2 W/51 Areva 1/14 690TT

Davis Besse 2 B&W BWI 5/14 690TT

1 W=Westinghouse, CE=Combustion Engineering, BWI=Babcock and Wilcox International (also referred to as 

Babcock and Wilcox Canada), B&W=Babcock and Wilcox, ABB=Asea Brown Boveri (also referred to as 

Combustion Engineering), Areva (also referred to as Framatome)

2 TT= thermally treated, MA = mill-annealed

3 Permanently shutdown

4 Never operated with replacement steam generators
1-33

Table 1-7: Units with Thermally Treated Alloy 600 Tubes (12/2014)

Unit Date1 Model Number 

of SGs

Replacement2

Braidwood 2 1988 D5 4 N

Byron 2 1987 D5 4 N

Catawba 2 1986 D5 4 N

Comanche Peak 2 1993 D5 4 N

Indian Point 2 2000 44F 4 Y

Millstone 3 1986 F 4 N

Point Beach 1 1984 44F 2 Y

Robinson 2 1984 44F 3 Y

Salem 1 1997 F 4 Y

Seabrook 1 1990 F 4 N

Surry 1 1981 51F 3 Y

Surry 2 1980 51F 3 Y

Turkey Point 3 1982 44F 3 Y

Turkey Point 4 1983 44F 3 Y

Vogtle 1 1987 F 4 N

Vogtle 2 1989 F 4 N

Wolf Creek 1 1985 F 4 N

Callaway3 1984 F 4 N

1 Date of commercial operation or date of steam generator replacement, whichever is later. 2 “

N” means the unit has its original steam generators; “Y” means the steam generators are replacements. 3 Only the first 10 rows of the original Callaway steam generators had thermally treated tubes; the remaining 

tubes were mill-annealed Alloy 600. Callaway replaced their original steam generators in 2005 with steam 

generators with thermally treated Alloy 690 tubes.
1-34

Table 1-8: Age of Steam Generators at Units with Thermally Treated Alloy 600 Tubes 

(12/2013)

Unit Operating Time1

Original SG

Operating Time1

Replacement SG

Approximate EFPY2

For Current SG

Braidwood 2 25 N/A 22.2

Byron 2 26 N/A 23.3

Catawba 2 27 N/A 23.0

Comanche Peak 2 20 N/A 18.3

Indian Point 2 26 13 11.9

Millstone 3 28 N/A 21.2

Point Beach 1 13 30 25.0

Robinson 2 14 29 23.4

Salem 1 20 17 14.0

Seabrook 1 23 N/A 20.0

Surry 1 8 33 26.5

Surry 2 7 33 27.0

Turkey Point 3 9 32 24.3

Turkey Point 4 10 31 23.8

Vogtle 1 27 N/A 23.6

Vogtle 2 25 N/A 22.0

Wolf Creek 1 28 N/A 23.9

Callaway3 21 N/A

1 Operating Time = calendar years of operation as of 12/31/2013

2 Approximate EFPY = approximate effective full power years as of 12/31/2013

3 Only the first 10 rows of the original Callaway steam generators had thermally treated tubes; the remaining 

tubes were mill-annealed Alloy 600. Callaway replaced their original steam generators in 2005 with steam 

generators with thermally treated Alloy 690 tubes.
1-35

Figure 1-1: Typical Pressurized Water Reactor Power Plant
1-36

Figure 1-2: Typical PWR Recirculating Steam Generator without a Preheater
1-37

Figure 1-3: Typical PWR Once-Through Steam Generator
1-38

Figure 1-4: U-Bend Features
1-39

Figure 1-5: Typical PWR Recirculating Steam Generator with a Preheater
1-40

Figure 1-6: Typical Steam Generator Channel Head in a Recirculating Steam Generator
1-41

Figure 1-7: Partial and Full Depth Expansions
1-42

Figure 1-8: Typical Tubesheet Joint – Full Depth Expansion
1-43

Figure 1-9: Combustion Engineering Steam Generator
1-44

Figure 1-10: Typical Tube Support Configurations
1-45

Figure 1-11: Illustration of H* Distance
1-46

Figure 1-12: Alloy 800 Tubesheet Sleeve
1-47

Figure 1-13: Alloy 800 Tube Support Sleeve
1-48

Figure 1-14: Steam Generator Tube Degradation Mechanisms
1-49

Figure 1-15: Number of Units with Thermally Treated Alloy 600 Steam Generator Tubes as a Fun

2-1

2 STEAM GENERATOR DESIGNS IN UNITS WITH

THERMALLY TREATED ALLOY 600 TUBES

2.1 Introduction

Steam generators with thermally treated Alloy 600 tubes can be divided into three categories: 

model D5, model F, and replacement steam generators. The latter category includes all units 

that replaced original steam generators (which had mill-annealed Alloy 600 tubes) with steam 

generators containing thermally treated Alloy 600 tubes. The design of the steam generators in 

these three categories are discussed further below. A summary of the design features of steam 

generators with thermally treated Alloy 600 tubing is provided in Table 2-1.

2.2 Model D5 Steam Generators

Westinghouse model D5 steam generators have 4,570 thermally treated Alloy 600 tubes with an 

outside diameter of 1.9 cm (0.750 in.) and a 1.09 mm (0.043 in.) nominal wall thickness. The 

tubes are hydraulically expanded for the full depth of the tubesheet at each end. The tubes are 

supported by stainless steel support plates with quatrefoil holes and V-shaped chrome plated 

Alloy 600 anti-vibration bars (AVBs). Figure 2-1 depicts the model D5 steam generator tube 

support configuration. As shown in this figure, several naming conventions are used for the 

tube support plates. Model D5 steam generator tubes have a square tube pitch as depicted in 

Figure 2-2 with a tube spacing of 2.7 cm (1.063 in.).

The model D5 steam generators have several design features that set them apart from other 

steam generators with thermally treated Alloy 600 tubes. These features include a preheater 

and a T-slot. The preheater is a region in the tube bundle which preheats the incoming 

feedwater (secondary coolant) before entering the main region of the tube bundle. The design 

and operation of the preheater are discussed further below. The T-slot is an untubed portion of 

the tube bundle. It has a T shape and is used in steam generator blowdown for sludge removal. 

The T-slot is depicted in Figure 2-2.

The preheater region (near the feedwater inlet) and its relation to the tube bundle are shown in 

Figure 1-5. The preheater region is on the cold-leg side of the tube bundle and faces the 

feedwater inlet. A more detailed view of the preheater region is given in Figure 2-3. As can be 

inferred from Figure 2-3, the first several rows of tubes in the periphery of the tube bundle are 

not supported at baffle plates E and H (actually 5 rows of tubes are not supported). These 

tubes are sometimes called “window tubes.”

Feedwater flowing into the steam generator first passes through a venturi insert in the main feed 

nozzle. The insert serves as a backflow restrictor to limit the rate of blowdown from the steam 

generator in the event of a main feedwater line break. In the preheater section, as illustrated in 

Figure 2-3, the incoming feedwater enters the inlet waterbox and encounters the impingement 

plate, which directs the water outward to fill the waterbox volume and downward to the 

preheater inlet between baffle plates B and D. In the lower section of the preheater, or first 

pass, the feedwater enters the tube bundle. The water then flows around the tubes and baffles 

until it enters the main region of the tube bundle. Because the water changes direction between 

the baffle plates of the preheater (i.e., right-to-left between B and D and then left-to-right 

between D and E), this type of preheater design is called a “counterflow preheater.”
2-2

In the early 1980s, when Westinghouse steam generators with preheaters were first deployed, 

tube wear attributed to tube vibration in the preheat section of the steam generator was 

discovered at several foreign units. The wear was occurring primarily in the outer three rows of 

tubes in the preheater section (rows 47, 48, and 49). The tube wear was because of large 

tube-to-baffle-plate clearances and relatively high velocities of the nonuniform, turbulent inlet 

flow, which allowed the tubes to vibrate within the clearance.

The root cause of the tube wear and design modifications to mitigate its occurrence are 

discussed in NUREG-0966, “Safety Evaluation Report Related to the D2/D3 Steam Generator 

Design Modification,” and NUREG-1014, “Safety Evaluation Report Related to the D4/D5/E 

Steam Generator Design Modification.” The design modifications for units with D5 steam 

generators involved expanding selected tubes (approximately 124 tubes) at baffle plates B 

and D to make the tubes stiffer. The expansion of tubes at baffle plate locations was intended 

to limit the tube movement at the baffle plate intersections to a few hundredths of a millimeter 

(a few thousandths of an inch). Westinghouse developed a proprietary process for hydraulically 

expanding the steam generator tubes at the baffle plates. The hydraulic expansion was 

intended to limit the residual stresses from the expansion such that combined with the relatively 

low temperature in the preheater region there would be no significant increase in the potential 

for stress corrosion cracking at the expanded locations. The expansions were designed to be 

entirely within the baffle plate to prevent bulging of the tube outside of the baffle plates.

In addition to the expansion of the tubes at the baffle plate locations, the feedwater flow was 

split by diverting a fraction of the main feedwater flow through an auxiliary feedwater nozzle to 

reduce the flow velocities and the potential for tube vibration. For the four units with model D5 

steam generators, approximately 10 percent of the main feedwater flow was diverted. The 

auxiliary nozzle is in the upper portion of the steam generator as illustrated in Figure 1-5.

The model D5 steam generator design incorporated many enhancements compared to earlier 

models including (1) utilizing stainless steel, a more corrosion-resistant material, as the material 

for the tube support plates and baffles, (2) changing the shape of the holes in the tube support 

plates from circular to a quatrefoil shape to improve flow, (3) expanding the tubes within the 

tubesheet by hydraulic means in lieu of mechanical rollers to reduce stresses, (4) thermally 

treating the Alloy 600 tubes to enhance their resistance to corrosion, and (5) changing the holes 

in the flow distribution baffles from slotted to circular shape to improve flow.

Model D5 steam generators are used at Braidwood Station, Unit 2; Byron Station, Unit 2;

Catawba Nuclear Station, Unit 2; and Comanche Peak Nuclear Power Plant, Unit 2.

2.3 Model F Steam Generators

The model F steam generators were designed in the mid-1970s. Except for the model F steam 

generators at Callaway Plant (which were replaced in 2005), all model F steam generators have 

5,626 thermally treated Alloy 600 tubes. At Callaway, only the first 10 rows of tubes in each 

steam generator had thermally treated tubes (i.e., only 1,214 tubes per steam generator were 

thermally treated). The tubes have an outside diameter of 1.75 cm (0.688 in.) and a nominal 

wall thickness of 1.01 mm (0.040 in.). The tubes are hydraulically expanded for the full depth of 

the tubesheet at each end. The tubes are supported by stainless steel support plates with 

quatrefoil holes and V-shaped chrome plated Alloy 600 AVBs. The first 10 rows of tubes were 

stress-relieved to improve corrosion resistance. Figure 2-4 depicts the model F steam 
2-3

generator tube support configuration. As shown in this figure, several naming conventions are 

used for the tube support plates. Model F steam generator tubes have a square tube pitch as 

depicted in Figure 2-5 with a tube spacing of 2.5 cm (0.980 in.).

Unlike the model D5 steam generator, the model F steam generator does not have a preheater 

region. In the model F steam generator, the secondary-system water (feedwater) is fed through 

a feedwater nozzle to a feedring into the downcomer where it mixes with recirculating water 

draining from the moisture separators. This downcomer water flows to the bottom of the steam 

generator, across the top of the tubesheet, and then up through the tube bundle, where steam is 

generated (Figure 1-2).

Model F steam generators are used at Millstone Power Station, Unit 3; Salem Nuclear 

Generating Station, Unit 1; Seabrook Station; Vogtle Electric Generating Plant, Units 1 and 2;

and Wolf Creek Generating Station. As discussed above, the model F steam generators at 

Callaway only had thermally treated Alloy 600 tubes in the first 10 rows of tubes and were 

replaced in 2005. The model F steam generators at Salem 1 are replacement steam generators 

that were originally intended to be installed in the canceled Seabrook 2 unit. As a result, the 

Salem 1 steam generators are discussed as replacement steam generators.

2.4 Replacement Steam Generators

Three steam generator models are used at units that replaced their original steam generators 

with steam generators with thermally treated Alloy 600 tubes, namely the Westinghouse models 

44F, 51F, and F. These models do not have a preheater region.

Westinghouse model 44F steam generators have 3,214 thermally treated Alloy 600 tubes with 

an outside diameter of 2.22 cm (0.875 in.) and a 1.27-mm (0.050-in.) nominal wall thickness. 

The tubes are hydraulically expanded for the full depth of the tubesheet at each end. The tubes 

are supported by stainless steel support plates with quatrefoil holes and V-shaped AVBs. 

Figure 2-6 depicts the model 44F steam generator tube support configuration, using the typical 

naming convention. Model 44F steam generator tubes have a square tube pitch as depicted in 

Figure 2-7 with a tube spacing of approximately 3 cm (1.2 in.).

Model 44F steam generators are used at Indian Point Nuclear Generating, Unit 2; Point Beach 

Nuclear Plant, Unit 1; H.B. Robinson Steam Electric Plant, Unit 2; and Turkey Point Nuclear 

Generating, Units 3 and 4.

Westinghouse model 51F steam generators have 3,342 thermally treated Alloy 600 tubes with 

an outside diameter of 2.22 cm (0.875 in.) and a 1.27-mm (0.050-in.) nominal wall thickness. 

The tubes are hydraulically expanded for the full depth of the tubesheet at each end. The tubes 

are supported by stainless steel support plates with quatrefoil holes and V-shaped AVBs. The 

tubes in rows 1 through 8 received a supplemental thermal treatment (stress relieving) after 

bending, while still in the manufacturing facility. Also, starting with the model F steam 

generators (including the model 44F and 51F steam generators), a set of geometric controls 

were implemented for bending the tubes (i.e., manufacturing the U-bends). The controls 

included strict requirements for ovality, the U-bend-to-leg flatness, and leg spacing. These 

improved manufacturing requirements resulted in consistent U-bends, which in turn translated 

into uniform stresses. The geometric controls helped to eliminate localized stress 

discontinuities present in earlier steam generators. Figure 2-8 depicts the model 51F steam 

generator tube support configuration, using the typical naming convention. Model 51F steam 
2-4

generator tubes have a square tube pitch as depicted in Figure 2-9 with a tube spacing of about

3.25 cm (1.281 in.). Model 51F steam generators are used at Surry 1 and 2.

Although the steam generators at Salem 1 are replacement steam generators, the steam 

generators are true model F steam generators. They were initially scheduled to be installed in 

Seabrook 2, which was never completed. The design of the model F steam generators is 

discussed in Section 2.3.
2-5

Table 2-1: Steam Generator Design Information for Units with Thermally Treated Alloy 600 

Unit

Commercial 

Operation Date

SG 

Replacement 

Date PWR Type SG Designer SG Fabricator SG Model

Tube 

Manufacturer Tube OD

Tube 

Wall

Number 

of Tubes

Tube 

Pitch

Tubesheet 

Thickness

Expansion 

Method

Expansion 

Extent

Support 

Material

U-Bend 

Stress Relief 

After Bending 

Braidwood 2 10/17/1988 Westinghouse Westinghouse Westinghouse D5 Westinghouse 0.750 0.043 4570 1.0631 21.20 Hydraulic Full 405 R1-9 1.125-inch TSP thickness. 

Byron 2 08/21/1987 Westinghouse Westinghouse Westinghouse D5 Westinghouse 0.750 0.043 4570 1.0631 21.20 Hydraulic Full SS R1-91

144 tubes hydraulically exp

Chrome plated Alloy 600 A

Callaway2 12/19/1984 11/17/2005 Westinghouse Westinghouse Westinghouse F Westinghouse 0.688 0.040 1214 0.98 Hydraulic Full R1-10 Steam generators are no lo

Catawba 2 08/19/1986 Westinghouse Westinghouse Westinghouse D5 Westinghouse 0.750 0.043 4578 1.0625 21.20 Hydraulic Full 405SS R1-9

Chrome plated Inconel AV

thickness. Autogenous we

Comanche Peak 2 08/03/1993 Westinghouse Westinghouse Westinghouse D5 Westinghouse 0.750 0.043 4570 1.063 21.23 Hydraulic Full 405SS R1-9

 p 

FDB and all preheater baff

top preheater baffle are 1.1

Indian Point 2 08/01/1974 12/01/2000 Westinghouse Westinghouse Westinghouse 44F Sandvik 0.875 0.050 3214 ~1.21

 Sq 22.01 Hydraulic Full 405SS R1-8

U et a e tac e pa s o p 

square cross section, chro

holes. TSPs have quatrefo

Millstone 3 04/23/1986 Westinghouse Westinghouse Westinghouse F Westinghouse 0.688 0.040 5626 0.98 Sq 21.23 Hydraulic Full R1-10 R1 radius is 2.20 inches. 

Point Beach 1 12/21/1970 03/01/1984 Westinghouse Westinghouse Westinghouse 44F Westinghouse 0.875 0.050 3214 1.234 Sq Hydraulic Full SS R1-8

R1 bend radius is 2.19-inc

circular holes. TSPs have 

Robinson 2 03/07/1971 10/01/1984 Westinghouse Westinghouse Westinghouse 44F Westinghouse 0.8751 0.0501 32141 ~1.21 Hydraulic Full R1-8

Salem 1 06/30/1977 07/01/1997 Westinghouse Westinghouse Westinghouse F Westinghouse 0.688 0.040 5626 0.981 Hydraulic Full 405SS R1-10

3 s aped, c o e p ated 

FDB and TSP 1, 2, and 3 a

have quatrefoil openings.

Seabrook 08/19/1990 Westinghouse Westinghouse Westinghouse F Westinghouse 0.688 0.040 5626 0.981 Hydraulic Full R1-10

TSPs 1-4 are 0.75-inches 

U-bend region was stress r

Model F steam generators)

Surry 1 12/22/1972 07/01/1981 Westinghouse Westinghouse Westinghouse 51F Westinghouse 0.875 0.050 3342 1.281 Hydraulic Full 405SS R1-8

 p y 

Only lower assembly and p

Moisture separators upgrad

Surry 2 05/01/1973 09/01/1980 Westinghouse Westinghouse Westinghouse 51F Westinghouse 0.875 0.050 3342 1.281 21.00 Hydraulic Full 405SS R1-8

 p y 

Only lower assembly and p

Moisture separators upgrad

Turkey Point 3 12/14/1972 04/01/1982 Westinghouse Westinghouse Westinghouse 44F Westinghouse 0.875 0.050 3214 1.234 Sq 22.08 Hydraulic Full 405SS R1-8 FDB has circular holes. TS

Turkey Point 4 09/07/1973 05/01/1983 Westinghouse Westinghouse Westinghouse 44F Westinghouse 0.875 0.050 3214 1.234 Sq 22.08 Hydraulic Full 405SS R1-8 FDB has circular holes. TS

Vogtle 1 06/01/1987 Westinghouse Westinghouse Westinghouse F Westinghouse 0.688 0.040 5626 0.98 Sq Hydraulic Full 405 R1-10

R1 radius is 2.2-inches. U

tubes. Chrome plated Alloy 

inch thick. Highest 4 TSPs 

Vogtle 2 05/20/1989 Westinghouse Westinghouse Westinghouse F Westinghouse 0.688 0.040 5626 0.981 Hydraulic Full 405 R1-10 R1 radius is 2.2-inches. U

Wolf Creek 09/03/1985 Westinghouse Westinghouse Westinghouse F Westinghouse 0.6881 0.0401 5626 0.981 Hydraulic Full SS R1-10 Hard roll tack expansion.

Notes: AVB = anti-vibration bar

FDB = flow distribution baffle

OD = outside diameter

SG = steam generator

Sq = square

SS = stainless steel

TSP = tube support plate

1

Assumed based on model type

2

Steam generators with thermally treated Alloy 600 tubes are no longer in operation. Replacement date is the data on which the thermally treated Alloy 600 steam generator tubes were removed from service.

Based on H*, tubesheet thickness is 21.03-inches for model D5, F, and 51F steam generators and 21.810-inches for model 44F steam generators. Presumably these thicknesses are without cladding.
2-6

Figure 2-1: Westinghouse Model D5 Steam Generator Tube Support Locations
2-7

Figure 2-2: Westinghouse Model D5 Steam Generator Tubesheet Map
2-8

Figure 2-3: Preheater Region of Westinghouse Model D5 Steam Generator
2-9

Figure 2-4: Westinghouse Model F Steam Generator Tube Support Locations
2-10

Figure 2-5: Westinghouse Model F Steam Generator Tubesheet Map
2-11

Figure 2-6: Westinghouse Model 44F Steam Generator Tube Support Locations
2-12

Figure 2-7: Westinghouse Model 44F Steam Generator Tubesheet Map
2-13

Figure 2-8: Westinghouse Model 51F Steam Generator Tube Support Locations
2-14

Figure 2-9: Westinghouse Model 51F Steam Generator Tubesheet Map
3-1

3 THERMALLY TREATED ALLOY 600 STEAM GENERATOR TUBE

OPERATING EXPERIENCE

3.1 Data Gathering Methods and Introduction

This section summarizes inspection results for units with thermally treated Alloy 600 steam 

generator tubes from December 2001 through December 2013. Prior operating experience is 

summarized in NUREG-1771. Some added information from primarily the first half of 2014 is 

also included in this section. The information was gathered primarily from reports submitted to 

the NRC in accordance with a unit’s technical specifications. These reports discuss the scope 

of the inspections, the indications detected, the number of tubes plugged, and the results of 

condition monitoring. The level of detail provided in these reports varies from unit to unit and 

frequently from tube inspection outage to outage. In addition, the results and interpretation of 

the results represent the licensee’s analysis and evaluation at the time the report was 

submitted. This may have changed over time. Some inspection results were also obtained 

through regional inspection reports, summaries of conference calls with licensees, and meeting 

summaries. A detailed review of regional inspection reports was not conducted, and that data 

were not compiled. In spite of these limitations, this report provides useful insights into the 

operating experience with thermally treated Alloy 600 steam generator tubes.

In this section, the units with thermally treated Alloy 600 steam generator tubes are divided into 

one of three categories: plants with model D5 steam generators, plants with model F steam 

generators, and plants with replacement model steam generators. For each unit, there is 

(1) a summary of the inspections, (2) a table summarizing the full-length bobbin coil 

examinations and number of tubes plugged during each outage, (3) a table summarizing the 

reasons for plugging each tube, and (4) a table listing the tubes plugged for reasons other than 

wear at the AVBs. In the tables that summarize the reasons for tube plugging, a category 

referred to as “other” was used to capture tubes that were plugged and for which the specific 

reason for plugging was not provided or was not clear. Tubes in this category were subdivided 

based on the location where the degradation was reported (e.g., at the top of the tubesheet). 

None of these indications were considered to have resulted from stress corrosion cracking.

3.2 Model D5 Steam Generator Operating Experience

Inspection results for Braidwood 2, Byron 2, Catawba 2, and Comanche Peak 2 are provided in 

this section of the report.

3.2.1 Braidwood 2

Tables 3-1, 3-2, and 3-3 summarize the information discussed below for Braidwood 2. 

Table 3-1 provides the number of full-length bobbin inspections and the number of tubes 

plugged and deplugged during each outage for each of the four steam generators. Table 3-2 

lists the reasons why the tubes were plugged. Table 3-3 lists tubes plugged for reasons other 

than wear at the AVBs.

Braidwood 2 has four Westinghouse model D5 steam generators. The licensee numbers its 

tube supports from 1H to 11H on the hot-leg side of the steam generator and from 1C to 11C on 

the cold-leg side (Figure 2-1). Based on accident analysis considerations, a maximum of 
3-2

30 percent of the tubes can be plugged in any one steam generator and a maximum of 

24 percent of the tubes in the four steam generators can be plugged.

During refueling outage (RFO) 9 in 2002, 100 percent of the tubes in steam generator A were 

inspected full length with a bobbin coil. As a result of these inspections, two tubes were 

plugged. These two tubes were plugged for wear at the AVBs. In addition to the bobbin coil 

inspections, all plugs in steam generator A were inspected visually. No degradation or 

abnormal leakage was identified during the inspection of the plugs. 

The only steam generator tube degradation mechanism observed during RFO 9 was wear at the 

AVBs.

A total of 343 indications of AVB wear were detected in steam generator A. The maximum 

depth reported for the AVB wear indications was 40 percent throughwall.

Inspection and maintenance on the secondary side of the steam generator were also performed 

during RFO 9. To reduce the amount of sludge on the top of the tubesheet, sludge lancing was 

performed in all four steam generators. After the sludge lancing, foreign object search and 

retrieval (FOSAR) was performed. FOSAR was performed on the top of the tubesheet in all four 

steam generators and at the 8th and 11th tube support plate in steam generators A and C. 

The visual inspections performed during FOSAR on the top of tubesheet focused on the 

periphery of the tube bundle, the open tube lane (i.e., the region between the hot- and cold-leg 

of the row 1 tubes), and the T-slot region. In addition, limited visual inspections within the tube 

bundle on the top of the tubesheet were performed down two hot-leg and cold-leg tube columns 

in all four steam generators. The upper tube support plate visual inspection also included the 

open tube lane and limited in-bundle inspections to assess deposit loading. The FOSAR 

inspections revealed a total of six loose parts in steam generators B (2 objects), C (1 object), 

and D (3 objects), four of which were removed. These loose parts included weld slag (3), a wire 

bristle (1), duct tape (1), and a metal object (1). None of these parts resulted in tube wear. 

Of the two objects that could not be removed, one was in steam generator B (row 22, columns 

79 and 80) and was characterized as weld slag measuring approximately 2.86 cm (1.125 in.) in 

height, 2.54 cm (1 in.) in length, and 8.89 mm (0.35 in.) in width on the tubesheet in the cold-leg; 

and the other object was in steam generator D (rows 6 and 7, column 2) and was characterized 

as a metal object measuring approximately 9.5 mm (0.375 in.) in height, 6.35 mm (0.25 in.) in 

length, and 6.35 mm (0.25 in.) in width on the tubesheet in the hot-leg. This latter object could 

be traced back to RFO 3 in 1993. 

There was no evidence of primary-to-secondary leakage during Cycle 10 (spring 2002 to fall 

2003).

During RFO 10 in 2003, 100 percent of the tubes in each of the four steam generators were 

inspected full length with a bobbin coil. In addition to the bobbin coil inspections, a rotating 

probe equipped with a plus-point coil was used to inspect:

• the expansion transition region on the hot-leg side of the steam generator from 7.6 cm 

(3 in.) above to 7.6 cm (3 in.) below the top of the tubesheet in 50 percent of the tubes 

• the U-bend region of 50 percent of the tubes in rows 1 and 2

• 50 percent of hot-leg dents and dings with bobbin voltage amplitudes greater than 

5 volts.
3-3

A rotating probe equipped with a plus-point coil was also used to inspect 20 percent of the tube 

expansions at the preheater baffles B and D (i.e., cold-leg tube support plate 2C and 3C, 

respectively) in steam generators B and C. In addition, all tube plugs in each of the four steam 

generators were inspected visually. No degradation or abnormal leakage was identified during 

the inspection of the plugs. 

As a result of these inspections, 58 tubes were plugged—10 were plugged for wear at the 

AVBs, 3 tubes were plugged because of outside-diameter-initiated crack-like indications at the 

hot-leg tube support plates, 3 low-row (i.e., stress-relieved) tubes were plugged preventatively 

because they had an eddy current offset indicative of higher residual stress, and 42 tubes were 

plugged for foreign objects. These 42 tubes included tubes plugged because of wear attributed 

to the foreign object, and it included tubes preventatively plugged because of the potential that 

they may be affected by nearby foreign objects. The cold legs of all 42 of these tubes were 

stabilized.

The only steam generator tube degradation mechanisms observed during RFO 10 were 

(1) wear at the AVBs, (2) wear at the preheater tube supports, (3) wear attributed to loose parts, 

and (4) axially oriented outside-diameter stress corrosion cracking at the tube support plate 

elevations.

RFO 10 inspections identified a total of 748 indications of AVB wear: 315 indications in steam 

generator A, 83 indications in steam generator B, 225 indications in steam generator C, and 

125 indications in steam generator D. The maximum depth reported for the AVB wear 

indications was 49 percent throughwall.

Wear was also detected at the tube support plates in the preheater region. Six tubes had 

indications of wear. The depth of these indications ranged from 4 percent to 18 percent

throughwall.

Before the commencement of RFO 10, tubes with an eddy current offset that could indicate 

higher residual stresses (and therefore higher susceptibility to cracking) were identified. 

Cracking associated with tubes with an eddy current offset was observed at Seabrook 

(Information Notice (IN) 2002-21, “Axial Outside-Diameter Cracking Affecting Thermally Treated 

Alloy 600 Steam Generator Tubing,” dated June 25, 2002, and its supplement, dated 

April 1, 2003, for more details).

The technique for detecting the eddy current offset was a quantitative technique for the tubes in 

rows 1 through 9 and a semi-qualitative technique for the tubes in rows 10 and above (the 

steam generator has 49 rows of tubes). For the low-row tubes (i.e., rows 1 through 9), the 

thermal stress relief of the U-bend region of the tube should result in consistently low stresses 

throughout the tube (i.e., no eddy current offset should exist). Any significant eddy current 

offset would indicate higher stresses in the straight span section of the tube. In the higher row 

tubes (i.e., greater than row 9), an eddy current offset is expected because the U-bend region of 

the tube is not stress relieved after bending. As a result, the method for determining the 

presence of an abnormal offset for the higher row tubes involved calculating the average eddy 

current offset associated with each row of tubes and the standard deviation associated with this 

average. Tubes with an offset whose magnitude was less than the mean minus two standard 

deviations were considered to have potentially higher residual stresses. That is, for the higher 

row tubes, the absence of an offset may indicate higher stresses in the straight span portion of 

the tube.
3-4

As a result of applying this low frequency bobbin coil screening technique to previous bobbin 

coil inspections results (i.e., before 2003), 77 tubes with possibly high residual stresses in the 

straight span portion of the tube were identified (these higher stresses may result in a higher 

likelihood for cracking). Three of these 77 tubes were in low-row tubes (i.e., rows 1 through 9) 

and 74 were in higher row tubes. Before the outage, the licensee planned on plugging all three 

tubes in the low-row tubes with the offset and any of the tubes in the higher row tubes with the 

offset that had a distorted bobbin coil indication regardless of whether an inspection with a 

rotating probe indicated a flaw was present at the location of the distortion.

No crack-like indications were found at any location except for at the tube support plates. At the 

tube support plates, four axially oriented indications indicative of outside-diameter stress 

corrosion cracking were observed. These four crack-like indications were observed in three of 

the higher row tubes (i.e., one tube had two indications) with an offset in the eddy current data 

(the indications were in 3 of the 77 tubes identified with an offset before the outage). In 

addition, the expansion transitions of the three tubes with crack-like indications and 31 of the 

remaining 74 tubes with the eddy current offset were inspected with a rotating probe and no 

degradation was detected during these inspections. 

Of the three tubes plugged because of crack-like indications indicative of outside-diameter 

stress corrosion cracking, two were in steam generator C, and one was in steam generator A. 

In steam generator C, two axial indications were observed in the tube at row 21, column 50, and 

one axial indication was observed in the tube at row 38, column 20. In the tube at row 21 

column 50, one indication was at the third tube support plate on the hot-leg side and had a 

bobbin voltage of 0.34 volt while the other indication was at the fifth tube support plate on the 

hot-leg side and had a bobbin voltage of 0.17 volt. The maximum voltage from the plus-point

coil for the indication at the third tube support plate was 0.41 volt, the length was 1.85 cm 

(0.73 in.), and the maximum depth was estimated from the voltage to be 47 percent throughwall. 

The percent degraded area was calculated to be 33.5 percent. The indication at the fifth tube 

support plate has a plus-point voltage of 0.23 volt. In the tube at row 38 column 20, the axial 

indication was at the seventh tube support plate on the hot-leg side tube and had a bobbin 

voltage of 0.13 volt and a plus-point voltage of 0.12 volt. None of these three indications were 

present during the prior inspection of these tubes in 2000 (based on a hindsight review). In 

steam generator A, one axial indication was observed in the tube at row 25, column 42. This 

indication was at the third tube support plate on the hot-leg side and had a bobbin voltage of 

0.08 volt and a plus-point voltage of 0.25 volt. With hindsight, a bobbin signal (about 0.07 volt) 

could be identified at this location in the 2002 tube inspection data. In the 2000 bobbin coil 

data, a questionable indication of 0.06 volts can be identified, but it is questionable in relation to 

the background noise. Each of these four bobbin indications was confirmed to be present with a 

rotating probe equipped with a plus-point coil and all of them were associated with a tube 

support plate land and were confined to within the tube support plate thickness. The eddy 

current offset in these three high row tubes was the least of any of tubes in the respective rows, 

indicating that the residual stresses in the straight spans of these tubes could be higher than the 

rest of the tubes, making these tubes more susceptible to cracking. The safety significance of 

these indications was analyzed, and it was concluded that all tubes had adequate integrity. 

These tubes were not in-situ pressure tested. All three of these tubes were plugged as were all 

three of the low-row tubes that had an eddy current offset (even though no flaws were detected 

in these tubes). 

FOSAR was performed in all four steam generators on the top of the tubesheet and in the 

preheater region during RFO 10. This was the first time that FOSAR was performed in the 

preheater region. The FOSAR revealed numerous loose parts primarily in the preheater region. 
3-5

Most of these parts were retrieved and did not result in any tube wear; however, a few loose 

parts could not be removed or resulted in tube wear. Six tubes had indications of wear 

attributed to loose parts. These indications ranged in size from 5 percent to 38 percent 

throughwall. For those tubes with wear adjacent to loose parts that could not be retrieved, the 

tubes were stabilized and plugged.

Of the loose parts that were detected, only nine could not be removed from the steam 

generators. For five of these parts, a licensee analysis showed that it was acceptable to leave 

these parts and the nearby tubes in service. Four of these parts were small wires between the 

tube and the tube support plate that could be grabbed, but could not be removed. The fifth part 

was a small metal object on the top of the tubesheet in steam generator D. This part has been 

present since RFO 6 (1997) and appears to be in the same location and has not changed in 

size. None of these five parts has caused any tube wear. 

For the remaining four loose parts, the tubes surrounding these parts were plugged and 

stabilized. Forty-two tubes were plugged and stabilized because of finding these parts. Most of 

these tubes (35) were plugged because of finding two manufacturing fit-up bars (also referred to 

as backing bars) on top of preheater baffle B (i.e., the second cold-leg tube support) in steam 

generator B. These bars measure 2.54 cm (1 in.) by 2.54 cm (1 in.) by 7.6 cm (3 in.) and assist 

in the assembly of the steam generator. They were installed (i.e., welded) on the bottom of 

preheater baffle D (i.e., the third cold-leg tube support). These fit-up bars serve no structural or 

operational function. After visually identifying the presence of these fit-up bars, it was 

determined from previous eddy current data that one of these bars was present on the top of 

preheater baffle B (i.e., the second cold-leg tube support) since the spring of 1990, while the 

other has been present since the fall of 1994. These bars resulted in tube wear with one bar 

resulting in two wear scars (maximum depths of 28 percent and 21 percent throughwall) in one 

tube and the other bar resulting in one wear scar (maximum depth of 5 percent throughwall). 

One of these bars also was attributed to a volumetric indication that was detected in a 

neighboring tube in 1994 (and measured 39 percent throughwall) and was subsequently 

plugged (but not stabilized) in 1997. With the visual identification of this part, this volumetric 

indication is now attributed to wear from the fit-up bar. 

Each steam generator has 22 fit-up bars. Fourteen of these bars are on the bottom of the first 

hot- and cold-leg tube support, four are on the bottom of baffle plate D (i.e., the third cold-leg 

tube support), and four are on a portion of the preheater near the center of the tube bundle and 

above the first tube support plate (i.e., 1H and 1C). If these latter bars were to fall, they would 

most likely end up on the first tube support plate. During the outage, the backing bars were 

determined to be present either directly or indirectly in all four steam generators. All of the 

backing bars were in place (with the exception of the two mentioned above). The failure of 

these two backing bars was attributed to fabrication loads/weld shrinkage. The backing bars 

were most likely misaligned such that when the permanent wedges and stay rods were 

installed, they resulted in high loads on the backing bar welds, resulting in their failure. The 

wedges and stay rods support and position the support plate. Visual inspection of the two 

backing bars showed that the welds had sheared and there was no evidence that the failure 

was a result of fatigue. 

As discussed above, the two backing bars found on top of preheater baffle B could not be 

removed from the steam generator. As a result, all tubes surrounding the backing bars were 

stabilized and plugged. In addition, the licensee stabilized and plugged all tubes surrounding 

the tube that was plugged in 1997 for the volumetric indication near one of these backing bars. 
3-6

As a precautionary measure, the tubes surrounding the remaining two intact backing bars on 

the bottom of preheater baffle plate D in steam generator B were also stabilized and plugged. 

On April 25, 2005, the steam generator portion of the Braidwood 2 technical specifications was 

revised to limit the extent of inspection in the hot-leg tubesheet region. Specifically, the 

technical specifications excluded the portion of tube that is more than 43.2 cm (17 in.) below the 

top of the tubesheet from inspection (i.e., approximately the lowermost 10.2 cm (4 in.) of tube in 

the tubesheet on the hot-leg side was excluded from inspection, and hence any flaws that may 

exist in this region are permitted to remain in service). This revision was applicable only to RFO 

11 and the subsequent operating cycle (Agencywide Documents Access and Management 

System (ADAMS) Accession No. ML051170149)

During RFO 11 in 2005, 100 percent of the tubes in each of the four steam generators were 

inspected full length with a bobbin coil. In addition, a rotating probe equipped with a plus-point 

coil was used to inspect:

• 20 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the hot-leg side 

• 20 percent of the tubes from the top of the tubesheet to 43.2 cm (17 in.) below the top of 

the tubesheet on the hot-leg side of the steam generator (this included 20 percent of the 

bulges—with bobbin voltage amplitudes greater than or equal to 18 volts—and 

overexpansions—with expansions greater than or equal to 0.038 mm (1.5 mils or 0.0015 

in.)—between the top of the tubesheet and 43.2 cm (17 in.) below the top of the 

tubesheet on the hot-leg side of the steam generator) 

• the expansion transition region on the hot-leg side (from 7.6 cm (3 in.) above to 7.6 cm 

(3 in.) below the top of the tubesheet) in 50 percent of the tubes identified as having 

increased residual stress. 

In addition, a rotating probe equipped with a plus-point coil was also used to inspect 20 percent 

of the tube expansions in the preheater in steam generator C, and the plug expansion zone 

region in the one tube that had previously been deplugged. In addition, all tube plugs in each of 

the four steam generators were inspected visually. No degradation or abnormal leakage was 

identified during the inspection of the plugs. 

As a result of these inspections, six tubes were plugged—five for wear at the AVBs, and one for

wear from a loose part. This latter tube also was stabilized on the hot-leg side of the steam 

generator.

The only steam generator tube degradation mechanisms observed during RFO 11 were wear at 

the AVBs, wear at the preheater tube supports, and wear attributed to loose parts.

A total of 775 indications of AVB wear were detected during RFO 11: 334 indications in steam 

generator A, 82 indications in steam generator B, 226 indications in steam generator C, and 133 

indications in steam generator D. The maximum depth reported for the AVB wear indications 

was 44 percent throughwall.

Wear was also observed at the tube support plates in the preheater region. Eight tubes had 

indications of wear. The depth of these indications ranged from 4 percent to 21 percent 

throughwall. 
3-7

Wear attributed to loose parts was detected in four tubes, including the tube that was plugged. 

The maximum depth reported for the wear indication attributed to a foreign object in the tube 

that was plugged during RFO 11 was 24 percent throughwall. This indication was below the 

eighth tube support plate on the hot-leg side of the steam generator.

FOSAR was conducted in the preheater region of steam generator B during RFO 11. No 

foreign objects that had the potential of causing significant tube wear were identified. Most

objects identified were retrieved, and for the objects remaining in the steam generator (small 

objects), the licensee performed an analysis confirming that they were acceptable to leave in 

the steam generator. Because secondary-side visual inspections were not performed in the 

other three steam generators, a rotating probe was used to inspect the preheater tube 

expansion transitions in the corner tube region. No wear attributed to loose parts and no 

possible loose parts were identified during these inspections. The corner tube region is an area 

in the preheater region on the second baffle plate that is adjacent to the flow blocking device. 

Industry operating experience indicates that foreign objects (loose parts) migrate to this area 

and may cause tube wear. 

Visual inspections of the waterbox cap plate and waterbox rib region was conducted in all four 

steam generators during RFO 11. This was in response to industry operating experience 

indicating that extensive erosion could occur in these regions (Byron 2). Only trace amounts of 

erosion were observed in the waterbox cap plate flow holes. No erosion was observed in the 

waterbox rib holes.

The secondary-side moisture separator region of steam generator D was inspected during RFO 

11. This was the first in-service inspection of this region. Erosion of the primary moisture 

separator tangential nozzles, downcomer barrels, and swirl vanes was identified. This condition 

existed in varying degrees on 12 of the 16 primary separator assemblies. The components 

identified with the missing magnetite layer are fabricated from carbon steel. Several ultrasonic 

thickness measurements were taken in areas with the most apparent erosion (in areas where 

the magnetite layer was missing). The normal thickness of the various components is 6.35 mm 

(0.250 in.) and the minimum measured thickness of any of the ultrasonically inspected 

components was 4.5 mm (0.177 in.) An analysis was performed by the licensee that 

determined that the erosion in the affected areas would not penetrate through wall over the next 

operating cycle; and therefore, would not affect steam generator performance or generate loose 

parts. 

No crack-like indications were detected during RFO 11.

On October 24, 2006, the steam generator portion of the Braidwood 2 technical specifications 

was revised to limit the extent of inspection in the hot-leg tubesheet region. Specifically, the 

technical specifications were revised to exclude the portion of tube that is more than 43.2 cm 

(17 in.) below the top of the tubesheet from inspection (i.e., approximately the lowermost

10.2 cm (4 in.) of tube in the tubesheet on the hot-leg side was excluded from inspection, and 

hence any flaws that may exist in this region are permitted to remain in service). This revision 

was applicable only to RFO 12 and the subsequent operating cycle (ADAMS Accession No. 

ML062780507).

During RFO 12 in 2006, 100 percent of the tubes in each of the four steam generators were 

inspected full length with a bobbin coil. In addition to the bobbin coil inspections, a rotating 

probe equipped with a plus-point coil was used to inspect:
3-8

• 20 percent of the tubes within the tubesheet on the hot-leg side from 7.6 cm (3 in.)

above to 7.6 cm (3 in.) below the top of the tubesheet 

• 20 percent of the tubes within the tubesheet from the top of the tubesheet to 43.2 cm 

(17 in.) below the top of the tubesheet on the hot-leg side of the steam generator (this 

included 20 percent of the hot-leg bulges with bobbin voltage amplitudes greater than or 

equal to 18 volts and overexpansions greater than or equal to 0.038 mm (1.5 mils) within 

the hot-leg tubesheet to 43.2 cm (17 in.) below the top of the tubesheet)

• 100 percent of the 71 tubes within the tubesheet on the hot-leg side from 7.62 cm (3 in.)

above to 43.2 cm (17 in.) below the top of the tubesheet in tubes identified as having 

increased residual stress

A rotating probe equipped with a plus-point coil also was used to inspect:

• 20 percent of the preheater baffle plate expansions in steam generator D

• 25 percent of the hot-leg dents and dings with bobbin voltage amplitudes greater than 3 

volts in each of the four steam generators

• the U-bend region of 25 percent of the tubes in rows 1 and 2 in each of the four steam 

generators

In addition, a rotating probe equipped with a plus-point coil was also used to inspect the plug 

expansion zone region in the one tube that had been deplugged. All of the bobbin coil data 

from the hot-leg and cold-leg region of the tubesheet were analyzed to identify any unexpanded 

tubes in each of the four steam generators. In addition, all tube plugs in each of the four steam 

generators were inspected visually. No degradation or abnormal leakage was identified during 

the inspection of the plugs. 

As a result of these inspections, 14 tubes were plugged—10 for wear at the AVBs, 2 for wear 

attributed to loose parts, and 2 for indications of wear at the tube support plates in the preheater 

region.

The only steam generator tube degradation mechanisms observed during RFO 12 were wear at 

the AVBs, wear at the preheater tube supports, and wear attributed to loose parts.

A total of 847 indications of AVB wear were detected during RFO 12: 374 indications in steam 

generator A, 92 indications in steam generator B, 242 indications in steam generator C, and 139 

indications in steam generator D. The maximum depth reported for the AVB wear indications 

was 46 percent throughwall.

Eight tubes were identified with wear indications at the tube support plates in the preheater 

region. The depth of these indications ranged from 3 percent to 46 percent throughwall.

Two tubes were identified with new indications of wear attributed to loose parts. One of the 

wear indications was 16 percent throughwall, and it was identified in steam generator A, in row 

12, column 70, slightly below the fifth tube support plate on the hot-leg side. The second wear 

indication was 22 percent throughwall, and it was identified in steam generator C in row 8, 

column 18 slightly below the seventh tube support plate on the hot-leg side. Both tubes affected 
3-9

by secondary-side foreign objects were stabilized and plugged. Neither of these two tube 

locations was accessible for secondary-side visual inspections. Review of eddy current 

plus-point data for the affected tubes and the surrounding tubes showed no evidence of a 

foreign object remaining in the area. No anomalies were identified in the support plate or 

surrounding structures. Review of historical eddy current data showed no signs of wear or a 

foreign object at these locations in previous outages. In addition to these two tubes, four other 

tubes had indications of foreign object wear. The indications in these four tubes have not 

changed since RFO 11.

All of the tubes were confirmed to be expanded within the tubesheet region.

FOSAR was performed in each of the four steam generators during RFO 12. Inspections were 

performed at the top of the tubesheet, periphery of the tube bundle, limited in-bundle, and tube 

free lane. FOSAR was also performed in the preheater high flow regions in steam generator C. 

No foreign objects that had the potential to cause significant tube wear were identified in the 

preheater region in steam generator C. Most objects identified were retrieved, and the licensee 

analyzed the objects remaining in the steam generator (small objects), confirming that they were 

acceptable to leave in the steam generator. Because secondary-side visual inspections were 

not performed in the preheater region of the other three steam generators, a rotating probe was 

used to inspect the preheater tube expansion transitions in the corner tube region. No wear 

attributed to loose parts and no possible loose parts were identified during these inspections. 

The corner tube region is an area in the preheater region on the second baffle plate that is 

adjacent to the flow blocking device. Industry operating experience indicates that foreign 

objects (loose parts) migrate to this area and may cause tube wear. FOSAR inspections 

revealed 22 loose parts in steam generators A (1 object), B (1 object), C (18 objects) and D (2 

objects), 17 of which were removed. None of these objects caused wear to the surrounding 

tubes.

The waterbox cap plate and waterbox rib region in steam generator C were inspected visually

during RFO 12. These inspections indicated only trace amounts of erosion in the waterbox cap 

plate flow holes (similar to that observed in RFO 11), and no erosion was observed in the 

waterbox rib holes.

Of the five foreign objects that could not be retrieved, four were characterized as wires 0.4 mm 

(0.016 in.) in diameter and of various lengths (with a maximum length of 1.9 cm (0.75 in.)). 

These four objects were in the preheater region of steam generator C (i.e., at the second

cold-leg tube support). The fifth foreign object that could not be removed was characterized as 

a 2.54-cm long by 3.175-mm tall by .254-mm thick (1-in. long by 0.125-in. tall by 0.010-in. thick)

metal strip, and was in steam generator D (at row 3, column 3 at the top of the tubesheet on the 

hot-leg side). The licensee performed an analysis and determined that operation until the next 

scheduled steam generator inspection (i.e., RFO 13) was acceptable with these foreign objects 

remaining in the steam generators.

Visual inspection of the waterbox rib and cap plate regions and the 8th and 11th tube support 

plate regions in steam generator C were also performed during RFO 12. The inspections at the 

tube support plates were primarily performed to assess deposit loading.

Follow-up visual inspections and ultrasonic thickness measurements were taken in eroded 

areas of the secondary-side moisture separator region of steam generator D. These areas were 

initially identified during RFO 11. Continued erosion of the components was identified, although 

none of the areas was throughwall. An analysis was performed by the licensee that determined 
3-10

that the erosion in the affected areas would not penetrate through wall over the next operating 

cycle; and therefore, would not affect steam generator performance or generate loose parts. 

On March 30, 2007, the steam generator portion of the Braidwood 2 technical specifications

was revised to make them performance-based consistent with TSTF Improved Standard 

Technical Specifications Change Traveler TSTF-449 and to delete Westinghouse laser welded 

sleeving as an authorized repair method (ADAMS Accession Nos. ML070810354 and 

ML071210555).

On April 18, 2008, the steam generator portion of the Braidwood 2 technical specifications was 

revised to permit certain sized flaws near the tube end in both the hot- and cold-leg sides of the 

steam generator to remain in service. Specifically, the technical specifications were revised to 

(1) permit flaws having a circumferential component less than or equal to 203 degrees found in 

the portion of the tube below 43.2 cm (17 in.) from the top of the tubesheet and above 2.54 cm 

(1 in.) from the bottom of the tubesheet to remain in service, (2) require the removal from 

service all flaws having a circumferential component greater than 203 degrees found in the 

portion of the tube below 43.2 cm (17 in.) from the top of the tubesheet and above 2.54 cm 

(1 in.) from the bottom of the tubesheet, (3) require the removal from service all tubes with 

service-induced flaws between the top of the tubesheet and 43.2 cm (17 in.) below the top of 

the tubesheet, and (4) permit all axial indications found in the portion of the tube below 43.2 cm 

(17 in.) from the top of the tubesheet to remain in service. In addition, the technical 

specifications were modified to indicate that when more than one flaw with circumferential 

components is found in the portion of the tube below 43.2 cm (17 in.) from the top of the 

tubesheet and above 2.54 cm (1 in.) from the bottom of the tubesheet with the total of the 

circumferential components being greater than 203 degrees and the axial separation distance of 

less than 2.54 cm (1 in.), then the tube must be removed from service (overlapping portions of 

the flaws only need to be counted once in determining the total circumferential involvement of 

the flaws). For flaws within 2.54 cm (1 in.) of the bottom of the tubesheet, the technical 

specifications were modified to indicate (1) when one or more flaws with circumferential 

components are found and the total of the circumferential components exceeds 94 degrees, 

then the tube shall be removed from service and (2) when one or more flaws with 

circumferential components are found in the portion of the tube within 2.54 cm (1 in.) from the 

bottom of the tubesheet and within 2.54 cm (1 in.) axial separation distance of a flaw above 

2.54 cm (1 in.) from the bottom of the tubesheet, and the total of the circumferential components 

found in the tube exceeds 94-degrees then the tube shall be removed from service (overlapping 

portions of the flaws only need to be counted once in determining the total circumferential 

involvement of the flaws). This revision to the technical specifications was applicable only to 

RFO 13 and the subsequent operating cycle (ADAMS Accession No. ML080920889).

There was no evidence of primary-to-secondary leakage during Cycle 13 (fall 2006 to spring 

2008).

During RFO 13 in 2008, 100 percent of the tubes in each of the four steam generators were 

inspected full length with a bobbin coil excluding the U-bend region of the tubes in rows 1 and 2 

(and the cold-leg straight sections of 15 tubes since these tubes were plugged before the 

completion of the cold-leg inspections). In addition to the bobbin coil inspections, a rotating 

probe equipped with a plus-point coil was used to inspect:

• 20 percent of the tubes on the hot-leg side from 7.6 cm (3 in.) above to 7.6 cm (3 in.)

below the top of the tubesheet
3-11

• 20 percent of the tubes from the top of the tubesheet on the hot-leg side of the steam 

generator to the hot-leg tube end (this included 20 percent of the hot-leg bulges with 

bobbin voltage amplitudes greater than or equal to 18 volts and overexpansions greater 

than or equal to 0.038 mm (1.5 mils) above 2.54 cm (1 in.) from the tube end)

• 100 percent of the tubes from the tube end to 2.54 cm (1 in.) above the tube-end on the 

hot-leg side

• 100 percent of the tubes from 7.62 cm (3 in.) above the tubesheet on the hot-leg side to 

the hot-leg tube end in tubes identified as having increased residual stress

A rotating probe equipped with a plus-point coil was also used to inspect:

• 20 percent of the preheater baffle plate expansions in steam generator A (and several 

peripheral tubes in the other steam generators at tube support 2C near the flow blocking 

region of the preheater because this location has been known as an area where 

secondary-side foreign objects may collect because of the flow conditions in this region)

• 100 percent of the hot-leg dents and dings with bobbin voltage amplitudes greater than 3 

volts in tubes with increased residual stress in each of the four steam generators

• 25 percent of the hot-leg dents and dings with bobbin voltage amplitudes greater than 3 

volts in tubes in each of the four steam generators

• the U-bend region of 25 percent of the tubes in rows 1 and 2 in each of the four steam 

generators

• 100 percent of the wear indications contained in in-service tubes with increased residual 

stress (none were identified in RFO 13)

In addition, a rotating probe equipped with a plus-point coil was also used to inspect the plug 

expansion zone region in the one tube that had previously been deplugged. In addition, all tube 

plugs in each of the four steam generators were inspected visually. No degradation or 

abnormal leakage was identified during the inspection of the plugs.

As a result of these inspections, 23 tubes were plugged—6 for wear at the AVBs, 1 for wear 

attributed to loose parts, and 16 for primary water stress corrosion cracking indications near the 

tube ends.

The only steam generator tube degradation mechanisms observed during RFO 13 were 

(1) wear at the AVBs, (2) wear at the preheater tube supports, (3) wear attributed to loose parts, 

and (4) primary water stress corrosion cracking at the tube ends.

A total of 868 indications of AVB wear were detected during RFO 13: 360 indications in steam 

generator A, 97 indications in steam generator B, 249 indications in steam generator C, and 162 

indications in steam generator D. The maximum depth reported for the AVB wear indications 

was 43 percent throughwall. 

Six tubes were identified with wear indications at the tube support plates in the preheater region. 

The depth of these indications ranged from 3 percent to 30 percent throughwall.
3-12

One tube in row 3, column 85 in steam generator C had an 11 percent throughwall indication 

slightly above the fifth tube support plate on the cold-leg side. This tube was stabilized and 

plugged. Review of previous data indicates that the indication had been present since the first 

in-service inspection in 1990 and had not changed. Additionally four tubes distributed in steam 

generators A, B, and D had five indications of foreign object wear that had not changed since 

RFO 12. These tubes were left in service since the depth of the degradation is below the 

Technical Specification limits and visual verification that the object that had caused the wear 

was no longer present.

A total of 285 axial and 46 circumferential indications were detected in the bottom 2.54 cm 

(1 in.) of tubing on the hot-leg side of the steam generator during RFO 13. These indications 

were attributed to primary water stress corrosion cracking and are in 288 tubes. Of the 288 

tubes affected by these indications, 16 were plugged because the flaw size exceeded the 

acceptance criteria discussed above. All 16 of these tubes were in steam generator A, and all 

but 1 of these tubes were in row 1. Two of the tubes with axial indications near the tube end 

have potentially higher residual stress as determined by eddy current inspection. Both tubes 

were left in service. Given that there are 71 tubes with potentially higher residual stress, the 

percentage of tubes with high residual stress that have cracks is approximately 2.8 percent. 

Cracking was observed in 1.6 percent of the tubes without potentially higher residual stresses.

Sludge lancing and FOSAR was performed in all four steam generators during RFO 13. The 

FOSAR was performed after the sludge lancing, and the following areas on the top of the 

tubesheet were inspected: tubesheet annulus, peripheral tubes (three to five tubes deep), tube 

lane, and T-slot. In addition, FOSAR was performed in the tube lane and in the peripheral tubes 

in the tube lane (three to five tubes deep) on the first baffle plate.

A visual inspection of the secondary-side moisture separator regions was performed in all four 

steam generators during RFO 13. These inspections were performed in response to previous 

erosion observed in the moisture separator tangential nozzles, downcomer barrels, and swirl 

vanes in steam generator D during RFO 11. This was the first inspection of all accessible areas 

in steam generators A, B, and C. Continued erosion of the components in steam generator D 

was identified, although none of the areas was throughwall. Erosion was also found in the other 

three steam generators with the most significant eroded area being identified in steam generator 

C, which exhibited a maximum wall loss of 48 percent based on the original manufacturing 

nominal wall thickness. The licensee performed an analysis, which determined that the erosion 

in the affected areas would not penetrate through wall over the next operating cycle; and 

therefore, would not affect steam generator performance or generate loose parts.

Limited secondary-side visual inspections of the upper bundle region in steam generator C have 

been performed since RFO 9 to evaluate and trend upper bundle deposits in order to schedule 

future cleaning operations. Access to the upper bundle region is available through 5.08-cm 

(2.0-in.) diameter access openings at the 8th and 11th tube supports. The visual inspections 

were performed primarily on tubes adjacent to the tube lane with some limited in-bundle 

inspections. During RFO 13, portions of tube support plates 8, 9, 10, and 11 in steam generator 

C were inspected visually. Most plates had accumulated a layer of soft sludge or soft scale 

deposits that ranged from 3- to 7.62-mm (0.120- to 0.300-in.) thick. Flow holes and quatrefoils 

were clear and open, but trace amounts of deposits were forming around the edges. The hotleg tube bundle deposits were noticeably more developed than the cold-leg.

On October 16, 2009, the steam generator portion of the Braidwood 2 technical specifications 

was revised to limit the extent of inspection in the tubesheet region. Specifically, the technical 
3-13

specifications were revised to exclude the portion of tube that is more than 43 cm (16.95 in.)

below the top of the tubesheet from inspection (i.e., approximately the lowermost 10.2 cm (4 in.)

of tube in the tubesheet was excluded from inspection, and hence any flaws that may exist in 

this region are permitted to remain in service). This revision was only applicable for RFO 14 

and the subsequent operating cycle (ADAMS Accession No. ML092520512).

There was no evidence of primary-to-secondary leakage during Cycle 14 (spring 2008 to fall 

2009).

During RFO 14 in 2009, 100 percent of the tubes in each of the four steam generators were 

inspected full length with a bobbin coil, excluding the U-bend region of the tubes in rows 1 and 

2. In addition to the bobbin coil inspections, a rotating probe equipped with a plus-point coil was 

used to inspect the following in each of the four steam generators:

• the U-bend region of 25 percent of the tubes in rows 1 and 2

• 30 percent of the tubes from 10.2 cm (4 in.) above the top of the tubesheet to 45.7 cm 

(18 in.) below the top of the tubesheet on the hot-leg side (which included 30 percent of 

bulges within the top 43 cm (16.95 in.) of the tubesheet on the hot-leg side with bobbin 

voltage amplitudes greater than or equal to 18 volts and overexpansions greater than or 

equal to 0.038 mm (1.5 mils))

• all 71 tubes identified as having increased residual stress from 10.2 cm (4 in.) above the 

top of the tubesheet to 45.7 cm (18 in.) below the top of the tubesheet on the hot-leg 

side

A rotating probe equipped with a plus-point coil was also used to inspect:

• 25 percent of hot-leg dents and dings with bobbin voltage amplitudes greater than 3 

volts in each of the four steam generators

• 100 percent of the hot-leg dents and dings with bobbin voltage amplitudes greater than 2

volts (total of 4 dents and dings) in the 71 tubes with potentially high residual stress

• all wear indications in the 71 tubes with potentially high residual stress (no indications)

• 20 percent of the preheater baffle plate expansions in steam generator B (i.e., 20

percent of the tube expansions at tube supports 2C and 3C)

• the preheater expansions near the “corner” of the preheater (i.e., the outer peripheral 

tubes near the flow blocking region on tube support 2C) in steam generators B, C, and D

In addition to these eddy current inspections, all tube plugs in each of the four steam generators

were inspected visually. No anomalies were identified during the inspection of the plugs.

As a result of these inspections, six tubes were plugged—one for AVB wear and five for wear 

attributed to loose parts.

The only steam generator tube degradation mechanisms observed during RFO 14 were wear at 

the AVBs, wear at the preheater tube supports, and wear attributed to loose parts.
3-14

A total of 896 indications of AVB wear were detected during RFO 14: 374 indications in steam 

generator A, 108 indications in steam generator B, 241 indications in steam generator C, and 

173 indications in steam generator D. The maximum depth reported for the AVB wear 

indications was 41 percent throughwall.

In addition to the wear indications at the AVBs, six indications of wear at the tube support plates 

in the preheater region were identified in six tubes. The depth of these indications ranged from 

5 percent to 36 percent throughwall.

Fourteen indications of wear attributed to loose parts were found in 13 tubes during RFO 14. 

These indications ranged from 9 percent to 37 percent throughwall. Five of the wear indications 

(in four tubes) did not change in size from the previous inspection and a visual inspection did 

not identify any loose parts near the tube. These tubes remain in-service. Three tubes had 

wear indications attributed to a piece of slag that measured 5.1 mm (0.2 in.) by 3.8 mm 

(0.15 in.) by 5.1 mm (0.2 in.) The slag was removed from the steam generator and the tubes 

were left in service. Five of the tubes with a wear indication were stabilized and plugged since 

the location could not be inspected visually. One tube was allowed to remain in-service since a 

visual inspection did not identify any loose parts in the vicinity of the wear indication.

During RFO 14, the bottom of the expansions transitions of all tubes were verified to be within 

2.54 cm (1 in.) of the top of the tubesheet.

During RFO 14, inspection/maintenance was performed on the secondary side of the steam 

generators. During RFO 14, a visual inspection of the waterbox cap plate in steam generator D 

was performed. No components were missing; however, there were trace levels of erosion at 

the cap plate flow hole openings. The amount of erosion has had no appreciable change since 

RFO 11 in 2005.

Visual inspections of the secondary-side moisture separator region was performed in steam 

generators B and C during RFO 14 because of detecting erosion of the moisture separator 

tangential nozzles, downcomer barrels, and swirl vanes during RFO 13. Ultrasonic thickness 

measurements were taken of the eroded areas with an emphasis on re-inspecting the areas 

identified as eroded during RFO 13. These inspections showed that the erosion was continuing, 

but no indications of throughwall erosion were found. The extent of erosion was similar in the 

two steam generators with a maximum wall loss of 47 percent in steam generator B and 38

percent in steam generator C as compared to the original manufacturing nominal value. During 

RFO 13, the wall loss in steam generator C measured 48 percent throughwall. This 

discrepancy was attributed, in part, to the magnetite layer that covers the internal surfaces. The 

magnetite layer is not uniform and significantly changes from cycle-to-cycle. Although some 

magnetite is removed to couple the ultrasonic transducer to the component, the inaccessible 

surface of the component is not cleaned before the inspection, and the ultrasonic thickness 

reading varies depending on the thickness and density of the magnetite layer. In addition, 

because the surfaces being monitored are internal to the steam generator, they cannot be 

physically marked. As a result, the exact same location may not be measured each inspection.

A licensee analysis indicated that the erosion in the affected areas is not projected to penetrate 

throughwall, create loose parts, or affect steam generator performance before the next 

inspection.

On April 13, 2011, the steam generator portion of the Braidwood 2 technical specifications was 

revised to limit the extent of inspection in the tubesheet region, excluding the portion of tube that 

is more than 43 cm (16.95 in.) below the top of the tubesheet from inspection (i.e., 
3-15

approximately the lowermost 10.2 cm (4 in.) of tube in the tubesheet was excluded from 

inspection, and hence any flaws that may exist in this region are permitted to remain in service). 

This revision was only applicable for RFO 15 and the subsequent operating cycle (ADAMS 

Accession No. ML110840580).

There was no evidence of primary-to-secondary leakage during Cycle 15 (fall 2009 to spring 

2011).

During RFO 15 in 2011, 100 percent of the tubes in each of the four steam generators were 

inspected full length with a bobbin coil, excluding the U-bend region of the tubes in rows 1 and 

2. In addition to the bobbin coil inspections, a rotating probe equipped with a plus-point coil was 

used to inspect the following in each of the four steam generators:

• the U-bend region of 25 percent of the tubes in rows 1 and 2 (and 39 other tubes with 

manufacturing artifacts)

• 25 percent of the tubes from 10.2 cm (4 in.) above the top of the tubesheet to 45.7 cm 

(18 in.) below the top of the tubesheet on the hot-leg side (which included 25 percent of 

bulges within the top 43 cm (16.95 in.) of the tubesheet on the hot-leg side with bobbin 

voltage amplitudes greater than or equal to 18 volts and overexpansions greater than or 

equal to 0.038 mm (1.5 mils))

• all tubes (71 tubes) identified as having increased residual stress from 10.2 cm (4 in.)

above the top of the tubesheet to 45.7 cm (18 in.) below the top of the tubesheet on the 

hot-leg side

A rotating probe equipped with a plus-point coil was also used to inspect:

• 25 percent of the historic hot-leg dents and dings with bobbin voltage amplitudes greater 

than 3 volts in each of the four steam generators

• 100 percent of the hot-leg dents and dings identified during RFO 15 with bobbin voltage 

amplitudes greater than 3 volts in each of the four steam generators

• 100 percent of the hot-leg dents and dings with bobbin voltage amplitudes greater than 3

volts (2 dents and dings) in the 71 tubes with potentially high residual stress

• all wear indications in the 71 tubes with potentially high residual stress (1 indication)

• 25 percent of the preheater baffle plate expansions in all four steam generators (i.e., 25

percent of the tube expansions at tube supports 2C and 3C)

• 100 percent of the preheater expansions near the “corner” of the preheater (i.e., the 

outer peripheral tubes near the flow blocking region on tube support 2C) in the three 

steam generators in which a visual inspection of the preheater region was not scheduled 

to be performed (i.e., steam generators B, C, and D)

In addition to these eddy current inspections, all tube plugs in each of the four steam generators

were inspected visually. No anomalies were identified during the inspection of the plugs.
3-16

As a result of these inspections, 30 tubes were plugged—5 for AVB wear, 2 for preheater tube 

support wear, 18 for wear attributed to loose parts, 4 for potential loose parts, and 1 for axially 

oriented outside-diameter stress corrosion cracking.

The only steam generator tube degradation mechanisms observed during RFO 15 were 

(1) wear at the AVBs, (2) wear at the preheater tube supports, (3) wear attributed to loose parts, 

and (4) axially oriented outside-diameter stress corrosion cracking at the tube support plate 

elevations (in a tube with potentially elevated residual stresses as evidenced by an offset in the 

eddy current data).

A total of 927 indications of AVB wear were detected during RFO 15: 385 indications in steam 

generator A, 106 indications in steam generator B, 257 indications in steam generator C, and 

179 indications in steam generator D. The maximum depth reported for the AVB wear 

indications was 45 percent throughwall.

In addition to the wear indications at the AVBs, six indications of wear at the tube support plates 

in the preheater region were identified in six tubes. The depth of these indications ranged from 

4 percent to 41 percent throughwall.

Twenty-eight indications of wear attributed to loose parts were found in 27 tubes during RFO 15. 

These indications ranged from 4 percent to 40 percent throughwall. Nine of the wear indications 

(in eight tubes) did not change in size from the previous inspection and a visual inspection did 

not identify any loose parts near the tube. These tubes remain in-service. Eighteen tubes with 

a wear indication were stabilized and plugged since the location could not be inspected visually. 

One tube was allowed to remain in-service since a visual inspection did not identify any loose 

parts in the vicinity of the wear indication.

Three indications of axially oriented outside-diameter stress corrosion cracking were identified in 

one tube (row 2, column 35) during RFO 15. All of the indications were on the hot-leg at an 

elevation where the tube passes through the tube support plate. Indications were detected at 

tube supports 3H (maximum voltage of 0.22 volts, length of 2.13 cm (0.84 in.), and maximum 

depth of 36.3 percent throughwall), 7H (maximum voltage of 0.25 volts, length of 0.66 cm 

(0.26 in.), and maximum depth of 30.8 percent throughwall), and 9H (maximum voltage of 

0.3 volts, length of 2.2 cm (0.87 in.), and maximum depth of 48.3 percent throughwall). The 

indications at all three tube supports were associated with a single quatrefoil land. All of the 

indications were confirmed with a Ghent probe. This tube had an eddy current signature 

indicative of high residual stresses (i.e., a low-row tube with an eddy current offset).

Thirty-nine tubes were identified with manufacturing indications in the U-bend region. The 

manufacturing artifacts in the U-bend represent a dimensional change in the tube diameter at 

the tangent point (i.e., where the tube transitions from the straight portion to the U bend) that 

was created during tube bending. These artifacts are similar to the artifact that was present in a 

tube that experienced cracking at this location at Vogtle 1 in 2009.

During RFO 15, inspection/maintenance was performed on the secondary side of the steam 

generators. Sludge lancing was scheduled to be performed in all four steam generators. 

Fifty-four pounds of sludge was removed from steam generator A, 39.5 pounds of sludge was 

removed in steam generator C, and 46.5 pounds of sludge was removed from steam generator 

D. Following sludge lancing, FOSAR was scheduled for all four steam generators. These 

inspections revealed no foreign objects in steam generator A and five objects were observed in 
3-17

steam generator D. Of the five objects in steam generator D, four were removed (wire bristles) 

and the other object, which has been present since RFO 6, remains adhered to the tubesheet.

During RFO 15, steam generator A was inspected visually. These inspections included the 

waterbox cap plate and the “corner” preheater expansion region on tube support 2C. The 

inspections revealed five wire bristles, which were removed; a deposit that looked like a 

machine turning that broke up when retrieval was attempted; and a bushing that had been in the 

steam generator since a prior inspection.

Visual inspections of the secondary-side moisture separator region was performed in steam 

generator B during RFO 15 because of detecting erosion of the moisture separator tangential 

nozzles, downcomer barrels, and swirl vanes during RFO 13 and RFO 14. Ultrasonic thickness 

measurements were taken of the eroded areas with an emphasis on re-inspecting the areas 

identified as eroded during RFO 13 and RFO 14. These inspections indicated that the erosion 

was continuing, but no indications of throughwall erosion were identified. The maximum wall 

loss measured 51 percent as compared to the original manufacturing nominal value. An 

analysis (performed by the licensee) indicated that the erosion in the affected areas is not 

projected to penetrate throughwall, create loose parts, or affect steam generator performance 

before the next inspection.

On October 5, 2012, the steam generator portion of the Braidwood 2 technical specifications 

was revised to limit the extent of inspection in the tubesheet region and to remove Combustion 

Engineering tungsten inert gas welded sleeving as an authorized repair method. Specifically, 

the technical specifications were revised to exclude the portion of tube that is more than 35.59 

cm (14.01 in.) below the top of the tubesheet from inspection (i.e., approximately the lowermost 

17.8 cm (7 in.) of tube in the tubesheet was excluded from inspection, and hence any flaws that 

may exist in this region are permitted to remain in service (ADAMS Accession No. 

ML12262A360). With approval of this amendment, there were no authorized repair methods 

(other than tube plugging) at Braidwood 2.

There was no evidence of primary-to-secondary leakage during Cycle 16 (spring 2011 to fall 

2012).

During RFO 16 in 2012, 100 percent of the tubes in each of the four steam generators were 

inspected full length with a bobbin coil, excluding the U-bend region of the tubes in rows 1 and 

2. In addition to the bobbin coil inspections, a rotating probe equipped with a plus-point coil was 

used to inspect the following in each of the four steam generators:

• the U-bend region of 25 percent of the tubes in rows 1 and 2 (and 39 other tubes with 

manufacturing artifacts)

• 25 percent of the tubes from 10.2 cm (4 in.) above the top of the tubesheet to 38 cm 

(15 in.) below the top of the tubesheet on the hot-leg side (which included 25 percent of 

bulges within the top 35.59 cm (14.01 in.) of the tubesheet on the hot-leg side with 

bobbin voltage amplitudes greater than or equal to 18 volts and overexpansions greater 

than or equal to 0.038 mm (1.5 mils))

• all 71 tubes found to have increased residual stress from 10.2 cm (4 in.) above the top of 

the tubesheet to 38 cm (15 in.) below the top of the tubesheet on the hot-leg side
3-18

A rotating probe equipped with a plus point coil was also used to inspect:

• 25 percent of the hot-leg dents and dings with bobbin voltage amplitudes greater than 3 

volts in each of the four steam generators

• 100 percent of the hot-leg dents and dings identified during RFO 16 with bobbin voltage 

amplitudes greater than 3 volts in each of the four steam generators

• 100 percent of the hot-leg dents and dings with bobbin voltage amplitudes greater than 

3 volts (3 dents and dings) in the 71 tubes with potentially high residual stress, 

• all wear indications in the 71 tubes with potentially high residual stress (no indications)

• 25 percent of the preheater baffle plate expansions in all four steam generators (i.e., 25

percent of the tube expansions at tube supports 2C and 3C)

• 100 percent of the preheater expansions near the “corner” of the preheater (i.e., the 

outer peripheral tubes near the flow blocking region on tube support 2C) in the two

steam generators in which a visual inspection of the preheater region was not scheduled 

to be performed (i.e., steam generators A and D)

In addition to these eddy current inspections, all tube plugs in each of the four steam generators

were inspected visually. No anomalies were identified during the inspection of the plugs.

As a result of these inspections, 11 tubes were plugged—2 for AVB wear, 6 for wear attributed 

to loose parts, 2 for potentially having increased residual stresses, and 1 for axially oriented 

outside-diameter stress corrosion cracking.

The only steam generator tube degradation mechanisms observed during RFO 16 were 

(1) wear at the AVBs, (2) wear at the preheater tube supports, (3) wear attributed to loose parts, 

(4) axially oriented outside-diameter stress corrosion cracking at tube support plate elevations, 

and (5) axially oriented outside-diameter stress corrosion cracking in the freespan.

A total of 969 indications of AVB wear in 530 tubes were detected during RFO 16: 408

indications (in 219 tubes) in steam generator A, 107 indications (in 61 tubes) in steam generator 

B, 273 indications (in 139 tubes) in steam generator C, and 181 indications (in 111 tubes) in 

steam generator D. The maximum depth reported for the AVB wear indications was 40 percent

throughwall.

In addition to the wear indications at the AVBs, four indications of wear at the tube support 

plates in the preheater region were identified in four tubes. The depth of these indications 

ranged from 2 percent to 15 percent throughwall.

Sixteen indications of wear attributed to loose parts were found in 15 tubes during RFO 16. 

These indications ranged from 10 percent to 39 percent throughwall. Ten of the wear 

indications (in nine tubes) did not change in size from the previous inspection and a visual 

inspection did not identify any loose parts near the tube. These tubes remain in-service. Six

tubes with a wear indication were stabilized and plugged since the location could not be

inspected visually.
3-19

Three indications of axially oriented outside-diameter stress corrosion cracking were identified in 

one tube (row 44, column 47) during RFO 16. All three indications were on the hot-leg side of 

the steam generator. Two of the indications were at an elevation where the tube passes 

through the tube support plate. Indications were detected at tube supports 3H (maximum pluspoint voltage of 0.64 volts, length of 1.42 cm (0.56 in.), and maximum depth of 69.6 percent

throughwall) and 5H (maximum plus-point voltage of 0.25 volts, length of 0.122 cm (0.48 in.), 

and maximum depth of 50.0 percent throughwall). These two indications were associated with 

a single quatrefoil land and did not extend outside the tube support plate. One of the indications 

(maximum plus-point voltage of 0.34 volts, length of 0.48 cm (0.19 in.), and maximum depth of 

56.4 percent throughwall) was in the freespan between tube supports 3H and 5H and originated 

from a low level ding indication (with a bobbin amplitude of approximately 1 volt). There was no 

evidence of a scratch along the length of the tube. The indications at the tube supports and in 

the freespan were not aligned axially along the length of the tube as evidenced from the 

plus-point data that was acquired from 7.62 cm (3 in.) above tube support 5H to 7.62 cm (3 in.)

below tube support 3H. The affected tube was identified as potentially having elevated residual 

stresses caused by nonoptimal tube processing because the eddy current data for this tube (a 

high row tube) had no U-bend offset signal (typically referred to as a “2-sigma tube”). 

This tube had not been identified as a tube potentially having elevated residual stress when the 

screening was done in 2000. It was not identified because the analyst mistakenly used the 

peak-to-peak voltage on one leg of the eddy current data instead of the maximum voltage rate. 

As a result, a re-evaluation of the high row tubes was performed during RFO 16. This review 

identified no other tubes with potentially elevated residual stress. All the tubes with potentially 

elevated residual stress were reviewed to determine if any had no voltage offset (similar to the 

tube that had the axial indications this outage). Two tubes were identified with this condition 

and were preventatively plugged.

The indication at the 3H tube support plate was in-situ pressure tested, with no leakage 

observed at any test pressure, including the test pressure associated with three times the 

normal operating differential pressure. Only the indication at 3H was tested because it 

exceeded the threshold for performing in-situ pressure testing.

During the original production analysis of the bobbin coil eddy current data, only the indication at 

the 3H tube support plate was identified. The primary or secondary analysis of the data did not 

find the other two indications in this tube (at 5H and in the freespan), but rather the independent 

qualified data analyst found the indications. The primary analysis (of the bobbin coil data) was 

performed using an automated data analysis system operated in the interactive mode, and the 

secondary analysis was performed using human analysts. An investigation into why the 

freespan indication was not identified by the automated analysis system revealed that the 

freespan indication had a phase angle of 151 degrees, whereas the flaw identification algorithm 

was set to only identify indications that were less than 150 degrees. Because of these findings, 

the licensee increased its criterion to 151 degrees. The criterion was not increased above 

151 degrees because of concerns that many nonflaw-like signals would be identified.

The automated data analysis system missed the indication at the 5H tube support plate 

because the flaw identification algorithm was not applied at this location. For the automated 

flaw identification algorithm to apply at a tube support plate, the entire tube support plate must 

be contained within a data evaluation window size of 27. Because the entire 5H tube support 

plate was not within this window size, the automated system did not apply the flaw identification 

algorithm at this location. The licensee increased the window size to 31 to ensure the flaw 
3-20

identification algorithm would be applied to all tube support plates. The licensee also reduced 

the voltage threshold for identifying the tube support plate region from 1 volt to 0.8 volts.

Because of these findings, all bobbin coil data were re-analyzed with the automated data 

analysis system operated in the interactive mode with the revised criteria. The re-analysis 

identified no additional crack-like indications.

The licensee reviewed the prior inspection data for the three indications attributed to 

outside-diameter stress corrosion cracking. This review revealed a 20-degree change in the 

phase angle of the freespan indication (which appeared ding-like) from 1990 to the present. For 

the indications at the tube supports, no indications were present in the 2009 data at either 

support and no indication was present in the 2011 data for the 5H tube support plate. However, 

with hindsight, some evidence of a signal could be seen in the 2011 data for the signal at the 3H 

tube support plate (but the signal would not have been reportable).

During RFO 16, inspection/maintenance was performed on the secondary side of the steam 

generators. Sludge lancing was performed in all four steam generators. After sludge lancing, 

the top of the tubesheet was inspected visually, including the annulus, tube lane, T-slot, and the 

peripheral tubes (three to five tubes into the tube bundle). The tube surfaces at the top of the 

tubesheet were mostly clean with minor soft sludge deposition on all tube surfaces except at the 

in-bundle columns within the kidney region on the hot-leg side of the steam generator, which 

had scale deposition on the tubes to a maximum height of 12.7 mm (0.5 in.) above the 

tubesheet. These results were consistent with past inspections.

These inspections found 75 loose parts. Of these loose parts, 23 (including 2 loose parts that 

were present in prior outages) were removed from the steam generators, 20 involved an 

unknown red substance (which could not be retrieved or sampled), 12 were loose parts that 

were present in prior outages but could not be removed from the steam generators, and 20 

were new loose parts (mainly wire and one machine turning) that could not be retrieved. Most

of the loose parts were small wires (that are similar to bristles from wire brushes), small 

machine turnings, and weld slag). No tube wear was associated with these loose parts. The 

licensee performed an analysis, which showed it was acceptable to leave the loose parts in the 

steam generator until the next inspection. This analysis was based on foreign object size, 

mass, materials and flow conditions. The red substance was evaluated based on various 

expected sources and materials and was also determined to be acceptable.

During RFO 16, a visual inspection of the high flow regions on preheater tube support 2C (which 

is the first support that experiences incoming main feedwater flow) and the waterbox rib and cap 

plate region were performed in steam generators B and C. Soft loose sludge was found in 

some in-bundle tube column locations. The height of the sludge was less than 3.175 mm 

(0.125 in.). No hard sludge deposits were identified.

The upper tube bundle region in steam generator C was also inspected visually during RFO 16. 

This inspection was performed at tube supports 8 and 11 and included the tube lanes and four 

in-bundle columns at each tube support plate. The purpose of these inspections was to assess 

the general condition of the upper tube bundle. Trace amounts of loose scale deposits on the 

support plates and a layer of scale deposits on the tubes at both the hot-leg and cold-leg inbundle tube column region were observed. The quatrefoil flow holes on the cold-leg were free 

of blockage and only contained trace amounts of scale. Several quatrefoils on the hot-leg sided 

exhibited the initiation of minor scale forming at the bottom edge of several quatrefoil flow holes. 

The amount of blockage in the affected quatrefoil flow holes was visually estimated to be 
3-21

approximately 10 percent or less. Most of the quatrefoil flow holes inspected did not exhibit 

scale formation or blockage. There were no notable changes in the deposit characteristics or 

blockage since the last inspection in RFO 14. It was observed, however, that deposit blockage 

appears to have affected more quatrefoil flow holes during RFO 16 than in RFO 14.

No anomalous structural conditions were found during the secondary-side visual inspections.

No visual or ultrasonic thickness measurements of the secondary-side moisture separator 

region were performed during RFO 16.

Visual inspections of the channel head cladding were performed during RFO 16. The 

inspections were limited to the lower portion of the channel head, within a radial distance of 

about 91.4 cm (36 in.) from the channel head drain tube. This location was considered as 

having the highest potential for accumulating concentrated borated water during refueling 

outages. The visual inspection included the divider plate-to-channel head weld, the top of the 

channel head bowl drain tube, and the channel head cladding in the general area. Gross 

defects such as through-cladding holes or breaches that could expose the carbon steel base 

material were not identified. Wastage of the carbon steel base material was not identified (as 

evidenced through a lack of rust-colored stains. 

On March 21, 2013, the steam generator portion of the Braidwood 2 technical specifications 

was revised to make them consistent with TSTF Improved Standard Technical Specifications 

Change Traveler TSTF-510 (ADAMS Accession No. ML13009A172).

3.2.2 Byron 2

Tables 3-4, 3-5, and 3-6 summarize the information discussed below for Byron 2. Table 3-4 

summarizes the full-length bobbin inspections and the number of tubes plugged and deplugged 

during each outage for each of the four steam generators. Table 3-5 lists the reasons why the 

tubes were plugged. Table 3-6 lists tubes plugged for reasons other than wear at the AVBs.

Byron 2 has four Westinghouse model D5 steam generators. The licensee numbers its tube 

supports from 1H to 11H on the hot-leg side of the steam generator and from 1C to 11C on the 

cold-leg side (Figure 2-1).

In July 2001, a small primary-to-secondary leak was identified in steam generator C. From July 

2001 through December 2001, the leak rate was primarily less than 7.57 lpd (2 gpd). The leak

rate increased in January 2002 to about 37.9 lpd (10 gpd). In February 2002, the leak rate

started to oscillate between 37.9 and 94.6 lpd (10 and 25 gpd) for several weeks and then 

returned to less than 19 lpd (5 gpd). The leak rate began increasing again in late April/early 

May. On June 22, 2002, Byron 2 was shut down when the leak rate was slightly above 284 lpd 

(75 gpd) (i.e., 284 to 303 lpd, or 75 to 80 gpd).

To identify the source of the leak, a pressure test (standing water and 344.7 kilopascals (kPa) 

(50 pounds per square inch (psi)) overpressure) was performed on the secondary side of the 

steam generator. With no applied pressure on the secondary side of the steam generator (i.e., 

only the static head of the water covering the tube bundle), a steady stream of water was 

observed coming from the cold-leg side of the tube in Row 43, Column 23. To ensure all 

leaking tubes were identified, a 344.7 kPa (50 psi) nitrogen overpressure was applied to the 

secondary side of the steam generator, and no other leaking tubes were identified.
3-22

A bobbin coil and rotating probe equipped with a plus-point coil were used to inspect the leaking 

tube, identifying a flaw 1.35 cm (0.53 in.) above cold-leg tube support 2C, which is in the 

preheater region of the steam generator. The bobbin coil inspection was performed on the full 

length of the tube. The flaw was characterized as an outside-diameter-initiated volumetric flaw 

measuring 7.62 mm (0.3 in.) in length and affecting 103 degrees of the tube circumference. The 

flaw had a voltage of 2.02 volts. Although the flaw is known to be 100 percent throughwall

(because it was leaking), two eddy current techniques estimated the depth to be 71 percent

throughwall (amplitude technique) or 97 percent throughwall (phase analysis). 

The leaking tube was in-situ pressure tested to confirm its structural and leakage integrity. At a 

pressure corresponding to normal operating pressure, the leakage from the tube measured 

136 lpd (36 gpd). The licensee attributed the difference between this value and the value 

observed during operation (i.e., about 284 lpd (75 gpd)) to the sensitivities/accuracies of the 

techniques. At a pressure corresponding to a steam line break (target pressure of 20,120 kPa 

(2,918 psi) given that the tests were performed at ambient temperature), the leakage from the 

tube measured 223 lpd (59 gpd). The actual test pressure was 20,680 kPa (3,000 psi). After 

inserting a bladder in the tube to avoid excessive leakage, the tube was pressurized to 

32.410 kPa (4,700 psi) (slightly above the target pressure of 31,830 kPa (4,617 psi)) and the 

tube did not burst. All pressures were held for 5 minutes. These results confirmed the tube had 

adequate structural and leakage integrity.

In addition to the leaking tube, 10 surrounding tubes were also inspected. Of these 10 tubes, 7 

tubes were inspected with a bobbin coil probe from the cold-leg tube end to tube support 3C. In 

addition to these bobbin coil examinations, a rotating probe equipped with a plus-point coil was 

used to inspect seven tubes (not including the tube that leaked), at tube support 2C and 3C 

from 5.1 cm (2 in.) above to 5.1 cm (2 in.) below the tube support and 3 tubes at tube support 

2C from 5.1 cm (2 in.) above to 5.1 cm (2 in.) below the tube support. These inspections 

resulted in the identification of three other flaws in two tubes. As with the leaking tube these 

flaws were outside-diameter-initiated volumetric flaws. In tube row 43, column 22, a 7.62-mm 

(0.3-in.) long flaw affecting 106 degrees of the tube circumference and estimated at 37 percent

throughwall was observed 12.4 mm (0.49 in.) above the second tube support plate on the 

cold-leg side (i.e., 2C). The voltage associated with this flaw was 0.42 volts. In tube row 43 

column 24, there were two indications. One indication was 6.02 mm (0.237 in.) in length, 

affected 67 degrees of the tube circumference, and was estimated at 11 percent throughwall. 

This indication was 11.7 mm (0.46 in.) above the top of the second tube support plate on the 

cold-leg side, and it had a voltage of 0.07 volts. The second indication on this tube was 2.16 cm 

(0.85 in.) above the top of the second tube support plate on the cold-leg side (i.e., 2C) and was 

6.78 mm (0.267 in.) in length, affected 51 degrees of the tube circumference, and was 

estimated at 13 percent throughwall. The voltage associated with this flaw was 0.08 volts. 

These tubes were last examined in 1,999 and there was no indication of degradation at that 

time. All three affected tubes were stabilized and plugged.

No visual inspections on the secondary side of the steam generator were performed during the

June 2002 mid-cycle outage; however, the eddy current data were reviewed for evidence of a 

loose part signal. There was no evidence of a loose part evident in the eddy current data. More 

detailed inspections of this region were planned for the next refueling outage, which was 

scheduled for September 2002. As discussed below, these inspections resulted in attributing 

the wear in these three tubes to two pieces of spiral wound sheathing.

No primary-to-secondary leakage was observed between June 2002 (following plugging the 3 

tubes discussed above) and RFO 10.
3-23

During RFO 10 in 2002, 100 percent of the tubes in each of the four steam generators were 

inspected full length with a bobbin coil. In addition to the bobbin coil inspections, a rotating 

probe equipped with a plus-point coil was used to inspect 75 percent of the tubes from 7.6 cm (3 

in.) above to 7.6 cm (3 in.) below the top of the tubesheet on the hot-leg side of the steam 

generator, and the U-bend region of 75 percent of the tubes in rows 1 and 2. A rotating probe 

equipped with a plus-point coil was also used to inspect the following in each of the four steam 

generators:

• 25 percent of the hot-leg dings and dents with bobbin voltage amplitudes greater than 5 

volts in steam generators A and B

• 100 percent of the hot-leg dings and dents with bobbin voltage amplitudes greater than 5 

volts in steam generators C and D 

• 25 percent of the preheater baffle plate expansions in steam generators B, C, and D

In addition to these eddy current inspections, visual inspections were performed on all tube 

plugs in each of the four steam generators. No degradation or abnormal leakage was identified 

during the inspection of the plugs. 

As a result of these inspections, 14 tubes were plugged—2 for indications of wear at the AVBs, 

11 for foreign object wear, and 1 for an indication of wear at the tube support plates in the

preheater region.

The only steam generator tube degradation mechanisms observed during RFO 10 were wear at 

the AVBs, wear at the preheater tube supports, and wear attributed to loose parts.

A total of 757 indications of AVB wear in 453 tubes were detected during RFO 10: 195 

indications (in 111 tubes) in steam generator A, 291 indications (in 165 tubes) in steam 

generator B, 162 indications (in 102 tubes) in steam generator C, and 109 indications (in 75 

tubes) in steam generator D. The maximum depth reported for the AVB wear indications was 

40 percent throughwall.

In addition to the wear indications at the AVBs, 15 tubes were found that contained indications 

of wear in the preheater region at the tube support plates. The depths of these indications 

ranged from 6 percent to 19 percent throughwall. The tube plugged because of preheater wear, 

at row 48, column 36, was preventatively plugged.

Tube degradation attributed to foreign objects was found in 11 tubes. The indications ranged 

from 3 percent to 32 percent throughwall. All 11 tubes that contained these indications of wear 

attributed to foreign objects were plugged. No indications of wear attributed to foreign objects 

were left in service. All foreign objects that caused wear in the tubes were removed from the 

steam generators although there was no foreign object near one of the tubes with wear. This 

latter tube is in a region where the object may have been removed by sludge lancing.

During this outage, the licensee knew of the cracking indications identified at Seabrook (NRC IN

2002-21) and included the eddy current data from the Seabrook indications in their site specific 

performance demonstration.
3-24

To reduce the amount of sludge on the top of the tubesheet, sludge lancing was performed in 

each of the four steam generators. After the sludge lancing, FOSAR was performed at the top 

of the tubesheet in each of the four steam generators. Because of the degradation observed 

during the mid-cycle outage in June 2002, FOSAR also was performed in the 

preheater/waterbox region of steam generator C. In steam generator B, an upper bundle 

inspection also was planned to evaluate thermal performance. 

The FOSAR near the tubes that were plugged in June 2002 identified two pieces of spiral 

wound sheathing. These two pieces were similar in appearance and structure, and measured 

3.175 mm (an eighth inch) in diameter and approximately 7.62 and 8.89 cm (3 and 3.5 in.) in 

length. Laboratory analysis revealed these two pieces were originally one piece. 

Fatigue-induced failure of this object was most likely caused during the fretting of the tube that 

resulted in the mid-cycle outage in June 2002. After this failure, the two pieces migrated 

downstream of the damaged tubes. No maintenance activities that would have resulted in 

leaving this sheathing in the secondary system were identified. The licensee postulated that the 

increased feedwater flow from their recent power uprate may have caused dormant objects to 

migrate through systems and into the steam generator. These objects were believed to be the 

cause of the wear on the leaking tube, because they had wear marks and geometry that

matched the degradation on the affected tubes. The licensee postulated that the object might

have been in the steam generator since fabrication because no maintenance activities could 

have resulted in leaving the sheathing in the secondary system. 

There was no evidence of primary-to-secondary leakage during Cycle 11 (fall 2002 to spring 

2004).

During RFO 11 in 2004, 100 percent of the tubes in each of the four steam generators were 

inspected full length with a bobbin coil. In addition to the bobbin coil inspections, a rotating 

probe equipped with a plus-point coil was used to inspect the following in each of the four steam 

generators:

• 25 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the hot-leg side of the steam generator 

• 100 percent of the tubes (40) from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of 

the tubesheet on the hot-leg side of the steam generator in tubes with the potential of 

having increased residual stress

• the U-bend region of 25 percent of the tubes in rows 1 and 2

• 25 percent of the hot-leg dents and dings with bobbin voltage amplitudes greater than 5 

volts

A rotating probe equipped with a plus-point coil also was used to inspect 25 percent of the 

preheater baffle plate expansions in steam generators A and D (i.e., 25 percent of the tube 

expansions of preheater baffle B (cold-leg tube support 2C) and D (cold-leg tube support 3C)). 

In addition to these eddy current inspections, visual inspections were performed on all tube 

plugs in each of the four steam generators. No degradation or abnormal leakage was identified 

during the inspection of the plugs. 

As a result of these inspections, 92 tubes were plugged—1 for indications of wear at the AVBs 

and 91 for foreign objects. These 91 tubes included 1 tube that was plugged because of wear 
3-25

attributed to the foreign object and 90 tubes preventatively plugged to prevent potential loose 

parts from affecting active tubes. The cold legs of all 91 tubes were stabilized.

The only steam generator tube degradation mechanisms observed during RFO 11 were wear at 

the AVBs, wear at the preheater tube supports, and wear attributed to loose parts.

A total of 702 indications of AVB wear in 430 tubes were detected during RFO 11: 173 

indications (in 102 tubes) in steam generator A, 273 indications (in 158 tubes) in steam 

generator B, 158 indications (in 106 tubes) in steam generator C, and 98 indications (in 64 

tubes) in steam generator D. The maximum depth reported for the AVB wear indication was 40

percent throughwall.

In addition to the wear indications at the AVBs, 21 tubes were found that contained indications 

of wear in the preheater region at the tube support plates. The depth of these indications 

ranged from 5 percent to 22 percent throughwall.

Before the commencement of the steam generator tube inspections, a low frequency bobbin coil 

eddy current screening technique was used to identify tubes that may have an eddy current 

offset similar to that observed at Seabrook. At Seabrook, several tubes were identified to have 

crack-like indications associated with this offset (NRC IN 2002-21, “Axial Outside-Diameter 

Cracking Affecting Thermally Treated Alloy 600 Steam Generator Tubing” dated June 25, 2002, 

and its supplement dated April 1, 2003, for more details). 

The technique for detecting the eddy current offset was similar to that used at Braidwood 2 in 

the fall of 2003 (ML033580377). The technique for detecting the offset was a quantitative 

technique for the tubes in rows 1 through 9 and a semi-qualitative technique for the tubes in 

rows 10 and above (there are 49 rows of tubes in the steam generator). For the low-row tubes 

(i.e., rows 1 through 9, inclusive), the thermal stress relief of the U-bend region of the tube 

should result in consistently low stresses throughout the tube (i.e., no eddy current offset should 

exist). Any significant eddy current offset would be indicative of higher stresses in the straight 

span section of the tube. In the higher row tubes (i.e., greater than row 9), an eddy current 

offset is expected because the U-bend region of the tube is not stress relieved after bending. 

As a result, the methodology for the higher-row tubes involved calculating the average eddy 

current offset along with the standard deviation associated with the higher-row tubes. To 

identify tubes with an offset that may be a precursor for cracking, tubes were “flagged” that had 

an offset whose magnitude was less than the mean minus two standard deviations. That is, for 

the higher-row tubes, the absence of an offset may indicate higher stresses in the straight span 

portion of the tube. 

As a result of applying this low-frequency bobbin coil screening technique to its previous bobbin 

coil inspection results (i.e., RFO 10 results) from each steam generator, the licensee identified 

40 tubes with possibly high residual stresses in the straight span portion of the tube (these 

higher stresses could result in a higher likelihood for cracking). All 40 tubes were higher-row 

tubes (i.e., greater than row 9). These tubes were inspected full length with a bobbin coil probe, 

and were inspected with a rotating probe in the hot-leg expansion transition region.

Inspection and maintenance on the secondary side of the steam generator also were performed 

during RFO 11. To reduce the amount of sludge on the top of the tubesheet, sludge lancing 

was performed in all four steam generators. After the sludge lancing, FOSAR was performed

on the top of the tubesheet and in the preheater region of each of the four steam generators. 

This was the first time that FOSAR was performed in the preheater region in steam generators 
3-26

A, B, and D. Visual inspections were also performed at the 8th and 11th tube support plates in 

steam generator B to assess the deposit loading conditions in the steam generators.

Numerous objects (e.g., hard scale/sludge rocks, washers, pieces of Flexitallic gaskets) were 

found during these inspections. Most of these parts were retrieved and did not result in any 

appreciable tube wear. However, tube degradation was found in five tubes that was attributed 

to wear from a loose part. The depths of these indications ranged from 6 percent to 57 percent

throughwall. The wear indications in two of these tubes were a result of interaction with a 

“backing” bar and are discussed further below. All loose parts that caused tube damage were 

removed from the steam generators. There were a few parts that could not be removed from 

the steam generators, but these parts did not result in any indicated tube wear. These latter 

parts are also discussed further below.

Nine small wires and one hard sludge rock could not be removed from the steam generators. In 

addition, four loose parts that have been present in the steam generator for many years could 

not be removed. The licensee evaluated the potential for these parts to cause tube damage,

concluding no tube integrity concerns exist for at least two cycles. For most parts, the licensee 

concluded there was no tube integrity concern associated with these parts for six years or more. 

In steam generator A, two carbon steel “backing” bars measuring 26.67 cm (10.5 in.) long by 

1.9 cm (0.75 in.) wide by 0.635 cm (0.25 in.) thick were found in the preheater region (i.e., the 

cold-leg of the steam generator). One of these bars was in the periphery and resulted in tube 

wear while the other was deeper in the tube bundle and did not result in any tube damage. The 

backing bar in the periphery damaged two tubes: row 49, column 50 had a 57 percent

throughwall indication; row 49 column 51 had a 17 percent throughwall indication. The 

indications were slightly above preheater baffle plate “B” (i.e., tube support 2C). These two 

tubes were stabilized and plugged. Backing bar 1, the one that caused the tube damage was 

identified by eddy current examination and subsequently removed from the steam generator. 

Backing bar 2 was removed before performing the eddy current examination. The tube with the 

57 percent throughwall indication was in-situ pressure tested (a local test that only spanned the 

flawed region), and it was determined that the tube met all performance criteria. There was no 

leakage at any of the test pressures up to three times the normal operating differential pressure. 

The tube was stabilized and plugged.

The two backing bars found in steam generator A came from the waterbox cap plate region. 

The waterbox cap plate region is near the lower feedwater inlet and is associated with the 

preheater region of the steam generator. The cap plate (i.e., the top portion of the waterbox) 

was modified during initial steam generator fabrication to allow access to the waterbox. The 

modification involved cutting out two rectangular sections measuring 25.4 cm (10 in.) long and 

5.1 cm (2 in.) wide and then welding these cutout regions back into the cap plate once access to 

the waterbox was no longer needed. To facilitate the welding of the cutout region into the cap 

plate, backing bars were used on the underside of each of the cutout regions of the cap plate. 

Two long backing bars (26.7 cm (10.5 in.) by 1.9 cm (0.75 in.) by 6.35 mm (0.25 in.)) and two 

small backing bars (or tabs) were used for each cutout region. These backing bars were 

secured to the underside of the cutout with tack welds. The cutout region was then welded to 

the cap plate from the top. 

As a result of visual inspections performed in 2004, it was discovered that for one of the two 

cutout regions in steam generator A, all four backing bars were present, although for the other 

cutout region, both long backing bars and one of the short (3.175 cm or 1.25 in.) backing bars 

was missing. The two long backing bars were found and retrieved while the short backing bar 
3-27

was not found despite the 100 percent bobbin coil inspection and a visual inspection of all 

high-flow regions. In addition to the degradation of the tack welds securing these three backing 

bars, erosion of the weld associated with the cutout region was discovered. 

Because of these findings, previous eddy current data were reviewed to ascertain when the 

backing bars detached from the cap plate. Because no wear was detected during the last 

outage in fall 2002 when a 100 percent bobbin coil inspection was performed, the licensee 

concluded that the backing bars detached during the cycle just before RFO 11 (i.e., cycle 11,

between fall 2002 and spring 2004).

To determine the extent of condition, the fabrication records were reviewed and visual 

inspections were performed of the cap plate region in all four steam generators. These efforts 

resulted in the conclusion that the waterbox cap plate was not modified in steam generators B 

and C, but that the cap plate in steam generators A and D were modified. However, the 

inspections and record review indicated that the modifications in steam generator D were 

different than that in steam generator A. Namely, in steam generator D, a full penetration weld 

with no “permanent” backing bars was used to reinstall the cut-out region into the cap plate (a 

removable backing bar may have been used). In addition, the cutout region for steam generator 

D was not rectangular shaped, but rather was three-sided and involved the edge of the cap 

plate. Based on the visual inspections, the licensee concluded there is no integrity concern with 

the weld of the cut-out region in steam generator D (i.e., no evidence of erosion of the cap 

plate/cutout region weld and no evidence that backing bars was used). The weld was inspected 

from the underside of the cap plate (i.e., no visual inspections were performed from the top of 

the cap plate).

Given that three backing bars detached during the cycle and the condition of the weld of the 

cutout region in steam generator A, the licensee evaluated the consequences of a failure of the 

cutout region and the consequences associated with failure of the remaining backing bars (i.e., 

the two long and three short backing bars remaining). The two main concerns associated with 

failure of these regions are that feedwater flow can bypass the preheater and loose parts can 

damage the tubes. 

The licensee determined that if the cutout region or the backing bars detached from the cap 

plate, loose parts could result in unacceptable tube damage. As a result, 91 tubes were 

stabilized and plugged in steam generator A. These 91 tubes included all peripheral tubes in 

rows 40 and higher (including all tubes in row 49) and several tubes in the T-slot region of the 

steam generator. Row 40 was selected because there is a physical barrier in this region that 

would restrict the passage of these parts. The licensee’s evaluation concluded that wear with 

the edge of the backing bars was more limiting than wear with the side of the backing bar. This 

was supported not only by analysis but also on the lack of degradation associated with the 

second backing bar. The first backing bar damaged two tubes because of edge wear on one 

tube and flat wear on an adjacent tube (as discussed above). 

If the cutout region were to come free from the cap plate, there would be less flow through the 

preheater region (i.e., the feedwater would bypass the preheater). This condition would result in 

a decrease in thermal efficiency and would alter the nominal ratio of flow coming into the steam 

generator through the upper and lower feedwater nozzles. As a result, the licensee evaluated: 

(1) the potential for flow-induced vibration to affect the tubes, (2) waterbox structural integrity, 

(3) the effect on normal operating parameters, and (4) the effect on safety analysis for 

design-basis transients and accidents. The licensee concluded that failure of the cutout regions 

of the cap plate would not result in flow-induced vibration of the tubes, would not affect the 
3-28

structural integrity of the waterbox, and did not affect the safety analyses for design basis 

transients and accidents. Upon failure of the cutout region, the licensee indicated that a small 

feedwater transient could occur possibly resulting in a feedwater flow (high/low) alarm. Failure 

of the cutout regions would also result in changes to steam generator secondary pressure 

(82.7 kPa (12 psi) pressure drop). The primary water temperature across the steam generator 

also would change (i.e., nominal loop differential temperature would change). The net result of 

a failure could result in a loss of 3 percent thermal power. The licensee concluded that any 

changes to operating parameters would be acceptable from a safety standpoint (including 

changes to the core power distribution).

On September 19, 2005, the steam generator portion of the Byron 2 technical specifications 

was revised to limit the extent of inspection in the hot-leg tubesheet region. Specifically, the 

technical specifications were revised to exclude the portion of tube that is more than 43.2 cm 

(17 in.) below the top of the tubesheet from inspection (i.e., approximately the lowermost 10.2 

cm (4 in.) of tube in the tubesheet on the hot-leg side was excluded from inspection, and hence 

any flaws that may exist in this region are permitted to remain in service). This revision was 

applicable only to RFO 12 and the subsequent operating cycle (ADAMS Accession No. 

ML052230019).

There was no evidence of primary-to-secondary leakage during Cycle 12 (spring 2004 to fall 

2005).

During RFO 12 in 2005, 100 percent of the tubes in each of the four steam generators were 

inspected full length with a bobbin coil. In addition to the bobbin coil inspections, a rotating 

probe equipped with a plus-point coil was used to inspect 20 percent of the tubes from 7.62 cm 

(3 in.) above to 43.2 cm (17 in.) below the top of the tubesheet on the hot-leg side of the steam 

generator. The latter sample included at least 20 percent of bulges with bobbin voltage 

amplitudes greater than or equal to 18 volts and overexpansions greater than or equal to 

0.038 mm (1.5 mils) within the top 43.2 cm (17 in.) of the hot-leg tubesheet. In addition, a 

rotating probe equipped with a plus-point coil was used to inspect all 40 tubes identified as 

having increased residual stress from 7.62 cm (3 in.) above to 43.2 cm (17 in.) below the top of 

the tubesheet on the hot-leg side of the steam generator. The above inspections were 

performed in each of the four steam generators. A rotating probe equipped with a plus-point coil 

was also used to inspect 20 percent of the total number of preheater baffle expansions that 

would be contained in a single steam generator, with the inspections being equally distributed 

between steam generators B, C, and D. In addition to these eddy current inspections, all tube 

plugs in each of the four steam generators were inspected visually. No degradation or 

abnormal leakage was identified during the inspection of the plugs. 

As a result of these inspections, 17 tubes were plugged—1 for wear at the AVBs, 6 for

indications of wear at the tube support plates in the preheater region, 7 for indications of foreign 

object wear, 2 for bulges at the cold-leg tubesheet, and 1 for not being hydraulically expanded in 

the hot-leg tubesheet.

The only steam generator tube degradation mechanisms observed during RFO 12 were wear at 

the AVBs, wear at the preheater tube supports, and wear attributed to loose parts.

A total of 775 indications of AVB wear in 466 tubes were detected during RFO 12: 167 

indications (in 96 tubes) in steam generator A, 282 indications (in 163 tubes) in steam generator 

B, 195 indications (in 126 tubes) in steam generator C, and 131 indications (in 81 tubes) in 
3-29

steam generator D. The maximum depth reported for the AVB wear indications was 40 percent

throughwall.

In addition to the wear indications at the AVBs, 22 tubes were found that contained indications 

of wear in the preheater region at the tube support plates. The depths of these indications 

ranged from 6 percent to 49 percent throughwall. Although several tubes exceeded the 40

percent throughwall repair criteria, the licensee indicated that the increase in depth estimates 

from prior outages was mainly a result of using a new technique from the Electric Power 

Research Institute to size wear associated with quatrefoil tube support plate openings. Using 

the previous technique for sizing the wear indications resulted in growth rates comparable to 

those observed in prior cycles. Six tubes were stabilized and plugged because of wear at the 

preheater tube support plates.

Ten tubes had wear indications attributed to loose parts. The depths of these indications 

ranged from 7 percent to 33 percent throughwall. Three of the indications did not change from 

the previous inspection since the foreign object was removed in the prior outage. These tubes 

were returned to service (i.e., they were not plugged). However, seven tubes were stabilized 

and plugged because the loose parts could not be retrieved because of the lack of access to the 

affected location. Of the seven tubes plugged for wear from loose parts, six were in steam 

generator B, and 1 was in steam generator D. Four of the six tubes plugged in steam generator 

B had indications at the fifth tube support plate on the hot-leg side. The eddy current data 

indicated the presence of a loose part; however, this location was not accessible for visual 

inspection to confirm or remove the part. The depth of penetration for these four tubes was 33

percent, 13 percent, and 10 percent (two tubes). The eddy current data contained evidence of 

wear, but not of a loose part during RFO 5. The first indication of the loose part was observed 

during RFO 8. During RFO 9 the eddy current data indicated the part had moved and affected 

two other tubes. There were no indications of the loose part or additional wear in this region 

during RFO 11. In 2005, indications of wear were also found in two other tubes in steam 

generator B at the seventh tube support plate on the hot-leg side. These locations were not 

accessible for visual confirmation or removal of a loose part. The depth of penetration for these 

indications was 22 percent and 12 percent. There were no previous indications of objects or 

wear at these locations. These six tubes met the structural integrity performance criteria, and all 

were stabilized and plugged. The tube plugged in steam generator D for wear attributed to 

loose parts was also stabilized and plugged. The indication in this tube was at the sixth tube 

support plate on the cold-leg side.

Two tubes were preventatively plugged because the tubes had bulges with large voltage 

magnitudes (greater than 150 volts). One of these bulges was within the tubesheet, and one 

was slightly above the top of the tubesheet. The tube with the large voltage bulge above the top 

of the tubesheet was stabilized. Both of the bulges were present since the preservice

inspection.

One tube in steam generator D was preventatively plugged because it had not been 

hydraulically expanded into the tubesheet on the hot-leg side of the steam generator. This 

condition was present in previous inspections. The hydraulic expansion was verified to be 

present in all the other tubes in each of the four steam generators. 

To reduce the amount of sludge on the top of the tubesheet, sludge lancing was performed in 

each of the four steam generators. After the sludge lancing, FOSAR was performed on the top 

of the tubesheet to identify and remove foreign objects that may be found. The FOSAR 

inspection consisted of inspecting the tube lane, peripheral annulus, T-slot, and all tubes along 
3-30

the periphery of the tube bundle in each of the four steam generators. The objective of the 

peripheral tube inspection was to inspect as far into the tube bundle as the inspection 

technology would allow, typically three or four tubes into the bundle.

Additionally, FOSAR was performed on one of the preheater tube support plates (i.e., the 

second tube support plate) on the cold-leg side in steam generator A to identify and remove any 

foreign objects that may be found. The current preheater FOSAR strategy at Byron 2 is to 

inspect one preheater each refueling outage on a rotating basis. The visual inspection 

consisted of a row-by-row in-bundle inspection of all accessible tubes from the end of the T-slot 

(row 21) through the last tube row (row 49) and tube columns 52 through 63 from the end of the 

T-slot to the divider plate (row 1). These areas consist of the high flow regions that are 

considered to be most susceptible to foreign material tube damage. 

As a result of post sludge lance visual inspections in steam generator A at the top of the 

tubesheet, seven foreign objects were found. The objects were identified as: four pieces of 

slag metal, one piece of slag metal or hard scale, one piece of gasket material, and one metallic 

object. All objects were retrieved with the exception of the one piece of slag metal/hard scale. 

This object was firmly wedged between two peripheral tubes and could not be removed. 

Because the piece was not removed, conclusive characterization could not be achieved. The 

piece appears to be either hard scale in the form of a sludge rock or a piece of slag. Eddy 

current inspection did not detect the presence of a foreign object on the affected tubes, hence it 

is likely that the object is not metallic but is composed of a tenacious sludge rock-type material. 

The affected and surrounding tubes were not damaged as determined by eddy current and 

visual inspection. This object was first identified during RFO 11 and remained unchanged in 

RFO 12. Evaluations performed for the object in both RFO 11 and RFO 12 determined that it 

would take 7.5 years for the object to wear a tube to its structural limit, although, no wear 

degradation was found during RFO 11 or RFO 12 that was associated with this object. The 

affected tubes remain in service.

As a result of the visual inspections of the preheater tube support plate of steam generator A, 13 

foreign objects were identified. Nine of the objects were characterized as small wires, similar to 

brush wires. The remaining four objects were characterized as small pieces of gasket material. 

There was no tube damage associated with these objects as determined by eddy current and 

visual inspection. All of the objects were removed from the steam generator, with the exception 

of 1 small gasket piece and 2 small brush-like wires. An evaluation was performed that 

confirmed the acceptability of operation with these objects remaining in the steam generator for 

at least two fuel cycles between inspections, which bounds the current one-cycle inspection 

frequency at Byron 2.

In steam generator B, four loose parts were found and retrieved. One foreign object was found 

and retrieved in steam generators C and D. These parts included small wires, gasket material, 

and other small, unidentified metal objects. There was no tube damage associated with any of 

the confirmed loose parts.

All foreign material remaining in the steam generators were analyzed to validate that tube 

structural and leakage performance criteria would be met until the next steam generator tube 

inspections. This analysis was performed for all foreign material remaining in each of the four 

steam generators after the RFO 12 inspection, including new and historical foreign objects. 

Based on this analysis it was concluded that the tube structural and leakage integrity is 

projected to be maintained throughout the next operating cycle (i.e., until RFO 13).
3-31

A repair to the waterbox cap plate in steam generator A was performed by attaching a clamping 

device made from stainless steel plates above and below the original cap plate. The new plates 

were held in place with stainless steel studs inserted through the existing 12.7 mm (0.5 in.) flow 

holes. This repair required a new 6.35-cm (2.5-in.) diameter access penetration through the 

steam generator shell and wrapper. The newly installed plates are slightly larger than the 

original plate (trapezoid, 25.4 cm (10 in.) long, and 5 to 10.2 cm (2 to 4 in.) wide). The visual 

inspection detected no change in the appearance of the cut-out region or the backing bars. The 

piece of backing bar discovered missing in the spring 2004 RFO was not found in the 2005 

inspection (despite looking for the part in all high-flow areas), but the licensee analyzed the

condition and determined it would not affect tube integrity for at least another cycle of operation.

The steam drum and moisture separator region of steam generator B was inspected during 

RFO 12. These visual inspections included inspection of the secondary moisture separator 

banks, mid-deck plate, primary moisture separators, downcomer barrels and tangential nozzle 

assemblies, intermediate deck plate, auxiliary feedwater piping and supports, and primary 

separator slip-fit joint in the lower deck region. No degradation, erosion, deformation, or weld 

cracking was observed in the components other than the erosion (missing magnetite layer) of 

the moisture separator tangential nozzles, downcomer barrels, swirl vanes, spacer tabs, and 

orifice rings. This condition existed in varying degrees on 12 of the 16 primary separator 

assemblies. All components with the missing magnetite layer are fabricated from carbon steel. 

Several ultrasonic thickness measurements were taken in areas with the most apparent erosion

(in areas where the magnetite layer was missing). The nominal thickness of the various 

components is 6.35 mm (0.250 in.), and the minimum measured thickness of any of the 

ultrasonically inspected components was 4.65 mm (0.183 in.) (on one swirl vane blade). The 

licensee performed an analysis that determined that the erosion in the affected areas would not 

penetrate through wall over the next operating cycle; and therefore, would not affect steam 

generator performance or generate loose parts. 

In a few instances, some of the welds that join the primary separator assembly sub-parts 

contained very localized material loss of not more than an estimated 25 percent. Additionally on 

several primary separator barrels inside wall surfaces where magnetite was missing, a narrow 

localized depression (scallop) was observed to exist at the junction with the trailing edge of the 

swirl vane blades. The depression was too narrow to obtain an ultrasonic thickness 

measurement, but the worst-case location was estimated to have a 40-percent wall loss in a 

very localized area. There were no areas of through wall erosion observed in any of the 

components inspected.

On March 30, 2007, the steam generator portion of the Byron 2 technical specifications was 

revised to limit the extent of inspection in the hot-leg tubesheet region, to revise the steam 

generator portion of their technical specifications making them performance-based consistent 

with TSTF-449, and to delete Westinghouse laser-welded sleeving as an authorized repair 

method. Regarding the extent of inspections in the tubesheet region, the technical 

specifications were revised to exclude the portion of tube on the hot-leg side of the steam 

generator that is more than 43.2 cm (17 in.) below the top of the tubesheet from inspection (i.e., 

approximately the lowermost 10.2 cm (4 in.) of tube in the tubesheet on the hot-leg side was 

excluded from inspection, and hence any flaws that may exist in this region are permitted to 

remain in service). This revision was applicable only to RFO 13 and the subsequent operating 

cycle (ADAMS Accession Nos. ML070810354 and ML071210555).

There was no evidence of primary-to-secondary leakage during Cycle 13 (fall 2005 to spring 

2007).
3-32

During RFO 13 in 2007, 100 percent of the tubes in each of the four steam generators were 

inspected full length with a bobbin coil, excluding the U-bend region of the tubes in rows 1 and 

2. In addition to the bobbin coil inspections, a rotating probe equipped with a plus-point coil was 

used to inspect the following in each of the four steam generators:

• the U-bend region of 25 percent of the tubes in rows 1 and 2

• 30 percent of the tubes from 7.62 cm (3 in.) above to 43.2 cm (17 in.) below the top of 

the tubesheet on the hot-leg side

• 30 percent of bulges with bobbin voltage amplitudes greater than or equal to 18 volts 

and overexpansions greater than or equal to 0.038 mm (1.5 mils) within 43.2 cm (17 in.)

of the top of the tubesheet on the hot-leg side 

• all tubes (40) identified as having increase residual stress from 7.62 cm (3 in.) above to 

43.2 cm (17 in.) below the top of the tubesheet on the hot-leg side 

A rotating probe equipped with a plus-point coil also was used to inspect:

• 25 percent of hot-leg dents and dings with bobbin voltage amplitudes greater than 5 

volts in each of the four steam generators

• 50 percent of the hot-leg dents and dings with bobbin voltage amplitudes between 3 and 

5 volts in each of the four steam generators (including all such hot-leg dents in the 40 

tubes with potentially high residual stress)

• 25 percent of the preheater baffle plate expansions in steam generators B and C (i.e., 25

percent of the tube expansions at tube supports 2C and 3C)

Rotating probes equipped with a plus-point coil also were used to inspect expansion transitions 

and bulges that are significantly above the top of the tubesheet and areas of wear in the tubes 

with potentially high residual stress. In addition to these eddy current inspections, all tube plugs 

in each of the four steam generators were inspected visually. No degradation or abnormal 

leakage was identified during the inspection of the plugs. 

As a result of these inspections, 17 tubes were plugged—3 for indications of wear at the AVBs, 

3 for wear attributed to loose parts, 10 for possible loose parts, and 1 for a large voltage bulge 

near the top of the tubesheet.

The only steam generator tube degradation mechanisms observed during RFO 13 were wear at 

the AVBs, wear at the preheater tube supports, and wear attributed to loose parts.

A total of 838 indications of AVB wear in 487 tubes were detected during RFO 13: 181 

indications (in 102 tubes) in steam generator A, 310 indications (in 170 tubes) in steam 

generator B, 204 indications (in 129 tubes) in steam generator C, and 143 indications (in 86 

tubes) in steam generator D. The maximum depth reported for the AVB wear indications was 

42 percent throughwall.
3-33

In addition to the wear indications at the AVBs, 16 tubes were identified with wear indications at 

the tube support plates in the preheater region. The depth of these indications ranged from 5

percent to 39 percent throughwall. None of these tubes were plugged.

Six indications of wear attributed to loose parts were found in five tubes during RFO 13. These 

indications ranged from 12 percent to 31 percent throughwall. Three of the wear indications 

were in two of the tubes. The size of these indications did not change from the previous 

inspection because the loose parts were removed during RFO 11. These two tubes (three 

indications) were left in service. Two other wear indications (in two tubes) were stabilized and 

plugged because the loose parts could not be retrieved because of the lack of access to the 

affected location. Although the other wear indication (in one tube) was accessible, this tube was 

stabilized and plugged because access to the nearest inspection port would have required 

scaffolding to be built because the indication was at the eighth hot-leg support. Two 

neighboring tubes to this latter wear indication had indications of possible loose parts. As a 

result, these two tubes and eight additional tubes were stabilized and plugged. The eight extra

tubes were stabilized and plugged since the possible loose part is near two tubes that were 

plugged, but not stabilized, in prior outages (one in RFO 2 and one in RFO 7). These latter two 

tubes were not stabilized because the indications in these tubes were attributed, at the time, to 

pitting (a volumetric form of degradation).

In 23 locations, the expansion transition or a bulge is significantly outside the hot-leg and coldleg tubesheet. All locations were inspected with the plus-point probe and no degradation was 

found in any of the locations. One of the tubes with a bulge was preventatively stabilized and 

plugged since the bobbin voltage amplitude of the bulge was large (139.4 volts). This bulge 

indication was present during preservice and subsequent in-service inspections. This indication 

had not changed over time. The tube that contained the bulge was stabilized and plugged 

because of the increased sensitivity of bulges to stress corrosion cracking.

Inspection and maintenance on the secondary side of the steam generator also were performed 

during RFO 13. To reduce the amount of sludge on the top of the tubesheet, sludge lancing 

was performed in each of the four steam generators. After the sludge lancing, FOSAR was 

performed. The top of the tubesheet was visually inspected in the tubesheet annulus, 

peripheral tubes (3-5 tubes deep), tube lane, and T-slots. Also, the tube lane and tube lane 

peripheral tubes were inspected at the first baffle support plate in each of the four steam 

generators. Four foreign objects were identified at the tubesheet. The objects were 

characterized as two pieces of weld slag, a wire brush bristle and a small metallic object. One 

piece of weld slag and the metallic object were removed. The other piece of weld slag was an

object that has been in the steam generator for several cycles that was firmly wedged between 

two tubes. The condition of this object was unchanged from previous outages, and it was left in 

the steam generator. The wire brush bristle could not be retrieved because it was firmly 

contained within a hard scale pile adhered to the tubesheet. No tube damage was attributed to 

these loose parts as determined by eddy current and visual inspection. No loose parts were 

found on the first baffle support plate in any steam generator. 

The preheater region of the tube bundle is an area where loose parts can accumulate 

particularly at tube support 2C because this is where the feedwater enters the steam generator. 

In addition, the 144 tubes that were expanded into tube supports 2C and 3C (because of 

concerns about tube vibration) in this region could be more susceptible to cracking. These tube 

expansions could also interfere with the detection of possible loose parts during the eddy 

current examinations. As a result, Byron 2 has a program to inspect cold-leg tube support 2C 

for loose parts using visual and eddy current techniques. The current preheater FOSAR 
3-34

strategy at Byron 2 is to inspect visually one preheater each refueling outage on a rotating 

basis. The visual inspection of cold-leg tube support 2C consists of a visual inspection of the 

tube annulus from Row 49 to the flow block and each tube row from the end of the T-slot (row 

21) through the last tube row (row 49). The purpose of the flow block is to block the flow along 

the tube annulus and to distribute the flow into the tube bundle. This configuration can trap 

loose parts between the wrapper, flow block, and the tubes above the cold-leg tube support 2C. 

For steam generators that are not visually inspected at tube support 2C, a plus-point probe 

inspection of the tubes that are hydraulically expanded from the flow block to row 49 is 

performed (in addition to the bobbin coil inspection) to see if possible loose parts or tube 

damage is present. These areas consist of the high flow regions that are considered to be most 

susceptible to foreign material tube damage. In addition to these inspections, rotating probe 

inspections of the preheater baffle plate expansions are performed in one steam generator on at 

least 20 percent of the 2C and 3C baffle plate expansion transitions to inspect for cracking. 

During RFO 13, 25 percent of the preheater baffle plate expansions in steam generators B and 

C were inspected with a plus-point coil to detect cracking. Furthermore, several baffle plate 

expansions at tube support 2C near the flow block were inspected with a plus-point coil in steam 

generators A, B, and C to detect possible loose parts and wear. No degradation or possible 

loose parts were detected in these inspections.

FOSAR was performed at tube support 2C in steam generator D during RFO 13. Each tube 

was inspected visually from row 21 (end of the T-slot) through row 49 (the row closest to the 

feedwater inlet). Tube columns 52 through 63 were inspected from the end of the T-slot to the 

divider plate (row 1), and the tube wrapper annulus was inspected from row 49 to the flow block. 

These inspections resulted in identifying eight loose parts. These objects were characterized as 

small bristle brush wires (five), a small spring measuring 2.59 mm (0.102 in.) long by 2.29 mm 

(0.09 in.) in diameter, weld slag, and a small machine turning. Five of the objects were 

removed. Three of the wires could not be retrieved because they were firmly wedged between 

the baffle plate crevice and the tube. One of the stuck wires was an object that was present in 

prior outages and had not changed since the previous inspection. None of the objects caused 

any tube damage as determined by eddy current and visual inspections.

The licensee performed an engineering evaluation for all loose parts that remained in the steam 

generators. The evaluation considered the object characteristics, flow conditions, tube vibration 

amplitudes and the assumption of any pre-existing tube flaws. The evaluation concluded that 

the objects remaining in the steam generators would not cause significant tube wear over the 

next operating cycle.

Follow-up visual inspections and ultrasonic thickness measurements were taken in eroded 

areas of the secondary-side moisture separator region of steam generator B, and inspections 

and measurement of the secondary-side moisture separator region in steam generators A, C, 

and D were performed for the first time. Continued erosion of the components (moisture 

separator tangential nozzles, downcomer barrels, and swirl vanes) in steam generator B was 

identified, although none of the areas was throughwall. Similar extent of erosion was found in 

the other three steam generators. Through an analysis, the licensee determined that significant 

margin remained in the eroded areas before the erosion would penetrate throughwall and affect

steam generator performance or possibly generating loose parts. The erosion in the affected 

areas was not projected to penetrate throughwall or produce loose parts over the next two 

operating cycles when the next inspection is planned. 
3-35

On October 1, 2008, the steam generator portion of the Byron 2 technical specifications was 

revised to permit certain sized flaws near the tube end in both the hot- and cold-leg sides of the 

steam generator to remain in service. Specifically, the technical specifications were revised to 

(1) permit flaws having a circumferential component less than or equal to 203 degrees found in 

the portion of the tube below 43.2 cm (17 in.) from the top of the tubesheet and above 2.54 cm 

(1 in.) from the bottom of the tubesheet to remain in service, (2) require the removal from 

service all flaws having a circumferential component greater than 203 degrees found in the 

portion of the tube below 43.2 cm (17 in.) from the top of the tubesheet and above 2.54 cm 

(1 in.) from the bottom of the tubesheet, (3) require the removal from service all tubes with 

service-induced flaws between the top of the tubesheet and 43.2 cm (17 in.) below the top of 

the tubesheet, and (4) permit all axial indications found in the portion of the tube below 43.2 cm 

(17 in.) from the top of the tubesheet to remain in service. In addition, the technical 

specifications were modified to indicate that when more than one flaw with circumferential 

components are found in the portion of the tube below 43.2 cm (17 in.) from the top of the 

tubesheet and above 2.54 cm (1 in.) from the bottom of the tubesheet with the total of the 

circumferential components being greater than 203 degrees and the axial separation distance of 

less than 2.54 cm (1 in.), then the tube must be removed from service (overlapping portions of 

the flaws only need to be counted once in determining the total circumferential involvement of 

the flaws). For flaws within 2.54 cm (1 in.) of the bottom of the tubesheet, the technical 

specifications were modified to indicate (1) when one or more flaws with circumferential 

components are found and the total of the circumferential components exceeds 94 degrees, 

then the tube shall be removed from service and (2) when one or more flaws with 

circumferential components are found in the portion of the tube within 2.54 cm (1 in.) from the 

bottom of the tubesheet and within 2.54 cm (1 in.) axial separation distance of a flaw above 

2.54 cm (1 in.) from the bottom of the tubesheet, and the total of the circumferential components 

found in the tube exceeds 94 degrees then the tube shall be removed from service (overlapping 

portions of the flaws only need to be counted once in determining the total circumferential 

involvement of the flaws). This revision to the technical specifications was applicable only to 

RFO 14 and the subsequent operating cycle (ADAMS Accession No. ML082340799).

There was no evidence of primary-to-secondary leakage during Cycle 14 (spring 2007 to fall 

2008).

During RFO 14 in 2008, 100 percent of the tubes in each of the four steam generators were 

inspected full length with a bobbin coil, excluding the U-bend region of the tubes in rows 1 and 

2. In addition to the bobbin coil inspections, a rotating probe equipped with a plus-point coil was 

used to inspect the following in each of the four steam generators:

• the U-bend region of 25 percent of the tubes in rows 1 and 2

• 20 percent of the tubes from 7.62 cm (3 in.) above the top of the tubesheet to the tube 

end on the hot-leg side (which included 20 percent of bulges with bobbin voltage 

amplitudes greater than or equal to 18 volts and overexpansions greater than or equal to 

0.038 mm (1.5 mils) within the tubesheet on the hot-leg side)

• 100 percent of the tubes from the tube end to 5.1 cm (2 in.) above the tube-end on the 

hot-leg side, 20 percent of the tubes from the tube-end to 5.1 cm (2 in.) above the tubeend on the cold-leg side

• all tubes (40) identified as having increased residual stress from 7.62 cm (3 in.) above 

the top of the tubesheet to the tube end on the hot-leg side
3-36

A rotating probe equipped with a plus-point coil was also used to inspect:

• 25 percent of hot-leg dents and dings greater than 3 volts in each of the four steam 

generators

• 100 percent of the hot-leg dents and dings greater than 2 volts (total of 4 indications) in 

the 40 tubes with potentially high residual stress

• 20 percent of the preheater baffle plate expansions in all four steam generators (i.e., 20

percent of the tube expansions at tube supports 2C and 3C)

• 100 percent of the preheater expansions near the “corner” of the preheater (i.e., the 

outer peripheral tubes near the flow blocking region on tube support 2C) in the three 

steam generators in which a visual inspection of the preheater region was not performed 

(i.e., steam generators A, C, and D)

Rotating probes equipped with a plus-point coil also were used to inspect 21 expansion 

transitions and bulges that are significantly above the top of the tubesheet on both the hot-leg 

and cold-leg side of the steam generator in each steam generator, and areas of wear in the 

tubes with potentially high residual stress (a total of 18 indications). In addition to these eddy 

current inspections, all tube plugs in each of the four steam generators were inspected visually. 

No degradation or abnormal leakage was identified during the inspection of the plugs. 

As a result of these inspections, 13 tubes were plugged—1 for an indication of wear at the 

AVBs, 3 for wear at tube supports in the preheater, 3 for wear attributed to loose parts, 5 for

possible loose parts, and 1 preventatively because the tubesheet bore hole was larger than that 

assumed in the development of the alternate repair criteria for indications in the tubesheet 

region.

The only steam generator tube degradation mechanisms observed during RFO 14 were 

(1) wear at the AVBs, (2) wear at the preheater tube supports, (3) wear attributed to loose parts, 

and (4) axially oriented primary water stress corrosion cracking at the tube end.

A total of 891 indications of AVB wear in 662 tubes were detected during RFO 14: 192 

indications (in 146 tubes) in steam generator A, 314 indications (in 220 tubes) in steam 

generator B, 233 indications (in 178 tubes) in steam generator C, and 152 indications (in 118 

tubes) in steam generator D. The maximum depth reported for the AVB wear indications was 

40 percent throughwall.

In addition to the wear indications at the AVBs, 19 tubes were identified with wear indications at 

the tube support plates in the preheater region. The depth of these indications ranged from 5

percent to 45 percent throughwall. Three tubes were plugged because of wear in the preheater 

region.

Six indications of wear attributed to loose parts were found in five tubes during RFO 14. These 

indications ranged from 15 percent to 38 percent throughwall. Three of the wear indications 

were in two of the tubes. The size of these indications did not change from the previous 

inspection because the loose parts were removed during RFO 11. These two tubes (three 

indications) were left in service. Three other wear indications (in three tubes) were stabilized 

and plugged because the loose parts could not be retrieved because of the lack of access to the 

affected location. Two neighboring tubes to one of the tubes with a wear indication were 
3-37

stabilized and plugged to bound the area affected by the loose part because the loose part 

appeared to have moved since RFO 13. One of these three wear indications had a loose part 

lodged in the bottom edge of one of the quatrefoil flow holes, and another of the wear 

indications was attributed to a similarly located loose part although no evidence existed of a 

possible loose part from the eddy current inspection. This latter tube was plugged because it 

was assumed the loose part was still at this location although it was not detectable by eddy 

current inspection.

Three other tubes were stabilized and plugged because of a loose part. These tubes did not 

exhibit any wear, but eddy current and visual inspection showed that the loose part had moved 

slightly since RFO 13. These tubes were plugged to ensure the loose part does not adversely 

affect them.

Inspections in the tubesheet resulted in the identification of 65 axial indications in 64 tubes. All 

axial indications were on the hot-leg side of the steam generator and were within the bottom 

12.7 mm (0.5 in.) of the tube and originated from the inside surface of the tube. There were no 

cracking indications found in the cold-leg region of the tubesheet and no circumferential 

indications were identified.

No crack-like indications were found in the 40 tubes with potentially higher residual stress.

Inspection and maintenance on the secondary side of the steam generator also were performed 

during RFO 14. To reduce the amount of sludge on the top of the tubesheet, sludge lancing 

was performed in each of the four steam generators. After the sludge lancing, FOSAR was 

performed at the top of the tubesheet and on top of the flow distribution baffle. In steam 

generator B, FOSAR also was conducted on the preheater baffle plate and visual inspections 

were performed of the waterbox region including the target plate, distribution ribs, and cap plate. 

In steam generator C, in-bundle visual inspections were performed on tube supports 8 and 11.

Eleven foreign objects were found on the top of the tubesheet (2 in steam generator A, 1 in B 

and 8 in C). Visual inspections of the waterbox region in steam generator B revealed no erosion 

on the target plate and distribution ribs; however, a trace amount of erosion was noted on the 

cap plate flow holes. In steam generator C, deposit loading was assessed at the 11th tube 

support plate. There was a light to moderate loading of deposits, which was consistent with 

prior outages.

During RFO 14, no visual inspections of the primary moisture separator components were 

performed.

On October 16, 2009, the steam generator portion of the Byron 2 technical specifications was 

revised to limit the extent of inspection in the tubesheet region. Specifically, the technical 

specifications were revised to exclude the portion of tube that is more than 43 cm (16.95 in.)

below the top of the tubesheet from inspection (i.e., approximately the lowermost 10.2 cm (4 in.)

of tube in the tubesheet was excluded from inspection, and hence any flaws that may exist in 

this region are permitted to remain in service). This revision was only applicable for RFO 15 

and the subsequent operating cycle (ADAMS Accession No. ML092520512).

There was no evidence of primary-to-secondary leakage during Cycle 15 (fall 2008 to spring 

2010).
3-38

During RFO 15 in 2010, 100 percent of the tubes in each of the four steam generators were 

inspected full length with a bobbin coil, excluding the U-bend region of the tubes in rows 1 and 

2. In addition to the bobbin coil inspections, a rotating probe equipped with a plus-point coil was 

used to inspect the following in each of the four steam generators:

• the U-bend region of 25 percent of the tubes in rows 1 and 2

• 25 percent of the tubes from 7.62 cm (3 in.) above the top of the tubesheet to 45.7 cm 

(18 in.) below the top of the tubesheet on the hot-leg side (which included 25 percent of 

bulges within the top 43 cm (16.95 in.) of the tubesheet on the hot-leg side with bobbin 

voltage amplitudes greater than or equal to 18 volts and overexpansions greater than or 

equal to 0.038 mm (1.5 mils))

• all tubes (40) identified as having increased residual stress from 7.62 cm (3 in.) above 

the top of the tubesheet to 45.7 cm (18 in.) below the top of the tubesheet on the hot-leg 

side

A rotating probe equipped with a plus-point coil was also used to inspect:

• 25 percent of hot-leg dents and dings with bobbin voltage amplitudes greater than 3 

volts in each of the four steam generators

• 100 percent of the hot-leg dents and dings with bobbin voltage amplitudes greater than 3 

volts (four tubes) in the 40 tubes with potentially high residual stress

• all wear indications in the 40 tubes with potentially high residual stress

• 25 percent of the preheater baffle plate expansions in all four steam generators (i.e., 25

percent of the tube expansions at tube supports 2C and 3C)

• 100 percent of the preheater expansions near the “corner” of the preheater (i.e., the 

outer peripheral tubes near the flow blocking region on tube support 2C) in the three 

steam generators in which a visual inspection of the preheater region was not scheduled 

to be performed (i.e., steam generators A, B, and D)

In addition to these eddy current inspections, all tube plugs in each of the four steam generators

were inspected visually. No anomalies were identified during the inspection of the plugs.

As a result of these inspections, one tube was plugged for wear attributed to a loose part.

The only steam generator tube degradation mechanisms observed during RFO 15 were wear at 

the AVBs, wear at the preheater tube supports, and wear attributed to loose parts.

A total of 925 indications of AVB wear were detected in 531 tubes during RFO 15: 192 

indications (in 109 tubes) in steam generator A, 324 indications (in 177 tubes) in steam 

generator B, 243 indications (in 144 tubes) in steam generator C, and 166 indications (in 101 

tubes) in steam generator D. The maximum depth reported for the AVB wear indications was 

39 percent throughwall.
3-39

In addition to the wear indications at the AVBs, 15 indications of wear at the tube support plates 

in the preheater region were identified in 15 tubes. The depth of these indications ranged from 

5 percent to 39 percent throughwall.

Five indications of wear attributed to loose parts were found in four tubes during RFO 15. 

These indications ranged from 17 percent to 31 percent throughwall. Three of the wear 

indications did not change in size from the previous inspection because the loose parts were 

removed during RFO 11. One of the tubes with a loose part wear indication was stabilized and 

plugged since the location could not be inspected visually. This loose part appears to have 

moved since RFO 14. One tube had a wear indication and there was no loose part present 

based on visual inspections; however, the neighboring tubes had previously been plugged for 

wear attributed to a loose part that had been removed from the steam generator.

During RFO 15, inspection/maintenance was performed on the secondary side of the steam 

generators. FOSAR was performed in the high-flow region of the preheater baffle plate 2C in all 

four steam generators. Feedwater enters the steam generator in the preheater waterbox 

between tube support plates 2C and 3C. The feed flow impinges on a target plate that 

disperses the feedwater to tube support plate 2C where the flow begins to travel through the 

baffle plate region. The area of highest flow is on tube support 2C underneath the feedwater 

nozzle.

During visual inspections of the preheater in steam generator C, four gasket material pieces 

were found. In addition, Flexitallic gasket material from the startup feedwater strainer was found 

in a downstream pipe. At the time of discovery, it was believed that some of the gasket material 

was missing. As a result, visual inspections of the preheater region in steam generators A, B, 

and D were performed. Two small pieces of gasket material were found in the steam generator 

A preheater, but no gasket material was found in steam generators B and D.

Visual inspections were performed on the primary moisture separator components in all four 

steam generators because of the erosion detected during RFO 13. Continued erosion was

identified in steam generator B; however, there were no indications of throughwall erosion. A 

similar extent of erosion was identified in the other three steam generators. A licensee analysis 

showed that the erosion in the affected areas was not projected to penetrate through wall or 

produce loose parts over the next two operating cycles. All of the moisture separator 

inspections that were planned were not conducted during RFO 15 because of expanding the 

scope of the preheater visual inspections to include all the steam generators (instead of one 

steam generator). As a result, additional inspections of the steam generator A and B moisture 

separators were scheduled for RFO 16.

On April 13, 2011, the steam generator portion of the Byron 2 technical specifications was 

revised to limit the extent of inspection in the tubesheet region. Specifically, the technical 

specifications were revised to exclude the portion of tube that is more than 43 cm (16.95 in.)

below the top of the tubesheet from inspection (i.e., approximately the lowermost 10.2 cm (4 in.)

of tube in the tubesheet was excluded from inspection, and hence any flaws that may exist in 

this region are permitted to remain in service). This revision was only applicable for RFO 16 

and the subsequent operating cycle (ADAMS Accession No. ML110840580).

There was no evidence of primary-to-secondary leakage during Cycle 16 (spring 2010 to fall 

2011).
3-40

During RFO 16 in 2011, 100 percent of the tubes in each of the four steam generators were 

inspected full length with a bobbin coil, excluding the U-bend region of the tubes in rows 1 and 

2. In addition to the bobbin coil inspections, a rotating probe equipped with a plus-point coil was 

used to inspect the following in each of the four steam generators:

• the U-bend region of 25 percent of the tubes in rows 1 and 2

• 25 percent of the tubes from 7.62 cm (3 in.) above the top of the tubesheet to 45.7 cm 

(18 in.) below the top of the tubesheet on the hot-leg side (which included 25 percent of 

bulges within the top 43 cm (16.95 in.) of the tubesheet on the hot-leg side with bobbin 

voltage amplitudes greater than or equal to 18 volts and overexpansions greater than or 

equal to 0.038 mm (1.5 mils))

• all 40 tubes identified as having increased residual stress from 7.62 cm (3 in.) above the 

top of the tubesheet to 45.7 cm (18 in.) below the top of the tubesheet on the hot-leg 

side

A rotating probe equipped with a plus-point coil was also used to inspect:

• 25 percent of hot-leg dents and dings with bobbin voltage amplitudes greater than 

3 volts in each of the four steam generators

• 100 percent of the hot-leg dents and dings with bobbin voltage amplitudes greater than 3 

volts (23 dents and dings) in the 40 tubes with potentially high residual stress

• all wear indications in the 40 tubes with potentially high residual stress (5 indications)

• 25 percent of the preheater baffle plate expansions in all four steam generators (i.e., 25

percent of the tube expansions at tube supports 2C and 3C)

• 100 percent of the preheater expansions near the “corner” of the preheater (i.e., the 

outer peripheral tubes near the flow blocking region on tube support 2C) in the three 

steam generators in which a visual inspection of the preheater region was not scheduled 

to be performed (i.e., steam generators A, B, and D)

In addition to these eddy current inspections, all tube plugs in each of the four steam generators

were inspected visually. No anomalies were identified during the inspection of the plugs.

As a result of these inspections, 28 tubes were plugged—1 for AVB wear, 7 for preheater tube 

support wear, 4 for wear attributed to loose parts, 14 to surround possible loose parts that could 

not be retrieved, 1 to surround a known loose part that could not be retrieved, and 1 for a 

manufacturing geometric indication.

The only steam generator tube degradation mechanisms observed during RFO 16 were wear at 

the AVBs, wear at the preheater tube supports, and wear attributed to loose parts.

A total of 1,023 indications of AVB wear were detected in 751 tubes during RFO 16. This 

included 233 indications (in 173 tubes) in steam generator A, 348 indications (in 243 tubes) in 

steam generator B, 271 indications (in 203 tubes) in steam generator C, and 171 indications (in 

132 tubes) in steam generator D. The maximum depth reported for the AVB wear indications 

was 40 percent throughwall.
3-41

In addition to the wear indications at the AVBs, 16 indications of wear at the tube support plates 

in the preheater region were identified in 16 tubes. The depth of these indications ranged from 

5 percent to 40 percent throughwall.

Nine indications of wear attributed to loose parts were found in eight tubes during RFO 16. 

These indications ranged from 17 percent to 38 percent throughwall. Four of the wear 

indications (in three tubes) did not change in size from the previous inspection because the 

loose parts were removed during a prior outage. These tubes remain in service. Four of the 

tubes with a wear indication were stabilized and plugged since the location could not be 

inspected visually. One tube was allowed to remain in service since a visual inspection did not 

identify any loose parts in the vicinity of the wear indication.

During RFO 16, 54 new dents were identified in steam generator B. All of the dents have small 

bobbin voltage amplitudes (2 to 5 volts) and are at the bottom edge of the tube support 3C. 

When viewed from above the 54 new dents have a symmetrical pattern across tube support 3C 

that is somewhat crescent shaped. A similar pattern of denting occurred between the RFO 9 

(2001) and RFO 10 (2002) inspections when about 100 dents were found at the same baffle 

plate. These dents were also at tube support 3C, in a crescent shape, and had bobbin voltage 

amplitudes ranging from 2 to 15 volts. Only nine of these historical dents changed in size 

between 2010 and 2011 (i.e., greater than what would be attributed to eddy current 

measurement uncertainty).

A rotating probe was used to inspect 25 percent of these new and historical dents at tube 

support 3C. The 80 millimeter coil on this probe was modified to be a non-surface riding coil to 

determine the length and width of the dents. When measuring the size of the dents, an attempt 

was made to determining the shape and orientation of the dent by inserting a bobbin coil and a 

strong rare earth magnet in the adjacent guide tube. This effort was unsuccessful.

The circumferential extent of most of the dents was 80 degrees, and most tubes were dented on 

just one side. A few tubes had two dents, with the dents separated circumferentially by 

approximately 160 degrees. The tubes with two dents had larger bobbin voltage amplitudes. 

There was no evidence of deposits, anomalies (burrs or high spots on the tube support holes), 

or damage to tube support 3C.

A review revealed no similar operating experience at other units. An operating review at Byron 

2 for water hammer and other flow or pressure transients revealed no events that could be 

correlated to the denting. There were no loose-part alarms during the cycle, and there was no 

evidence of reduced tube-to-tube spacing.

During RFO 16, inspection/maintenance was performed on the secondary side of the steam 

generators. FOSAR was performed at the top of the tubesheet in all four steam generators. A 

visual inspection of the upper tube bundle was performed in steam generator B and the steam 

drum region of steam generators A and B were visually inspected.

The upper bundle of steam generator B was inspected visually to assess the general condition 

at tube supports 8 and 11. The inspections indicated a thin layer of soft sludge is forming on the 

support plate. The quatrefoil openings had a thin layer of deposits at the lands, lobes, and 

edges, but they were still open. No loose parts or anomalous conditions were observed.
3-42

Visual inspections of the secondary-side moisture separator region was performed in steam 

generators A and B because of detecting erosion of the moisture separator tangential nozzles, 

downcomer barrels, and swirl vanes during RFO 13. Ultrasonic thickness measurements were 

taken of the eroded areas with an emphasis on re-inspecting the areas identified as eroded 

during RFO 13. These inspections indicated there was no significant increase in degradation 

since RFO 13. A licensee analysis showed that it was acceptable to operate two fuel cycles 

until the next inspection. The erosion in the affected areas is not projected to penetrate 

throughwall, create loose parts, or affect steam generator performance before the next 

inspection. The analysis also indicated that if a change in the currently understood 

erosion/corrosion profile does not occur, that inspection after three fuel cycles may be possible.

On October 5, 2012, the steam generator portion of the Byron 2 technical specifications was 

revised to limit the extent of inspection in the tubesheet region and to remove Combustion 

Engineering tungsten inert gas welded sleeving as an authorized repair method. Specifically, 

the technical specifications were revised to exclude the portion of tube that is more than 

35.59 cm (14.01 in.) below the top of the tubesheet from inspection (i.e., approximately the 

lowermost 17.8 cm (7 in.) of tube in the tubesheet was excluded from inspection, and hence any 

flaws that may exist in this region are permitted to remain in service (ADAMS Accession No. 

ML12262A360)). With approval of this amendment, there were no authorized repair methods 

(other than tube plugging) at Byron 2.

On March 21, 2013, the steam generator portion of the Byron 2 technical specifications was 

revised to make them consistent with TSTF-510 (ADAMS Accession No. ML13009A172).

During RFO 17 in 2013, no steam generator tubes were inspected.

3.2.3 Catawba 2

Tables 3-7, 3-8, and 3-9 summarize the information discussed below for Catawba 2. Table 3-7 

provides the number of full-length bobbin inspections and the number of tubes plugged and 

deplugged during each outage for each of the four steam generators. Table 3-8 lists the 

reasons why the tubes were plugged. Table 3-9 lists of tubes plugged for reasons other than 

wear at the AVBs.

Catawba 2 has four Westinghouse model D5 steam generators. The licensee numbers its tube 

supports using the alternate naming convention in Figure 2-1. There are 141 tubes expanded at 

two tube support plate locations to prevent vibration in the preheater section of these steam 

generators. These tubes are in the cold leg of the steam generators. The lowermost tube 

support (i.e., 1H) is a flow distribution baffle. It is 1.9 cm (0.75 in.) thick.

Based on accident analysis considerations, a maximum of 10 percent of the tubes can be 

plugged in the steam generators.

During RFO 12 in 2003, approximately 55 percent of the tubes in each of the four steam 

generators were inspected full length with a bobbin coil. In addition to the bobbin coil 

inspections, a rotating probe equipped with a plus-point coil was used to inspect approximately 

25 percent of the tubes at the top of the tubesheet and the U-bend region of approximately 25

percent of the row 1 and row 2 tubes. The above inspections were performed in each of the 

four steam generators. In addition, all tube plugs were visually inspected in each of the four 
3-43

steam generators, and an eddy current inspection was performed on approximately 20 percent

of the tube plugs in each of the four steam generators (13 plugs in steam generator A, 8 in B, 9 

in C, and 10 in D).

As a result of these inspections, 33 tubes were plugged—1 for wear at the AVBs, 6 for possible 

loose parts (including 2 tubes that had exhibited wear indications), 6 for wear in the preheater

region (tube support plate 13), 2 for permeability variations, 1 for an eddy current signal offset, 2 

preventatively for anomalous indications in the U-bend region, and 15 for overlapping dent and 

volumetric indications that could potentially mask a crack indication in the eddy current data.

No crack-like degradation was found at any location during this inspection. 

The anomalous indications in the U-bend region that caused two tubes (row 1, column 100, and 

row 1, column 106) in steam generator A to be plugged preventatively are believed to be a 

result of probe liftoff associated with the tangent point of the tube (i.e., the point where the tube 

starts to bend in the U-bend region). There was no change in these signals since RFO 9 

(1998).

As discussed above, one tube was preventatively plugged in steam generator C because of an 

offset in the eddy current signal. This offset was similar to what was observed at Seabrook. 

Seabrook identified a group of low-row tubes with offsets in the eddy current signals that had 

cracks in the tubes at the tube support plate elevations. The offset was attributed to the tubes 

being straightened and not thermally treated. These tubes are generally considered to be more 

susceptible to cracking. Only one low-row tube at Catawba 2 was identified with this eddy 

current offset (this tube was plugged, as discussed above).

During RFO 13 in 2004, about 56 percent of the tubes in each of the four steam generators 

were inspected full length with a bobbin coil. In addition to the bobbin coil inspections, a rotating 

probe was used to inspect the following in each of the four steam generators:

• the U-bend region of about 25 percent of the tubes in rows 1 and row 2 

• about 25 percent of the dents and dings

• from 5.1 cm (2 in.) above to 22.9 cm (9 in.) below the top of the tubesheet on the hot-leg 

side in about 26 percent of the tubes

In addition, a rotating probe was used to inspect all tubes with overexpansions in the hot-leg 

tubesheet region (about 1,300 tubes) from 5.1 cm (2 in.) above the hot-leg tubesheet to the 

hot-leg tube end in all four steam generators and 100 percent of the hot-leg tube ends in steam 

generator B, and 20 percent of the hot-leg tube ends in steam generators A, C, and D. These 

latter exams were from the hot-leg tube end to 5.1 cm (2 in.) above the hot-leg tube end. In 

addition, visual inspections were performed on all the tube plugs, and an eddy current 

inspection was performed on about 15 percent of tube plugs in each of the four steam 

generators (11 plugs in steam generator A, 7 in B, 7 in C, and 7 in D). No degradation or 

abnormal leakage was identified during the inspection of the plugs.

As a result of these inspections, 48 tubes were plugged—18 for loose parts, 12 for possible 

loose parts, 9 for crack-like indications in the tack roll region, 6 for indications near the 

tube-to-tubesheet weld that extended slightly into the tube material, 1 for a circumferential 
3-44

crack-like indication in an overexpanded region within the tubesheet, 1 for a permeability 

variation, and 1 for potential damage from a stabilizer installation error.

During rotating probe examinations at the top of the tubesheet region in steam generator B in 

RFO 13, several discrete circumferential indications were found in an overexpanded region of 

one tube. The location of the indications was about 17.8 cm (7 in.) below the top of the hot-leg 

tubesheet. The indications initiated from the inside diameter of the tubes, and are about 30 

degrees in circumferential extent. The overexpanded region extended for about 15 cm (6 in.)

and the diameter of the tube was estimated to be approximately 0.76 mm (0.003 in.) greater 

than that observed in the remainder of the expanded region in the tubesheet. Overexpansions 

in the tubesheet region are a result of expanding the tube into a region of the tubesheet that is 

not perfectly round. This out-of-round condition is a result of anomalies in the tubesheet drilling 

process (e.g., drill-bit wandering). Because of identifying these indications in the 

overexpansion, the scope of the rotating probe examinations in the tubesheet region were 

expanded to include all tubes with overexpanded regions in the hot-leg. These tubes were 

inspected from 5.1 cm (2 in.) above the top of the tubesheet to the tube end. There are about

1,300 tubes in the hot-leg tubesheet that have overexpanded regions. No other indications 

were found in the overexpanded regions.

Although no other indications were found in the overexpanded regions, several indications were 

found near the tube ends leading to an expansion of the original sample to include 100 percent

of the tube ends in steam generator B and 20 percent of the tube ends in steam generators A, 

C, and D (as discussed above). The tube end is a region that includes the tack expansion and 

the tube-to-tubesheet weld. The tack expansion region is where the tube was initially expanded 

into the tubesheet during steam generator fabrication to facilitate welding of the tube to the 

primary face of the tubesheet. In the case of Catawba 2, this region is frequently referred to as 

the tack roll region because the tack expansion was accomplished by mechanically rolling the 

tube into the tubesheet. The tack expansion forms a temporary expansion transition that is 

“removed” after welding when the tube is hydraulically expanded for the full depth of the 

tubesheet. The transition from the expanded portion of the tube within the tubesheet to the 

unexpanded portion of the tube at the top of the tubesheet is referred to as the expansion 

transition region of the tube.

At the time of the RFO 13 inspection, the licensee classified the indications into those that were 

in the weld and those that were in the tack expansion region. Because of this classification, 

there was 1 tube in steam generator A with indications in the tube-to-tubesheet weld, 9 tubes in 

steam generator B with indications in the tack roll region and 188 tubes with indications in the 

tube-to-tubesheet weld, and 7 tubes in steam generator D with indications in the 

tube-to-tubesheet weld. No indications were found in the tack roll region in steam generators A, 

C, and D. No indications were found in the tube-to-tubesheet weld region in steam generator C. 

Analyses performed subsequent to RFO 13 indicated that the indications classified as being in 

the tube-to-tubesheet weld were most likely in the tube (although it could not be ruled out that 

the indications extended into the weld).

In summary, 16 tubes were removed from service because of indications in the tubesheet 

region during RFO 13. These indications were treated as crack-like indications. These 

indications were axially and circumferentially oriented, consisted of either single or multiple 

cracks, and initiated from the inside diameter of the tube. All of the tubes with indications in the 

tack expansion region (nine tubes) and in overexpansions (one tube) were plugged. In addition, 

six tubes with indications near the tube-to-tubesheet weld were plugged since they appeared to 

extend slightly into the tube material. Indications classified as being in the tube-to-tubesheet 
3-45

weld were allowed to remain in service since the inspection of the tube-to-tubesheet weld and 

the repair of any indications detected in the weld are not governed by the surveillance 

requirements in the technical specifications.

During RFO 13, the preheater waterboxes in each of the four steam generators were inspected 

with special emphasis on the waterbox cap plate. The focus of the waterbox inspection was to 

evaluate modifications made to the cap plate during manufacturing since operating experience 

at another plant (Byron 2) indicated potential degradation of welds associated with regions of 

the cap plate that may have been cutout and welded back in place during manufacturing. 

During the RFO 13 inspections, cutout regions were identified in the cap plates in steam 

generators B, C, and D; however, there is no cutout region in steam generator A. These 

inspections found the welds to be structurally sound. Other than a cap plate backing bar being 

found loose, no anomalies were reported during these inspections. The backing bar was 

retrieved.

On January 13, 2005, Catawba 2 revised the steam generator portion of their technical 

specifications making them performance-based consistent with TSTF-449 (ADAMS Accession 

No. ML050110258).

On March 31, 2006, the steam generator portion of the Catawba 2 technical specifications was 

revised to limit the extent of inspection in the hot-leg and cold-leg tubesheet regions. 

Specifically, the technical specifications were revised to exclude the portion of tube that is more 

than 43.2 cm (17 in.) below the top of the tubesheet from inspection (i.e., approximately the 

lowermost 10.2 cm (4 in.) of tube in the tubesheet on the hot- and cold-leg side was excluded 

from inspection, and hence any flaws that may exist in this region are permitted to remain in 

service). This revision was applicable only to RFO 14 and the subsequent operating cycle 

(ADAMS Accession No. ML060760011 and ML060760111).

There was no evidence of primary-to-secondary leakage during Cycle 14 (fall 2004 to spring

2006).

During RFO 14 in 2006, about 55 percent of the tubes in each of the four steam generators 

were inspected full length with a bobbin coil. These inspections included tubes with previous 

indications, tubes on the periphery of the tube bundle two rows deep, tubes surrounding 

plugged tubes, and a minimum sample of 20 percent of the remaining tubes including all tubes 

not inspected with a bobbin coil since RFO 10. During the outage, more tubes were added to 

the inspection plan to bound possible loose parts identified by eddy current and visual 

inspections. In addition to the bobbin coil inspections, an array probe was used to inspect the 

following in each of the four steam generators:

• about 27 percent of the tubes from 5.1 cm (2 in.) above the top of the tubesheet on the 

hot-leg side to the hot-leg tube end, which included: 

– a 20 percent random sample

– all periphery tubes (although only the bobbin data were analyzed unless a 

condition was identified in the bobbin data that warranted a review of the array 

probe data)

– all previous overexpansions
3-46

– 20 percent of the newly identified overexpansions

• the U-bend region of about 20 percent of the row 1, row 2, and row 10 tubes 

• all of row 3 and row 4 tubes that were inspected with a bobbin coil

• 50 percent of previously identified dents with bobbin voltage amplitudes greater than 2 

volts

• all new dents 

• all new wear indications

• 20 percent of the tubes expanded into tube support 17 and 18 

• about 140 tubes per steam generator at tube support 18 because this location is at the 

bottom of the preheater region and loose parts tend to accumulate at this location

In addition, all tube plugs were inspected visually, and a rotating probe was used to inspect 

about 20 percent of the rolled plugs on the hot-leg side of the steam generator. No degradation 

or abnormal leakage was identified during the inspection of the plugs. 

As a result of these inspections, 14 tubes were plugged—9 for loose parts, 3 preventatively for

being expanded above the top of the tubesheet (over-roll condition), 1 preventatively for a 

geometry-related signal at the top of the tubesheet, and 1 because it was not expanded into the 

tubesheet on the cold-leg side. 

The only steam generator tube degradation mechanisms observed during RFO 14 were 

(1) wear at the AVBs, (2) wear at the tube support plates, (3) wear attributed to loose parts, and 

(4) primary water stress corrosion cracking at the tube end.

There was only one tube found not to be expanded for the full depth of the tubesheet. This tube 

was not expanded on the cold-leg side of the steam generator. Before plugging this tube, the 

tube was hard rolled into the tubesheet. The hot- or cold-leg side of the steam generator have 

no other known non-expanded or partially expanded tubes.

Thirteen tubes were discovered with an over-roll condition during RFO 14. The 3 tubes plugged 

because of an over-roll condition in RFO 14 were expanded significantly outside the tubesheet 

(greater than 4.45 cm (1.75 in.) above the top of the tubesheet), while the other 10 tubes were 

over-rolled less than 2.54 cm (1 in.) above the top of the tubesheet.

Although no tubes were plugged because of crack-like indications, stress corrosion cracking 

indications were identified in several tubes. All of these indications were in the lowermost 

10.2 cm (4 in.) of the tubesheet, and were allowed to remain in service per an approved repair 

criteria.

Secondary-side visual inspections were performed in each of the four steam generators at tube 

support plate 18. A total of 202 loose parts were identified, and 133 were removed. Of the 202 

loose parts, 22 were in steam generator A (11 removed), 76 were in steam generator B (57 

removed), 76 were in steam generator C (50 removed), and 28 were in steam generator D (15 
3-47

removed). All of the objects that were not removed were evaluated to ensure it was acceptable 

to leave them in the steam generator for one cycle of operation.

During RFO 14, follow-up inspections of the preheater waterboxes were performed with special 

emphasis on the waterbox cap plate. These inspections were only performed in steam 

generators B, C, and D since steam generator A does not have a cutout region (as confirmed 

during the RFO 13 inspections). Inspections of the rib assemblies, impingement plate, and cap 

plate, found no change in the condition since the prior inspections in RFO 13.

On October 31, 2007, the steam generator portion of the Catawba 2 technical specifications 

was revised to limit the extent of inspection in the hot-leg and cold-leg tubesheet regions. 

Specifically, the technical specifications were revised to exclude the portion of tube that is more 

than 43.2 cm (17 in.) below the top of the tubesheet from inspection (i.e., approximately the 

lowermost 10.2 cm (4 in.) of tube in the tubesheet on the hot- and cold-leg side was excluded 

from inspection, and hence any flaws that may exist in this region are permitted to remain in 

service). This revision was applicable only to RFO 15 and the subsequent operating cycle 

(ADAMS Accession No. ML072820013).

There was no evidence of primary-to-secondary leakage during Cycle 15 (spring 2006 to fall 

2007).

During RFO 15 in 2007, about 58 percent of the tubes in each of the four steam generators 

were inspected full length with a bobbin coil. The bobbin coil was used to inspect:

• all tubes with previous indications

• all tubes surrounding plugged tubes (one tube deep)

• all periphery tubes (outer perimeter, tube lane and T-slot) two rows deep 

• a 20 percent sample of row 1 through row 10 tubes

• all tubes with an eddy current offset indicating potentially high residual stresses (about 

27 tubes)

• a 25 percent random sample of the remaining tubes that were not inspected during RFO 

14

In addition to the bobbin coil inspections, an array probe was used to inspect the following in 

each of the four steam generators:

• 20 percent of the tubes from 7.62 cm (3 in.) above the hot-leg tubesheet to the hot-leg 

tube end (100 percent of the tubes were inspected in steam generator B)

• the U-bend region of 20 percent of the tubes in rows 1, 2, and 10

• 20 percent of tubes in rows 1 through 10 at tube supports 8 and 9 (i.e., the uppermost 

hot- and cold-leg tube support) for evidence of complete blockage of the tube support 

plate hole openings

• 20 percent of the expansions in the preheater region
3-48

An array probe also was used to inspect peripheral tubes two rows deep on the hot- and 

cold-leg sides from the top of the tubesheet to the first tube support plate, and peripheral tubes 

two rows deep at tube support 18 in each of the four steam generators. The array probe was 

also used to inspect:

• 20 percent of the overexpansions and bulges in the upper 43.2 cm (17 in.) of the 

tubesheet region in the hot- and cold-leg of steam generators A, C, and D

• 100 percent of the overexpansions and bulges in the upper 43.2 cm (17 in.) of the 

tubesheet region in the hot-leg of steam generator B

• 20 percent of these locations in the cold-leg of steam generator B

In addition, all new dent indications and existing dent indications not analyzed during RFO 14 

were inspected with an array probe. In addition to the eddy current inspections, visual 

inspections were performed on all tube plugs in each of the four steam generators.

As a result of these inspections, eight tubes were plugged. All 8 tubese were plugged for axially 

oriented outside-diameter crack-like indications (presumed to be outside-diameter stress 

corrosion cracking).

The only steam generator tube degradation mechanisms observed during RFO 15 were 

(1) wear at the AVBs, (2) wear at the tube support plates, (3) axially and circumferentially 

oriented primary water stress corrosion cracking at the hot-leg tube ends, (4) circumferentially 

oriented primary water stress corrosion cracking at the cold-leg tube ends, and (5) axially 

oriented outside-diameter stress corrosion cracking at the expansion transition/sludge pile.

The maximum depth reported for any AVB wear indications was 35 percent throughwall.

With respect to the cracking at the tube ends, inside diameter initiated indications were found in 

the hot-leg tack expansions in steam generator B, inside diameter initiated indications were 

found at the tube end in the hot-legs of steam generators A, C, and D, and circumferentially 

oriented, inside diameter initiated indications were found at the tube end in the cold-leg of steam 

generators A and D. The inside diameter initiated indications at the tube end in the cold-leg of 

steam generators A and D were all circumferentially oriented. A total of 15 indications were 

identified in 10 tubes. These tubes were left in service since these flaws are at least 43.2 cm 

(17 in.) below the top of the tubesheet. The cold-leg temperature is approximately 556 degrees 

Fahrenheit.

The outside-diameter initiated (non-wear) indications were all axially oriented and slightly above 

the top of the tubesheet in the sludge pile (a region in the steam generator where deposits tend 

to accumulate). The indications were in eight tubes; however, one tube had multiple indications. 

Several (if not all) of the indications were not associated with the expansion transition. The 

sludge pile height is 5.1 cm (2 in.) above the top of the tubesheet. Although the inspection 

scope at the top of the tubesheet only requires inspecting to 7.62 cm (3 in.) above the top of the 

tubesheet, data is typically acquired up to 10.2 cm (4 in.) above the top of the tubesheet. The 

maximum observed depth of any of these indications was 69 percent throughwall, and the 

maximum observed length was about 12.7 mm (0.5 in.). The indication with the maximum 

depth was not the longest indication. 
3-49

Several secondary-side maintenance activities were performed during RFO 15. Sludge lancing 

was performed in each of the four steam generators. After sludge lancing, secondary-side

visual inspections were performed on the top of the tubesheet including the tube free lane, the 

annulus, and selected in-bundle columns to verify the effectiveness of the sludge lancing. In 

addition, the 14 support blocks that are welded to the wrapper and underneath tube supports 1 

and 19 were inspected. No anomalies were identified.

In addition to the above secondary-side inspections, the top of tube support 18 in each steam 

generator were inspected visually. Similar inspections were performed during RFOs 13 and 14. 

The loose parts identified were consistent with those discovered in the previous outages, and 

loose parts that had a high likelihood to result in tube damage were removed. All loose parts 

that could not be retrieved were evaluated and determined to be acceptable for one cycle of 

operation.

The top tube support plate (08H and 09C) in steam generator A also was inspected visually to 

characterize the deposit loading and the extent to which the broached holes in the support plate 

were blocked. In addition array probe examinations were performed at 08H and 09C to assess 

tube hole blockage. Although these examinations were inconclusive because the inspection 

could not see the bottom of the support plate broached holes, severe blocking of the broached 

holes was not observed, and there were no observations that required immediate attention. 

Subsequent examinations in RFO 16 indicated that the broached openings at 08H and 09C 

were generally open with some evidence of deposits forming at the bottom of the broached 

openings. In addition, observations showed spalled deposits partially blocking a small number 

of openings. Evaluation of the array probe data from RFO 15 was indeterminate with regard to 

the extent of tube support hole blockage.

The steam drums in steam generators B and C were inspected visually. Also inspected were 

the secondary moisture separator banks (perforated plates, chevron vanes, and drain lines), 

primary moisture separator banks (swirl vane assemblies, downcomer barrel, tangential 

nozzles, riser barrel, and riser barrel slip fit joint), decks (upper, middle, intermediary, and 

lower), decking support structures, ladders, and auxiliary feedwater piping. No anomalies or 

degradation were identified.

On April 13, 2009, the steam generator portion of the Catawba 2 technical specifications was 

revised to permit certain sized flaws near the tube end in both the hot- and cold-leg sides of the 

steam generator to remain in service. Specifically, the technical specifications were revised to 

(1) permit flaws having a circumferential component less than or equal to 203 degrees found in 

the portion of the tube below 43.2 cm (17 in.) from the top of the tubesheet and above 2.54 cm 

(1 in.) from the bottom of the tubesheet to remain in service, (2) require the removal from 

service all flaws having a circumferential component greater than 203 degrees found in the 

portion of the tube below 43.2 cm (17 in.) from the top of the tubesheet and above 2.54 cm 

(1 in.) from the bottom of the tubesheet, (3) require the removal from service all tubes with 

service-induced flaws between the top of the tubesheet and 43.2 cm (17 in.) below the top of 

the tubesheet, and (4) permit all axial indications found in the portion of the tube below 43.2 cm 

(17 in.) from the top of the tubesheet to remain in service. In addition, the technical 

specifications were modified to indicate that when more than one flaw with circumferential 

components is found in the portion of the tube below 43.2 cm (17 in.) from the top of the 

tubesheet and above 2.54 cm (1 in.) from the bottom of the tubesheet with the total of the 

circumferential components being greater than 203 degrees and the axial separation distance of 

less than 2.54 cm (1 in.), then the tube must be removed from service (overlapping portions of 

the flaws only need to be counted once in determining the total circumferential involvement of 
3-50

the flaws). For flaws within 2.54 cm (1 in.) of the bottom of the tubesheet, the technical

specifications were modified to indicate (1) when one or more flaws with circumferential 

components are found and the total of the circumferential components exceeds 94 degrees, 

then the tube shall be removed from service and (2) when one or more flaws with 

circumferential components are found in the portion of the tube within 2.54 cm (1 in.) from the 

bottom of the tubesheet and within 2.54 cm (1 in.) axial separation distance of a flaw above 

2.54 cm (1 in.) from the bottom of the tubesheet, and the total of the circumferential components 

found in the tube exceeds 94 degrees, then the tube shall be removed from service (overlapping 

portions of the flaws only need to be counted once in determining the total circumferential 

involvement of the flaws). This revision to the technical specifications was applicable only to 

RFO 16 and the subsequent operating cycle (ADAMS Accession No. ML091030088).

There was no evidence of primary-to-secondary leakage during Cycle 16 (fall 2007 to spring 

2009).

During RFO 16 in 2009, 100 percent of the tubes in each of the four steam generators were 

inspected full length with a bobbin coil, except for the U-bend region of the tubes in rows 1 

through 5. In addition to the bobbin coil inspections, an array probe was used to inspect the 

following in each of the four steam generators:

• 100 percent of the tubes from 7.62 cm (3 in.) above the hot-leg tubesheet to the hot-leg 

tube end

• 100 percent of the tubes from 7.62 cm (3 in.) above the cold-leg tubesheet to the 

cold-leg tube end in steam generators A and D

• 20 percent of the tubes from 7.62 cm (3 in.) above the cold-leg tubesheet to the cold-leg 

tube end in steam generators B and C 

• the U-bend region of 35 percent of the tubes in rows 1 through 5 

• the U-bend region of 20 percent of the tubes in row 10 

• 20 percent of the preheater baffle plate expansions 

• all peripheral tubes two rows deep on the hot- and cold-leg sides from the top of the 

tubesheet to the first tube support plate, and peripheral tubes two rows deep at tube 

support 18 

• all new dent indications and all dents not inspected during RFO 15 

• all hot-leg tube support plate locations in tubes with potentially elevated residual 

stresses. 

In addition to the eddy current inspections, visual inspections were performed on all tube plugs 

in each of the four steam generators. All of the plugs were present and no degradation was 

observed.

As a result of these inspections, 10 tubes were plugged—6 for circumferentially oriented 

indications near the hot-leg tube end with circumferential extents greater than 94 degrees, 3 for 

axially oriented outside-diameter initiated indications at hot-leg tube supports, and 1 for a bulge 
3-51

at the top of the tubesheet on the hot-leg side of the steam generator. The bulge was attributed 

to fabrication of the steam generator.

The only steam generator tube degradation mechanism observed during RFO 16 were (1) wear 

at the AVBs, (2) wear at the tube support plates, (3) wear attributed to loose parts, (4) axially 

and circumferentially oriented primary water stress corrosion cracking at the hot-leg tube ends, 

and (5) axially oriented outside-diameter cracking indications at hot-leg tube supports.

The maximum depth reported for any AVB wear indications was 35 percent throughwall.

Axially and circumferentially oriented indications were observed near the hot-leg tube ends. 

Most of these indications were in steam generator B. For the circumferentially oriented 

indications near the tube ends, the largest measured about 4 cm (1.59 in.). The number of tube 

end indications has not significantly changed in the last four cycles. There were no indications 

detected at the cold-leg tube ends. All of the cold-leg tube end indications detected during RFO 

15 were classified as permeability variations in RFO 16.

Eight indications of axially oriented outside-diameter stress corrosion cracking were observed at 

the hot-leg tube supports in three tubes. Some of the tube support plate elevations had two 

indications. The two indications at the same tube support were at different lands. The largest 

amplitude observed for these eight indications was 0.35 volts as measured with a plus-point 

coil. All three of these tubes had elevated residual stresses as determined from the eddy 

current inspection. Sixty-five tubes are designated minus 2 sigma tubes, four of which have 

been plugged.

Secondary-side maintenance and inspection activities were also performed during RFO 16. A 

FOSAR was performed in the preheater region of all four steam generators. Some loose parts 

were detected and left in service. A licensee engineering analysis showed that tube integrity 

would be maintained for two inspection cycles for those parts left in the steam generator. 

Secondary-side visual inspections were performed at the upper tube support plate in steam 

generator A to evaluate the extent of blockage of the broached holes. Some lips of deposits 

have formed at the lower edges of the broached openings, but no evidence of significant

blockage was seen. No sludge lancing was performed during RFO 16. Sludge lancing is 

typically performed every other outage at Catawba 2.

On September 27, 2010, the steam generator portion of the Catawba 2 technical specifications 

was revised to limit the extent of inspection in the hot-leg and cold-leg tubesheet regions. 

Specifically, the technical specifications were revised to exclude the portion of tube that is more 

than 50.8 cm (20 in.) below the top of the tubesheet from inspection (i.e., approximately the 

lowermost 2.54 cm (1 in.) of tube in the tubesheet on the hot- and cold-leg side was excluded 

from inspection, and hence any flaws that may exist in this region are permitted to remain in 

service). This revision was applicable only to RFO 17 and the subsequent operating cycle 

(ADAMS Accession No. ML102640537).

There was no evidence of primary-to-secondary leakage during Cycle 17 (spring 2009 to fall 

2010).

During RFO 17 in 2010, 100 percent of the tubes in each of the four steam generators were 

inspected full length with a bobbin coil, except for the U-bend region of the tubes in rows 1 

through 5. In addition to the bobbin coil inspections, an array or rotating probe was used to 

inspect the following in each of the four steam generators:
3-52

• 100 percent of the tubes from 7.62 cm (3 in.) above the hot-leg tubesheet to the hot-leg 

tube end 

• the U-bend region of 100 percent of the row 1 tubes

• the U-bend region of 35 percent of the tubes in rows 2 through 5

• the U-bend region of 20 percent of the tubes in row 10

• 20 percent of the preheater baffle plate expansions

• all peripheral tubes two rows deep on the hot- and cold-leg sides from the top of the 

tubesheet to the first tube support plate

• all peripheral tubes two rows deep at tube support 18 on the cold leg

• all new dent indications

• all dents not inspected during RFO 16

• all hot-leg tube support plate locations in tubes with potentially elevated residual 

stresses

In addition to the eddy current inspections, all tube plugs in each of the four steam generators 

were inspected visually. All of the plugs were present and no degradation was observed.

As a result of these inspections, one tube was plugged for wear at a tube support plate.

The only steam generator tube degradation mechanisms observed during RFO 17 were 

(1) wear at the AVBs, (2) wear at the tube support plates, (3) wear attributed to loose parts, and 

(4) axially and circumferentially oriented primary water stress corrosion cracking at the hot-leg 

tube ends (all of which were greater than 50.8 cm (20 in.) from the top of the tubesheet so they 

were left in service).

The maximum depth reported for any AVB wear indications was 35 percent throughwall. The

maximum depth reported for wear at the tube support plates was 39 percent throughwall. There 

were 14 tubes that had wear attributed to interaction between the tube and the tube support 

plate. Ten tubes had wear attributed to loose parts.

The only secondary-side inspections performed during RFO 17 was FOSAR. There were 16

objects identified on the tubesheet in the 4 steam generators. Four of these objects were 

removed, seven were objects that were present in past inspections and remain unchanged, and 

five parts were evaluated. Evaluation (by the licensee) of the objects remaining in the steam 

generators showed that they were acceptable for at least two cycles of operation. No tube 

degradation was associated with any of these foreign objects.

On March 12, 2012, the steam generator portion of the Catawba 2 technical specifications was 

revised to limit the extent of inspection in the tubesheet region. Specifically, the technical 

specifications were revised to exclude the portion of tube that is more than 35.59 cm (14.01 in.)

below the top of the tubesheet from inspection (i.e., approximately the lowermost 17.8 cm (7 in.)
3-53

of tube in the tubesheet was excluded from inspection, and hence any flaws that may exist in 

this region are permitted to remain in service (ADAMS Accession No. ML12054A692)).

There was no evidence of primary-to-secondary leakage during Cycle 18 (fall 2010 to spring 

2012).

During RFO 18 in 2012, 100 percent of the tubes in each of the four steam generators were 

inspected full length with a bobbin coil, except for the U-bend region of the tubes in rows 1 

through 5. In addition to the bobbin coil inspections, an array probe was used to inspect the 

following in each of the four steam generators:

• 100 percent of the tubes from 7.62 cm (3 in.) above the hot-leg tubesheet to the hot-leg 

tube end

• the U-bend region of 100 percent of the row 1 tubes

• the U-bend region of 35 percent of the tubes in rows 2 through 5

• the U-bend region of 20 percent of the tubes in row 10

• 20 percent of the preheater baffle plate expansions

• all peripheral tubes (outer perimeter, open lane, and T-slot) two rows deep on the 

hot- and cold-leg sides from the top of the tubesheet to the first tube support plate

• all peripheral tubes two rows deep at tube support 18 on the cold leg

• all new dent indications

• all dents not inspected during RFO 17

In addition to the eddy current inspections, all tube plugs in each of the four steam generators

were inspected visually. All of the plugs were present and no abnormal conditions were

observed.

As a result of these inspections, five tubes were plugged—two tubes for wear associated with a 

possible foreign object and three for the presence of a possible foreign object.

The only steam generator tube degradation mechanisms observed during RFO 18 were 

(1) wear at the AVBs, (2) wear at the tube support plates, (3) wear attributed to loose parts, and 

(4) axially and circumferentially oriented primary water stress corrosion cracking at the hot-leg 

tube ends (all of which were greater than 50.8 cm (20 in.) from the top of the tubesheet so they 

were left in service).

The maximum depth reported for any AVB wear indications was 36 percent throughwall. There 

were 178 crack-like indications detected near the tube ends. Of these 178 indications, five were 

newly reported. Some of the indications have increased in voltage while other indications have 

decreased or stayed the same.

The only secondary-side inspections performed during RFO 18 was FOSAR in the preheater 

region. Inspection of the lower preheater baffle plate region identified foreign objects. 
3-54

Evaluation (by the licensee) of the objects remaining in the steam generators showed that they 

were acceptable for at least two cycles of operation (the next scheduled inspection of this 

region).

There was no evidence of primary-to-secondary leakage during Cycle 19 (spring 2012 to fall 

2013).

During RFO 19 in 2013, 100 percent of the tubes in each of the four steam generators were 

inspected full length with a bobbin coil, except for the U-bend region of the tubes in rows 1 

through 5. In addition to the bobbin coil inspections, an array probe was used to inspect the 

following in each of the four steam generators:

• 100 percent of the tubes from 7.62 cm (3 in.) above the hot-leg tubesheet to the hot-leg 

tube end

• the U-bend region of 100 percent of the row 1 tubes

• the U-bend region of 35 percent of the tubes in rows 2 through 5

• the U-bend region of 20 percent of the tubes in row 10

• 20 percent of the preheater baffle plate expansions not inspected during RFO 17 or RFO 

18 from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the tube support plate

• all peripheral tubes (outer perimeter, open lane, and T-slot) two rows deep on the 

hot- and cold-leg sides from the top of the tubesheet to the first tube support plate

• all peripheral tubes two rows deep at tube support 18 on the cold leg

• all new dent indications

• all dents not inspected during RFO 18

In addition to the eddy current inspections, visual inspections were performed on all tube plugs 

in each of the four steam generators. All of the plugs were present and no degradation was 

observed.

As a result of these inspections, seven tubes were plugged—two for wear attributed to a foreign 

object, three for wear associated with a possible foreign object that was still present, and two for

the presence of a possible foreign object.

The only steam generator tube degradation mechanisms observed during RFO 18 were 

(1) wear at the AVBs, (2) wear at the tube support plates, (3) wear attributed to loose parts, and 

(4) axially and circumferentially oriented primary water stress corrosion cracking at the hot-leg 

tube ends (all of which were greater than 50.8 cm (20 in.) from the top of the tubesheet so they 

were left in service).

Indications of AVB wear totaled 338 in 214 tubes during RFO 19: 134 indications (in 75 tubes) 

in steam generator A, 33 indications (in 22 tubes) in steam generator B, 69 indications (in 48 

tubes) in steam generator C, and 102 indications (in 69 tubes) in steam generator D. The 

maximum depth reported for the AVB wear indications was 35 percent throughwall.
3-55

In addition to the wear indications at the AVBs, 33 indications of wear at the tube support plates 

were identified in 30 tubes including 10 indications (in 8 tubes) in steam generator A, 15 

indications (in 14 tubes) in steam generator B, 5 indications (in 5 tubes) in steam generator C, 

and 3 indications (in 3 tubes) in steam generator D. The depth of these indications ranged from 

approximately 4 percent to 22 percent throughwall.

A total of 171 crack-like indications near the tube ends were identified during RFO 19 including 

1 indication (in 1 tube) in steam generator A, 154 indications (in 154 tubes) in steam generator 

B, 11 indications (in 11 tubes) in steam generator C, and 5 indications (in 5 tubes) in steam 

generator D. The number of tube end indications during the last few inspection outages has 

remained essentially the same.

The steam generator channel head cladding was inspected visually, and no degradation was

found.

Secondary-side inspections performed during RFO 19 included FOSAR at the top of the 

tubesheet. These inspections identified foreign objects. The licensee evaluated the objects 

remaining in the steam generators and they were acceptable for at least two cycles of operation

(the next scheduled inspection of this region). In addition to the top of tubesheet inspections, 

the top of the uppermost tube support plate in steam generator A was inspected visually. Minor 

amounts of scale and sludge were observed, but the quatrefoil holes were generally free of 

blockage from sludge and scale.

3.2.4 Comanche Peak 2

Tables 3-10, 3-11, and 3-12 summarize the information discussed below for Comanche Peak 2. 

Table 3-10 provides the number of full-length bobbin inspections and the number of tubes 

plugged and deplugged during each outage for each of the four steam generators. Table 3-11 

lists the reasons why the tubes were plugged. Table 3-12 lists tubes plugged for reasons other 

than wear at the AVBs.

Comanche Peak 2 has four Westinghouse model D5 steam generators. The licensee numbers 

its tube supports from 1H to 11H on the hot-leg side of the steam generator and from 1C to 11C 

on the cold-leg side (Figure 2-1).

During RFO 6 in 2002, 100 percent of the tubes in steam generators B and C were inspected 

full length with a bobbin coil, except for the U-bend region of the tubes in rows 1 and 2. In 

addition to the bobbin coil inspections, a rotating probe equipped with a plus-point coil was used 

to inspect:

• the hot-leg expansion transition region in 60 percent of the tubes

• the U-bend region of 100 percent of the tubes in rows 1 and 2

• the expansions at the preheater baffle plates in 50 percent of the tubes

• 100 percent of the dents at hot-leg tube support plate 3H with bobbin voltage amplitudes 

greater than or equal to 5 volts
3-56

No eddy current inspections were performed in steam generators A and D during RFO 6. In 

addition, all tube plugs were inspected visually.

As a result of these inspections, 11 tubes were plugged—3 for wear at the tube supports in the 

preheater (two of these were reclassified as wear from a loose part in RFO 8) and 8 for loose 

parts.

The only steam generator tube degradation mechanisms observed during RFO 6 were wear at 

the AVBs, wear at the preheater tube support, and wear attributed to loose parts.

Eighty-seven indications of AVB wear were detected in 56 tubes during RFO 6. This included 

41 indications (in 23 tubes) in steam generator B and 46 indications (in 33 tubes) in steam 

generator C. The maximum depth reported for the AVB wear indications was 34 percent

throughwall.

In addition to the wear indications at the AVBs, three indications of wear at the preheater tube 

supports were detected in three tubes. The maximum depth reported for the preheater wear 

indications was 11 percent throughwall (even after the RFO 8 reclassification of two of these 

indications). 

Eight tubes were identified with wear attributed to loose parts. Of these, three were plugged 

since the wear exceeded 40 percent throughwall. The maximum depth reported for these 

indications was 46 percent throughwall.

The only indications left in service in these two steam generators were those attributed to wear 

at the AVBs.

During RFO 6, FOSAR was performed on the secondary side of each of the four steam 

generators. These inspections along with the eddy current inspections identified about 96 loose 

parts/potential loose parts in steam generators A (4 objects), B (12 objects), and C (about 80 

objects). Only three loose parts/potential loose parts were not removed. Of the three locations 

where the loose parts/potential loose parts could not be removed, one location had a sludge 

rock, one had tube scale, and the third location was not accessible for visual inspection. The 

tubes near the loose parts/potential loose parts that could not be removed and the eight tubes 

with wear attributed to loose parts were plugged. One of the loose parts that was removed from 

steam generator B was a wedge measuring 10.2 cm (4 in.) by 5 cm (2 in.) by 2.54 cm (1 in.).

Before RFO 7, previous bobbin coil eddy current data were reviewed to identify tubes that could 

have high residual stress and therefore might be more susceptible to stress corrosion cracking. 

Because of this review, 73 tubes were identified as potentially having high residual stress. Of 

these tubes, eight were in low-row tubes (i.e., tubes that were stress relieved after bending). 

Inspection of these potentially affected tubes was made a permanent part of the Comanche 

Peak 2 Degradation Assessment.

During RFO 7 in 2003, 75 percent of the tubes in steam generator A and 55 percent of the tubes 

in steam generator D were inspected full length with a bobbin coil, except for the U-bend region 

of the tubes in rows 1 and 2. In addition to the bobbin coil inspections, a rotating probe 

equipped with a plus-point coil was used to inspect:

• 44 percent of the tubes from 7.62 cm (3 in.) above to 22.9 cm (9 in.) below the top of the 

tubesheet on the hot-leg side
3-57

• 6 percent of the tubes from 7.62 cm (3 in.) above the top of the tubesheet to the tube 

end on the hot-leg side, the U-bend region of 50 percent of the tubes in rows 1 and 2

• the expansions at the preheater baffle plates in 50 percent of the tubes

• 100 percent of the dents at hot-leg tube support plate 3H with bobbin voltage amplitudes 

greater than or equal to 5 volts

• 50 percent of the dings in the hot-legs with bobbin voltage amplitudes greater than 5 

volts

No eddy current inspections were performed in steam generators B and C during RFO 7. All 

tubes with high residual stress were inspected with a bobbin coil and with a rotating probe at the 

hot-leg expansion transition. In addition, all tube plugs in steam generators A and D were 

inspected visually.

As a result of these inspections, four tubes were plugged. All four tubes were plugged for wear 

at the AVBs. 

The only steam generator tube degradation mechanisms observed during RFO 7 were wear at 

the AVBs and wear at the preheater tube supports.

A total of 153 indications of AVB wear were detected in 91 tubes during RFO 7: 139 indications 

(in 82 tubes) in steam generator A and 14 indications (in 9 tubes) in steam generator D. 

Because the bobbin coil inspections during RFO 7 did not include 100 percent of the tubes, the 

actual number of AVB wear indications in these steam generators could be higher. The 

maximum depth reported for the AVB wear indications was 47 percent throughwall.

In addition to the wear indications at the AVBs, two indications of wear at the preheater tube 

supports were detected in two tubes. The maximum depth reported for the preheater wear 

indications was 4 percent throughwall.

During RFO 7, the secondary side of the steam generator was inspected visually. This included 

FOSAR at the top of the tubesheet, a limited scope in-bundle inspection at the top of the 

tubesheet, and an inspection of tube support 2C in all four steam generators. 

Twenty-seven loose parts were found in steam generators A (12 objects), B (5 objects), and D 

(10 objects). Nineteen of these objects were removed. The loose parts that could not be 

removed were a metal strip, two sludge rocks, weld slag, a 5.1-cm (2-in.) long nail, a piece of 

scale (deposit), a metal thread, and a crescent-shaped object. The licensee performed an 

evaluation and determined that it was acceptable to operate for up to two cycles with these 

loose parts in the steam generators.

In outages before RFO 8, the waterbox region was inspected visually in each of the four steam 

generators. Before RFO 8, the video tapes associated with these inspections were reviewed to 

assess if portions of the waterbox cap plate had been cut out during fabrication because

operating experience at Byron 2 showed that this location may be susceptible to degradation. 

This review indicated that a cut-out region does not exist in steam generators A, B, and D. The 

review of the video tape for steam generator C was not conclusive on whether a cut-out region 

existed in the cap plate. Subsequent inspections during RFO 8 indicated that a cut-out region in 

the cap plate does not exist in steam generator C.
3-58

During RFO 8 in 2005, 57 percent of the tubes in steam generator A, 59 percent of the tubes in 

steam generator B, 60 percent of the tubes in steam generator C, and 74 percent of the tubes in 

steam generator D were inspected full length with a bobbin coil, except for the U-bend region of 

the tubes in rows 1 and 2. In addition to the bobbin coil inspections, a rotating probe equipped 

with a plus-point coil was used to inspect:

• 47 percent of the tubes from 7.62 cm (3 in.) above to 22.9 cm (9 in.) below the top of the 

tubesheet on the hot-leg side

• 3 percent of the tubes from 7.62 cm (3 in.) above the top of the tubesheet to the tube 

end on the hot-leg side

• the U-bend region of 50 percent of the tubes in rows 1 and 2

• the expansions at the preheater baffle plates in 50 percent of the tubes

• 100 percent of the dents at hot-leg tube support plate 3H with bobbin voltage amplitudes 

greater than or equal to 2 volts

• 50 percent of the dings in the hot-legs with bobbin voltage amplitudes greater than 5 

volts

• 100 percent of the dings in the U-bend region with bobbin voltage amplitudes greater 

than 5 volts 

All tubes with high residual stress were inspected with a bobbin coil and with a rotating probe at 

the hot-leg expansion transition. In addition, the 100 largest over-expanded tubes as 

determined from the tube’s diameter and the largest 100 over-expanded tubes as determined by 

the bobbin voltage were included in the top of tubesheet rotating probe inspections. In addition, 

all tube plugs were inspected visually.

As a result of these inspections, 13 tubes were plugged—4 for wear at the AVBs, 4 for loose 

parts, 3 for single volumetric indications in the freespan region, 1 for a single volumetric 

indication at the tube support plate, and 1 for a restriction attributed to steam generator 

fabrication.

The only steam generator tube degradation mechanisms observed during RFO 8 were wear at 

the AVBs, wear at the preheater tube supports, and wear attributed to loose parts.

A total of 271 indications of AVB wear were detected in 164 tubes during RFO 8: 160

indications (in 93 tubes) in steam generator A, 43 indications (in 24 tubes) in steam generator B, 

50 indications (in 35 tubes) in steam generator C, and 18 indications (in 12 tubes) in steam 

generator D. Because the bobbin coil inspections during RFO 8 did not include 100 percent of 

the tubes, the actual number of AVB wear indications in these steam generators could be 

higher. The maximum depth reported for the AVB wear indications was 37 percent throughwall.

In addition to the wear indications at the AVBs, two indications of wear at the preheater tube 

supports were detected in two tubes. The maximum depth reported for the preheater wear 

indications was 7 percent throughwall.
3-59

Four tubes were identified with wear attributed to loose parts. These four tubes were plugged 

and were in steam generator C at row 6, column 33; row 7, column 33; row 48, column 40; and 

row 48, column 41. No visual inspections could be performed at the location of the wear for the 

tubes in row 6,column 33,and row 7,column 33,because the wear occurred at tube support 6C. 

Two adjacent tubes in this column—row 8,column 33,and row 9,column 33—were plugged 

during RFO 6 (2002) because of wear at the same tube support plate. As a result, the licensee 

hypothesized that the loose part is gradually migrating toward the middle of the bundle along 

this column. The licensee indicated that this is consistent with the direction of water flow that is 

from the outer rows toward the inner rows because tube support 6C has a cutout at the outer 

rows of tubes. Because the loose part was not retrieved, these tubes (row 6, column 33, and 

row 7, column 33) were stabilized and then plugged. Visual inspections around the tubes in row 

48, column 40, and row 48, column 41, did not reveal any loose parts at or near this location. 

The licensee concluded that the loose part has migrated away from this location, but no objects 

were found for several rows inward along the flow direction. As a result, the licensee 

hypothesized that the object could have broken up, allowing it to migrate far from this location. 

These tubes were plugged, but not stabilized because the part is no longer present at this 

location.

The three tubes plugged because of single volumetric indications in the freespan had 

indications that suggested lap signals similar to those observed in other steam generators. The 

bobbin signals have not changed from prior inspections at these locations. The tube that was 

plugged because of a single volumetric indication at the tube support plate was attributed to a 

manufacturing anomaly and has remained unchanged since 1994. The indication is pit-like;

therefore, the licensee ruled out wear because of tube support interaction or interaction with a 

loose part.

Sludge lancing was performed in each of the four steam generators during RFO 8. In addition, 

FOSAR was performed in accessible areas of the top of the tubesheet and tube support 2C in 

each steam generator. These inspections were more extensive than those performed in past 

outages especially on tube support 2C. These inspections found about 100 foreign objects in 

each of the four steam generators. These objects had accumulated over the previous eight 

cycles of plant operation. The licensee evaluated the parts to assess their potential effect on 

tube degradation and to prioritize the loose parts for retrieval. This evaluation took into 

consideration the shape, size, and estimated material composition of the parts, as well as the 

local flow conditions where the parts were found. The parts were classified as high, medium, or 

low priority for retrieval. High priority implied uncertainty as to what the result would be from an 

evaluation of acceptability for leaving the part in service for two cycles of operation if it could not 

be retrieved. The medium classification implied reasonable success in justifying leaving the part 

in the steam generator for two cycles. The low priority classification consisted of parts that had 

a high confidence of acceptability for leaving in service. Most of the high and medium priority 

parts were retrieved, as well as some that were classified as low priority. A final engineering 

evaluation of the parts remaining in the steam generators led the licensee to conclude that there 

was no threat to tube integrity from these parts for at least two full cycles of operation.

Some possible loose part indications were reported in all steam generators at the top of the 

tubesheet on the hot-leg side of the steam generator and at tube supports 2C, 3C, and 6C. All 

possible loose part locations accessible for visual inspection were inspected and any objects 

found were either retrieved or it was concluded that they were acceptable to leave in service 

based on an engineering evaluation.
3-60

On September 12, 2006, Comanche Peak 2 revised the steam generator portion of its technical 

specifications making it performance-based consistent with TSTF-449 (ADAMS Accession No. 

ML062340117).

During RFO 9 in 2006, no steam generator tubes were inspected. In addition, no sludge lancing 

was performed.

There was no evidence of primary-to-secondary leakage during Cycle 10 (fall 2006 to spring 

2008).

During RFO 10 in 2008, about 60 percent of the tubes in each of the four steam generators 

were inspected full length with a bobbin coil, except for the U-bend region of the tubes in rows 1 

and 2. In addition to the bobbin coil inspections, a rotating probe equipped with a plus-point coil 

was used to inspect:

• 50 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the hot-leg side

• 50 percent of the hot-leg bulges and overexpansions within the tubesheet

• 100 percent of the tubes from the tube-end to 5.1 cm (2 in.) above the tube end on the 

hot-leg side of the steam generator

• the U-bend region of 50 percent of the row 1 and row 2 tubes

• 50 percent of the preheater baffle plate expansions, 100 percent of the dents at hot-leg 

tube support plate 3H with bobbin voltage amplitudes greater than or equal to 2 volts

• 50 percent of the dings in the hot-leg and U-bend with bobbin voltage amplitudes greater 

than or equal to 5 volts

All tubes with high residual stress were inspected with a bobbin coil (full length) and with a 

rotating probe at the hot-leg expansion transition. In addition, all tube plugs were inspected 

visually. No anomalies were identified during the inspection of the plugs.

As a result of these inspections, 13 tubes were plugged, either for axial or circumferential 

indications near the hot-leg tube end.

The only steam generator tube degradation mechanisms observed during RFO 10 were 

(1) wear at the AVBs, (2) wear at the preheater tube supports, (3) wear attributed to loose parts, 

and (4) axially and circumferentially oriented primary water stress corrosion cracking at the

hot-leg tube end.

A total of 275 indications of AVB wear were detected in 167 tubes during RFO 10: 156 

indications (in 95 tubes) in steam generator A, 47 indications (in 25 tubes) in steam generator B, 

54 indications (in 35 tubes) in steam generator C, and 18 indications (in 12 tubes) in steam 

generator D. Although the bobbin coil inspections during RFO 10 did not include 100 percent of 

the tubes, all tubes with previously identified indications were inspected. The maximum depth 

reported for the AVB wear indications was 34 percent throughwall. The average growth rate of 

the AVB wear indications was 0.06 percent throughwall per effective full power year. The 

growth rate evaluated at a 95 percent probability and 50 percent confidence was 1.41 percent
3-61

throughwall per effective full power year. Both the average and the 95 percent probability 

growth rate have declined since RFO 4.

In addition to the wear indications at the AVBs, two indications of wear at the preheater tube 

supports were detected in two tubes. The maximum depth reported for the preheater wear 

indications was 7 percent throughwall.

Two indications of wear attributed to loose parts were identified in two tubes during RFO 10. 

The loose part at the location of the wear was removed from the steam generator. The 

maximum depth reported for these indications was 23 percent throughwall.

The axially and circumferentially oriented indications near the tube ends initiated from the inside 

diameter of the tube; therefore, the licensee attributed the indications to primary water stress 

corrosion cracking (however, no tube pulls were performed to confirm they resulted from 

corrosion). Of the 13 tubes with indications near the tube ends, 1 tube is from the population of 

tubes identified as possibly having elevated residual stress. Of these 13 tubes, 9 had axial 

indications and 4 had circumferential indications at the hot-leg tube end. 

Several secondary-side maintenance activities were performed during RFO 10. Sludge lancing 

and FOSAR were performed in each of the four steam generators. In addition, upper bundle 

video inspections were performed in steam generator C. Thirty-two pounds of sludge were 

removed from the four steam generators, which is consistent with the prior history of sludge 

removal. All possible loose part indications reported from the eddy current data were reviewed 

for possible visual inspection. FOSAR was performed on all possible loose parts in accessible 

areas (i.e., top of tubesheet and a large portion of cold-leg tube support 2C). The visual 

inspection resulted in the identification of parts on the tubesheet and on cold-leg tube support 

2C. Those parts identified through visual inspection were reviewed; and, if they could have 

caused tube wear, the neighboring tubes were visually inspected. Loose parts were found in 

each of the four steam generators. Some of these parts were retrieved. For those parts not 

retrieved, they were evaluated to ensure that they would not compromise tube integrity until the 

next inspection. The upper bundle visual inspection in steam generator C indicated a very light 

dusting of magnetite on the tubes mainly in the hot-leg region. The tube support openings were 

open and free of any significant deposits. No degradation was detected during these visual 

inspections.

On October 9, 2009, the steam generator portion of the Comanche Peak 2 technical 

specifications was revised to limit the extent of inspection in the hot-leg and cold-leg tubesheet 

regions. Specifically, the technical specifications were revised to exclude the portion of tube 

that is more than 43 cm (16.95 in.) below the top of the tubesheet from inspection (i.e., 

approximately the lowermost 10.2 cm (4 in.) of tube in the tubesheet on the hot-and cold-leg 

side was excluded from inspection, and hence any flaws that may exist in this region are 

permitted to remain in service). This revision was applicable only to RFO 11 and the 

subsequent operating cycle (ADAMS Accession No. ML092740076).

During RFO 11 in 2009, no steam generator tube or steam generator secondary-side

inspections were performed. No sludge lancing was performed during RFO 11.

After RFO 11 in 2009, Comanche Peak 2 implemented a 4.5-percent power uprate.

On April 6, 2011, the steam generator portion of the Comanche Peak 2 technical specifications 

was revised to limit the extent of inspection in the hot-leg and cold-leg tubesheet regions. 
3-62

Specifically, the technical specifications were revised to exclude the portion of tube that is more 

than 43 cm (16.95 in.) below the top of the tubesheet from inspection (i.e., approximately the 

lowermost 10.2 cm (4 in.) of tube in the tubesheet on the hot- and cold-leg side was excluded 

from inspection, and hence any flaws that may exist in this region are permitted to remain in 

service). This revision was applicable only to RFO 12 and the subsequent operating cycle 

(ADAMS Accession No. ML110770322).

There was no evidence of primary-to-secondary leakage during Cycle 12 (fall 2009 to spring 

2011).

During RFO 12 in 2011, about 70 percent of the tubes in each of the four steam generators 

were inspected full length with a bobbin coil, which included all tubes with prior indications and 

all tubes not inspected during RFO 10. In addition to the bobbin coil inspections, a rotating 

probe equipped with a plus-point coil was used to inspect:

• 50 percent of the tubes from 7.62 cm (3 in.) above to 43.2 cm (17 in.) below the top of 

the tubesheet on the hot-leg side (including all tubes not inspected during RFO 10)

• the U-bend region of 50 percent of the row 1 and row 2 tubes (including all tubes not 

inspected during RFO 10)

• 50 percent of the preheater baffle plate expansions (including all tubes not inspected 

during RFO 10)

• 100 percent of the dents at hot-leg tube support plate 3H with bobbin voltage amplitudes 

greater than or equal to 2 volts

• 50 percent of the dents and dings in the hot-leg with bobbin voltage amplitudes greater 

than or equal to 5 volts (including all such dents and dings not inspected during RFO 10)

All tubes with potentially high residual stress were inspected with a bobbin coil (full length) and 

with a rotating probe at the hot-leg expansion transition. In addition, all tube plugs were 

inspected visually. All plugs were in place and no issues were identified during the inspections.

As a result of these inspections, three tubes were plugged. All of these tubes were plugged for 

wear at the AVBs.

The only steam generator tube degradation mechanisms observed during RFO 12 were wear at 

the AVBs, wear at the preheater tube supports, and wear attributed to loose parts.

A total of 286 indications of AVB wear were detected in 177 tubes during RFO 12: 160 

indications (in 97 tubes) in steam generator A, 48 indications (in 27 tubes) in steam generator B, 

56 indications (in 38 tubes) in steam generator C, and 22 indications (in 15 tubes) in steam 

generator D. Of these 286 indications, 15 were new indications. The depth of the new 

indications was less than 20 percent throughwall. The maximum depth reported for the AVB 

wear indications was 44 percent throughwall. The average growth rate of the wear indications 

is 0.15 percent throughwall per two cycles of operation (2.862 effective full power years). For 

the last operating period, the growth rate at a 95 percent probability and 95 percent confidence 

is 1.48 percent per effective full-power year (and at a 95 percent probability and 50 percent

confidence the growth rate is 1.05 percent per effective full-power year). In general, the growth 
3-63

rate has decreased with time. Although the bobbin coil inspections during RFO 12 did not 

include 100 percent of the tubes, all tubes with previously identified indications were inspected.

In addition to the wear indications at the AVBs, two indications of wear at the preheater tube 

supports were detected in two tubes. The maximum depth reported for the preheater wear 

indications was 7 percent throughwall. The depth of these indications is not changing.

Three indications of wear attributed to loose parts were identified in two tubes during RFO 12. 

The two tubes were adjacent to each other and the loose part that caused the wear was 

removed from the steam generator. The maximum depth reported for these indications was 30

percent throughwall.

Inspection and maintenance on the secondary side of the steam generators were performed 

during RFO 12. Sludge lancing and FOSAR was performed in all four steam generators. A 

total of 29 pounds of sludge was removed from the four steam generators. The FOSAR was 

performed at the top of the tubesheet and baffle plate B. In addition, the FOSAR was performed 

on flow distribution baffle plate A in the cold-leg side of the steam generator.

In addition to these secondary-side activities, the upper bundle region of steam generator D was 

inspected visually during RFO 12. Specifically, tube supports 8 and 11 were inspected in 

columns 71, 72, 97, and 98. The tube outside surface and the tube support plate crevices were 

clean with very little deposit accumulation. For tube support plate 8, a thin film of magnetite 

exists on the tubes in the hot-leg, but not on the cold-leg. The quatrefoil flow holes remain open 

and free of significant deposit, with slightly more deposit formation on the hot-leg side of the 

steam generator. The center stay rod in the tube lane and the wrapper block welds on the 

nozzle side were inspected from the tube lane and found to be intact with no visible structural 

degradation. The wrapper block welds at the end of each column gap were intact with no visible 

structural degradation. The stay rod in columns 70 and 71 was inspected and no structural 

issues were identified. For tube support plate 11, the center stay nut was in good condition with 

no noticeable degradation and the welds were intact. There was a light layer of magnetite on 

the U-bend region of the tubes. The wrapper block weld at the nozzle side was viewed from the 

tube lane and was found to be intact with no visible degradation. The hot-leg columns 

inspected were clean with some speckled deposits on the tubes. The quatrefoil holes were 

open and free of significant deposits. The wrapper block welds at the ends of the column gap 

97–98 were intact with no visible structural degradation. The stay rod cap and weld in column 

gap 70–71 had no structural issues. The cold-leg column gaps 71–72 and 97–98 were clean 

and free of deposit. The quatrefoil flow holes were also free of deposits. The wrapper block 

welds at the end of each column gap were intact with no visible structural degradation. During 

these inspections, the top of tube support plate 10 was viewed. The flow holes in support plate 

10 were also free of deposits. The tubes on the hot-leg side of the steam generator contained a 

light dusting of magnetite.

After startup from RFO 12 in May 2011, Comanche Peak 2 was shut down (from 100 percent

power) because of high sodium concentration in all four steam generators because of leakage 

from two main condenser tubes. The condenser tubes were damaged by a falling object. The 

sodium concentration rose to approximately 3,000 parts per billion. High concentrations of 

sodium are a potential long term steam generator tube corrosion concern.

On October 18, 2012, the steam generator portion of the Comanche Peak 2 technical 

specifications was revised to limit the extent of inspection in the tubesheet region. Specifically, 

the technical specifications were revised to exclude the portion of tube that is more than 35.59 
3-64

cm (14.01 in.) below the top of the tubesheet from inspection (i.e., approximately the lowermost 

17.8 cm (7 in.) of tube in the tubesheet was excluded from inspection, and hence any flaws that 

may exist in this region are permitted to remain in service (ADAMS Accession No. 

ML12263A036)).

During RFO 13 in 2012, no steam generator tube or steam generator secondary-side

inspections were performed.

On February 27, 2014, the steam generator portion of the Comanche Peak 2 technical 

specifications was revised to make them consistent with TSTF-510 (ADAMS Accession No. 

ML14042A223).

There was no evidence of primary-to-secondary leakage during Cycles 13 and 14 (spring 2011 

to spring 2014).

3.3 Model F Steam Generator Operating Experience

Inspection results for Millstone 3, Seabrook, Vogtle 1, Vogtle 2, and Wolf Creek are provided in 

this section of the report. In addition, the results from inspections of the first 10 rows of tubes at 

Callaway (i.e., the thermally treated Alloy 600 steam generator tubes) are discussed up until the 

replacement of the steam generators in 2005. Although Salem 1 has model F steam generators 

and were the original steam generators to be used at the canceled Seabrook 2 facility, the 

summary of operating experience for Salem 1 is included in Section 3.4 on replacement steam 

generators because the flow conditions in the Salem 1 steam generators could be significantly 

different than in other model F steam generators potentially resulting in differences in operating 

experience.

3.3.1 Callaway

Tables 3-13, 3-14, and 3-15 summarize the information discussed below for Callaway. Table 

3-13 provides the number of full-length bobbin inspections and the number of tubes plugged 

and deplugged during each outage for each of the four steam generators. Table 3-14 lists the 

reasons why the tubes were plugged. Table 3-15 lists tubes plugged for reasons other than 

wear at the AVBs.

Callaway has four Westinghouse model F steam generators. The licensee numbers its tube 

supports from the hot-leg flow distribution baffle (FBH) to 7H on the hot-leg side of the steam 

generator and from cold-leg flow distribution baffle (FBC) to 7C on the cold-leg side (Figure 2-4). 

Although Callaway has both thermally treated and mill-annealed Alloy 600 tubes, the following 

summarizes the inspections and repairs to the thermally treated tubes. Callaway was 

authorized in the plant technical specifications to use laser-welded sleeves and electrosleeves 

to repair defective tubes.

There was no evidence of primary-to-secondary leakage during Cycle 12 (spring 2001 to fall 

2002).

During RFO 12 in 2002, 100 percent of the tubes in steam generators A and D were inspected 

full length with a bobbin coil. In addition to the bobbin coil inspections, a rotating probe 

equipped with a plus-point coil was used to inspect:
3-65

• 100 percent of the tubes from 5.1 cm (2 in.) above to x inches below the top of the 

tubesheet on the hot-leg side in all four steam generators (with “x” ranging from 

approximately 3.2 to 8.0 depending on the location of the tube within the tube bundle)

• the U bend region of 100 percent of the tubes in rows 1 and 2 in steam generator C

• 20 percent of the dents and dings with bobbin voltage amplitudes greater than 2 volts in 

all four steam generators

• 100 percent of the laser welded sleeves in steam generator C (which includes the two 

thermally treated tubes that were sleeved during RFO 8)

Additional inspections were performed in the non-thermally treated tubes.

As a result of these inspections, two thermally treated tubes were plugged. These tubes were 

plugged for wear at the tube support plate elevations. The indications were associated with the 

tube support plate lands and were at the ends of the tube support plate. The maximum depth 

reported for these indications was 16 percent throughwall. No crack-like indications were 

detected in the thermally treated tubes during RFO 12.

During RFO 12, sludge lancing was performed in all four steam generators.

During RFO 13 in 2004, 100 percent of the tubes in each of the four steam generators were 

inspected full length with a bobbin coil. In addition to the bobbin coil inspections, a rotating 

probe equipped with a plus-point coil was used to inspect:

• 100 percent of the tubes from 5.1 cm (2 in.) above to x inches below the top of the 

tubesheet on the hot-leg side in all four steam generators (with “x” ranging from about 5 

to 9 depending on the location of the tube within the tube bundle)

• the U-bend region of 100 percent of the tubes in rows 1 and 2 in steam generator A

• 100 percent of the dents and dings with bobbin voltage amplitudes greater than 5 volts in 

all four steam generators

• 20 percent of the dents and dings with bobbin voltage amplitudes greater than 2 volts in 

all four steam generators

• 100 percent of the laser welded sleeves in steam generator A (which includes the one 

thermally treated tube that was sleeved during RFO 8)

In addition, ultrasonic examination was performed on all electrosleeves in steam generator C 

(which includes the three thermally treated tubes that were electrosleeved during RFO 10). 

Additional inspections were performed in the non-thermally treated tubes.

As a result of these inspections, two thermally treated tubes were plugged. These tubes were 

plugged for single volumetric indications at or near a tube support plate. No crack-like 

indications were detected in the thermally treated tubes during RFO 13.

During RFO 14 in 2005, Callaway replaced their original Westinghouse model F steam 

generators (with primarily mill-annealed Alloy 600 tubes) with Framatome model 73/19T 
3-66

recirculating steam generators (with thermally treated Alloy 690 tubes). At the time of 

replacement, Callaway revised the steam generator portion of their technical specifications 

making them performance-based consistent with TSTF-449 (ADAMS Accession No. 

ML052570086).

3.3.2 Millstone 3

Tables 3-16, 3-17, and 3-18 summarize the information discussed below for Millstone 3. Table 

3-16 provides the number of full-length bobbin inspections and the number of tubes plugged 

and deplugged during each outage for each of the four steam generators. Table 3-17 lists the 

reasons why the tubes were plugged. Table 3-18 lists tubes plugged for reasons other than 

wear at the AVBs.

Millstone 3 has four Westinghouse model F steam generators. The licensee numbers its tube 

supports using the alternate naming convention in Figure 2-4.

During RFO 7, visual inspections of the feedrings and upper internal components in all four 

steam generators were performed. In addition, ultrasonic examination of the feedrings in steam 

generators B and D was performed. Erosion of the feedring/J-tubes was identified with steam 

generator D having the most limiting erosion rate. The licensee evaluated this degradation and 

determined it to be acceptable for at least two more cycles of operation. The visual inspections 

of the upper internal components did not reveal any degradation that could threaten tube 

integrity.

During cycle 8 (spring 2001 to fall 2002), there was minimal primary-to-secondary leakage (less 

than 3.79 lpd (1 gpd)).

During RFO 8 in 2002, 100 percent of the tubes in steam generators A and C were inspected 

full length with a bobbin coil, except for the U-bend region of the row 1 tubes. In addition to the 

bobbin coil inspections, a rotating probe equipped with a plus-point coil was used to inspect:

• 73 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the hot-leg side in steam generator A

• 50 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the hot-leg side in steam generator C

• 20 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the cold-leg side in steam generator A

• less than 1 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top 

of the tubesheet on the cold-leg side in steam generator C

• the U-bend region of 50 percent of the tubes in rows 1 and 2 in steam generators A and 

C

• 100 percent of the hot-leg dents and dings with bobbin voltage amplitudes greater than 

3 volts in steam generators A and C
3-67

No eddy current inspections were performed in steam generators B and D during RFO 8. All 

tube plugs in steam generators A and C were inspected visually. No degradation or abnormal 

leakage was identified during the inspection of the plugs.

Because these inspections, 11 tubes were plugged—7 for wear at the AVBs, 2 for wear 

attributed to loose parts, 1 for wear in a tube near a loose part that could not be retrieved, and 1 

for an obstruction.

The only steam generator tube degradation mechanisms observed during RFO 8 were wear at 

the AVBs and wear attributed to loose parts.

In steam generator A, 222 indications of AVB wear were detected in 112 tubes during RFO 8. 

In steam generator C, 54 indications of AVB wear were detected in 20 tubes during RFO 8. The 

maximum depth reported for the AVB wear indications was 45 percent throughwall. The 

average growth rate for these indications over two cycles of operation is less than 1.3 percent

throughwall. 

The plus-point inspections resulted in the identification of 59 volumetric indications affecting 50 

tubes. Thirty-six of these indications (in 32 tubes) were determined to be manufacturing burnish 

marks and not service-induced. The remaining 23 indications (in 18 tubes) were attributed to 

loose parts or manufacturing burnish marks that could not be confirmed with the bobbin coil. 

One of these tubes had an associated loose part indication and was removed from service (as 

discussed above). This loose part was on the secondary side of steam generator C and was a 

small section of flat stock that had become wedged between tubes. Review of the historical

eddy current data identified that this small part had been at this location since 1989 (RFO 2). 

Although only minor damage was identified, this tube was stabilized and plugged. The stabilizer 

increases the damping of the tube, reducing flow-induced vibration, and prohibits interaction 

with adjacent tubes in the unlikely event of a complete severance. Many of the volumetric 

indications were small and only detectable with a rotating probe.

The tube that was plugged because of an obstruction was obstructed 18.5 cm (7.29 in.) above 

the end of the tube on the cold-leg side (i.e., about 33 cm (13 in.) below the top of the 

tubesheet). The obstruction blocked the insertion of a 1.37-cm (0.540-in.) diameter probe. An 

inspection of this tube with smaller diameter probes, such as the 1.32-cm (0.520-in.) probe, was 

not attempted because smaller probes would not have supplied adequate fill factors. This tube 

had been inspected with a 1.42-cm (0.560-in.) diameter probe during the preservice, RFO 1, 

RFO 2, RFO 4, mid-cycle (RFO 6), and RFO 6 inspections. Consequently, it was concluded 

that the obstruction was service induced.

Inspection and maintenance on the secondary side of the steam generator also were performed 

during RFO 8. To reduce the amount of sludge on the top of the tubesheet, sludge lancing was 

performed in each of the four steam generators. In addition, FOSAR was performed in each of 

the four steam generators. Twelve loose parts remained in the four steam generators following 

RFO 8 (five in steam generator A, two in B, four in C, and one in D). These parts included small 

diameter wires, machine curls, sludge rocks, metal shavings, plate, and slag. The licensee has 

evaluated these loose parts and determined they are acceptable to leave in service. The tubes 

near these parts are inspected periodically to ensure tube integrity is maintained. A visual 

inspection of upper internal components was performed in limited locations in steam generator 

A. No degradation that could threaten tube integrity was identified.
3-68

During cycle 9 (fall 2002 to spring 2004), there was minimal primary-to-secondary leakage (less 

than 1 gpd).

During RFO 9 in 2004, 100 percent of the tubes in steam generators B and D were inspected 

full length with a bobbin coil, except for the U-bend region of the row 1 tubes. In addition to the 

bobbin coil inspections, a rotating probe equipped with a plus-point coil was used to inspect:

• 50 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the hot-leg side in steam generators B and D

• 37 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the cold-leg side in steam generator D

• the U-bend region of 50 percent of the tubes in rows 1 and 2 in steam generators B and 

D

• 100 percent of the hot-leg dents and dings with bobbin voltage amplitudes greater than 

or equal to 3 volts in steam generators B and D

• all potential loose part locations (11 tubes) including 1 tube surrounding the tubes with 

potential loose part indications in steam generators B and D (38 tubes)

No eddy current inspections were performed in steam generators A and C during RFO 9. No 

degradation or abnormal leakage was identified during the inspection of the plugs.

As a result of these inspections, 10 tubes were plugged—1 for wear at the AVBs, 2 for wear 

attributed to loose parts, 2 for damage during installation of a hand-hole during fabrication (one 

of which had degradation estimated to be greater than 40% throughwall), and 5 for a possible 

loose part (three of these tubes had measurable wear).

The only steam generator tube degradation mechanisms observed during RFO 9 were wear at 

the AVBs, wear attributed to loose parts, and wear attributed to maintenance.

In steam generator B, 90 indications of AVB wear were detected in 39 tubes during RFO 9. In 

steam generator D, 119 indications of AVB wear were detected in 61 tubes during RFO 9. The 

maximum depth reported for the AVB wear indications was 37 percent throughwall.

The plus-point inspections resulted in the identification of 30 volumetric indications affecting 25 

tubes. Fifteen of these volumetric indications (in 14 tubes) were determined to be 

manufacturing burnish marks and not service-induced. These indications were reported with 

the bobbin coil probe and were present in the preservice (1985) bobbin coil data. The

indications were present in the 1985 data; however, they did exhibit some change. This change 

was attributed (by the licensee) to differences in the examination techniques and equipment.

Of the remaining 15 volumetric indications (in 11 tubes), 13 were attributed to loose parts 

damage, and 2 (above tube support 8H) were attributed to secondary-side damage incurred 

because of the installation of hand-holes during steam generator fabrication. All 15 of these 

indications were in steam generator D. The indication in one of the two tubes attributed to 

damage during hand-hole installation was present during RFO 1, while the indication in the 

other tube was small and was not detectable with the bobbin coil (it was detected with the 

rotating probe, and RFO 9 was the first time this tube was inspected with a rotating probe).
3-69

Of the 11 tubes with these 15 indications, 7 tubes were plugged. Two of the tubes plugged 

were the ones with indications attributed to hand-hole installation, and the remaining 5 tubes 

were plugged because of wear attributed to loose parts. Of these latter 5 tubes, 2 tubes were 

affected by a loose part that was removed from the steam generator whereas for the other 3 

tubes, the presence of a loose part could not be visually confirmed since the indications were 

above the flow distribution baffle. Because the existence of the loose part could not be 

confirmed visually, these three tubes (along with two other nearby tubes with potential loose 

part indications) were plugged. Loose parts identified on top of the flow distribution baffle in the 

past have been small items such as machining curls. None of these latter five tubes was

stabilized.

Of the four tubes with volumetric indications that were not plugged, all were first reported in 

RFO 9; however, one was not present in prior bobbin examinations (row 9 column 42), one was 

present since RFO 7 (row 27 column 39), one was present since the preservice inspection and 

has a small ding associated with the volumetric indication (row 38 column 20), and one was 

present since RFO 3 (row 52 column 91). The licensee plans to reexamine the first and last two

of these indications during the next outage.

During RFO 9, there were 345 dents in 197 tubes and 202 dings in 154 tubes in steam 

generator B with bobbin voltage amplitudes greater than or equal to 2 volts. Similarly, in steam 

generator D, there were 315 dents in 188 tubes and 261 dings in 211 tubes with bobbin voltage 

amplitudes greater than or equal to 2 volts. Of these, 89 dents in 73 tubes and 89 dings in 65 

tubes in steam generator B had bobbin voltage amplitudes greater than or equal to 3 volts. 

Similarly, 161 dents in 104 tubes and 82 dings in 70 tubes in steam generator D had bobbin 

voltage amplitudes greater than or equal to 3 volts. 

Visual and ultrasonic phased-array examinations on the nozzles of the feedring of steam 

generator D were performed during RFO 9. This data were used to re-verify and establish a 

maximum erosion rate for determining an appropriate repair date for the other three steam 

generators. The areas of erosion on the feedring in steam generator D were repaired by 

welding. The planned repair dates for the feedrings are RFO 10 for steam generator B, RFO 11 

for steam generator C, and RFO 12 for steam generator A.

During RFO 9, a visual inspection of upper internal components was performed in steam 

generator D at, and above, the seventh tube support plate. No degradation that could threaten 

tube integrity was identified. Additionally, a general examination of the steam drum area was 

performed in all steam generators during the installation and removal of equipment used to 

perform an upper bundle flush. No degradation that could threaten tube integrity was identified.

During RFO 10 in 2005, 100 percent of the tubes in steam generators A and C were inspected 

full length with a bobbin coil, except for the U-bend region of many of the tubes in rows 1 and 2. 

In addition to the bobbin coil inspections, a rotating probe equipped with a plus-point coil was 

used to inspect:

• 50 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the hot-leg side in steam generators A and C

• 1,054 overexpansions from 7.62 cm (3 in.) above to 40.6 cm (16 in.) below the top of the 

tubesheet on the hot-leg side in steam generators A and C
3-70

• the U-bend region of about 80 percent of the tubes in rows 1 and 2 in steam generators 

A and C (including the U-bend region of all tubes in rows 1 and 2 not inspected with a 

rotating probe during RFO 8 and all U-bend regions not inspected with a bobbin probe in 

RFO 10)

• all newly reported dents and dings with bobbin voltage amplitudes greater than or equal 

to 3 volts on the hot-leg side of steam generators A and C

• all previously reported dents and dings that exhibited a change in bobbin voltage 

amplitude greater than or equal to 0.5 volts or a change in phase angle greater than or 

equal to 10 degrees from the data obtained during the previous two inspections on the 

hot-leg side of steam generators A and C

No eddy current inspections were performed in steam generators B and D during RFO 10.

As a result of these inspections, two tubes were plugged. These tubes were plugged for wear 

at the AVBs.

The only steam generator tube degradation mechanisms observed during RFO 10 were wear at 

the AVBs, wear attributed to loose parts, and wear attributed to maintenance equipment (sludge 

lance sled).

In steam generator A, 259 indications of AVB wear were detected in 135 tubes during RFO 10. 

In steam generator C, 59 indications of AVB wear were detected in 25 tubes during RFO 10. 

The maximum depth reported for the AVB wear indications was 42 percent throughwall. In 

steam generator A, 62 of the 259 AVB wear indications were new, and in steam generator C, 10 

of the 59 AVB wear indications were new. The maximum depth reported for the new AVB wear 

indications was 25 percent throughwall. The average wear rate over the past two operating 

cycles for steam generator A was 0.94 percent with a standard deviation of 3.24 percent. The 

average wear rate over the past two operating cycles for steam generator C was 1.61 percent

with a standard deviation of 3.00 percent.

There were 32 volumetric indications (other than wear at the AVBs) left in service during 

RFO 10. These indications were attributed to wear from a loose part or wear because of

mechanical interaction with sludge lancing equipment employed in previous outages. There are 

no known loose parts or potential loose parts remaining at any of the locations with these 

volumetric indications. Of these 32 indications, 21 were present during RFO 8, and there was 

no significant change in the depth of the indications (i.e., the change was attributed to factors 

such as probe wear and diametric offset of the probe rather than growth of the indications).

There are 8,783 overexpansions in the tubesheet region of the four steam generators. Of 

these, 3,260 are on the hot-leg side of the steam generator. The 1,054 overexpansions 

examined during RFO 10 represent 32 percent of the total population of overexpansions on the 

hot-leg side of the steam generators. The overexpansions that were inspected included all 

overexpansions with bobbin coil voltage amplitudes exceeding 28 volts and some of the 

overexpansions with bobbin coil voltage amplitudes between 18 and 28 volts. This latter 

sample (with voltage amplitudes between 18 and 28 volts) were in either the approximately 200 

tubes with overexpansions with amplitudes greater than 28 volts or the 50 percent of the tubes 

that were inspected from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the tubesheet. 

The inspections were focused on the upper region of the tubesheet because these were 

considered by the licensee to be the greatest risk to tube integrity.
3-71

Secondary-side visual inspections were performed in the no-tube lane (i.e., the region between 

the row 1 of the hot and cold legs) and the annulus at the top of the tubesheet in steam 

generators A and C during RFO 10. In addition, all locations of possible loose parts (five to six 

locations) were inspected visually. The only loose parts that were detected were near the 

locations where possible loose part indications were identified from the eddy current data. As a 

result of these inspections, one piece of weld wire was located and removed. The other 

locations with possible loose part indications either had sludge deposits or no discernible cause 

for the possible loose part indication. There was no tube wear associated with any of the 

possible loose part indications.

An inspection of the internal areas of the steam generator C steam drum down to the seventh

tube support plate was also conducted during RFO 10. All steam drum components viewed 

appeared structurally sound and in good condition, with the exception of J-tubes numbers 1, 15, 

16, and 30. These J-tubes showed signs of erosion at the nozzle weld to header interface on 

the inside diameter of the header. Ultrasonic testing and weld repair (overlay) were performed 

on these nozzles during RFO 10. Repairs to the same J-tubes were also completed in steam 

generator B during RFO 10. Mid-deck and intermediate deck components viewed appeared to 

be in good condition and functioning as designed. On the lower deck, some leakage was 

observed at the riser barrel/downcomer slip joint, as well as some minor roughness or pitting on 

the primary separators in the location of feedwater overspray. No significant loss of material to 

the primary separators was observed and conditions were similar to those observed during the 

previous inspection. The AVBs appeared in good condition.

During RFO 9 and RFO 10, a review of the bobbin coil eddy current data from the tubes in rows 

1 through 10 was performed to identify tubes that have high residual stress (i.e., an eddy current 

offset) and therefore might be more susceptible to stress corrosion cracking. Because of this 

review, no tubes were identified as potentially having high residual stress.

During RFO 11 in 2007, 100 percent of the tubes in steam generators B and D were inspected 

full length with a bobbin coil, except for the U-bend region of tubes in rows 1 and 2. In addition 

to the bobbin coil inspections, a rotating probe equipped with a plus-point coil was used to 

inspect:

• 50 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the hot-leg side in steam generators B and D

• about 44 percent of the overexpansions in the tubesheet from nominally 7.62 cm (3 in.)

above to 43.2 cm (17 in.) below the top of the tubesheet on the hot-leg side in steam 

generator B and 74 percent of the overexpansions in this region in steam generator D

• the U-bend region of 100 percent of the tubes in rows 1 and 2 in steam generators B and 

D

• 100 percent of the dents and dings with bobbin voltage amplitudes greater than or equal 

to 3 volts on the hot-leg side of steam generators B and D

• all previously reported dents and dings (of any size) that exhibit a change in bobbin 

voltage amplitude greater than or equal to 0.5 volts or a change in phase angle greater 

than or equal to 10 degrees from the data obtained during the previous two inspections 

on the hot-leg side of steam generators B and D. 
3-72

No eddy current inspections were performed in steam generators A and C during RFO 11.

As a result of these inspections, four tubes were plugged—two for wear at the AVBs and two for

wear attributed to loose parts. 

The only steam generator tube degradation mechanisms observed during RFO 11 were wear at 

the AVBs and wear attributed to loose parts.

In steam generator B, 94 indications of AVB wear were detected in 43 tubes during RFO 11. In 

steam generator D, 131 indications of AVB wear were detected in 70 tubes during RFO 11. The 

maximum depth reported for the AVB wear indications was 38 percent throughwall.

Seven volumetric indications were detected in five tubes during RFO 11. These indications are 

primarily wear attributed to foreign objects. The largest of these indications had a depth of 

47 percent throughwall.

During RFO 11, there were 622 dents and dings in steam generator B with bobbin voltage 

amplitudes greater than or equal to 2 volts. Similarly, in steam generator D, there were 540 

dents and dings with bobbin voltage amplitudes greater than or equal to 2 volts. Of these, 360 

dents and dings in steam generator B had bobbin voltage amplitudes greater than or equal to 3 

volts. Similarly, 336 dents and dings in steam generator D had bobbin voltage amplitudes 

greater than or equal to 3 volts.

Inspection and maintenance on the secondary side of the steam generators also were 

performed during RFO 11. Sludge lancing and FOSAR was performed in each of the four 

steam generators. There were no known loose parts remaining in either steam generators B or 

D (although 5 loose parts (e.g., metal shaving, metal turnings, and broken drill bit) were 

detected).

In steam generator A, the top of tubesheet visual inspection revealed no loose sludge in the 

annulus, about 0.03 mm (one-thirty-second inch) of light sludge under the blowdown pipe, no 

erosion was evident in the blowdown pipe flow holes, and no loose parts were identified. In 

steam generator C, the top of tubesheet visual inspection revealed a few flakes of deposits 

around the annulus, no loose sludge on the top of tubesheet or in the no-tube lane, no erosion 

was evident in the blowdown pipe flow holes, and one previously identified loose part near the 

cold-leg portion of the tube in row 1, column 4, was still present with no indicated movement 

since the previous inspection.

An upper bundle flush was performed in steam generators A and C during RFO 11. To assess 

the condition of the U-bend region and the upper internal region of the steam generators, visual 

and ultrasonic inspections were performed. The results of the inspections in steam generator A 

were:

• The top of the seventh support plate exhibited a light deposit, which appeared to have 

settled out from the water.

• The broached holes were very clear compared to RFO 10.

• All AVBs, wedges, and support blocks appeared satisfactory.
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• A light, easily disturbed, uniform coating of deposits on the steam drum was evident.

• No major blockage in the perforated holes of the secondary separators was evident and 

the chevrons appeared straight with a light deposit.

• The primary separator swirl vanes exhibited no sign of erosion on the leading edge of 

the vanes during visual inspection.

• All deck welds and supports were satisfactory.

• All feedring supports and associated welds were satisfactory.

• No degradation was observed in any of the 30 J-tubes except for the previously 

observed flow accelerated corrosion on J-tubes 1, 15, 16, and 30 (which were repaired 

during RFO 11).

• Ultrasonic thickness readings on the feedring 35.6-cm (14-in.) tee and 35.6-cm (14-in.)

to 25.4-cm (10-in.) reducers revealed below nominal wall thickness at the toe of the 

25.4-cm (10-in.) reducer to feedring piping weld (however, the components were all 

found to be structurally acceptable).

The results of the upper bundle inspections in steam generator C were: 

• The broached holes of the seventh tube support plate that face the annulus were mostly 

clear with little or no evidence of fouling or blockage.

• Most of the broached holes facing away from the annulus (i.e., in-bundle) exhibited 

some form of fouling (an estimated 80 percent to 90 percent of the broached hole 

openings on the seventh tube support plate exhibited partial fouling during RFO 10).

• All AVBs, wedges, and support blocks inspected at the seventh tube support plate 

elevation appeared satisfactory.

• There was no erosion evident on the primary separator swirl vane edges. 

Inspections were performed both pre- and post-sludge lancing and upper bundle flush activities 

during RFO 11 to evaluate the effect of not cleaning during RFO 10. These inspections 

indicated less blocking of the quatrefoil holes after the RFO 11 upper bundle flush.

On May 31, 2007, Millstone 3 revised the steam generator portion of their technical 

specifications making them performance-based consistent with TSTF-449 (ADAMS Accession 

No. ML071380257).

On September 30, 2008, the steam generator portion of the Millstone 3 technical specifications 

was revised to permit certain-sized flaws near the tube end in both the hot- and cold-leg sides of 

the steam generator to remain in service. Specifically, the technical specifications were revised 

to (1) permit flaws having a circumferential component less than or equal to 203 degrees found 

in the portion of the tube below 43.2 cm (17 in.) from the top of the tubesheet and above 

2.54 cm (1 in.) from the bottom of the tubesheet to remain in service, (2) require the removal 

from service all flaws having a circumferential component greater than 203 degrees found in the 
3-74

portion of the tube below 43.2 cm (17 in.) from the top of the tubesheet and above 2.54 (1 in.)

from the bottom of the tubesheet, (3) require the removal from service all tubes with serviceinduced flaws between the top of the tubesheet and 43.2 cm (17 in.) below the top of the 

tubesheet, and (4) permit all axial indications found in the portion of the tube below 43.2 cm 

(17 in.) from the top of the tubesheet to remain in service. In addition, the technical 

specifications were modified to indicate that when more than one flaw with circumferential 

components is found in the portion of the tube below 43.2 cm (17 in.) from the top of the 

tubesheet and above 2.54 cm (1 in.) from the bottom of the tubesheet with the total of the 

circumferential components being greater than 203 degrees and the axial separation distance of 

less than 2.54 cm (1 in.), then the tube must be removed from service (overlapping portions of 

the flaws only need to be counted once in determining the total circumferential involvement of 

the flaws). For flaws within 2.54 cm (1 in.) of the bottom of the tubesheet, the technical 

specifications were modified to indicate (1) when one or more flaws with circumferential 

components are found and the total of the circumferential components exceeds 94 degrees, 

then the tube shall be removed from service and (2) when one or more flaws with 

circumferential components are found in the portion of the tube within 2.54 cm (1 in.) from the 

bottom of the tubesheet and within 2.54 cm (1 in.) axial separation distance of a flaw above 

2.54 cm (1 in.) from the bottom of the tubesheet, and the total of the circumferential components 

found in the tube exceeds 94 degrees, then the tube shall be removed from service (overlapping 

portions of the flaws only need to be counted once in determining the total circumferential 

involvement of the flaws). This revision to the technical specifications was applicable only to 

RFO 12 and the subsequent operating cycle (ADAMS Accession Nos. ML082321292 and 

ML082810147).

During cycle 12 (spring 2007 to fall 2008), there was minimal primary-to-secondary leakage 

(less than 0.1 gpd).

During RFO 12 in 2008, 100 percent of the tubes in steam generators A and C were inspected 

full length with a bobbin coil, except for the U-bend region of tubes in rows 1 and 2. In addition 

to the bobbin coil inspections, a rotating probe equipped with a plus-point coil was used to 

inspect:

• 40 percent of the tubes from 7.62 cm (3 in.) above the tubesheet to the tube end on the 

hot-leg side in steam generators A and C (an additional 10 percent of the tubes were 

inspected from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the tubesheet on 

the hot-leg side)

• 12.5 percent of the tubes (peripheral tubes) from 7.6 cm (3 in.) above to 7.6 cm (3 in.)

below the top of the tubesheet on the cold-leg side in steam generators A and C, all 

overexpansions and bulges not inspected during the last inspection of these steam 

generators

• the U bend region of 100 percent of the tubes of rows 1 and 2 in steam generators A and 

C

• 100 percent of the dents and dings with bobbin voltage amplitudes greater than or equal 

to 2 volts on the hot-leg side of steam generators A and C

No eddy current inspections were planned for steam generators B and D during RFO 12; 

however, because of finding crack-like indications near the tube ends, 100 percent of the hot-leg 

tube ends were inspected in all four steam generators, 20 percent of the cold-leg tube ends 
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were inspected in steam generators A, B, and C, and 100 percent of the cold-leg tube ends 

were inspected in steam generator D. In addition, all tube plugs were inspected visually. No 

degradation of the tube plugs was identified.

As a result of these inspections, 26 tubes were plugged—1 for wear at the AVBs, 2 for wear 

attributed to loose parts, and 23 for tube end indications.

The only steam generator tube degradation mechanisms observed during RFO 12 were 

(1) wear at the AVBs, (2) wear attributed to loose parts, (3) wear attributed to fabrication, 

(4) wear attributed to maintenance (sludge lance sled), and (5) axially and circumferentially 

oriented primary water stress corrosion cracking at the tube ends.

A total of 262 AVB wear indications were identified in steam generator A during RFO 12. Of 

these, 14 indications were new (i.e., not previously reported). The average growth rate of the 

previously identified AVB wear indications is approximately 0.18 percent throughwall per 

effective full power year. Sixty-four 64 AVB wear indications were identified in steam generator 

C during RFO 12. Of these, five indications were new. The average growth rate of the 

previously identified AVB wear indications is low (actually it was negative because of nondestructive examination uncertainty associated with the depth measurements). The maximum 

depth reported for the AVB wear indications was 38 percent throughwall.

Twenty-four indications of wear attributed to loose parts were identified during RFO 12. These 

24 indications were in 22 tubes. All but two of these indications were present in prior 

inspections and have not changed in size. The two tubes plugged for wear attributed to loose 

parts had maximum depths of 41 percent and 42 percent throughwall. The indications had not 

changed in size since the prior inspection; however, the application of a new sizing technique 

resulted in the indications being sized with depths greater than the tube repair (plugging) 

criteria.

Two indications of wear attributed to fabrication were detected. These two indications were in 

two tubes.

Eighteen indications of wear attributed to maintenance equipment (sludge lance sled) were 

identified. These 18 indications were in 14 tubes. The maximum depth reported for these 

indications was 21 percent throughwall.

Indications were found near the tube ends on the hot-leg in all four steam generators and on the 

cold-leg in steam generator D. Axial, circumferential, and mixed-mode indications were 

detected. At the hot-leg tube ends, 101 axial indications were detected in 94 tubes and 54

circumferential indications were detected in 48 tubes. In addition, 4 tubes were identified as 

having mixed mode degradation (i.e., both axial and circumferential indications in the same tube 

end) at the hot-leg tube ends. At the cold-leg tube ends, one circumferential indication was 

detected in one tube. After applying the repair criteria discussed above, 23 tubes were removed 

from service for tube-end indications (this included all four tubes with mixed mode indications 

even though they did not exceed the repair criteria).

FOSAR was performed in the annulus, no-tube lane and the periphery of steam generators A 

and C. In addition, deposit mapping was performed in steam generators A and C during RFO 

12.
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Secondary-side visual inspections were performed in the upper bundle region of steam 

generator B during RFO 12. These inspections focused on the seventh tube support plate, 

AVBs, the U-bend region, primary separators, decks, feedring, J-tubes (including the welds), 

secondary separators (including the perforations), piping, supports, ladders, and wedges. Flow 

accelerated corrosion was observed during prior inspections on J-tubes 1, 15, 16, and 30 in all 

four steam generators. The flow accelerated corrosion was observed on welds of reducers (or 

T’s). Welds are known to have lower chromium content. The affected J-tubes in all four steam 

generators were previously repaired with a weld overlay. The inspections in steam generator B 

during RFO 12 indicated no new signs of flow accelerated corrosion and the overlays were 

intact with no degradation. Some minor surface rust was observed on the upper internals that

are fabricated from carbon steel.

A 7-percent power uprate was implemented at Millstone 3 after RFO 12. Before the power 

uprate, the hot-leg operating temperature was 617 degrees Fahrenheit. After the power uprate, 

the hot-leg temperature was 620 to 622 degrees Fahrenheit.

On May 3, 2010, the steam generator portion of the Millstone 3 technical specifications was 

revised to limit the extent of inspection in the tubesheet region. Specifically, the technical 

specifications were revised to exclude the portion of tube that is more than 33.27 cm (13.1 in.)

below the top of the tubesheet from inspection (i.e., approximately the lowermost 20.32 cm 

(8 in.) of tube in the tubesheet was excluded from inspection, and hence any flaws that may 

exist in this region are permitted to remain in service). This revision was applicable only to RFO 

13 and the subsequent operating cycle (ADAMS Accession No. ML100770358).

The maximum primary-to-secondary leakage during the cycle before RFO 13 (fall 2008 to spring 

2010) was 0.83 lpd (0.22 gpd).

During RFO 13 in 2010, 100 percent of the tubes in steam generators B and D were inspected 

full length with a bobbin coil, except for the U-bend region of the tubes in rows 1 and 2. In 

addition to the bobbin coil inspections, a rotating probe equipped with a plus-point coil was used 

to inspect the following in steam generators B and D:

• 50 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the hot-leg side 

• 13 percent of the tubes (peripheral tubes) from 7.6 cm (3 in.) above to 7.6 cm (3 in.)

below the top of the tubesheet on the cold-leg side 

• 40 tubes with overexpansions from 7.62 cm (3 in.) above to 38.1 cm (15 in.) below the 

top of the tubesheet on the hot-leg side in steam generator B 

• 70 tubes with overexpansions from 7.62 cm (3 in.) above to 38.1 cm (15 in.) below the 

top of the tubesheet on the hot-leg side in steam generator D 

• the U-bend region of 100 percent of the row 1 and row 2 tubes 

• various other locations including dents and dings 

No eddy current inspections of the tubes were performed in steam generators A and C. In 

addition, all tube plugs in steam generators B and D were inspected visually. No degradation of 
3-77

the tube plugs was identified (although there was a light boric acid coating on some of the 

plugs) and all plugs were in their proper location.

As a result of these inspections, seven tubes were plugged one for wear at the AVBs, one for

inside diameter chatter (eddy current noise), and five for wear attributed to a loose part.

The only steam generator tube degradation mechanisms observed during RFO 13 were 

(1) wear at the AVBs, (2) wear at the tube support plates, (3) wear attributed to loose parts, and 

(4) wear attributed to fabrication.

A total of 102 AVB wear indications were identified in 49 tubes in steam generator B during RFO 

13. Of these, eight indications were new (i.e., not previously reported). Approximately 133 AVB 

wear indications were identified in 72 tubes in steam generator D during RFO 13. Of these, 14 

indications were new. The maximum depth reported for the AVB wear indications was 

37 percent throughwall.

Two indications of wear at the tube support plates were identified during RFO 13. Although this 

is the first reported instance of wear at the tube support plates at Millstone 3, one of the two 

indications was determined to exist since at least the RFO 7 (2001) inspection. The maximum 

depth reported for the tube support plate wear indications was 22 percent throughwall.

Of the five tubes plugged for wear attributed to loose parts, three were plugged because the 

location was not accessible for visual inspection to confirm a part was no longer present (there 

was no evidence of a loose part from the eddy current inspection of the tubes), one was 

plugged because the depth exceeded the plugging limit (52 percent throughwall), and one was 

plugged because the depth exceeded the plugging limit when sized using a new technique (it 

had previously been sized as having a depth less than the plugging limit). In addition to these 

tubes, six other tubes (in three locations) had wear attributed to loose parts. In these instances, 

either a visual inspection confirmed the absence of a loose part or the part was removed.

One tube was identified as having wear attributed to fabrication.

Several foreign objects were identified during FOSAR activities. Two machine curls and a piece 

of Flexitallic gasket were left in the steam generators along with a historic loose part that is fixed 

in the steam generators.

Secondary-side visual inspections were performed in all four steam generators during RFO 13. 

Visual inspections of the top of tubesheet area and an upper bundle flush were performed in 

each steam generator. These inspections indicated that the top of tubesheet annulus and 

divider lane were clean and the blowdown pipe and center tie rod were in good condition. In 

addition to these inspections, the upper bundle region of steam generator C was inspected 

visually during RFO 13 to offer a more detailed assessment of support fouling and flow 

accelerated corrosion. These inspections focused on the area above the seventh tube support 

plate. The secondary moisture separator chevrons were in good condition. The perforated 

holes of the outer plate showed minor buildup of sludge in the bore of the holes. The chevrons 

were straight and had a light coating of sludge deposits. The primary moisture separator swirl 

vanes were in good condition. The vanes had a slight deposit on them but the edges were 

sharp showing no indication of erosion. There was a heavy deposit of sludge on the steam 

drum shell wall of the upper deck. This deposit became thicker higher up on the shell. Ladders, 

drains, wedges, supports, and associated welds were considered acceptable. The 30 J-nozzles 

on the main feedwater pipe were internally and externally inspected. They were in good 
3-78

condition. J-nozzles 1, 15, 16, and 30 had a weld overlay applied during a previous outage and 

internal inspections indicated that the erosion/corrosion damage of these four nozzles had not 

advanced since the last inspection. Some of the primary separator riser barrels showed some 

minor erosion from overspray of the J-nozzles. The erosion/roughness is very minor and will be 

monitored during future outages. Video inspection of the upper tube bundle seventh tube 

support plate indicated that there bridging of sludge deposits between the tubes and AVBs. The 

broached holes in the seventh tube support plate showed a slight ridge of sludge at the bottom 

of the tube support plate. None of the broached holes viewed were found to be fully blocked. 

The AVB deposits appeared to be similar to the deposits on the top of the tubesheet: thick, but 

not easily disturbed.

On October 7, 2011, the steam generator portion of the Millstone 3 technical specifications was 

revised to limit the extent of inspection in the tubesheet region. Specifically, the technical 

specifications were revised to exclude the portion of tube that is more than 38.6 cm (15.2 in.)

below the top of the tubesheet from inspection (i.e., approximately the lowermost 15.24 cm 

(6 in.) of tube in the tubesheet was excluded from inspection, and hence any flaws that may 

exist in this region are permitted to remain in service). This revision was applicable only to RFO 

14 and the subsequent operating cycle (ADAMS Accession No. ML112580517).

There was no evidence of primary-to-secondary leakage during Cycle 14 (spring 2010 to fall 

2011).

During RFO 14 in 2011, 100 percent of the tubes in steam generators A and C were inspected 

full length with a bobbin coil, except for the U-bend region of the tubes in rows 1 and 2. In 

addition to the bobbin coil inspections, an array probe was used to inspect:

• about 50 percent of the tubes at the top of the tubesheet on the hot-leg side, which 

included:

– about 40 percent of the tubes from 7.62 cm (3 in.) below the top of the tubesheet 

to the first hot-leg tube support

– about 10 percent of the tubes from 38.6 cm (15.2 in.) below the top of the 

tubesheet to the first hot-leg tube support

• about 13 percent of the tubes at the top of the tubesheet on the cold-leg side, which 

included: 

– about 10 percent of the tubes from 7.62 cm (3 in.) below the top of the tubesheet 

to the first cold-leg tube support 

– about 3 percent of the tubes from 38.6 cm (15.2 in.) below the top of the 

tubesheet to the first hot-leg tube support 

In addition to the bobbin coil and array probe exams, a rotating probe equipped with a plus-point 

coil was used to inspect the U-bend region of 100 percent of the tubes of rows 1 and 2, and 

various other locations including dents and dings. No eddy current inspections of the tubes 

were performed in steam generators B and D. In addition, all tube plugs in steam generators A

and C were inspected visually. No degradation of the tube plugs was identified (although a light 

boric acid coating was noted on some of the plugs) and all plugs were in their proper location.
3-79

Steam generator A has 67 tubes that have been identified as high stress tubes from the eddy 

current data. Steam generator C has 39 such tubes. All of these tubes were inspected full 

length with a bobbin coil. All of these tubes were inspected with an array probe from the hot-leg 

tube end to the first tube support on the hot-leg side of the steam generator. In addition, a 

rotating probe was used to inspect 28 locations (dents, dings, manufacturing burnish marks, 

volumetric wear, or ambiguous signals from other probes) in 21 of these tubes.

As a result of these inspections, 11 tubes were plugged—3 tubes for wear at the AVBs, 7

because the bottom of their expansion transitions was greater than 2.54 cm (1 in.) below the top 

of the tubesheet, and 1 for wear attributed to a loose part.

The only steam generator tube degradation mechanisms observed during RFO 14 were 

(1) wear at the AVBs, (2) wear at the tube support plates, (3) wear attributed to loose parts, and 

(4) wear attributed to fabrication.

About 300 AVB wear indications were identified in 153 tubes in steam generator A during RFO 

14. Of these, 50 indications were new (i.e., not previously reported). Sixty-eight AVB wear 

indications were identified in 32 tubes in steam generator C during RFO 14. Of these, four

indications were new. The maximum depth reported for the AVB wear indications was 

38 percent throughwall. Two of the indications of AVB wear (in one tube) in steam generator A 

were at the apex of the tube. This row of tubes (row 5) is not supported by an AVB. The 

indications were attributed to wear caused by the bottom of the AVB supporting the tubes in the 

row above it. This latter tube was plugged.

Two indications of tube support plate wear (in two tubes) were identified during RFO 14. The 

maximum depth reported for the tube support plate wear indications was 11 percent

throughwall. 

Several volumetric indications attributed to wear from foreign objects and fabrication were 

identified during RFO 14. Most of the other volumetric indications have been present since 

previous inspections.

Secondary-side maintenance and visual inspections were performed in all four steam 

generators during RFO 14. High-pressure sludge lancing and an upper bundle flush were

performed in each steam generator. After sludge lancing, visual inspections of the top of 

tubesheet annulus and no-tube lane were performed to assess the as-left condition, cleanliness, 

and to identify and remove any retrievable foreign objects. Locations where the eddy current 

inspections showed the presence of a possible loose part also were inspected visually if the 

location was accessible. The upper bundle flush and sludge lancing removed loose deposits 

throughout the tube bundle and at the top of the tubesheet. The top of tubesheet in all four 

steam generators was mostly clean with minor flake piles remaining in the peripheral regions. 

The remaining sludge flakes were mainly at the 90-degree handholes in the stay rod lance 

shadow zones near the suction feet and totaled less than a cup each. In-bundle views from the 

periphery showed the tubesheet was very clean in all four steam generators. The no-tube lane 

was clean and the center stay rod and blowdown piping were in good condition.

In addition, in steam generator D, the steam drum was inspected visually to evaluate the 

material condition and cleanliness of key components such as moisture separators, drain 

systems, and interior surfaces. In addition, visual inspections also took place of the upper tube 

bundle and AVB supports, feedring internal interface (for evidence of flow accelerated 

corrosion), and the upper tube support plate (to assesses material condition and cleanliness) in 
3-80

steam generator D. These inspections indicated that the secondary moisture separator 

chevrons were in good condition, the perforated holes of the outer plate had minor buildup of 

sludge in the bore of the hole, and no holes were plugged. The chevrons were straight and had 

a light coating of sludge deposits. The primary moisture separator swirl vanes were in good 

condition. The vanes had a slight deposit on them but the edges were sharp showing no 

indication of erosion. There was a heavy deposit of sludge on the steam drum shell wall of the 

upper deck. This deposit became thicker higher up on the shell. Ladders, drains, wedges, 

supports, and associated welds were considered acceptable. The 30 J-nozzles on the main 

feedwater pipe were inspected internally and externally. They were in good condition. Jnozzles 1, 15, 16, and 30 had a weld overlay applied during a previous outage and internal 

inspections showed that the erosion/corrosion damage of these four nozzles had not advanced 

since the last inspection in RFO 9 (2004). Evidence of overspray from some of the J-nozzles 

was present on the primary separator riser barrels. The upper bundle inspections were 

performed after the upper bundle flush. Visual inspections of the steam drum and upper tube 

bundle above the seventh tube support plate showed the steam generator was structurally in 

good condition. Most of the loose deposits in the upper tube bundle region had been removed 

by the upper bundle flush operation. The broached holes at the periphery revealed only a slight 

ridge of sludge buildup at the bottom side of the seventh tube support plate.

On December 6, 2012, the steam generator portion of the Millstone 3 technical specifications 

was revised to limit the extent of inspection in the tubesheet region. Specifically, the technical 

specifications were revised to exclude the portion of tube that is more than 38.6 cm (15.2 in.)

below the top of the tubesheet from inspection (i.e., approximately the lowermost 15.24 cm 

(6 in.) of tube in the tubesheet was excluded from inspection, and hence any flaws that may 

exist in this region are permitted to remain in service (ADAMS Accession No. ML12299A498)).

On January 11, 2013, the steam generator portion of the Millstone 3 technical specifications 

was revised making them consistent with TSTF-510 (ADAMS Accession No. ML12333A255).

There was no evidence of primary-to-secondary leakage during Cycle 15 (fall 2011 to spring 

2013).

During RFO 15 in 2013, 100 percent of the tubes in steam generators B and D were inspected 

full length with a bobbin coil, except for the U-bend region of the tubes in rows 1 and 2. In 

addition to the bobbin coil inspections, an array probe was used to inspect 100 percent of the 

tubes from 38.6 cm (15.2 in.) below the top of the tubesheet on the hot-leg side to the first hotleg tube support, and about 13 percent of the tubes from 38.6 cm (15.2 in.) below the top of the 

tubesheet on the cold-leg side to the first cold-leg tube support. In addition to the bobbin coil 

and array probe exams, a rotating probe equipped with a plus-point coil was used to inspect the 

U-bend region of 100 percent of the tubes in rows 1 and 2, and various other locations including 

dents and dings. In addition, all tube plugs in steam generators B and D were inspected 

visually. No degradation of the tube plugs was identified and all plugs were in their proper 

location. No eddy current inspections of the tubes were performed in steam generators A and 

C. 

As a result of these inspections, 10 tubes were plugged—9 for wear at the tube support plates 

and 1 for a restriction that has typically required multiple attempts to obtain acceptable eddy 

current data.
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The only steam generator tube degradation mechanisms observed during RFO 15 were 

(1) wear at the AVBs, (2) wear at the tube support plates, (3) wear attributed to loose parts, and 

(4) wear attributed to fabrication.

A total of 106 AVB wear indications were identified in 50 tubes in steam generator B during RFO 

15. Of these, nine indications were new (i.e., not previously reported). A total of 165 AVB wear 

indications were identified in 88 tubes in steam generator D during RFO 15. Of these, 34 

indications were new. The maximum depth reported for the AVB wear indications was 

35 percent throughwall.

Twelve indications of tube support plate wear were detected in 11 tubes in steam generator B 

during RFO 15. Of these indications, nine were new. Seven indications of tube support plate 

wear were detected in seven tubes in steam generator D during RFO 15. Of these indications, 

five indications were new. The maximum depth reported for the tube support plate wear 

indications was 47 percent throughwall.

Two of the new wear indications at the tube support plates exceeded 40 percent of the tube wall 

thickness. These two tubes were plugged as were seven other tubes with new wear indications 

at the tube support plates. These seven other tubes had wear indications with depths greater 

than or equal to 15 percent of the wall thickness. These latter tubes were plugged to address 

uncertainty in the growth rate of these newly developed flaws. Two explanations for the 

increased number of indications were considered: (1) increase in feedwater flow resulting from 

the stretch power uprate that was implemented around RFO 12 and (2) heavy deposit inventory 

on the secondary side of the steam generators. The increase in wear at the tube support plates 

from increased flow was discounted because similar increases in the number of wear 

indications had not been observed in the other steam generators (A and C) when they were 

inspected during RFO 14 and because an increase in the wear rate at the AVBs has not been 

observed since implementing the stretch power uprate. As a result, the RFO 15 inspection 

results could be indicative of changing local flow conditions in the tube bundle. With the 

changing flow conditions, areas of the tube bundle more susceptible to flow-induced vibration 

would be expected to respond in a manner similar to a new steam generator in which depth 

growth tends to be more rapid in locations particularly susceptible to wear such as at broached 

openings with sharp edges or burrs followed by volumetric growth that tends to remain constant 

with time (and consequently the depth growth tends to slow with time).

Several volumetric indications attributed to wear from foreign objects or fabrication were 

identified during RFO 15. All of these volumetric indications have been present since previous 

inspections.

All tubes in steam generators B and D have expansion transitions that are within 2.54 cm (1 in.)

of the top of the secondary face of the tubesheet.

To identify tubes that have potentially high residual stress and therefore might be more 

susceptible to stress corrosion cracking, bobbin coil eddy current data were reviewed. Two 

methods were used to find tubes with potentially elevated residual stresses. These methods 

looked at the offset in the eddy current data between the straight span and the U-bend region of 

the tubing. Both methods rely on whether the offset voltage is more than two standard 

deviations below the regression line/average (in the higher rows, the absence of an offset 

indicates potentially elevated residual stresses in the straight span portion of the tubing). The 

first method assumes a linear relationship between the offset voltage and the row number. This 

method indicates there is a relatively steady decrease in the average offset voltage from row 11 
3-82

through about row 45. After row 45, there appears to be no obvious relationship between 

voltage and row number, (i.e., the average for the offsets in rows 45 and greater is fairly 

constant with no decreasing trend in the higher rows). Because this first method could result in 

biasing the potentially elevated residual stress tubes to those in rows 11 through 45, a second 

method was used that relies on the average and a standard deviation for each row in each 

steam generator. In addition, tubes were characterized based on whether one (tier 2) or both 

(tier 1) legs of the eddy current data exhibited the eddy current offset attributed to potentially 

elevated residual stresses. Applying these criteria to all four steam generators, 159 tubes were 

identified as tier 1 tubes and 1,243 tubes were identified as Tier 2 tubes (i.e., these tubes failed 

one or both of the screening methods).

The hot- and cold-leg steam generator channel head regions in steam generators B and D were 

inspected visually during RFO 15. These inspections included the tubesheet cladding, the tubeto-tubesheet welds, the partition divider plate, stub runner, divider plate-to-tubesheet cladding 

weld, divider plate-to-channel head weld, stub runner-to-divider plate weld, and the stub runnerto-tubesheet weld. The weld examinations are performed to identify gross degradation. No 

degradation was identified. In addition, no discoloration or rust stains were found that would 

indicate a breach of the cladding.

Secondary-side maintenance and visual inspections were performed in steam generators B, C, 

and D during RFO 15. High-pressure sludge lancing and an upper bundle flush were performed 

in these three steam generators. After sludge lancing, the top of tubesheet annulus and no-tube 

lane were inspected visually to assess the as-left condition, cleanliness, and to identify and 

remove any retrievable foreign objects. Visual inspection of locations where the eddy current 

inspections indicated the presence of a possible loose part was also performed if the location 

was accessible. These inspections indicated that the top of tubesheet was mostly clean with 

minor flake piles remaining. 

In addition, in steam generator C, the steam drum was inspected visually to evaluate the 

material condition and cleanliness of key components such as moisture separators, drain 

systems, and interior surfaces. In addition, the upper tube bundle and AVB supports, feedring 

internal interface (for evidence of flow accelerated corrosion), and the upper tube support plate 

(to assesses material condition and cleanliness) was inspected visually in steam generator C 

during RFO 15 after upper bundle flush operations. These inspections showed that the steam 

drum and upper bundle region were in good structural condition with no evidence or erosion or 

corrosion. A light, tightly adhering layer of deposit material was noted on the surfaces inside the 

steam space. Deposit bridging was seen between the tubes and the AVBs, but much of the 

loose deposit material was removed during the upper bundle flush process. Spalled deposits on 

the tubes were seen in the mid-span of the U-bend region (i.e., between the top of the U-bend 

and the top tube support plate). Some blockage of the tube support openings was observed

during both visual examination and with a low frequency eddy current technique referred to as 

“deposit mapping.”

To address the deposit buildup on the secondary side of the steam generators, two corrective 

actions are being put into place: (1) deposit minimization treatment will be applied in 2014 and 

2016 to reduce the deposit loading and clear the tube support plate blockage; and (2) injection 

of polyacrylic acid to reduce corrosion product accumulation in the steam generators. 

Polyacrylic acid is a high molecular weight polymer designed to “wrap up” incoming iron from 

the feed train and allow that iron to be passed through to the steam generator blowdown line 

before depositing in the steam generators.
3-83

The deposit minimization treatment is a “soft” cleaning process, developed by AREVA, designed 

to reduce the amount of deposit material on the secondary side of the steam generator. It uses 

a low concentration of oxalic acid that acts as a complexing agent in the dissolution of iron oxide 

deposits. A final passivation step employs lower concentrations of oxalic acid and hydrogen 

peroxide. The process results in very low corrosion rates for internal steam generator 

subcomponents. 

3.3.3 Seabrook

Tables 3-19, 3-20, and 3-21 summarize the information discussed below for Seabrook. Table 

3-19 provides the number of full-length bobbin inspections and the number of tubes plugged 

and deplugged during each outage for each of the four steam generators. Table 3-20 lists the 

reasons why the tubes were plugged. Table 3-21 lists tubes plugged for reasons other than 

wear at the AVBs.

Seabrook has four Westinghouse model F steam generators. The licensee numbers its tube 

supports using the alternate naming convention in Figure 2-4.

The quatrefoil openings in the tube support plate were inspected in RFO 7 using the upper 

bundle in bundle (UBIB) tool. Those inspections showed insignificant blockage in the tube 

support plate quatrefoil area.

During RFO 8 in 2002, 100 percent of the tubes in each of the four steam generators were 

inspected full length with a bobbin coil, except for the U-bend region of the tubes in rows 1 and 

2. In addition to the bobbin coil inspections, a rotating probe equipped with a plus-point coil was 

used to inspect:

• 50 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the hot-leg side in steam generators A and D (the actual extent above the 

top of the tubesheet may have been greater than 7.6 cm (3 in.) to ensure the entire 

portion of the tube within the sludge pile was inspected)

• the U-bend region of 50 percent of the row 1 and row 2 tubes in steam generators A and 

D 

• 40 percent of the hot-leg dents and dings with bobbin voltage amplitudes greater than 5 

volts that were in the straight section of the tubing in steam generators A and D

In addition to the eddy current inspections, all tube plugs in each of the four steam generators

were inspected visually.

As a result of these inspections, 35 tubes were plugged—11 for wear at the AVBs, 9 for loose 

parts, and 15 for axially oriented outside-diameter stress corrosion cracking. Of the nine tubes 

plugged because of loose parts, two tubes exhibited wear, one tube exhibited a possible loose 

part signal with no associated wear, and six tubes were plugged because the possible loose 

part indication in a nearby tube could not be removed from the steam generator.

The only steam generator tube degradation mechanisms observed during RFO 8 were (1) wear 

at the AVBs, (2) wear attributed to loose parts, (3) wear attributed to maintenance equipment,

and (4) axially oriented outside-diameter stress corrosion cracking at the tube support plates.
3-84

About 1,200 AVB wear indications were detected in the four steam generators: 303 indications 

in steam generator A, 175 in steam generator B, 223 in steam generator C, and 530 in steam 

generator D. Of these indications, 57 in steam generator A were new, 40 in steam generator B 

were new, 36 in steam generator C were new, and 117 in steam generator D were new. The 

maximum depth reported for the new indications was 23 percent throughwall.

Eight of the nine tubes plugged because of loose parts were in the same general area in steam 

generator A. One of these eight tubes had exhibited wear slightly above 05H (and the 

plus-point coil also indicated the presence of a possible loose part at this location), one had a 

possible loose part indication and no wear, and the remaining six had no possible loose part or 

wear indications at this location. This area (05H) was not accessible for visual examination so 

these latter six tubes were plugged (but not stabilized) to provide a buffer area between the 

tubes affected by the possible loose part and other active tubes. The licensee indicated that the 

size of this foreign object is small because no possible loose part indications were reported in 

any of the surrounding tubes except for one. The licensee concluded that small foreign objects 

do not have significant potential to cause tube severance because they do not have sufficient 

mass or size to affect the entire cross section of any given tube.

Five indications of wear were identified in five tubes. This wear was attributed to interaction 

between the tube and the sludge lance equipment. The maximum depth reported for these 

indications was 37 percent throughwall. Two indications of wear near the flow distribution baffle 

were detected in the four steam generators (one in A and one in D). These indications are 

attributed to equipment used for pressure pulse cleaning (PPC) the steam generators.

During RFO 8, 42 indications of potential axially oriented outside-diameter stress corrosion 

cracks were detected in 15 low-row tubes (i.e., tubes in rows 1 through 10 that are the tubes 

that had the U-bend stress relieved after the bending of the tube). All indications were in steam 

generator D and all indications were in the region where the tube passes through a tube support 

plate (i.e., tube-to-tube support plate intersection). No cracking was observed at the top of the 

tubesheet expansion transition region. Indications were reported on both the hot- and cold-leg 

side of the steam generator. In all cases where a cold-leg indication was reported, a hot-leg 

indication was also reported on the same tube. All indications were confined to tubes in rows 4 

through 9. Multiple tube support plate intersections on the same tube were affected in most 

cases. The indications on only 3 of the 15 tubes were confined to a single tube support plate 

intersection. Several intersections were reported to contain multiple indications (i.e., an 

indication at more than one land at the same tube support plate elevation). The indications 

were reported from tube support 02H through 06H on the hot-leg and from 03C and 05C on the 

cold-leg. All of the 42 cracked tube support plate intersections detected during RFO 8 were 

inspected during RFO 6. A re-review of the RFO 6 eddy current data showed that there was a 

detectable (but non-callable) signal in 25 of the 42 locations. The remaining 17 intersections 

exhibited no signal indicative of cracking in RFO 6.

Ultrasonic testing was performed using the ultrasonic test eddy current (UTEC) system to offer 

greater insight into the axial outside-diameter cracking indications confirmed by the plus-point 

probe. Of the 42 indications confirmed by the plus-point probe as outside-diameter cracking, 19 

were tested with UTEC. In addition, one indication (at row 2, column 48 at the top of the 

tubesheet on the hot-leg side) initially recorded as a single volumetric indication after plus-point 

testing, was examined with the UTEC probe. This indication was determined to be a geometric 

indication with no evidence of degradation. Selection of the indications to be tested by UTEC 

was based on the relative ranking of the plus-point voltages, the number of locations that could 

be practically tested, and the objective to obtain a significant sample of the single and multiple 
3-85

axial indications based on the plus-point tests. The UTEC system confirmed the presence of 

axial indications at the tube support plate elevations initiating from the outside surface of the 

tube.

Because outside-diameter cracking was a potentially new degradation mechanism in steam 

generators with thermally treated Alloy 600 tubing, two tubes were removed from steam 

generator D for destructive examination. The tubes removed included the hot-leg side of row 5, 

column 62; and the cold-leg side of row 9, column 63. In general, the tubes selected included 

some of the largest indications based on both bobbin and plus-point voltages, offered a 

significant number of potentially degraded intersections, and supplied broad coverage across 

the region of occurrence (i.e., hot-leg and cold-leg sections). The pulled tubes included the 

indication with the largest measured depth and the indication with the largest voltage amplitude.

After removal of the tube-to-tubesheet weld and relaxation of the hydraulic expansion region, 

the tubes were pulled through the tubesheet. The tube in row 5, column 62, was cut below the 

sixth tube support plate. The pull force was 3,536 lbs. and dropped to essentially zero after 

initial breakaway. The tube in row 9, column 63, was cut below the fifth tube support plate. The 

pull force was 3,373 lbs. and dropped to essentially zero after initial breakaway.

The licensee completed its root cause evaluation, including destructive examination of two 

pulled tubes, confirming that the indications were axially oriented stress corrosion cracks that 

initiated from the tube’s outside diameter. No transgranular cracks were observed. Additional

details concerning the destructive evaluation of the pulled tubes are provided below.

Several portions of both of the pulled tubes were pressure tested. The largest indication (row 5 

column 62, at 04H) was tested to 48,260 kPa (7,000 psi) without signs of leakage. This tube 

was not pressurized to burst to save the indication for fractographic examination. A minor 

indication at 02H in row 5 column 62 exhibited a burst pressure of 79,290 kPa (11,500 psi). 

Several other flawed and non-flawed sections were burst tested. These specimens had burst 

pressures of about 89,630 kPa (13,000 psi) and there was no leakage observed during these 

tests. No foil or bladder were used in these burst tests.

Post burst testing visual inspections indicated that row 5, column 62, had cracks at 02H, 03H, 

and 04H. Indications were called in the field at 03H, 04H, and 05H. The indication missed in 

the field at 02H was approximately 3.5 mm (0.14 in.) long and had a maximum depth of 

36 percent throughwall and a percent degraded area of 20 percent. The false call at 05H was 

about 0.2 volts as determined from the bobbin coil (and 0.3 volts from the plus-point coil). The 

largest crack in tube row 5, column 62, was about 1.9 cm (0.75 in.) long and had a maximum 

depth of 99.5 percent throughwall and a percent degraded area of 63 percent. This indication 

did not leak at 48,260 kPa (7,000 psi).

Similarly post burst testing visual inspections indicated that row 9, column 63, had cracks at 03C 

and 04C. Indications were called in the field at 04C. The indication missed in the field was 

about 6.6 mm (0.26 in.) long and had a maximum depth of 52 percent throughwall and a percent 

degraded area of 34 percent.

The burst openings of the specimens comprised numerous axially oriented intergranular cracks 

that were confined to the width of the quatrefoil land and had a maximum length of about 1.9 cm 

(0.75 in.). The maximum depths of the specimens ranged from 34 percent to 99 percent, the 

average depths ranged from 20 percent to 50 percent, and the lengths ranged from 5 mm (0.2

in.) to 19 mm (0.75 in.). Shallow intergranular attack approximately 1 to 2 grains deep was 
3-86

observed all around the circumference of the tube in the quatrefoil land areas. The flaws 

initiated from the tube’s outside surface. No transgranular cracks were observed.

Thin deposits were noticed on the tube samples in the crevice that exists between the tube and 

the tube support plate land. No heavy crust was observed in any of the samples examined. 

Chemical analysis of the deposits indicated that there were no detrimental species such as 

chlorides or sulfates in the specimens or in the crack tips. An independent laboratory detected 

a trace amount of copper and lead; however, the amount detected was within the margin of 

error and was so minute that it was not detectable in the tests performed by the original 

laboratory. The levels of copper and lead observed were not unusually high and are consistent 

with that found in other tubes removed for in-service steam generators.

Chemical analysis of the pulled tube specimens showed that the material contains a carbon 

content of 0.047 percent C, which the licensee believes is higher than the average carbon 

content typically found in thermally treated Alloy 600 tubes currently in service at Seabrook 

(~0.03 percent carbon).

The metallurgical analysis showed that the overall microstructure in the pulled tube specimens 

was not “ideal” when compared to typical thermally treated Alloy 600 material. Specific findings 

from the metallurgical analysis were as follows:

• Mechanical tests showed the pulled tube material has a yield strength of 70 kilopounds 

per square inch (ksi), as compared to 60 ksi reported for this material in the certified 

material test report.

• Metallography showed that the pulled tube material contains average grain sizes of 

ASTM Size 10 to 11, which is smaller than typical thermally treated Alloy 600 material. It 

also contains duplex grains—two different sizes of grains instead of a uniform size. A 

significant amount of banding (a segregated structure consisting of alternating nearly 

parallel bands of different composition) was observed in the pulled tube material, which 

is unusual for thermally treated Alloy 600 material.

• The microstructure in the pulled tube material contains a significant amount of 

intragranular carbides and very few intergranular carbides. Thermally treated Alloy 600 

material typically contains more intergranular carbides and very few intragranular 

carbides.

This structure (fine equiaxed grains with significant variation in grain size and nonuniform “banded” grain distribution and extensive intragranular carbides) is considered 

not to be optimum but within the bounds of “normal” for thermally treated tubing.

• The licensee modified a standard ASTM test, ASTM A262 Practice C, “Nitric Acid Test 

for Detecting Susceptibility to Intergranular Attack in Austenitic Stainless Steels,” to 

determine the pulled tube susceptibility to stress corrosion cracking. The test results 

suggested that the pulled tube material was not sensitized.

The tensile strength of the pulled tube specimens was also determined. The tensile strength of 

the tubes was higher than the certified material test report values and also was higher than the 

typical values for similar tubing. The yield strength for the pulled tube specimens was about

70 ksi and the ultimate strength was about 120 ksi.
3-87

Although the microstructure of the pulled tubes was not ideal, it is consistent with the expected 

range of microstructures for this material.

Residual stress measurements of the pulled tubes indicated that the average tensile hoop 

residual stresses in regions close to the cracks were about 22 ksi. This is larger than expected 

for any final tubing condition especially thermally treated tubing. The licensee indicated that 

because of the typically nonlinear through wall stress distribution, actual surface residual 

stresses near the material yield strength (65 ksi) were probably present during operation. 

Typical thermally treated Alloy 600 tubing has hoop residual stresses of about 3 ksi. Testing of 

archival thermally treated tube material obtained from the same heats as those affected by the 

cracking had more prototypical residual stresses of 1 to 2 ksi. For mill annealed Alloy 600 

tubing, typical residual stress levels are 10 ksi.

The licensee indicated that the threshold of stress required to initiate cracks in thermally treated 

tubing is at least 40 ksi. The threshold for crack propagation is not well defined because of

limited industry experience. The licensee postulated that the source of the high residual stress 

is either an abnormal thermal treatment that was not effective in removing the residual stresses 

or a process such as tube straightening that occurred after the thermal treatment. The precise 

processing steps responsible for the adverse stress state could not be conclusively determined 

from a review of the tube processing records.

Evidence of abnormal secondary water chemistry was not found and chemistry is not believed 

to have been a significant factor in the early onset of stress corrosion cracking at Seabrook. 

Seabrook has maintained secondary chemistry in accordance with industry (Electric Power 

Research Institute (EPRI)) guidelines throughout plant life and has not experienced any major 

chemical excursions.

In summary, the root cause of the cracking is high residual stress caused by non-optimum tube 

processing. A contributing factor is the concentration of secondary water chemistry 

contaminants in the crevice between the tube and the quatrefoil lands. The chemistry of this 

crevice at Seabrook is not unusually aggressive as is supported by the chemical analysis of the 

deposits on the tube surface and on the crack faces.

During the investigation of the root cause of the indications, a clear shift in the eddy current 

signal (150 kHz absolute channel) became evident in the tubes at Seabrook with axial cracks. 

This offset or shift in the low-frequency (150 KHz) absolute channel between the straight leg 

portion of the tube and the U-bend region was attributed to changes in the residual stresses in 

the tube (actually the conductivity of the tube as discussed below). No offset in the eddy current 

data were expected in the low-row tubes (i.e., rows 1 through 10) because the U-bend region is 

stress-relieved after bending, resulting in consistently low levels of residual stress throughout 

the tube. Because testing of the archived material for the heats of material affected by this 

cracking found the expected low levels of stress, the licensee attributed the changes in residual 

stress levels and the resultant eddy current offset in these tubes to nonoptimal tube processing. 

A similar shift in the eddy current data also was observed during tests at San Onofre Nuclear 

Generating Station in 1986 in which mill-annealed tubes were thermally treated over part of their 

length and tested with a bobbin probe. A clear shift in the signal was observed at the transition 

from the mill-annealed to thermally treated material. It is believed that the specific property of 

the material being measured by the eddy current probe is conductivity, which is known to vary 

with the degree of strain of the material (cold work increases a material’s hardness, which leads 
3-88

to an increase in resistivity). Stress is not being directly measured, but is inferred from the 

knowledge that the pulled tubes have high residual stress in the straight legs (because the 

cracks were there) and that the low-row U-bends have low residual stress (because they were 

stress relieved after bending).

For the low-row tubes (i.e., those that had been stress relieved after bending), the residual 

stresses are expected to be consistent throughout the tube. As a result, no offset is expected in 

the eddy current data. However, for the higher-row tubes (i.e., those not receiving the local 

U-bend stress relief), the residual stresses are expected to be higher in the U-bend region when 

compared to the straight portion of the tube. As a result, there should be an offset in the eddy 

current data when transitioning from the straight portion of the tube into the U-bend region. The 

lack of an offset in the high-row tubes could indicate higher stresses in the straight portion of the 

tubing (i.e., nonoptimal tube processing). For the higher-row tubes, the licensee determined 

that the tubes in any given row had a somewhat repeatable offset with some scatter around the 

mean. As the row number increased (and the bend radius increased and the strain decreased), 

the average offset in a row decreased (as would be expected since the stresses in the U-bend 

region of the higher-row tubes should decrease as the row number increases). This trend was 

observed through row 50. After row 50, this decrease in the offset was not observed. The 

licensee postulated that deposits may have contributed to the lack of the trend beyond row 50.

Based on the above findings, the eddy current data from the prior outage was reviewed to 

determine the number of tubes that may have potentially high residual stresses (i.e., exhibit the 

offset). This review included not only low-row tubes, where the residual stresses are expected 

to be consistent throughout the tube, but also the higher-row tubes (i.e., those not receiving the 

local U-bend stress relief), where the residual stresses are expected to be higher in the U-bend 

region (when compared to the straight portion of the tube). Review of the eddy current data 

from the tubes in all four steam generators identified 21 tubes, including the 15 tubes with 

cracks, which exhibited the eddy current offset. The 15 tubes with cracks (including the two 

tubes pulled for destructive examination) were plugged during RFO 8. The six additional tubes 

identified as having the offset showed no signs of degradation during RFO 8 and were all 

low-row tubes (rows 1 through 10). These six tubes were plugged during RFO 9 as discussed 

below. The 21 low-row tubes identified with the offset were all in steam generator D.

More information from the licensee on the root cause of the cracking at the tube support plate 

intersections may be found under ADAMS Accession Nos. ML023240524 and ML023300457. 

This issue was also summarized in NRC IN 2002-21, “Axial Outside-Diameter Cracking 

Affecting Thermally Treated Alloy 600 Steam Generator Tubing” and NRC IN 2002-21, 

Supplement 1 (ADAMS Accession Nos. ML021770094 and ML030900517, respectively).

Inspection of the tube support plate quatrefoil openings was performed in RFO 8 using the UBIB

tool. Those inspections showed insignificant blockage in the tube support plate quatrefoil area.

During cycle 9 (spring 2002 to fall 2003), the primary-to-secondary leak rate was less than 

3.79 lpd (1 gpd). The only measurable leak rate was in steam generator B where the leak rate 

typically fluctuated between 0.75 and 1.89 lpd (0.2 and 0.5 gpd) with spikes up to 2.65 lpd 

(0.7 gpd). This leak rate is consistent with that observed in previous cycles. The leakage is 

postulated to be coming from leak limiting plugs used in the steam generators.
3-89

During RFO 9 in 2003, 100 percent of the tubes in each of the four steam generators were 

inspected full length with a bobbin coil, except for the U-bend region of the tubes in rows 1 and 

2. In addition to the bobbin coil inspections, a rotating probe equipped with a plus-point coil was 

used to inspect:

• 20 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the hot-leg side in all four steam generators (the actual extent above the 

top of the tubesheet may have been greater than 7.62 cm (3 in.) to ensure the entire 

portion of the tube within the sludge pile was inspected)

• the U-bend region of 20 percent of the row 1 and row 2 tubes in all four steam 

generators

• 20 percent of the hot-leg dents and dings with bobbin voltage amplitudes greater than 5 

volts that were in the straight section of the tubing in all four steam generators

In addition to these eddy current inspections, all tube plugs in each of the four steam generators

were inspected visually.

As a result of these inspections, 15 tubes were plugged—9 for wear at the AVBs, 3 for axially 

oriented outside diameter stress corrosion cracking, and 3 were preventatively plugged with 

absolute drift signals (eddy current offset) characteristic of high residual stress.

The only steam generator tube degradation mechanisms observed during RFO 9 were (1) wear 

at the AVBs, (2) wear attributed to loose parts, (3) wear attributed to maintenance equipment, 

and (4) axially oriented outside-diameter stress corrosion cracking at the tube support plates. 

As of RFO 9, no tube wear associated with the tube support plates has been observed at 

Seabrook.

About 1,300 indications of wear at the AVBs were detected in the four steam generators during 

RFO 9. This includes 320 indications in steam generator A, 195 in steam generator B, 221 in 

steam generator C, and 567 in steam generator D. The maximum depth reported for the AVB 

wear indications was 43 percent throughwall.

Six volumetric indications have been reported at various locations throughout the tube bundle. 

These indications have been attributed to loose parts that are no longer present. Those 

indications that were detected in prior outages have not changed in size.

Two indications of wear near the flow distribution baffle were detected in the four steam 

generators (one in A and one in D) during RFO 9. Both indications are at the flow distribution 

baffle and are in a region where a pulser from the PPC had been positioned during RFO 4 and 

5. PPC is a high pressure gas cleaning and filtration process. The sudden release of gas 

through the PPC nozzles causes a mass of water in the steam generator to move upward and 

act as a washing action to dislodge sludge deposits from the steam generator tubes and support 

surfaces. The pressure pulses are performed at 10-second intervals by means of pressure 

pulsers externally mounted to the hand holes. Because the pulsers are near the flow 

distribution baffle, the pulsations cause a small relative displacement of structural components 

including the tubes that can result in minor wear on the tubes.

Similar indications have been observed in other Model F steam generators at other plants that 

have applied PPC. These indications are consistently in row 1 at columns 31 through 33 and 
3-90

columns 91 through 93 at the flow distribution baffle, and with a depth typically from 5 percent to 

25 percent throughwall. A review of the data from RFO 8 showed that the same signals were 

present at that time.

Several tubes in row 1 have indications about 48.26 cm (19 in.) above the top of the tubesheet. 

These indications have not changed since the prior inspection and have been attributed to 

interaction with the rail of the sludge lance equipment. The indications are consistent with 

indications reported at other plants.

There were three tubes with nine indications of axially oriented, outside-diameter-initiated stress 

corrosion cracking at seven support plate intersections in RFO 9 (two tubes had two indications 

at the same tube support plate elevation). These three tubes, along with three other tubes were 

identified after RFO 8 as having an absolute drift signal (eddy current offset) that could indicate 

greater susceptibility to stress corrosion cracking. The other three tubes with the absolute drift 

signal (eddy current offset) did not have any indications of stress corrosion cracking. All six of 

these tubes were plugged. As a result, all tubes in the low rows with an eddy current offset 

were removed from service in RFO 9. The stress corrosion cracking indications in these three 

tubes had bobbin voltages ranging from 0.04 volts to 0.81 volts and plus-point voltages ranging 

from 0.26 to 0.75 volts. All of the indications that were detected with a bobbin coil on the hot-leg 

were confirmed as flaws with a plus-point coil; however, there were two bobbin indications on 

the cold-leg that were not confirmed as flaws with a plus-point coil.

Two bulge indications are in the tube at row 22, column 75, in steam generator D. These 

bulges are 8.9 cm (3.51 in.) and 5.4 cm (2.11 in.) above the top of the tubesheet on the cold-leg 

side of the steam generator. Further examination with the plus-point probe showed no 

degradation at these bulges. These indications were present in prior inspections and have not 

changed.

An overexpansion is in the tube in row 34, column 42, in steam generator D. The 

overexpansion is about 2.54 cm (1 in.) above the top of the tubesheet and is not associated with 

the tubesheet expansion (i.e., the expansion does not extend above the top of the tubesheet). 

This indication has not changed since the last inspection.

Inspection and maintenance on the secondary side of the steam generator also were performed 

during RFO 9. To reduce the amount of sludge on the top of the tubesheet, sludge lancing was 

performed in each of the four steam generators. In addition, FOSAR was performed in each of 

the four steam generators, in the tubesheet annulus and the blowdown lane. As a result of 

these inspections, six foreign objects were found; one in steam generators A; three in steam 

generator B; and two in steam generator C. Five were removed. At row 31, column 11, in 

steam generator C, a dumbbell-shaped loose part that was found in RFO 1 was visually verified

as remaining stuck between two tubes in its original location. No loose parts were observed in 

steam generator D during RFO 9. As a result, only one known loose part remains in any of the 

four steam generators.

After RFO 9, one tube in steam generator B at row 29, column 97, was found as having an eddy 

current offset. This tube is a high-row tube and had no distorted support plate indications during 

RFO 8. A licensee analysis showed that it was acceptable (from a structural and leakage 

integrity standpoint) to leave this tube in service until the next planned inspection in RFO 11.

During RFO 10 in 2005, no steam generator tubes were inspected.
3-91

On September 29, 2006, the steam generator portion of the Seabrook technical specifications 

was revised to limit the extent of inspection in the hot-leg tubesheet region. Specifically, the 

technical specifications were revised to exclude the portion of tube that is more than 43.2 cm 

(17 in.) below the top of the tubesheet from inspection (i.e., approximately the lowermost 10.2 

cm (4 in.) of tube in the tubesheet on the hot-leg side was excluded from inspection, and hence 

any flaws that may exist in this region are permitted to remain in service). This revision was 

applicable only to RFO 11 and the subsequent operating cycles (ADAMS Accession No. 

ML062630457).

Cycle 11 (spring 2005 to fall 2006) presented no evidence of primary-to-secondary leakage.

During RFO 11 in 2006, 100 percent of the tubes in each of the four steam generators were 

inspected full length with a bobbin coil, except for the U-bend region of the tubes in rows 1 and 

2. In addition to the bobbin coil inspections, a rotating probe equipped with a plus-point coil was 

used to inspect:

• 30 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the hot-leg side in all four steam generators

• 50 percent of the bulges and overexpansions in the top 43.2 cm (17 in.) of the tubesheet 

on the hot-leg side in all four steam generators

• the U-bend region of 30 percent of the tubes in row 1 and row 2 in all four steam 

generators

• 30 percent of the hot-leg dents and dings with bobbin voltage amplitudes greater than or 

equal to 5 volts 

In addition to these eddy current inspections, all tube plugs in each of the four steam generators

were inspected visually. No degradation or abnormal leakage was identified during the 

inspection of the plugs.

As a result of these inspections, 21 tubes were plugged—3 for wear at the AVBs, 1 for a wear 

indication (volumetric indication) below the sixth tube support plate, 1 for a potentially elevated 

residual stress with no indications of cracking, and 16 for possible loose parts. The maximum 

depth reported for the AVB wear indications was 44 percent.

The only steam generator tube degradation mechanisms observed during RFO 11 were wear at 

the AVBs, wear attributed to loose parts, and wear attributed to maintenance equipment.

Of the 16 tubes plugged because of possible loose parts, all were in the same general area in 

steam generator C. Two of the plugged tubes had indications of possible loose parts and wear 

measuring 39 percent (row 58, column 54) and 48 percent (row 59, column 57) throughwall. 

These indications were in the cold-leg slightly above the flow distribution baffle. Additional

rotating probe inspections in tubes surrounding this area resulted in finding six more possible 

loose part indications. This location could not be accessed for removal of the possible loose 

parts. As a result, the two tubes with possible loose part indications and wear, the six tubes 

with possible loose part indications and no associated wear, and eight more tubes were plugged 

to bound the location of the eight possible loose parts. The observed degradation suggested to 

the licensee that the loose part is linear and lying on the flow distribution baffle. A visual 

inspection of this region in RFO 13 (2009) indicated that the loose part was a nail and was fixed 
3-92

in place. No attempts were made to remove the nail during RFO 13 since the risk involved was 

too great and because the nail is fixed in place and surrounded by plugged tubes. This nail was 

removed from the steam generator in RFO 14.

No possible loose part indication was detected in association with the tube plugged because of

a volumetric wear indication below the sixth tube support plate on the cold-leg side of steam 

generator D.

The previously reported wear indications at the flow distribution baffle were reported during RFO 

11. These indications were attributed to PPC, and the indications have not changed since the 

previous inspection.

The one tube identified after RFO 9 with an eddy current offset (absolute drift signal) indicative 

of potentially high residual stress was plugged. This tube was a high-row tube (at row 29, 

column 97, in steam generator B) and did not exhibit any crack-like indications.

FOSAR was performed in each of the four steam generators during RFO 11. The search 

consisted of visual inspection in the tube annulus area and the tube lane. As a result of these 

inspections, eight foreign objects were identified in steam generators A (three objects), B (two

objects), and C (three objects), seven of which were removed. At row 31, column 11, in steam 

generator C, a dumbbell-shaped loose part that was identified in RFO 1 was verified as 

remaining stuck between two tubes in its original location. No foreign objects were observed in 

steam generator D during RFO 11. No other secondary-side inspections were performed during 

RFO 11.

On March 28, 2007, the steam generator portion of the Seabrook technical specifications was 

revised making them performance-based consistent with TSTF-449 (ADAMS Accession Nos. 

ML070510645 and ML071420135).

During RFO 12 in 2008, no steam generator tubes were inspected. Advanced scale 

conditioning agent (ASCA) treatment was started to reduce the total scale loading in the steam 

generators. A full bundle copper ASCA was performed in RFO 12.

On October 13, 2009, the steam generator portion of the Seabrook technical specifications was 

revised to limit the extent of inspection in the tubesheet region. Specifically, the technical 

specifications were modified to exclude the portion of tube that is more than 33.27 cm (13.1 in.)

below the top of the tubesheet from inspection (i.e., approximately the lowermost 20.3 cm (8 in.)

of tube in the tubesheet was excluded from inspection, and hence any flaws that may exist in 

this region are permitted to remain in service). This revision was applicable only to RFO 13 and 

the subsequent operating cycle (ADAMS Accession No. ML092460184).

During cycle 13 (spring 2008 to fall 2009), steam generator B was found to have primary-tosecondary leakage, fluctuating between 0.75 and 2.65 lpd (0.2 and 0.7 gpd). There was no 

evidence of primary-to-secondary leakage in steam generators A, C, and D during cycle 13.
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During RFO 13 in 2009, 100 percent of the tubes in each of the four steam generators were 

inspected full length with a bobbin coil, except for the U-bend region of the tubes in rows 1 and 

2. In addition to the bobbin coil inspections, a rotating probe equipped with a plus-point coil was 

used to inspect:

• 50 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the hot-leg side in steam generators A, B, and D

• 100 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the hot-leg side in steam generator C 

• 50 percent of the bulges and overexpansions in the top 33.27 cm (13.1 in.) of the 

tubesheet on the hot-leg side in each of the four steam generators

• the U-bend region of 50 percent of the tubes in rows 1 and 2 (which included all U-bends 

that had not been inspected previously during this inspection period) in each of the four 

steam generators

• 50 percent of the dents and dings with bobbin voltage amplitudes greater than or equal 

to 5 volts in the freespan region of the hot-leg and in the U-bend in each of the four 

steam generators

• 50 percent of the dents and dings with bobbin voltage amplitudes greater than or equal 

to 2 volts at structures in the hot-leg and in the U-bend in each of the four steam 

generators.

In addition to these eddy current inspections, all tube plugs in each of the four steam generators

were inspected visually. All plugs were in their correct positions and there was no evidence of 

leakage past the plugs.

As a result of these inspections, 12 tubes were plugged—11 for wear at the AVBs and 1 for a 

single axial indication of outside-diameter stress corrosion cracking at the hot-leg expansion 

transition.

The only steam generator tube degradation mechanisms observed during RFO 13 were 

(1) wear at the AVBs, (2) wear at the flow distribution baffle attributed to application of PPC in a 

prior RFO, (3) wear attributed to foreign objects, wear attributed to maintenance equipment 

(sludge lance rail), and (4) axially oriented outside-diameter stress corrosion cracking at the hotleg expansion transition.

About 1,350 indications of wear at the AVBs were detected in the four steam generators during 

RFO 13. This includes about 400 indications in steam generator A, 250 in steam generator B, 

240 in steam generator C, and 460 in steam generator D. The maximum depth reported for the 

AVB wear indications was 45 percent throughwall.

Two wear indications (in 2 tubes) have historically been detected at the flow distribution baffle 

and were attributed to prior application of PPC. Similar indications have been observed in other 

model F steam generators that have applied PPC. The indications are typically observed in row 

1 at columns 31–33 and columns 91–93 at the flow distribution baffle. During RFO 13, one of 

these indications was not detected and the size of the other indication was consistent with prior 

inspection results.
3-94

About 10 wear indications (in 10 tubes) were detected and attributed to loose parts that were no 

longer present. Most of these indications were present in prior inspections and have not 

changed in size.

Eight wear indications (in six tubes) were attributed to interaction between the tubes and the 

sludge lance rail in a prior outage. The indications are in row 1, columns 36, 87, and 112, and 

are about 45.7 cm (18 in.) above the top of the tubesheet. The depths of the indications have 

not changed since at least RFO 9. The sludge lance rail was redesigned to prevent future tube 

interaction or aggravation of the existing wear condition.

Only one axially oriented outside-diameter stress corrosion cracking indication was detected 

during RFO 13. It was detected with a plus-point coil, pancake coil, and Ghent probe, and is a 

single axial indication at the hot-leg expansion transition with a length of approximately 3 mm 

(0.12 in.) and a peak-to-peak voltage of 0.44 volts. The crack started at the bottom of the 

expansion transition and extends down into the expanded region of tubing.

As of RFO 13, there were 15 high-row tubes in steam generator A, 26 high-row tubes in steam 

generator B, 18 high-row tubes in steam generator C, and 8 high-row tubes in steam generator 

D with potentially elevated residual stresses as determined from the eddy current data.

Two loose parts (other than sludge rocks) were reported during RFO 13. Both are in steam 

generator C. One loose part is near the top of the tubesheet and is dumbbell-shaped. It has 

been reported in prior outages. The other loose part is a nail at a flow distribution baffle. This 

loose part resulted in plugging 14 tubes during RFO 11. Both loose parts remain in the steam 

generator.

Inspection and maintenance on the secondary side of the steam generators were performed 

during RFO 13. A full bundle iron ASCA treatment was performed in all four steam generators. 

About 550 pounds of iron were removed from each steam generator. In addition, sludge lancing 

and FOSAR was performed in all four steam generators. FOSAR was performed in the tube 

lane and in the annulus area. About 164 pounds of sludge was removed from the top of the 

tubesheet area. A UBIB visual inspection of tube support plates was performed in steam 

generator C. The inspection included tube support plates 4 through 7 at columns 70 and 96 on 

both the hot- and cold-leg side of the steam generator. The inspection was performed after the 

full bundle ASCA was applied. The results were as expected with heavier scale buildup 

decreasing from the center line toward the outer columns as well as decreasing from upper tube 

support plate elevations to lower tube support plate elevations. Also, as expected, scale is 

more prevalent on the hot-leg side than on the cold-leg side of the steam generator. Most of the 

quatrefoil holes remain open and there were no completely blocked quatrefoils at any support 

plate elevations. Future UBIB inspections and ASCA treatments are planned.

During cycle 14 (fall 2009 to spring 2011), primary-to-secondary leakage was detected 

fluctuating between 0.75 and 2.65 lpd (0.2 and 0.7 gpd), in steam generator B. There was no 

evidence of primary-to-secondary leakage during cycle 14 in steam generators A, C, and D.

During RFO 14 in 2011, only rotating probe inspections of the portion of the tube near the top of 

the tubesheet on the hot-leg side were performed. Specifically, a rotating probe equipped with a 

plus-point coil was used to inspect 20 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm 

(3 in.) below the top of the tubesheet on the hot-leg side in steam generators A, B, and D, and 

100 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 
3-95

tubesheet on the hot-leg side in steam generator C. In addition to these eddy current 

inspections, all tube plugs in each of the four steam generators were inspected visually.

As a result of these inspections, no tubes were plugged.

The only steam generator tube degradation mechanism observed during RFO 14 was wear 

attributed to foreign objects. Six indications were detected during RFO 14. One of the 

indications was new, while the other five indications were present in prior inspections and have 

not changed in size.

Inspection and maintenance on the secondary side of the steam generators were performed 

during RFO 14. A top of tubesheet ASCA treatment was performed in all four steam 

generators. About 98 pounds of iron were removed from all four steam generators. In addition, 

FOSAR (in the tube lane and in the annulus area) and sludge lancing was performed in all four 

steam generators. About 323 pounds of sludge were removed from the top of tubesheet area 

from all four steam generators. In addition, the nail that resulted in 14 tubes being plugged 

during RFO 11 was removed from the steam generator. Only two objects are known or 

presumed to remain in the steam generators: a dumbbell-shaped object captured between two 

plugged tubes above the top of the tubesheet in steam generator C, which has been present 

since RFO 1, and an object just above the fifth hot-leg tube support plate in steam generator A,

which was identified during RFO 8. For this latter object, seven tubes surrounding the object 

were plugged in RFO 8.

On September 10, 2012, the steam generator portion of the Seabrook technical specifications 

was revised to limit the extent of inspection in the tubesheet region. Specifically, the technical 

specifications were revised to exclude the portion of tube that is more than 38.63 cm (15.21 in.)

below the top of the tubesheet from inspection (i.e., approximately the lowermost 15.24 cm 

(6 in.) of tube in the tubesheet was excluded from inspection, and hence any flaws that may 

exist in this region are permitted to remain in service (ADAMS Accession No. ML12178A537)).

During cycle 15 (spring 2011 to fall 2012), primary-to-secondary leakage was detected in steam 

generator B, fluctuating between 0.75 and 3.4 lpd (0.2 and 0.9 gpd). There was no evidence of 

primary-to-secondary leakage during cycle 15 in steam generators A, C, and D.

During RFO 15 in 2012, 100 percent of the tubes in each of the four steam generators were 

inspected full length with a bobbin coil, except for the U-bend region of the tubes in rows 1 and 

2. In addition to the bobbin coil inspections, a rotating probe equipped with a plus-point coil was 

used to inspect: 

• 50 percent of the tubes from 7.62 cm (3 in.) above to 38.63 cm (15.21 in.) below the top 

of the tubesheet on the hot-leg side (which included 50 percent of the bulges and 

overexpansions in the top 38.63 cm (15.21 in.) of the tubesheet on the hot-leg side)

• the U-bend region of 50 percent of the tubes in rows 1 and 2 

• 50 percent of the dents and dings with bobbin voltage amplitudes greater than 5 volts in 

the hot-leg and in the U-bend

As a result of finding a crack-like indication at a dent in steam generator C (described below), a 

rotating probe equipped with a plus-point coil was used to inspect:
3-96

• 100 percent of the dents and dings with bobbin voltage amplitudes greater than 5 volts in 

the hot-leg and in the U-bend in steam generator C

• 20 percent of the dents and dings with bobbin voltage amplitudes greater than 2 volts 

and less than or equal to 5 volts in the hot-leg in steam generator C

• 100 percent of the dents and dings with bobbin voltage amplitudes greater than or equal 

to 5 volts at the eighth (uppermost) tube support on the cold-leg in steam generator C

• 20 percent of the dents and dings with bobbin voltage amplitudes greater than 2 volts 

and less than or equal to 5 volts at the eighth (uppermost) tube support on the cold-leg 

in steam generator C

In addition to these eddy current inspections, all tube plugs and in the channel heads in each of 

the four steam generators were inspected visually. There was no evidence of leakage past the 

plugs. There was no evidence of degradation found during the channel head inspections.

As a result of these inspections, nine tubes were plugged—six for wear at the AVBs, two for

axially oriented outside-diameter stress corrosion cracking indications, and one for a probe head 

that became stuck near the tube tangent point.

The only steam generator tube degradation mechanisms observed during RFO 15 were 

(1) wear at the AVBs, (2) wear at the tube support plates, (3) wear at the flow distribution baffle 

attributed to application of PPC in a prior RFO, (4) wear attributed to foreign objects, (5) wear 

attributed to maintenance equipment (sludge lance rail), (6) axially oriented outside-diameter 

stress corrosion cracking at a hot-leg dented tube support plate elevation, and (7) axially 

oriented outside-diameter stress corrosion cracking in the freespan region on the hot-leg side of 

the steam generator. 

A total of 1,279 indications of wear at the AVBs were detected in 592 tubes in the four steam 

generators during RFO 15. Of these 1,279 indications, 154 were new indications. There were 

358 indications detected in 173 tubes in steam generator A, 233 indications in 125 tubes in 

steam generator B, 236 indications in 100 tubes in steam generator C, and 452 indications in 

194 tubes in steam generator D. The maximum depth reported for the AVB wear indications 

was 55 percent throughwall.

Eleven indications of wear attributed to interaction between the tube and the tube support plates 

were reported in RFO 15. Of these indications, six were new and the other five were reported in 

prior outages as wear attributed to foreign objects. However, they were reclassified during RFO 

15 as tube support plate wear indications. The indications that were reclassified as tube 

support plate wear indications have not changed in size since the previous inspection.

Two wear indications (in two tubes) have historically been detected at the flow distribution baffle 

and were attributed to prior application of PPC. Similar indications have been observed in other 

model F steam generators that have applied PPC. The indications are typically observed in row 

1 at columns 31–33 and columns 91–93 at the flow distribution baffle. During RFO 15, the 

inspections showed that these indications are not changing.

Six wear indications (in six tubes) were detected and attributed to loose parts that were no 

longer present. Most of these indications were present in prior inspections and have not 

changed in size.
3-97

Eleven wear indications (in eight tubes) were attributed to interaction between the tubes and the 

sludge lance rail in a prior outage. Of these 11 indications, 3 indications (in 2 tubes) were not 

previously reported. These 11 indications are in row 1, columns 11, 36, 87, and 112 and are 

about 45.7 cm (18 in.) above the top of the tubesheet. The depths of the indications that were 

previously reported have not changed since at least RFO 9. The sludge lance rail was 

redesigned to prevent future tube interaction or aggravation of the existing wear condition.

Four crack-like indications were detected during RFO 15. These four indications were in two 

tubes. Three axially oriented outside-diameter stress corrosion cracking indications were

detected in the freespan region of a tube above the flow distribution baffle and below the first 

tube support plate on the hot-leg side of the steam generator. All three indications were in one 

tube. In addition, one axially oriented outside-diameter stress corrosion cracking indication was 

detected at a dent at the uppermost tube support plate on the hot-leg side of the steam 

generator.

For the indications in the freespan region of the tube, the bobbin coil inspections resulted in 

identifying one of these three indications. The indication was in the freespan region of a tube on 

the hot-leg side of the steam generator between the flow distribution baffle and the first tube 

support plate. To further inspect the region where the bobbin coil indication was detected, a 

rotating probe equipped with a plus-point coil was used. This inspection confirmed that the 

indication was axially oriented, crack-like, and had initiated from the outside diameter of the tube 

(typically referred to as outside-diameter stress corrosion cracking). The indication had a 

plus-point voltage amplitude of about 0.96 volts, a length of 1.32 cm (0.52 in.), and a maximum 

depth of 77 percent of the tube wall thickness. A Ghent 3-4 probe also was used to inspect this 

location. All three probes identified the flaw signal. During the rotating probe inspections, two 

other outside-diameter stress corrosion cracking indications were identified in the same tube. 

These two indications were not detected during the bobbin coil inspections. These other

indications were about 15.24 cm (6 in.) above the initially detected indication and were smaller 

in size. One indication had a plus-point voltage of 0.24 volts, a length of 3.8 mm (0.15 in.), and 

a maximum depth of 45 percent of the tube wall thickness. The other indication had a plus-point

voltage amplitude of 0.38 volts, a length of 4.57 mm (0.18 in.), and a maximum depth of 56

percent of the tube wall thickness.

Although there was no reportable bobbin signal at these two locations, there were benign 

signals at these locations since the preservice inspection. These benign signals were 

characterized as small dents/dings from the preservice inspection data and had exhibited local 

conductivity changes after the first cycle of operation at temperature. The three indications 

were not considered components of a single indication since the indications were separated by 

ligaments of sound material and were not in the same axial plane.

In addition to these three indications of axially oriented outside-diameter stress corrosion 

cracking in one tube, another axially oriented outside-diameter stress corrosion cracking

indication was detected in another tube. This latter indication was associated with a 

dented/dinged region of the tube at the top tube support plate on the hot-leg side of the steam 

generator. This tube had two dents/dings at the uppermost tube support plate: one at the 

bottom edge of the tube support plate had a bobbin voltage amplitude of 11.35 volts, and one at 

the upper edge of the tube support plate had a bobbin voltage amplitude of 8.96 volts. The 

crack-like indication was associated with the dent/ding at the lower edge of the tube support 

plate and was detected during the rotating probe inspections of dents/dings. A rotating probe is 

typically used to inspect dents/dings that have bobbin voltage amplitudes greater than 5 volts 
3-98

since the bobbin coil is not qualified to detect crack-like indications in such dents/dings. The 

crack-like indication had a plus-point coil voltage amplitude of 0.89 volts, a length of 5.59 mm 

(0.22 in.), and a maximum depth of 76 percent of the tube wall thickness.

Neither of the tubes with cracking indications had any evidence of high residual stress because 

of nonoptimal tube processing as discussed in NRC IN 2002-21, Supplement 1, “Axial 

Outside-Diameter Cracking Affecting Thermally Treated Alloy 600 Steam Generator Tubing.” 

These four indications are further discussed in NRC IN 2013-11, July 3, 2013, “Crack-Like 

Indications at Dents/Dings and in the Freespan Region of Thermally Treated Alloy 600 Steam 

Generator Tubes.”

Eight bulges were reported in seven tubes during RFO 15. All bulges are slightly above the top 

of tubesheet and have been reported in prior inspections. No degradation was associated with 

any of the bulge signals.

Inspection and maintenance on the secondary side of the steam generators were performed 

during RFO 15. FOSAR (in the tube lane and in the annulus area) and sludge lancing was 

performed in all four steam generators. In addition, in-bundle inspections were performed in 

several columns in each steam generator to assess the effectiveness of the top of tubesheet 

ASCA treatment that was performed in RFO 14. These in-bundle inspections revealed that 

scale collars still remain on some tubes in the kidney region of the steam generator (a region of 

low water cross flow across the tubesheet and is typically near the center of the tube bundle). 

The ASCA treatment reduced the number and size of the scale collars. Only three foreign 

objects are known to remain in the steam generators: a dumbbell-shaped object captured 

between two plugged tubes above the top of the tubesheet in steam generator C that has been 

present since RFO 1; and a glass lens and Delrin sliver from the UBIB inspection tool.

In addition, a UBIB visual inspection was performed in steam generator C to assess the 

effectiveness of the full bundle ASCA treatment performed in RFO 13. The inspection was 

mainly focused on the sixth and seventh tube support plates. The seventh support plate is the 

uppermost tube support plate with quatrefoil shaped holes. Inspections were performed in 

columns 76, 78, 92, 93, 95, 96, and 97. These columns were chosen since there are equipment 

and flow slot alignment conditions that only allow inspection of specific columns. The 

inspections showed that the quatrefoil lobes are not occluded and are open to flow. There were 

no signs of bridging of the lobes.

A visual inspection of the upper steam drum was performed in steam generator A. The 

components inspected were the feedring, J-tubes, J-tube to feedring welds (a sampling), 

primary moisture separators, secondary separators, welds, structural components, thermal 

sleeve, and backing rings. In addition some depth measurements of the feedring thickness 

were made at several locations using ultrasonic inspection techniques. The results of these

inspections showed that all components are covered with a protective layer of magnetite. No 

bare metal (rust areas) were noted. The ultrasonic thickness readings indicated that no thinning 

of the feedring was occurring. There were no anomalies noted at the J-tube to feed ring welds.

On October 25, 2013, the steam generator portion of the Seabrook technical specifications was 

revised making them consistent with TSTF-510 (ADAMS Accession No. ML13107A016).

3.3.4 Vogtle 1
3-99

Tables 3-22, 3-23, and 3-24 summarize the information discussed below for Vogtle 1. 

Table 3-22 provides the number of full-length bobbin inspections and the number of tubes 

plugged and deplugged during each outage for each of the four steam generators. Table 3-23 

lists the reasons why the tubes were plugged. Table 3-24 lists tubes plugged for reasons other 

than wear at the AVBs.

Vogtle 1 has four Westinghouse model F steam generators. The licensee numbers its tube 

supports from the hot-leg flow distribution baffle (FBH or BPH) to 7H on the hot-leg side of the 

steam generator and from the cold-leg flow distribution baffle (FBC or BPC) to 7C on the 

cold-leg side (Figure 2-4).

In 2000, the feedwater ring weld backing rings were inspected, and the results were acceptable. 

Future inspections of these backing rings are planned to be performed at least once every six 

refueling outages.

During RFO 10 in 2002, 100 percent of the tubes in steam generators A and D were inspected 

full length with a bobbin coil, except for the U-bend region of the tubes in rows 1 and 2. In 

addition to the bobbin coil inspections, a rotating probe equipped with a plus-point coil was used 

to inspect 50 percent of tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the hot-leg side of steam generators A and D, and the U-bend region of 60

percent of the row 1 and row 2 tubes in steam generators A and D. Additionally, a bobbin coil 

and a rotating probe equipped with a plus-point coil were used to inspect tubes in rows 1 and 2 

from the top of the tubesheet to the flow distribution baffle in steam generator A before and after 

ultrasonic energy cleaning (UEC). No steam generator tubes were inspected in steam 

generators B and C.

As a result of these inspections, two tubes were plugged for difficulty passing the plus-point 

probe through the U-bends of the tubes.

The only steam generator tube degradation mechanisms observed during RFO 10 were wear at 

the AVBs and wear attributed to a loose part.

About 140 indications of AVB wear were detected in 58 tubes in steam generator A. In steam 

generator D, 179 indications were detected in 96 tubes. The 95 percent cumulative probability 

growth values are less than 10 percent for the prior 2-cycle interval. The rate of progression of 

the wear at the AVBs has not changed significantly and there were no tubes found to have 

experienced excessive wear at the AVBs. The maximum depth reported for the AVB wear 

indications was 34 percent throughwall.

One indication of wear attributed to a loose part was reported during RFO 10. This indication 

was at a hot-leg baffle plate in steam generator A. The maximum depth reported for this 

indication was 19 percent throughwall. The indication has not changed in size since originally 

detected during RFO 8.

The two tubes that were plugged were low-row tubes. In these two tubes, the plus-point probe 

bound and stopped rotating during the examinations. Attempts were made to inspect the 

U-bends from both the hot-leg and cold-leg side of the steam generator with a 12.7-mm 

(0.500-in.) diameter rotating probe. Although both tubes had passed a 1.32-mm (0.520-in.) 

bobbin coil during previous inspections, the 12.7-mm (0.500-in.) diameter rotating probe 

inspection was not successful. The binding of the rotating probe in the tube was attributed by 
3-100

the licensee to differences in the design dimensions of the rotating coil and bobbin probes and 

their ability to traverse the low-row U-bends.

During RFO 10, in steam generator A, the top of the tubesheet received UEC, where ultrasonic 

energy disrupts scale and secondary-side deposits that have accumulated on the outside 

surface of steam generator tubes. 

The process was applied in steam generator A for the purpose of field demonstration of the 

process, which had not previously been used in a commercial nuclear power plant steam 

generator. In this process, ultrasonic energy was initiated into the tube bundle through

operation of ultrasonic transducers that were placed in the tube lane and covered with water. 

The water level was maintained at 48.3 cm (19 in.) above the top of the tubesheet (which is 

below the flow distribution baffle) during transducer operation. Inspections were performed 

before and after the UEC to validate laboratory test results that indicated no adverse effects to 

tube integrity during application of the process. The pre- and post-UEC eddy current 

inspections revealed no detectable detrimental effects because of the high frequency sound 

waves.

On November 24, 2002, both Vogtle units were shut down because of high sodium 

concentrations in the feedwater system. The sodium was introduced into the feedwater system 

when sodium phosphate rather than methoxypropylamine was added to the feedwater system in 

both units. Methoxypropylamine is normally added to the feedwater system for corrosion 

control. 

During RFO 11 in 2003, 100 percent of the tubes in steam generators B and C were inspected 

full length with a bobbin coil, except for the U-bend region of tubes in rows 1 and 2. In addition 

to the bobbin coil inspections, a rotating probe equipped with a plus-point coil was used to 

inspect:

• 50 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the hot-leg side (including any tubes not examined during RFO 9) in steam 

generators B and C

• the U-bend region of 50 percent of the row 1 and row 2 tubes (including any tubes not 

examined during RFO 9) in steam generators B and C

• 100 percent of the dents with bobbin voltage amplitudes greater than or equal to 5 volts 

in the straight leg areas in steam generators B and C. 

In addition to these eddy current inspections, the tube plugs were inspected visually, the extent 

of blockage of the quatrefoil openings was assessed using a rotating probe equipped with a 

plus-point coil, and the phosphate chemistry excursion that occurred during cycle 11 was

evaluated with a rotating probe equipped with a plus-point coil. No steam generator tubes were

inspected in steam generators A and D.

As a result of these inspections, three tubes were plugged—one for wear at the AVBs, one for a 

volumetric indication, and one for difficulty passing the plus-point probe through the U-bend of 

the tube.
3-101

The only steam generator tube degradation mechanisms observed during RFO 11 were wear at 

the AVBs and wear attributed to an impact from a loose part or a mechanical change in the tube 

(e.g., cold lap breaking off).

The maximum depth reported for the AVB wear indications was 43 percent.

The tube that was plugged with a volumetric indication had an indication that was consistent 

with an impact from a loose part or a mechanical change in the tube (e.g., cold lap breaking off).

The tube that was plugged because of difficulty passing the rotating probe though the tube was 

a row 1 tube. The 1.32-mm (0.520-in.) plus-point rotating probe would pass through the tube; 

however, because of a tight fit in the U bend, proper rotation of the probe was prevented at the 

apex of the U-bend region of the tube. The U bend region of the tube was inspected using a 

plus-point rotating probe during RFO 7 in 1997, though special effort was required to complete 

the inspection.

All RFO 9 bobbin data for steam generators B and C was reviewed to determine if any tubes 

exhibited an eddy current offset that could indicate higher residual stresses in the tubes (and 

therefore higher susceptibility to cracking). Cracking associated with tubes with an eddy current 

offset was observed at Seabrook in 2002 (NRC IN 2002-21, “Axial Outside Diameter Cracking 

Affecting Thermally Treated Alloy 600 Steam Generator Tubing” dated June 25, 2002, and its 

supplement dated April 1, 2003, for additional details). No indications of any eddy current offset 

were identified in the RFO 9 bobbin data for steam generators B or C.

The degree of blockage of the quatrefoil openings was assessed at 360 locations at tube 

support plates 6 and 7 on the hot-leg side of the steam generators and many other locations at 

other tube support plates. The eddy current signature was expected to reflect variation from a 

clean intersection. The results, however, did not quantify the extent of blockage of the quatrefoil 

openings because of the weak correlation between the rotating probe signatures and the results 

of the visual inspection. Because of these assessments, (1) no clean tube-to-tube support plate

intersections were observed, (2) the scale was significantly thicker at the bottom of the tube 

support plate than at the top along the length of the tube going through the tube support plate, 

and (3) more deposits were seen in tube support plate intersections at tube support plate 7 than 

at other tube support plates.

In the evaluation of the phosphate chemistry excursion, 100 percent of the tubes were inspected 

with the bobbin probe and 50 percent of the tubes were inspected with a plus-point probe at the 

top of the tubesheet on the hot-leg side. The licensee analyzed in detail a limited number of 

tubes, as well as compared the RFO 11 data to prior data to find any excursion signals that 

indicated the onset of corrosion. None was found.

UEC was performed in each of the four steam generators during RFO 11. The tubes near the 

ultrasonic transducers were inspected with a bobbin probe after the UEC. No indications were 

detected because of the UEC. The UEC was intended to remove scale deposit on the top of the 

tubesheet and scale collars.

During RFO 12 in 2005, 100 percent of the tubes in steam generators A and D were inspected 

full length with a bobbin coil, except for the U-bend region of the tubes in rows 1 and 2. In 

addition to the bobbin coil inspections, a rotating probe equipped with a plus-point coil was used 

to inspect:
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• 50 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the hot-leg side in steam generators A and D

• 100 percent of the bulges and overexpansions in the hot-leg side of the tubesheet in 

steam generator D

• 20 percent of the bulges and overexpansions in the hot-leg side of the tubesheet with 

the sample selected in the region from 7.62 cm (3 in.) above to 25.4 cm (10 in.) below 

the top of the tubesheet in steam generators A, B, and C (with the largest bulges 

selected first and the remaining inspections performed at bulges that were greater than 

18 volts and overexpansions with greater than 0.038 mm (1.5 mils) increase in the 

nominal expanded tube diameter)

• the U bend region of 50 percent of row 1 and row 2 tubes in steam generators A and D

• 100 percent of dents and dings with bobbin voltage amplitudes greater than or equal to 5 

volts that have not been previously inspected and are in the U-bend region or hot-leg in 

steam generators A and D

In addition to these eddy current inspections, tube plugs were inspected visually.

As a result of these inspections, two tubes were plugged. These tubes were plugged for 

circumferentially oriented stress corrosion cracking indications that initiated from the inside 

surface of the tube.

The only steam generator tube degradation mechanisms observed during RFO 12 were wear at 

the AVBs and circumferentially oriented primary water stress corrosion cracking associated with 

bulges in the tubesheet. Wear attributed to loose parts may also be present in the Vogtle steam 

generators; however, no report of any indications was provided for RFO 12.

About 110 indications of AVB wear were detected in 66 tubes in steam generator A. In steam 

generator D, 176 indications were detected in 98 tubes. The maximum depth reported for the 

AVB wear indications was 38 percent throughwall.

The circumferentially oriented stress corrosion cracking indications were associated with tube 

bulges in tubesheet on the hot-leg side of the steam generator. At Vogtle, a bulge is recorded 

at a certain location if the voltage of the bulge (as measured with a bobbin coil) exceeds a 

threshold value (e.g., 18 volts). Similarly, a location is classified as overexpanded if the 

diameter of the bulged area exceeds the average diameter of the tube by a specified amount

0.038 mm (0.0015 inch (1.5 mils) or greater). 

One of the tubes affected by circumferentially oriented stress corrosion cracking was at row 11, 

column 88. In this tube, two inside diameter initiated circumferential indications were identified 

in a 170-volt bulge. About 170 degrees separated the two indications. The indications were 

confirmed to be present with a plus-point coil, a Ghent probe (a transmit-receive probe), and a 

delta probe (a rotating probe with 3 coils). The indications were about 4.3 cm (1.7 in.) below the 

secondary face of the tubesheet, and the voltage associated with these indications was 

0.72 volts. During the last inspection of this tube in 2002, there were no indications at this 

location.
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The other affected tube was at row 6, column 101. In this tube, one inside diameter initiated 

circumferential indication was identified in a 109-volt bulge. The indication was confirmed to be 

present with a plus-point coil, a Ghent probe, and a delta probe. The indication was about

10 mm (0.4 in.) below the top of the tubesheet, and the voltage associated with this indication 

was 0.7 volts. During the last inspection of this tube in 1999, there were no indications at this 

location.

The number of tubes with bulges and overexpansions in each of the steam generators was 

estimated to be 201 in steam generator A, 446 in steam generator B, 123 in steam generator C, 

and 177 in steam generator D.

All RFO 10 bobbin data were reviewed for steam generators A and D to determine if any tubes 

exhibited an eddy current offset that could indicate higher residual stresses in the tubes (and 

therefore higher susceptibility to cracking). Steam generators B and C were reviewed similarly 

for RFO 11. Cracking associated with tubes with an eddy current offset was observed at 

Seabrook in 2002 and Braidwood 2 in 2003. Because of the reviews in the four steam 

generators, no tubes in the low rows (rows 1 through 10) exhibited an eddy current offset. 

In the high rows, the review found 118 tubes with an eddy current offset of less than the mean 

eddy current signal minus two standard deviations (mean minus 2 sigma). Fifty-four tubes in 

steam generator A, 17 tubes in steam generator B, 23 tubes in steam generator C, and 24 tubes 

in steam generator D had an offset less than the mean minus 2 sigma.

A small foreign object was found on the secondary side of steam generator A near the tubes in 

row 4, column 97, and row 5, column 96. This object is fixed in place.

UEC was performed in each of the four steam generators during RFO 12.

On August 28, 2006, Vogtle 1 revised the steam generator portion of their technical 

specifications making them performance-based consistent with TSTF-449 (ADAMS Accession 

No. ML062360577).

On September 12, 2006, the steam generator portion of the Vogtle 1 technical specifications 

was revised to limit the extent of inspection in the hot-leg tubesheet region. Specifically, the 

technical specifications were revised to exclude the portion of tube that is more than 43.2 cm 

(17 in.) below the top of the tubesheet from inspection (i.e., approximately the lowermost 10.2 

cm (4 in.) of tube in the tubesheet on the hot-leg side was excluded from inspection, and hence 

any flaws that may exist in this region are permitted to remain in service). This revision was 

applicable only to RFO 13 and the subsequent operating cycle (ADAMS Accession No. 

ML062260302).

There was no evidence of primary-to-secondary leakage during Cycle 13 (spring 2005 to fall 

2006).

During RFO 13 in 2006, all four steam generators were chemically cleaned. Full-bundle 

chemical cleaning was performed to reduce the deposit loading so as to limit the potential for 

tube corrosion and to eliminate the potential that severe secondary fouling would cause 

significant power reductions. The compositions of the iron removal solutions were based on the 

anticipated sludge and tube deposit inventories. This chemical cleaning operation incorporated 

elements of a process developed by EPRI and the Steam Generators Owners Group (SGOG)

and employed several phases where temperature adjustments were made to facilitate 

dissolution in specific regions of the tube bundle such as the tube support plate openings and 
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the top of tubesheet sludge region. Multiple rinse operations washed away the chemicals used 

to remove the residual iron before the copper-removal phase of the cleaning process. The 

process was completed after similar rinse steps following the copper-removal step. The 

chemical cleaning along with the follow-up mechanical cleaning techniques (e.g., the 

Consolidated Edison Combined Inspection and Lance (CECIL) system) removed 6,819 pounds 

of deposits. Based on the sludge removed and secondary visual inspection results, the licensee 

concluded the chemical cleaning was successful.

After the chemical cleaning, 100 percent of the tubes in steam generators B and C were 

inspected full length with a bobbin coil, except for the U-bend region of tubes in rows 1 and 2. 

In addition to the bobbin coil inspections, a rotating probe equipped with a plus-point coil was 

used to inspect:

• 100 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the hot-leg side in all four steam generators

• the U-bend region of 50 percent of row 1 and row 2 tubes in steam generators B and C

• 100 percent of the outermost two tubes around the entire periphery of the tube bundle 

from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the tubesheet on the hot- and 

cold-leg sides including both sides of the tube lane in steam generators B and C

• 100 percent of dents and dings in the U-bend region with bobbin voltage amplitudes 

greater than or equal to 5 volts in steam generators B and C

• about 25 percent of the bulges and overexpansions on the hot-leg side of the tubesheet 

from 7.62 cm (3 in.) above to 43.2 cm (17 in.) below the top of the tubesheet in steam 

generators A (resulted in inspecting 27 tubes), B (resulted in inspecting 80 tubes), and C 

(resulted in inspecting 21 tubes)

• 100 percent of the bulges and overexpansions on the hot-leg side of the tubesheet from 

7.62 cm (3 in.) above to 43.2 cm (17 in.) below the top of the tubesheet in steam 

generator D (78 tubes)

In addition to these eddy current inspections, all tube plugs in each of the four steam generators

were inspected visually.

As a result of these inspections, 19 tubes were plugged—1 for wear attributed to a loose part, 

1 for axially oriented outside-diameter stress corrosion cracking, and 17 for circumferentially 

oriented outside-diameter stress corrosion cracking.

The only steam generator tube degradation mechanisms observed during RFO 13 were 

(1) wear at the AVBs, (2) wear attributed to loose parts, (3) wear attributed to maintenance 

(UEC), and (4) axially and circumferentially oriented outside-diameter stress corrosion cracking 

at the expansion transition.

Sixty-four indications of AVB wear were detected in 35 tubes in steam generator B during RFO 

13. In steam generator C, 57 indications were detected in 33 tubes. The maximum depth 

reported for the AVB wear indications was 34 percent throughwall.
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Eleven indications of wear attributed to loose parts were identified in 10 tubes during RFO 13. 

These indications ranged in size from 8 percent to 42 percent throughwall. The tube plugged 

because of wear attributed to loose parts had a volumetric flaw above the cold-leg flow 

distribution baffle measuring 42 percent throughwall. Plus-point inspections were performed at 

this elevation for a two-tube buffer surrounding this volumetric flaw. No possible loose part 

indications were found during this inspection. Given the location of the indication, visual 

inspections could not be performed. The other wear indications attributed to loose parts had 

depths that ranged from 8 percent to 30 percent throughwall, and the indications were either at 

the top of the tubesheet, the flow distribution baffle, or the first tube support plate.

Shallow wall loss indications were identified in several tubes (six indications in three tubes) 

during the RFO 13 inspections. These indications were attributed to UEC that was performed in 

all four steam generators during both RFO 11 and 12. The prior inspection of these locations 

during RFO 11, after UEC was performed, found no indications of shallow wall loss. Visual 

inspection in steam generator B identified oxide removal patterns on several tubes that were 

hypothesized to be a result of cavitation during UEC. The inspection results in RFO 13 were 

classified as differential freespan signals, which resulted in further inspection with the rotating 

probe. The chemical cleaning during RFO 13 could have improved the detectability of the 

indications of shallow wall loss (all measured at 10 percent throughwall or less). The chemical 

cleaning preceded the eddy current inspection. The indications were attributed to UEC because 

they are adjacent to the location where the UEC cleaning system ultrasonic transducers were 

deployed. The RFO 13 bobbin examination was performed in the entire length of all tubes in 

steam generators B and C and no additional volumetric indications potentially attributable to 

UEC were detected. The purpose of the UEC deployment was to remove scale deposit and 

scale collars at the top of the tubesheet.

During RFO 13, 18 tubes were identified with indications of stress corrosion cracking in the four 

steam generators: 3 in steam generator A, 2 in steam generator B, 3 in steam generator C, and 

10 in steam generator D. Of these 18 tubes, 17 tubes had circumferentially oriented 

outside-diameter initiated indications and 1 tube had an axially oriented outside-diameter 

initiated indication. The tubes with circumferentially oriented indications either had single 

circumferential indications or multiple circumferential indications. The tube with the axial 

indication had a single axial indication. All circumferential indications were at the bottom of the 

hydraulic expansion transition at the top of the tubesheet on the hot-leg side of the steam 

generator. The axial flaw started at the bottom of the expansion transition and extended into the 

expanded portion of the tube within the hot-leg portion of the tubesheet. As a result, the 

indication is almost entirely below the bottom of the expansion transition.

For steam generators A, B and C, the crack-like indications were predominantly in low-row, 

high-column tubes along the periphery (between rows 1 through 6 and between columns 103 

through 119). All of the indications in steam generators A, B, and C were single circumferential 

indications.

To confirm the indications, five different inspection methods were used on some of the 

indications: plus-point, Ghent, 3 Coil Delta, and the 0.080 and 0.115 pancake coils. All of the 

inspection methods confirmed the indications with the exception that the 0.080 pancake coil did 

not find some of the small amplitude signals. Given these results, the licensee concluded that 

these indications were cracks. Some indications near the top of the tubesheet were identified 

with the plus-point probe but not confirmed with the Ghent, 3 Coil Delta probe or the 0.080 coil. 

These indications had voltages of about 0.06 volts to 0.08 volts, and were not treated as cracklike indications.
3-106

The largest circumferential crack-like indication was measured to have a circumferential extent 

of 216 degrees. The maximum depth reported for the circumferential indications was 74

percent throughwall. The largest percent degraded area for the circumferential indications was 

about 18 percent. The indication with the largest circumferential extent was not the same 

indication that had the maximum depth or the largest percent degraded area. The voltages 

associated with the circumferential indications were about 0.2 volts, although there was one 

indication that had a voltage of 0.55 volts. The plus-point data were reviewed for the tubes 

indicating outside-diameter stress corrosion cracking during this outage. No precursor signals 

in these tubes were found. 

The single axial indication was 11.7 mm (0.46 in.) long and had a maximum depth of 92 percent

throughwall. The voltage was 1.77 volts.

Inspection and maintenance on the secondary side of the steam generators were performed 

during RFO 13. FOSAR was performed in each of the four steam generators. The scope for 

the FOSAR inspections included the periphery of the tube bundle and the no-tube-lane at the 

top of the tubesheet. In addition, FOSAR inspections were performed to confirm that loose 

parts that could not be retrieved from the steam generators in prior outages were still at their 

previously identified locations. In addition, volumetric indications potentially attributable to wear 

from loose parts discovered during RFO 13 were visually inspected on the secondary side (if 

possible). These latter inspections were performed in steam generators A, B, and C. No loose 

parts or anomalous conditions were found during the FOSAR inspections.

In addition, inspections using the CECIL system were performed during RFO 13. The CECIL 

system was deployed in each of the four steam generators for the purpose of cleaning and 

inspecting the top of the tubesheet after the chemical cleaning had been completed. The 

system was deployed down several hot-leg side columns in the manway and nozzle sides in 

steam generators A and D, and in the nozzle side only in steam generator B. The initial 

inspections performed with CECIL revealed that minimal deposit remained in steam generator B 

after the chemical cleaning. In steam generators A and D, foreign objects and scale were 

observed in the regions traversed by the CECIL wand. The inspections performed after CECIL 

cleaning revealed no foreign objects and minimal scale.

In-bundle inspections were performed in steam generator A above the seventh tube support 

plate in a few columns of tubes on the hot- and cold-leg sides of the steam generator. The 

columns were found to be free of foreign objects and sludge. The quatrefoil holes and lands 

were clean and open. No anomalous conditions were observed in the seventh tube support 

plate inspection.

On April 9, 2008, the steam generator portion of the Vogtle 1 technical specifications was 

revised to permit certain-sized flaws near the tube end in both the hot- and cold-leg sides of the 

steam generator to remain in service. Specifically, the technical specifications were revised to 

(1) permit flaws having a circumferential component less than or equal to 203 degrees found in 

the portion of the tube below 43.2 cm (17 in.) from the top of the tubesheet and above 2.54 cm 

(1 in.) from the bottom of the tubesheet to remain in service, (2) require the removal from 

service all flaws having a circumferential component greater than 203 degrees found in the 

portion of the tube below 43.2 cm (17 in.) from the top of the tubesheet and above 2.54 cm 

(1 in.) from the bottom of the tubesheet, (3) require the removal from service all tubes with 

service-induced flaws between the top of the tubesheet and 43.2 cm (17 in.) below the top of 
3-107

the tubesheet, and (4) permit all axial indications found in the portion of the tube below 43.2 cm 

(17 in.) from the top of the tubesheet to remain in service. 

In addition, the technical specifications were modified to indicate that when more than one flaw 

with circumferential components is found in the portion of the tube below 43.2 cm (17 in.) from 

the top of the tubesheet and above 2.54 cm (1 in.) from the bottom of the tubesheet with the 

total of the circumferential components being greater than 203 degrees and the axial separation 

distance of less than 2.54 cm (1 in.), then the tube must be removed from service (overlapping 

portions of the flaws only need to be counted once in determining the total circumferential 

involvement of the flaws). For flaws within 2.54 cm (1 in.) of the bottom of the tubesheet, the 

technical specifications were modified to indicate (1) when one or more flaws with 

circumferential components are found and the total of the circumferential components exceeds 

94 degrees, then the tube shall be removed from service and (2) when one or more flaws with 

circumferential components are found in the portion of the tube within 2.54 cm (1 in.) from the 

bottom of the tubesheet and within 2.54 cm (1 in.) axial separation distance of a flaw above 

2.54 cm (1 in.) from the bottom of the tubesheet, and the total of the circumferential components 

found in the tube exceeds 94 degrees, then the tube shall be removed from service (overlapping 

portions of the flaws only need to be counted once in determining the total circumferential 

involvement of the flaws). This revision to the technical specifications was applicable only to 

RFO 14 and the subsequent operating cycle (ADAMS Accession No. ML080950232).

There was no evidence of primary-to-secondary leakage during Cycle 14 (fall 2006 to spring 

2008).

During RFO 14 in 2008, 100 percent of the tubes in steam generators A and D were inspected 

full length with a bobbin coil, except for the U-bend region of tubes in rows 1 and 2. In addition 

to the bobbin coil inspections, a rotating probe equipped with a plus-point coil was used to 

inspect:

• 100 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the hot-leg side in all four steam generators 

• the U-bend region of 50 percent of row 1 and row 2 tubes in steam generators A and D 

(including all row 1 and row 2 tubes not inspected during RFO 12)

• 100 percent of the tubes from the hot-leg tube end to 43.2 cm (17 in.) below the top of 

the tubesheet on the hot-leg side of the steam generator (i.e., the lowermost 10.2 cm 

(4 in.) of tube) in steam generators B and C

• 25 percent of the tubes from the hot-leg tube end to 43.2 cm (17 in.) below the top of the 

tubesheet on the hot-leg side of the steam generator (i.e., approximately the lowermost

10.2 cm (4 in.) of tube) in steam generators A and D 

• 25 percent of the bulges and overexpansions in the hot-leg side of the tubesheet from 

7.62 cm (3 in.) above to 43.2 cm (17 in.) below the top of the tubesheet in steam 

generator A 

• 100 percent of the bulges and overexpansions in the hot-leg side of the tubesheet from 

7.62 cm (3 in.) above to 43.2 cm (17 in.) below the top of the tubesheet in steam 

generators B, C, and D
3-108

• 100 percent of dents and dings in the U-bend region with bobbin voltage amplitudes 

greater than or equal to 5 volts in steam generators A and D 

In addition to these eddy current inspections, all tube plugs in all four steam generators were 

inspected visually. These latter inspections did not reveal any evidence that the plugs were 

leaking.

As a result of these inspections, 47 tubes were plugged—2 for wear at the AVBs, 10 for

circumferentially oriented outside-diameter stress corrosion cracking at the top of the tubesheet, 

1 for axially oriented outside-diameter stress corrosion cracking at the top of the tubesheet, 1 for

a geometric discontinuity near the tube end, and 33 for damage resulting from pulling a tube.

The only steam generator tube degradation mechanisms observed during RFO 14 were 

(1) wear at the AVBs, (2) wear attributed to loose parts, (3) axially and circumferentially oriented 

outside-diameter stress corrosion cracking at the expansion transition, and (4) axially and 

circumferentially oriented primary water stress corrosion cracking at the tube ends.

A total of 117 indications of AVB wear were detected in 68 tubes in steam generator A during 

RFO 14. In steam generator D, 172 indications in 94 tubes were detected. The maximum 

depth reported for the AVB wear indications was 43 percent throughwall.

Nine indications of wear attributed to loose parts were identified in eight tubes during RFO 14. 

Only one of these indications was new (i.e., eight of the indications had been detected in prior 

outages). Two of the indications were attributed to wear with the monorail system associated 

with sludge lance equipment. All of the indications except for the new indication were inspected 

visually in prior outages to confirm no loose parts were at the affected location. All of these 

historic indications are on the top of the tubesheet on the hot-leg side of the steam generator. 

The new indication was not inspected visually because no eddy current indication of a possible 

loose part existed at this location. This indication is on the hot-leg near the flow distribution 

baffle.

Crack-like indications were found at the top of the tubesheet in all four steam generators and 

near the tube-end in steam generators B and C. All crack-like indications were on the hot-leg 

side of the steam generator. The crack-like indications near the top of the tubesheet were 

attributed to outside-diameter initiated stress corrosion cracking. Of the 11 tubes with crack-like 

indications, 10 contained circumferentially oriented indications and 1 contained an axially 

oriented indication. The circumferential indications were at the bottom of the hydraulic 

expansion transition. The largest circumferential indications measured 215 degrees and had a 

percent degraded area of 40 percent. The axial indication began at the bottom of the hydraulic 

expansion transition and extended into the expanded section of the tube inside the tube sheet. 

Portions of two of the tubes with outside-diameter initiated indications at the top of the tubesheet 

were removed for destructive examination including the axial indication and one circumferential 

indication. The crack-like indications near the hot-leg tube ends were attributed to primary 

water stress corrosion cracking. Twenty-seven tubes contained crack-like indications. Of 

these, 21 had axially oriented indications and 6 had circumferentially oriented indications. Many 

of the tube end crack-like indications were in row 1 tubes. All of the tubes with tube end 

crack-like indications were left in service because they did not exceed the repair criteria for tube 

end indications (as discussed above).
3-109

One tube was identified with a 159 degree geometric discontinuity near the tube end. As 

discussed above this tube was plugged. Given the location of the signal and its circumferential 

character this tube was plugged even though it was not considered flawed.

Portions of two tubes were removed from steam generator D for destructive examination to 

characterize the morphology of the outside-diameter initiated indications detected near the top 

of the tubesheet on the hot-leg side of the steam generator during RFOs 13 and 14. This 

included the axial indication (in row 11, column 62) and the circumferential indication with the 

largest amplitude (in row 12, column 98). The circumferential indication with the largest 

amplitude did not have the largest measured size in terms of circumferential extent, maximum 

depth, or percent degraded area.

For the tubes being pulled, the expansion joint in the tubesheet was relaxed using a tungsten 

inert gas relaxation process. The tubes were then to be cut below the second tube support 

plate on the hot-leg side of the steam generator. This portion of the tubes would then be pulled 

through the tubesheet and cut into segments of various lengths.

The first four segments of the tube with the axial indication (i.e., row 11, column 62) were 

removed from the steam generator as expected (which included about 86 cm (34 in.) of the 

tube); however, after the fourth segment of the tube was cut, the remaining portion of the tube 

sprang back into the tubesheet since the tube had not been completely cut.

An eddy current probe was inserted into the cold-leg of the tube in row 11, column 62; however 

the probe could not be inserted past the seventh support plate on the cold-leg side of the SG 

(i.e., it could not be inserted into the U-bend region of the tube). Eighteen tubes were identified 

as being affected because of the tube pull operation. Of these 18 tubes, three tubes could not 

pass an eddy current probe. This included the pulled tube and two tubes below the pulled tube 

(i.e., row 9, column 62, and row 10, column 62). The other 15 tubes were in close proximity to 

other tubes. All of these tubes had a different eddy current signature than was present during 

the examinations performed on these tubes earlier in RFO 14. A visual inspection of this region 

showed that the tubes were in close proximity in the U-bend region and between the sixth and 

seventh tube support plates. The scope of the eddy current examinations discussed above 

included a one-to-two tube border around those tubes that were in close proximity (a two-tube 

border was maintained in the direction where the damage was occurring).

A video probe inspection was performed on the inside of the tube in row 11, column 62. This 

inspection revealed minor scarring on the inside surface of the tube, but there was no location 

where the tube was cut. Because the tube in row 11, column 62 was not cut below the second

tube support plate, the whole tube was being pulled through the tubesheet (rather than just the 

portion of the tube below the second tube support plate). This had an effect on the neighboring 

tubes because row 11, column 62, was being pulled toward other tubes.

The tubes that could not pass an eddy current probe would not permit the installation of a 

stabilizer through the U-bend region (A stabilizer is a wire cable installed inside a tube that 

prevents a tube that may sever from affecting a neighboring tube. The U-bend stabilizers are 

12.8 m (505 in.) long and run from the hot-leg tube end through the seventh tube support on the 

cold-leg. The stabilizer ends between supports on the cold-leg.) Since these tubes would not 

permit the installation of a stabilizer, the tubes surrounding these tubes were plugged and 

stabilized. Thirty-three tubes were plugged because of the removal of portion of the tube in row 

11, column 62. This included all tubes that were in close proximity to a neighboring tube. 
3-110

Before plugging the tube in row 11, column 62, the tube was hardrolled into the tubesheet to 

prevent the tube from rotating and pulling out of the tubesheet. In addition, a 12-foot stabilizer 

was installed in the tube in row 11, column 62. The stabilizer has a sleeve-like device to further 

stiffen the tube. The stabilizer will extend about 1 foot above the second tube support plate.

There was no indication that damage occurred at the AVBs or at the seventh tube support plate. 

The axial indication in row 11, column 62, was removed for destructive examination.

The forces used to pull the tube in row 11, column 62, were about 11,000 pounds. The tube 

with the circumferential indication was pulled (after verifying through visual examination that the 

tube was fully cut). It took 9,000 pounds of force to break the tube free from the tubesheet. 

After the expanded part of the tube was removed from the steam generator (about 53 cm or 

21 in.), the remaining portion of the tube essentially fell out of the steam generator.

The destructive examination of the pulled tubes confirmed the presence of outside-diameter 

initiated intergranular stress corrosion cracking within the expansion transition at the top of the 

tubesheet. Three axial cracks were found in the tube at row 11, column 62. The cracks were 

circumferentially separated by about 55-degrees and were 100 percent throughwall. The 

maximum depth of these indications was estimated by eddy current to be about 77 percent

throughwall. Circumferential cracking was found around the entire circumference of the tube in 

row 12, column 98. The maximum depth from the destructive examination was 80 percent

throughwall whereas the eddy current examination estimated the flaws to be 54 percent

throughwall. The percent degraded area was 21 percent from the destructive examination and 

was estimated to be 7.3 percent from the eddy current inspection. Both tubes were burst tested 

and both had burst pressures in excess of three times the normal operating differential 

pressure. The microstructure indicated relatively low amounts of intergranular carbides and 

high amounts of intragranular carbides indicating that the mill-annealing temperature may have 

been too low to put carbon/carbides into solution. Carbon in solution is necessary for the 

thermal treatment process to precipitate the carbides at the grain boundaries (and thereby 

improve corrosion resistance). More information concerning the results of destructive and nondestructive examination of these pulled tubes can be found in the pulled tube report (ADAMS 

Accession No. ML100560265).

On September 24, 2009, the steam generator portion of the Vogtle 1 technical specifications 

was revised to limit the extent of inspection in the tubesheet region. Specifically, the technical 

specifications were revised to exclude the portion of tube that is more than 33.27 cm (13.1 in.)

below the top of the tubesheet from inspection (i.e., approximately the lowermost 20.3 cm (8 in.)

of tube in the tubesheet was excluded from inspection, and hence any flaws that may exist in 

this region are permitted to remain in service). This revision was only applicable for RFO 15 

and the subsequent operating cycle (ADAMS Accession No. ML092170782).

There was no evidence of primary-to-secondary leakage during Cycle 15 (spring 2008 to fall 

2009); however, during plant shutdown, a few radiation monitor alarms indicated the presence 

of activity on the secondary side of the plant. Based on water chemistry samples, the 

primary-to-secondary leakage was from steam generator C. The leak rate was too small to 

measure. With static pressure from the water on the secondary side of steam generator C, 

there was no leakage observed on the primary side of the steam generator.

During RFO 15 in 2009, 100 percent of the tubes in steam generators B and C were inspected 

full length with a bobbin coil, except for the U-bend region of tubes in rows 1 and 2. In addition, 

the following tubes in steam generator D were inspected full length with a bobbin coil: a 
3-111

two-tube box of tubes around the stabilized tubes surrounding the 2008 tube pull location at row 

11, column 62, and the tubes in columns 61, 62, and 63 in rows 14 through 25 (the tubes above 

the pulled tube). In addition to the bobbin coil inspections, a rotating probe equipped with a 

plus-point coil was used to inspect:

• 100 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the hot-leg side in all four steam generators 

• the U-bend region of 100 percent of row 1 and row 2 tubes in all four steam generators,

the U-bend region of 20 percent of row 3 tubes in steam generator C

• 35 percent of the tubes from 7.62 cm (3 in.) above to 35.6 cm (14 in.) below the top of 

the tubesheet on the hot-leg side in all four steam generators (which resulted in almost 

100 percent of the bulges and overexpansions in the steam generators being inspected)

• 25 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the cold-leg side of steam generators B and C

• 100 percent of dents and dings with bobbin voltage amplitudes greater than or equal to 

2 volts in the hot-leg straight length in steam generators B and C 

In addition to these eddy current inspections, all tube plugs in all four steam generators were 

inspected visually. These latter inspections did not reveal any evidence that the plugs were 

leaking.

As a result of these inspections, 25 tubes were plugged—2 for wear at the AVBs, 20 for

circumferentially oriented outside-diameter stress corrosion cracking at the top of the tubesheet, 

1 for axially oriented primary water stress corrosion cracking at the hot-leg tangent point, 1 for a 

permeability variation, and 1 for a restriction.

The only steam generator tube degradation mechanisms observed during RFO 15 were 

(1) wear at the AVBs, (2) wear attributed to loose parts, (3) wear attributed to maintenance 

activities, (4) circumferentially oriented outside-diameter stress corrosion cracking at the top of 

the tubesheet on the hot-leg side of the steam generator, and (5) axially oriented primary water 

stress corrosion cracking at the hot-leg tangent point in a row 1 tube.

A total of 152 indications of wear at the AVBs were detected in 73 tubes in steam generator B 

and 154 indications of wear at the AVBs were detected in 85 tubes in steam generator C. The 

maximum depth reported for the AVB wear indications was 46 percent throughwall.

Ten indications of wear attributed to loose parts were detected during RFO 15. Six indications 

of wear in three tubes were attributed to past application of UEC to the steam generators. 

These indications have not changed since discovery in RFO 13. One indication of wear 

attributed to PPC was detected in RFO 15. This indication has not changed in the last three 

inspections of the tube.

Twenty tubes were identified with either single or multiple circumferentially oriented indications 

of outside-diameter stress corrosion cracking at the bottom of the hydraulic expansion transition 

at the top of the tubesheet on the hot-leg side of the steam generators. The percent degraded 

area for these indications ranged up to 19.3 percent, and the largest amplitude was 0.31 volts. 

Many of these circumferential indications were in tubes in low rows and high columns.
3-112

One tube was identified with an axially oriented primary water stress corrosion crack at the hotleg tangent point in a row 1 tube. The crack indication was approximately 7.9 cm (3.1 in.) above 

the seventh hot-leg tube support. The indication was close to the apex of the tube on the 

extrados of the tube. The crack indication is next to a manufacturing indication. There was no 

change in the eddy current signal for this manufacturing indication from the preservice

inspection in 1986 through approximately 2003. The axial length of the crack indication was 

about 1.4 cm (0.54 in.), the maximum depth was 100 percent throughwall, and the voltage

amplitude, as measured from the plus-point coil, was 3.09 volts. This tube was in-situ pressure 

tested and there was no leakage observed at normal operating differential pressures. At the 

differential pressure associated with main steam line break conditions, the leak rate through the 

flaw was about 0.008 lpm (0.002 gpm). The tube did not burst at three times the normal 

operating differential pressure, and the leakage under this condition was about 0.34 lpm 

(0.09 gpm). The flaw in this tube was suspected to be the cause of the primary-to-secondary 

leakage observed during shutdown for RFO 15.

The U-bend region of this tube was inspected in prior outages. The U-bend region was 

inspected with a bobbin coil in 1986 (preservice inspection), 1991, 1993, 1997, and 2000. 

A rotating probe examination of the U-bend region of this tube was also performed in 1997, 

2003, and 2009. The prior inspections of this tube indicated the presence of a manufacturing 

indication, referred to as a Blairsville bump (because the bump was most likely introduced 

during bending of the tube at a facility in Blairsville, PA). This bump is at the start of the bent 

region of the tube (i.e., the start of the U-bend region). During the review of the bobbin coil data 

obtained in 2000, one of the analysts reviewing the data (typically two analysts review all eddy 

current data) identified a nonquantifiable indication at the location where the crack-like indication 

was eventually discovered. This indication was eventually dismissed by the resolution analyst 

(an analyst who oversees the review of the primary and secondary data analysts) because the 

1997 rotating probe examination indicated that no flaws were present at this location, the bobbin 

coil data indicated that the signal had not changed since the 1986 inspection, and there was a 

general absence of any cracking in tubes fabricated from thermally treated Alloy 600 tubing at 

the time of the inspection. During the review of the 2003 rotating probe data, an axial indication 

was reported by one of the analysts at the location where the crack-like indication was 

eventually discovered. This indication was also dismissed by the resolution analyst because the 

indication from the rotating probe did not change appreciably from 1997 (1.75 volts as 

measured from the 300-kHz channel) to 2003 (1.83 volts as measured from the 300-kHz 

channel).

As discussed in NRC IN 2010-21, “Crack-Like Indication in the U-Bend Region of a Thermally 

Treated Alloy 600 Steam Generator Tube,” dated October 6, 2010, NRC staff reviewed the 2003 

and 2009 rotating probe eddy current data for the tube in row 1, column 20. Although NRC staff 

did not have all of the information available to the licensee, NRC staff’s review of the 2003 

rotating probe data indicated the presence of a flaw-like signal. These results highlight the 

limitation of confirming flaw signals based on signals exhibiting change from one inspection to 

the next and the difficulties in detecting new or unexpected forms of degradation.

One tube was plugged because of a restriction. The restriction was about 6.76 cm (2.66 in.)

above the top of the tubesheet on the hot-leg side of the steam generator. Although a probe 

could be pushed past the location of the restriction when the probe was not rotating, once the 

probe was rotating, it would stop rotating at the point of the restriction. This tube was last 

inspected during RFO 14. Visual inspections indicated no abnormal indications or damage on 
3-113

the secondary side of the tube. It is suspected that mechanical damage on the inside diameter 

of the tube from the rotating probe motor most likely caused the probe to stop rotating.

Inspection and maintenance on the secondary side of the steam generators were performed 

during RFO 15. Top of tubesheet sludge lancing, FOSAR, and upper internal steam drum 

visual inspections were performed in all four steam generators. In addition, a UBIB inspection 

and an inspection of the seventh tube support plate was performed in steam generator A. 

Sludge lancing removed 25 pounds of material from all four steam generators. The upper 

internals inspection in all four steam generator indicated mild erosion/corrosion on the swirl 

vanes and mild flow accelerated corrosion on the feedring. No anomalous conditions were 

identified during the UBIB inspection and the inspection of the seventh tube support plate in 

steam generator A. Visual inspection of the area where a tube removal (tube pull) in steam 

generator D resulted in damaging several tubes revealed no indication of movement of the 

tubes.

On March 14, 2011, the steam generator portion of the Vogtle 1 technical specifications was 

revised to limit the extent of inspection in the tubesheet region. Specifically, the technical 

specifications were revised to exclude the portion of tube that is more than 38.6 cm (15.2 in.)

below the top of the tubesheet from inspection (i.e., approximately the lowermost 15.24 cm 

(6 in.) of tube in the tubesheet was excluded from inspection, and hence any flaws that may 

exist in this region are permitted to remain in service). This revision was only applicable for 

RFO 16 and the subsequent operating cycle (ADAMS Accession No. ML110660264).

There was no evidence of primary-to-secondary leakage during Cycle 16 (fall 2009 to spring 

2011).

During RFO 16 in 2011, 100 percent of the tubes in steam generators A and D were inspected 

full length with a bobbin coil, except for the U-bend region of tubes in rows 1 and 2. In addition 

to the bobbin coil inspections, a rotating probe equipped with a plus-point coil was used to 

inspect:

• 100 percent of the tubes from 7.62 cm (3 in.) above to 38.6 cm (15.2 in.) below the top of 

the tubesheet on the hot-leg side in all four steam generators 

• the U-bend region of 100 percent of row 1 and row 2 tubes in all four steam generators 

• 25 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the cold-leg side of steam generators A and D

• 25 percent of dents and dings with bobbin voltage amplitudes greater than or equal to 

2 volts in the hot-leg straight length in all four steam generators 

In addition to these eddy current inspections, all tube plugs in all four steam generators were 

inspected visually. These latter inspections did not reveal any evidence that the plugs were 

leaking.

As a result of these inspections, two tubes were plugged—one for wear attributed to a loose 

part and one for an axially oriented outside-diameter stress corrosion crack indication below the 

bottom of the hot-leg expansion transition.
3-114

The only steam generator tube degradation mechanisms observed during RFO 16 were wear at 

the AVBs, wear attributed to loose parts, and axially oriented outside-diameter stress corrosion 

cracking below the bottom of the expansion transition.

A total of 124 indications of wear at the AVBs were detected in 72 tubes in steam generator A 

and 188 indications of wear at the AVBs were detected in 104 tubes in steam generator D. 

The maximum depth reported for the AVB wear indications was 35 percent throughwall.

Ten indications of wear attributed to loose parts were detected during RFO 16.

One tube was identified with an axially oriented indication of outside-diameter stress corrosion 

cracking, which was below the bottom of the hydraulic expansion transition at the top of the 

tubesheet on the hot-leg side of the steam generator. The indication had a length of 3.3 mm 

(0.13 in.) and a depth of 54.2 percent throughwall. 

Inspection and maintenance on the secondary side of the steam generators were performed 

during RFO 16. Top of tubesheet sludge lancing and FOSAR were performed in all four steam 

generators. FOSAR included the annulus and tube lane region including peripheral tubes, 

historical foreign objects, and possible loose part indications from the eddy current examination. 

Sludge lancing removed 23.5 pounds of material from all four steam generators. Based on 

eddy current data, there was no evidence of change in the area where a tube removal (tube 

pull) in steam generator D resulted in damaging several tubes.

On September 10, 2012, the steam generator portion of the Vogtle 1 technical specifications 

was revised to limit the extent of inspection in the tubesheet region. Specifically, the technical 

specifications were revised to exclude the portion of tube that is more than 38.6 cm (15.2 in.)

below the top of the tubesheet from inspection (i.e., approximately the lowermost 15.24 cm 

(6 in.) of tube in the tubesheet was excluded from inspection, and hence any flaws that may 

exist in this region are permitted to remain in service (ADAMS Accession No. ML12216A056)).

There was no evidence of primary-to-secondary leakage during Cycle 17 (spring 2011 to fall 

2012).

During RFO 17 in 2012, 100 percent of the tubes in steam generators B and C were inspected 

full length with a bobbin coil, except for the U-bend region of tubes in rows 1 and 2. In addition 

to the bobbin coil inspections, a rotating probe equipped with a plus-point coil was used to 

inspect:

• 100 percent of the tubes from 7.62 cm (3 in.) above to 38.6 cm (15.2 in.) below the top of 

the tubesheet on the hot-leg side in all four steam generators

• the U-bend region of 100 percent of row 1 and row 2 tubes in all four steam generators

• 25 percent of dents and dings with bobbin voltage amplitudes greater than or equal to 

2 volts in the hot-leg straight length in all four steam generators

In addition to these eddy current inspections, visual inspections were performed on all tube 

plugs and the low lying areas of the channel heads in all four steam generators. The inspection 

of the plugs did not reveal any evidence of boron deposits around the plugs nor was there any 

evidence of degradation of the plugs. There was no evidence of degradation in the channel 

head.
3-115

As a result of these inspections, three tubes were plugged. All of these tubes were plugged for 

wear at the AVBs.

The only steam generator tube degradation mechanisms observed during RFO 17 were wear at 

the AVBs, wear attributed to maintenance activities, and wear attributed to loose parts.

A total of 181 indications of wear at the AVBs were detected in 91 tubes in steam generator B

and 210 indications of wear at the AVBs were detected in 104 tubes in steam generator C. The 

maximum depth reported for the AVB wear indications was 44 percent throughwall.

Ten indications of wear attributed to loose parts were detected during RFO 17. Most of these 

indications have not changed in size since prior inspections.

Seven indications of wear in four tubes were attributed to past application of UEC to the steam 

generators. These indications have not changed since discovery in RFO 13. Four indications

of wear attributed to PPC were detected in RFO 17. These indications have not changed in size 

since the prior inspection. Two indications in two tubes were attributed to wear associated with 

the sludge lance monorail.

Inspection and maintenance on the secondary side of the steam generators were performed 

during RFO 17. Top of tubesheet sludge lancing and FOSAR were performed in all four steam 

generators. The FOSAR included the annulus and tubelane region including peripheral tubes, 

historical foreign objects, and possible loose part indications from the eddy current examination.

On September 26, 2013, the steam generator portion of the Vogtle 1 technical specifications 

was revised making them consistent with TSTF-510 (ADAMS Accession No. ML13218B274).

3.3.5 Vogtle 2

Tables 3-25, 3-26, and 3-27 summarize the information discussed below for Vogtle 2. 

Table 3-25 provides the number of full-length bobbin inspections and the number of tubes 

plugged and deplugged during each outage for each of the four steam generators. Table 3-26 

lists the reasons why the tubes were plugged. Table 3-27 lists tubes plugged for reasons other 

than wear at the AVBs.

Vogtle 2 has four Westinghouse model F steam generators. The licensee numbers its tube 

supports from the hot-leg flow distribution baffle (FBH or BPH) to 7H on the hot-leg side of the 

steam generator and from FBC/BPC to 7C on the cold-leg side (Figure 2-4).

During RFO 9 in 2002, 100 percent of the tubes in steam generators A and D were inspected 

full length with a bobbin coil, with the exception of the U-bend region of tubes in rows 1 and 2. 

In addition to the bobbin coil inspections, a rotating probe equipped with a plus-point coil was 

used to inspect:

• 50 percent of the tubes (including any tubes not examined in RFO 7) from 7.6 cm (3 in.) 

above to 7.6 cm (3 in.) below the top of the tubesheet on the hot-leg side in steam 

generators A and D

• the U-bend region of 60 percent of row 1 and row 2 tubes (including any tubes not 

examined in RFO 7) in steam generators A and D
3-116

• 100 percent of the dents in the U-bend region with bobbin voltage amplitudes greater 

than or equal to 5 volts in steam generators A and D

In addition, visual inspections were performed on tube plugs.

As a result of these inspections, two tubes were plugged. All tubes were plugged for wear at 

the AVBs.

The only steam generator tube degradation mechanisms observed during RFO 9 were wear at 

the AVBs and wear attributed to loose parts.

Sixty-nine indications of wear at the AVBs were detected in 45 tubes in steam generator A and 

136 indications of wear at the AVBs were detected in 79 tubes in steam generator D. The 

maximum depth reported for the AVB wear indications was 45 percent throughwall.

Two indications of wear attributed to loose parts were detected during RFO 9.

The feedwater ring weld backing rings were inspected during RFO 9, and the results were 

acceptable. Future inspections of these backing rings are planned to be performed at least

once every six refueling outages.

All RFO 7 bobbin data for steam generators A and D was reviewed to determine if any tubes 

exhibited an eddy current offset that could indicate higher residual stresses in the tubes (and 

therefore higher susceptibility to cracking). Cracking associated with tubes with an eddy current 

offset was observed at Seabrook in 2002. No indications of an eddy current offset were 

identified in the RFO 7 bobbin data for steam generators A or D.

On November 24, 2002, both Vogtle units were shut down because of high sodium 

concentrations in the feedwater system. The sodium was introduced into the feedwater system 

when sodium phosphate rather than methoxypropylamine was added to the feedwater system in 

both units. Methoxypropylamine is normally added to the feedwater system for corrosion 

control. 

There was no evidence of primary-to-secondary leakage during Cycle 10 (fall 2002 to spring 

2004).

During RFO 10 in 2004, 100 percent of the tubes in steam generators B and C were inspected 

full length with a bobbin coil, with the exception of the U-bend region of tubes in rows 1 and 2. 

In addition to the bobbin coil inspections, a rotating probe equipped with a plus-point coil was 

used to inspect:

• 100 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the hot-leg side in all four steam generators

• the U-bend region of 50 percent of row 1 and row 2 tubes in steam generators B and C

• 100 percent of the dents and dings in the straight length portion of the tubes on the 

hot-leg side of steam generators B and C with bobbin voltage amplitudes greater than or 

equal to 5 volts
3-117

In addition, a rotating probe equipped with a plus-point coil was used to inspect a sample of 

tubes that were possibly damaged because of the phosphate chemistry excursion discussed 

above. In addition, visual inspections were performed on tube plugs.

As a result of these inspections, 11 tubes were plugged—1 for wear at the AVBs, 1 for a 

permeability variation, and 9 for indications originally attributed to circumferentially oriented 

outside diameter stress corrosion cracking at the expansion transition. 

The only steam generator tube degradation mechanisms observed during RFO 10 were wear at 

the AVBs and circumferentially oriented outside-diameter stress corrosion cracking at the 

expansion transition.

A total of 102 indications of wear at the AVBs were detected in 50 tubes in steam generator B

and 28 indications of wear at the AVBs were detected in 18 tubes in steam generator C. The 

maximum depth reported for the AVB wear indications was 43 percent throughwall.

Nine indications that were originally attributed to circumferentially oriented outside-diameter 

stress corrosion cracking were identified at the top of the hot-leg tubesheet during RFO 10. The 

indications were within or at the hydraulic expansion transition. Of these nine indications, one 

was in steam generator A, three were in steam generator B, three were in steam generator C, 

and two were in steam generator D.

To further characterize the nature of the six indications in steam generators B and C, additional

inspections were performed including slow speed rotating probe inspections, magnetically 

biased rotating probe inspections, and ultrasonic testing (UT). Of the six indications, UT 

confirmed four were present. For the other two, the licensee could not rule out that the 

indications were below the threshold of detection for the UT equipment. The indications were 

sized with the plus-point coil. Most of the indications did not extend more than 60 degrees 

around the tube circumference; however, one did extend to 101 degrees. The deepest flaw was 

estimated to be 38 percent throughwall.

Eight of the nine circumferentially oriented indications were contained within a 20-tube by 

20-tube box near the center of the tube bundle. The UT examination did not confirm the ninth 

indication as being present. The sludge at the top of the tubesheet is characterized as collars of 

deposits surrounding the tubes rather than a consistent height of material between the tubes. 

The average sludge height for steam generators B and C was estimated to be about 2.54 cm 

(1 in.), with a maximum sludge height of about 6.35 cm (2.5 in.). The maximum sludge height is 

only observed on a small number of tubes. The licensee considers the top of the tubesheet 

region as being relatively clean.

Because of the discovery of these indications, portions of two tubes with circumferential 

indications were pulled from steam generator B (row 11, column 60, and row 12, column 59) for 

destructive examination. These tubes are in the central region of the tube bundle and therefore 

are not supported by the flow distribution baffle. These tubes were cut below the second tube 

support plate on the hot-leg side. The force needed to break the tube in row 12, column 59, free 

from the tubesheet and the tube support plate was about 3,600 pounds while the force needed 

to break the tube free in row 11, column 60, was about 3,300 pounds. The licensee indicated 

that based on the tube pull force measurements and the visual observation of a limited amount 

of deposits on the tube in the tube support plate region, no evidence existed to suggest that the 

two pulled tubes were locked-in at the tube support plate. Welded plugs were installed on the 
3-118

hot-leg side and mechanical plugs were installed on the cold-leg side in the tube holes of these 

two tubes.

The laboratory examination indicated that both pulled tubes exhibited a ring of gray/brownish 

deposit at, and slightly above, the expansion transition region. The height of this deposit was 

about 12.7 mm (0.5 in.) and it was about 0.1 to 0.2 mm (4 to 8 mils) in thickness. A dark grayish 

deposit was observed extending about 2.54 to 3.8 cm (1 to 1.5 in.) above the collar deposit on 

both tubes. A relatively thin and uniform gray oxide was noted on all remaining tube surfaces 

above the top of the tubesheet region. Although laboratory eddy current and ultrasonic testing 

detected signals that indicate deposits, none of the field signals indicative of crack-like 

indications were present in the laboratory-obtained data. Destructive (metallographic) 

examination of the top of the tubesheet region of row 12, column 59, showed no evidence of 

degradation. Although there was indication of copper and lead in the oxide deposit on the tube, 

no indication of corrosion initiation existed. Metallographic examination was not performed on 

the portion of the tube in row 11, column 60. The root cause of the field flaw-like signals was 

not identified; however, the licensee concluded that the false positive indications could be the 

result of the non-homogeneous scale or deposits on the tubes at the top of the tubesheet on the 

hot-leg side of the steam generators.

The laboratory evaluation of the field eddy current data indicated that the flaw-like signals from 

the eddy current data were not at the same azimuthal location as the ultrasonic indications. The 

flaw-like signals from the eddy current data were separated from the ultrasonic indications by 

about 90 to 150 degrees. Because of the findings from the laboratory evaluation, the licensee 

investigated techniques for differentiating flaw-like signals from deposits using eddy current 

techniques.

For RFO 10, all RFO 8 bobbin data from steam generators B and C were reviewed to determine 

if any tubes exhibited an eddy current offset that could indicate higher residual stresses was 

present. Because of this review, one high row tube was identified as having an eddy current 

offset. This tube (in row 40, column 48, in steam generator B) had two indications of wear at the 

AVBs, but did not contain any precursor signals indicative of stress corrosion cracking. This 

tube was left in service.

No evidence of tube damage from the phosphate chemical excursion was found during the 

rotating probe examinations.

On September 21, 2005, the steam generator portion of the Vogtle 2 technical specifications 

was revised to limit the extent of inspection in the hot-leg tubesheet region. Specifically, the 

technical specifications were revised to exclude the portion of tube that is more than 43.2 cm 

(17 in.) below the top of the tubesheet from inspection (i.e., approximately the lowermost 10.2 

cm (4 in.) of tube in the tubesheet on the hot-leg side was excluded from inspection, and hence 

any flaws that may exist in this region are permitted to remain in service). This revision was 

applicable only to RFO 11 and the subsequent operating cycle (ADAMS Accession No. 

ML052630014).

During RFO 11 in 2005, 100 percent of the tubes in steam generators A and D were inspected 

full length with a bobbin coil, with the exception of the U-bend region of tubes in rows 1 and 2. 

In addition to the bobbin coil inspections, a rotating probe equipped with a plus-point coil was 

used to inspect:
3-119

• 50 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the hot-leg side in steam generators A and D

• 100 percent of the overexpansions (greater than or equal to 0.038 mm (1.5 mils)) and 

bulges (with bobbin voltage amplitudes greater than or equal to 18 volts) within the 

upper 43.2 cm (17 in.) of the tubesheet on the hot-leg side in steam generators A and D

• the U-bend region of 50 percent of row 1 and row 2 tubes in steam generators A and D

• 100 percent of the dents and dings in the straight length portion of the tubes on the hotleg side of the steam generator with bobbin voltage amplitudes greater than or equal to 

5 volts in steam generators A and D

• about 60 to 80 tubes at the sixth and seventh tube support plates on the hot-leg side to 

ascertain the degree of blockage of the quatrefoil openings by deposits in steam 

generators A and D

In addition, tube plugs were inspected visually.

As a result of these inspections, no tubes were plugged.

The only steam generator tube degradation mechanisms observed during RFO 11 were wear at 

the AVBs and wear attributed to loose parts.

Sixty-six indications of wear at the AVBs were detected in 44 tubes in steam generator A, and 

151 indications of wear at the AVBs were detected in 84 tubes in steam generator D. The 

maximum depth reported for the AVB wear indications was 34 percent throughwall.

Two indications of wear attributed to loose parts were detected in two tubes during RFO 11.

An assessment of blockage of the tube support plate openings was performed during RFO 11. 

This assessment indicated that deposits were largely concentrated in the upper portion of the 

bundle on the hot-leg side. On the hot-leg side of the seventh tube support plate, the lobes that 

permit the passage of the water-steam mixture were not blocked; however, there were some 

quatrefoil lobes that were partially blocked by rings of deposits on the tubes on the bottom side 

of the tube support plate, with one location estimated to be 20-30 percent blocked. There were 

no observable gaps between the tubes and the tube support plate quatrefoil lands on the hot-leg 

side for tube support plate 7 (i.e., the deposit on the tube and the tube support plate merge to 

form a continuous field). The gaps between the tubes and the tube support plates on the coldleg side were visible, and only partially filled in a fraction of the tubes. On the hot-leg side of the 

sixth tube support plate, the lobes that permit the passage of the water-steam mixture were not 

blocked; however, most of the gaps between the tubes and the tube support plate quatrefoil 

lands were not visible. On the cold-leg side of the sixth tube support plate, these gaps are 

largely unfilled. The blockage observed has not resulted in any discernible effect on steam 

generator water level control.

For RFO 11, all RFO 9 bobbin data from steam generators A and D were reviewed to determine 

if an eddy current offset that could indicate higher residual stresses was present. No indications 

of an eddy current offset were identified in the low-row tubes in the RFO 9 bobbin data for 

steam generators A or D.
3-120

During RFO 11, FOSAR was performed in each of the four steam generators. FOSAR included

visual inspection of the annulus area at the top of the tubesheet and inspection of the tube-lane,

which runs through the center of the bundle at the top of the tubesheet. The FOSAR also 

included visual inspection of possible loose part indications identified during the eddy current 

inspection. Possible loose part indications only were identified in the steam generator A eddy 

current data. Eleven foreign objects were detected in steam generators A (three objects), 

B (two objects), and D (six objects). Of these 11 objects, 10 were removed. The foreign object 

that could not be retrieved was in the tube lane of steam generator A and was characterized as 

scale or a metal turning measuring 6.35 mm (0.250 in.) by 7.938 mm (0.03125 in.) by 3.177 mm 

(0.125 in.). A licensee analysis showed that leaving this object in the steam generator would 

not compromise tube integrity before the next inspection.

On August 28, 2006, Vogtle 2 revised the steam generator portion of their technical 

specifications making them performance-based consistent with TSTF-449 (ADAMS Accession 

No. ML062360577).

On September 12, 2006, the steam generator portion of the Vogtle 2 technical specifications 

was revised to limit the extent of inspection in the hot-leg tubesheet region. Specifically, the 

technical specifications were revised to exclude the portion of tube that is more than 43.2 cm 

(17 in.) below the top of the tubesheet from inspection (i.e., approximately the lowermost 10.2 

cm (4 in.) of tube in the tubesheet on the hot-leg side was excluded from inspection, and hence 

any flaws that may exist in this region are permitted to remain in service). This revision was 

applicable only to RFO 12 and the subsequent operating cycle (ADAMS Accession No. 

ML062260302).

During RFO 12 in 2006, 100 percent of the tubes in steam generators B and C were inspected 

full length with a bobbin coil, with the exception of the U-bend region of tubes in rows 1 and 2. 

In addition to the bobbin coil inspections, a rotating probe equipped with a plus-point coil was 

used to inspect:

• greater than 50 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the 

top of the tubesheet on the hot-leg side (including areas of special interest identified at 

Vogtle 1 during RFO 13 such as the 216 low-row, high-column tubes) in steam 

generators B and C

• 100 percent of the overexpansions and bulges from 7.62 cm (3 in.) above to 43.2 cm 

(17 in.) below the top of the tubesheet on the hot-leg side (which equates to 31 tubes in 

steam generator B and 25 tubes in steam generator C) in steam generators B and C

• the U-bend region of 50 percent of row 1 and row 2 tubes in steam generators B and C

• 100 percent of the dents and dings in the U-bends and the straight length portion of t he 

tubes on the hot-leg side of the steam generator with bobbin voltage amplitudes greater 

than or equal to 5 volts in steam generators B and C

In addition, tube plugs were inspected visually.

As a result of these inspections, no tubes were plugged.

The only steam generator tube degradation mechanisms observed during RFO 12 were wear at 

the AVBs and wear attributed to maintenance equipment.
3-121

A total of 116 indications of wear at the AVBs were detected in 56 tubes in steam generator B, 

and 26 indications of wear at the AVBs were detected in 16 tubes in steam generator C. 

The maximum depth reported for the AVB wear indications was 39 percent throughwall.

The indication attributed to secondary-side maintenance tooling was visually inspected and 

there was no indication of a loose part at the location of the wear scar. The damage was 

suspected to have occurred during RFO 11.

During RFO 12, all four steam generators were chemically cleaned. Full-bundle chemical 

cleaning was performed to reduce the deposit loading so as to limit the potential for tube 

corrosion and to eliminate the potential that severe secondary fouling would cause significant

power reductions. The compositions of the iron removal solutions were based on the 

anticipated sludge and tube deposit inventories. This chemical cleaning operation incorporated 

elements of the EPRI/SGOG process and employed several phases where temperature 

adjustments were made to facilitate dissolution in specific regions of the tube bundle such as 

the tube support plate openings and the top of tubesheet sludge region. Multiple rinse 

operations washed away the chemicals used to remove the residual iron before the 

copper-removal phase of the cleaning process. The process was completed after similar rinse 

steps following the copper-removal step. The chemical cleaning along with the follow-up 

mechanical cleaning techniques (e.g., CECIL) removed 4,957 pounds of deposits.

During RFO 12, FOSAR was performed in each of the four steam generators. The FOSAR 

included visual inspection of the annulus area at the top of the tubesheet (i.e., periphery of the 

tube bundle) and inspection of the tube-lane, which runs through the center of the bundle at the 

top of the tubesheet. FOSAR also included visual inspection of locations with wear attributed to 

possible loose parts (PLPs). Two small diameter wires and a screw were detected and 

removed during FOSAR. There was a limited amount of scale observed on the top of the 

tubesheet and no anomalous conditions were observed. 

The CECIL system was deployed in each of the four steam generators after the chemical 

cleanings were completed to clean and inspect the top of the tubesheet. Inspections performed 

after the CECIL cleaning revealed only residual amounts of hard deposit on the top of the 

tubesheet.

During RFO 12, seventh tube support plate was inspected visually in select columns in the 

steam generators. The columns were free of foreign objects and sludge, and the quatrefoil 

holes were clean and open. No anomalous conditions were observed during the inspection of 

the seventh tube support plate.

On September 16, 2008, the steam generator portion of the Vogtle 2 technical specifications 

was revised to permit certain sized flaws near the tube end in both the hot- and cold-leg sides of 

the steam generator to remain in service. Specifically, the technical specifications were revised 

to (1) permit flaws having a circumferential component less than or equal to 203 degrees found 

in the portion of the tube below 43.2 cm (17 in.) from the top of the tubesheet and above 

2.54 cm (1 in.) from the bottom of the tubesheet to remain in service, (2) require the removal 

from service all flaws having a circumferential component greater than 203 degrees found in the 

portion of the tube below 43.2 cm (17 in.) from the top of the tubesheet and above 2.54 cm 

(1 in.) from the bottom of the tubesheet, (3) require the removal from service all tubes with 

service-induced flaws between the top of the tubesheet and 43.2 cm (17 in.) below the top of 
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the tubesheet, and (4) permit all axial indications found in the portion of the tube below 43.2 cm 

(17 in.) from the top of the tubesheet to remain in service. 

In addition, the technical specifications were modified to indicate that when more than one flaw 

with circumferential components is found in the portion of the tube below 43.2 cm (17 in.) from 

the top of the tubesheet and above 2.54 cm (1 in.) from the bottom of the tubesheet with the 

total of the circumferential components being greater than 203 degrees and the axial separation 

distance of less than 2.54 cm (1 in.), then the tube must be removed from service (overlapping 

portions of the flaws only need to be counted once in determining the total circumferential 

involvement of the flaws). For flaws within 2.54 cm (1 in.) of the bottom of the tubesheet, the 

technical specifications were modified to indicate (1) when one or more flaws with 

circumferential components are found and the total of the circumferential components exceeds 

94 degrees, then the tube shall be removed from service and (2) when one or more flaws with 

circumferential components are found in the portion of the tube within 2.54 cm (1 in.) from the 

bottom of the tubesheet and within 2.54-cm (1-in.) axial separation distance of a flaw above 

2.54 cm (1 in.) from the bottom of the tubesheet, and the total of the circumferential components 

found in the tube exceeds 94 degrees, then the tube shall be removed from service (overlapping 

portions of the flaws only need to be counted once in determining the total circumferential 

involvement of the flaws). This revision to the technical specifications was applicable only to 

RFO 13 and the subsequent operating cycle (ADAMS Accession No. ML082530038).

There was no evidence of primary-to-secondary leakage during Cycle 13 (i.e., spring 2007 to 

fall 2008).

During RFO 13 in 2008, 100 percent of the tubes in steam generators A and D were inspected 

full length with a bobbin coil, with the exception of the U-bend region of tubes in rows 1 and 2. 

In addition to the bobbin coil inspections, a rotating probe equipped with a plus-point coil was 

used to inspect:

• greater than 50 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the 

top of the tubesheet on the hot-leg side in steam generators A and D 

• 40 percent of the tubes from the hot-leg tube end to 10.24 cm (4.03 in.) above the 

hot-leg tube end in steam generators A and D 

• 34 tubes in steam generator A and 63 tubes in steam generator D from the hot-leg tube 

end to 7.62 cm (3 in.) above the top of the tubesheet (this resulted in inspecting 

74 percent of the overexpansions (greater than 0.038 mm (1.5 mils) deviation in tube 

diameter) and bulges (signal greater than or equal to 18 volts as measured with a bobbin 

coil) that exist from 7.62 cm (3 in.) above to 43.2 cm (17 in.) below the top of the 

tubesheet on the hot-leg side in steam generator A and 88 percent of the bulges and 

overexpansions in the same region in steam generator D)

• 15 tubes in steam generator A and 61 tubes in steam generator D from the hot-leg tube 

end to 10.2 cm (4 in.) above the hot-leg tube end (this resulted in inspecting 71 percent

of the bulges and overexpansions in this region in steam generator A and 54 percent of 

the bulges and overexpansions in this region in steam generator D)

• the U-bend region of 50 percent of row 1 and row 2 tubes (including all U-bends in these 

rows not inspected during RFO 11) in steam generators A and D
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• 100 percent of the dents and dings in the U-bends with bobbin voltage amplitudes 

greater than or equal to 2 volts (with the total number of inspected dents and dings to 

constitute no less than 25 percent of the total dents and dings with bobbin voltage 

amplitudes greater than or equal to 2 volts and with any additional inspections being 

selected from the straight leg portion of the tubes on the hot-leg)

In addition, tube plugs were inspected visually, which revealed no evidence of plug leakage.

As a result of these inspections, one tube was plugged. This tube was plugged for wear at the 

AVBs.

The only steam generator tube degradation mechanisms observed during RFO 13 were wear at 

the AVBs, wear attributed to foreign objects, and wear from secondary-side cleaning activities.

About 70 indications of wear at the AVBs were detected in 45 tubes in steam generator A, and 

178 indications of wear at the AVBs were detected in steam generator D. The maximum depth 

reported for the AVB wear indications was 44 percent throughwall.

Five volumetric indications were detected in four tubes during RFO 13. The maximum depth 

reported for these indications was 24 percent throughwall. At the time of the RFO 13 

inspection, all of these indications were attributed to wear from secondary-side cleaning 

activities. However, in RFO 16, one of these five volumetric indications was reclassified as 

wear attributed to a foreign object. All five volumetric indications were observed in prior 

inspections and remain unchanged.

FOSAR was performed in steam generators A and D. In steam generator A, five possible loose 

part indications were visually inspected during the FOSAR. These inspections indicated that no 

foreign objects were present. There was, however, sludge agglomerations. In steam generator 

D, 12 foreign objects were identified during the FOSAR. Of these, only one was removed from 

the steam generator. An analysis by the licensee indicated it was acceptable to leave the 

11 objects in place until the next inspection (i.e., for at least two cycles).

On September 24, 2009, the steam generator portion of the Vogtle 2 technical specifications 

was revised to limit the extent of inspection in the tubesheet region. Specifically, the technical 

specifications were revised to exclude the portion of tube that is more than 33.27 cm (13.1 in.)

below the top of the tubesheet from inspection (i.e., approximately the lowermost 20.3 cm (8 in.)

of tube in the tubesheet was excluded from inspection, and hence any flaws that may exist in 

this region are permitted to remain in service). This revision was only applicable for RFO 14 

and the subsequent operating cycle (ADAMS Accession No. ML092170782).

There was no evidence of primary-to-secondary leakage during Cycle 14 (i.e., fall 2008 to 

spring 2010).

During RFO 14 in 2010, 100 percent of the tubes in steam generators B and C were inspected 

full length with a bobbin coil, with the exception of the U-bend region of tubes in rows 1 and 2. 

In addition to the bobbin coil inspections, a rotating probe equipped with a plus-point coil was 

used to inspect:

• 50 percent of the tubes in steam generators B and C from 7.62 cm (3 in.) above to 33.27 

cm (13.1 in.) below the top of the tubesheet on the hot-leg side, which included the 

bulges (a signal greater than or equal to 18 volts as measured with a bobbin coil) and 
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overexpansions (greater than or equal to 1.5 mil deviation in tube diameter) that were 

not tested in RFO 12

• the U-bend region of 50 percent of row 1 and row 2 tubes (including all U-bends in these 

rows not inspected during RFO 12) in steam generators B and C

• 100 percent of the dents and dings in the straight leg portion of tubing in the hot-leg with 

bobbin voltage amplitudes greater than or equal to 2 volts in steam generators B and C 

(with the total number of inspected dents and dings to constitute no less than 25 percent

of the total dents and dings with bobbin voltage amplitudes greater than or equal to 2 

volts and with any other inspections being selected from the U-bend portion of the tubes)

In addition, tube plugs were inspected visually. These latter inspections revealed no 

degradation and there was no evidence of plug leakage.

As a result of these inspections, two tubes were plugged. These tubes were plugged for wear 

at the AVBs.

The only steam generator tube degradation mechanisms observed during RFO 14 were wear at 

the AVBs and wear attributed to secondary-side cleaning activities (interaction between the tube 

and sludge lance equipment).

A total of 132 indications of wear at the AVBs were detected in 65 tubes in steam generator B, 

and 50 indications of wear at the AVBs were detected in 30 tubes in steam generator C. The 

maximum depth reported for the AVB wear indications was 46 percent throughwall.

One indication of wear attributed to secondary-side cleaning activities was detected in steam 

generator C. The wear occurred before RFO 10. The maximum depth reported for this 

indication was 21 percent throughwall.

There are no low-row tubes (i.e., rows 1 through 10) in any of the four steam generators that 

have an eddy current offset that would indicate the tubes had elevated residual stresses. 

However, there are 108 high-row tubes (i.e., tubes in rows 11 and higher) that do not have the 

expected eddy current signal offset (23 tubes in rows 12 through 40 in steam generator A, 

32 tubes in rows 13 through 49 in steam generator B, 31 tubes in rows 11 through 35 in steam 

generator C, and 22 tubes in rows 12 through 49 in steam generator D).

Inspection and maintenance on the secondary side of the steam generators were performed 

during RFO 14. Sludge lancing and FOSAR were performed in all four steam generators. 

Thirty-five pounds of sludge were removed from the steam generators. The FOSAR was 

performed in the tube lane. A UBIB visual inspection was performed in steam generator B. 

This inspection was from the top of tube support plate 3 to the bottom of tube support plate 7. 

There was no evidence of erosion, flow-accelerated corrosion, or cracking of the tube support 

plate ligaments. There was no flow hole blockage and there were no significant deposits in the 

quatrefoil shaped holes noted. The freespan region of the tubes was free of denting. There 

were no dense deposits identified in the tube bundle; however, light scale was observed on the 

tubes.

On March 14, 2011, the steam generator portion of the Vogtle 2 technical specifications was 

revised to limit the extent of inspection in the tubesheet region. Specifically, the technical 

specifications were revised to exclude the portion of tube that is more than 38.6 cm (15.2 in.)
3-125

below the top of the tubesheet from inspection (i.e., approximately the lowermost 15.2 cm (6 in.)

of tube in the tubesheet was excluded from inspection, and hence any flaws that may exist in 

this region are permitted to remain in service). This revision was only applicable for RFO 15 

and the subsequent operating cycle (ADAMS Accession No. ML110660264).

There was no evidence of primary-to-secondary leakage during Cycle 15 (i.e., spring 2010 to 

fall 2011).

During RFO 15 in 2011, 100 percent of the tubes in steam generators A and D were inspected 

full length with a bobbin coil, with the exception of the U-bend region of tubes in rows 1 and 2. 

In addition to the bobbin coil inspections, a rotating probe equipped with a plus-point coil was 

used to inspect:

• 50 percent of the tubes in steam generators A and D from 7.62 cm (3 in.) above to 

38.6 cm (15.2 in.) below the top of the tubesheet on the hot-leg side, which included 

bulges (a signal greater than or equal to 18 volts as measured with a bobbin coil) and 

overexpansions (greater than or equal to 1.5 mil deviation in tube diameter) within this 

region

• the U-bend region of 50 percent of row 1 and row 2 tubes in steam generators A and D

• 50 percent of the dents and dings in the straight leg portion of tubing in the hot-leg and in 

the U-bend with bobbin voltage amplitudes greater than or equal to 2 volts in steam 

generators A and D

In addition, all tube plugs were inspected visually in steam generators A and D. These latter 

inspections revealed no evidence of plug leakage.

As a result of these inspections, one tube was plugged. This tube was plugged for wear at the 

AVBs.

The only steam generator tube degradation mechanisms observed during RFO 15 were wear at 

the AVBs, wear attributed to foreign objects, and wear from secondary-side cleaning activities.

A total of 76 indications of wear at the AVBs were detected in 48 tubes in steam generator A, 

and 184 indications of wear at the AVBs were detected in 109 tubes in steam generator D. The 

maximum depth reported for the AVB wear indications was 44 percent throughwall.

Two sets of potential loose-part indications were detected in steam generator A. Visual 

inspection of the regions did not identify any foreign objects. One tube near one of the locations 

with possible loose part indications had a wear indication measuring 8 percent throughwall.

Six indications of wear attributed to secondary-side cleaning were identified in five tubes during 

RFO 15. The maximum depth reported for these indications was 24 percent throughwall. There 

has been no change in these indications since the prior inspection in RFO 13.

Inspection and maintenance on the secondary side of the steam generators were performed 

during RFO 15. Top of tubesheet sludge lancing, FOSAR and upper internal steam drum 

inspections were performed in all four steam generators. FOSAR inspections included the 

annulus and the no-tube lane, including the peripheral tubes and possible loose part indications 
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identified during the eddy current inspections. Sludge lancing removed 17.5 pounds of material 

from the steam generators.

The upper internal steam drum inspections included the secondary moisture separators, primary 

moisture separators, downcomer barrel and tangential nozzle assemblies, all deck plates, and 

the feedwater distribution rings. Wall thickness measurements of all four feedwater rings were 

made using ultrasonic testing. Additional visual inspections were performed within the 

feedwater rings and their J-nozzles as well as visual inspection of the weld backing rings. All 

components were found to have a uniform coating of tightly adhering magnetite. None of the 

weld backing rings revealed changes from the inspections performed during RFO 9. Visual 

inspections within all four steam generator feedwater rings revealed signs of base material loss 

on a limited number of feedwater ring to J-nozzle joints. Ultrasonic thickness testing of the 

feedwater rings identified areas of local thinning. An evaluation indicated that the conditions are 

not expected to impair the thermal performance function or structural integrity of the feedwater 

rings or other upper steam drum components nor are they expected to develop loose fragments 

that could affect the steam generator tubes.

On September 10, 2012, the steam generator portion of the Vogtle 2 technical specifications 

was revised to limit the extent of inspection in the tubesheet region. Specifically, the technical 

specifications were revised to exclude the portion of tube that is more than 38.6 cm (15.2 in.)

below the top of the tubesheet from inspection (i.e., approximately the lowermost 15.2 cm (6 in.)

of tube in the tubesheet was excluded from inspection, and hence any flaws that may exist in 

this region are permitted to remain in service (ADAMS Accession No. ML12216A056)).

There was no evidence of primary-to-secondary leakage during Cycle 16 (i.e., fall 2011 to 

spring 2013).

During RFO 16 in 2013, 100 percent of the tubes in steam generators B and C were inspected 

full length with a bobbin coil, with the exception of the U-bend region of tubes in rows 1 and 2. 

In addition to the bobbin coil inspections, a rotating probe equipped with a plus-point coil was 

used to inspect:

• 100 percent of the tubes in steam generators B and C from 7.62 cm (3 in.) above to 

38.6 cm (15.2 in.) below the top of the tubesheet on the hot-leg side, which included 

bulges (a signal greater than or equal to 18 volts as measured with a bobbin coil) and 

overexpansions (greater than or equal to 1.5 mil deviation in tube diameter) within this 

region

• 20 percent of the tubes in steam generators A and D from 7.62 cm (3 in.) above to 

38.6 cm (15.2 in.) below the top of the tubesheet on the hot-leg side

• the U-bend region of 100 percent of row 1 and row 2 tubes in steam generators B and C

• 100 percent of the dents and dings in the straight leg portion of tubing in the hot-leg and 

in the U-bend with bobbin voltage amplitudes greater than or equal to 2 volts in steam 

generators B and C 

In addition, all tube plugs were inspected visually in all four steam generators. All plugs were 

confirmed to be present and there was no indication of degradation in any of the tube plugs. 

Visual inspections of the channel heads in all four steam generators were also performed, and 

no degradation was observed.
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As a result of these inspections, two tubes were plugged—one for wear at the AVBs, and one 

for circumferentially oriented outside-diameter stress corrosion cracking at the expansion 

transition.

The only steam generator tube degradation mechanisms observed during RFO 16 were 

(1) wear at the AVBs, (2) wear attributed to foreign objects, (3) wear from secondary-side

cleaning activities, and (4) circumferentially oriented outside-diameter stress corrosion cracking

at the expansion transition.

A total of 139 indications of wear at the AVBs were detected in 70 tubes in steam generator B

and 66 indications of wear at the AVBs were detected in 35 tubes in steam generator C. The 

maximum depth reported for the AVB wear indications was 41 percent throughwall. 

Wear attributed to loose parts was observed in two tubes in steam generator A and in one tube 

in steam generator D. All of the indications were at the top of the tubesheet on the hot-leg side 

and none exhibited any change since the prior inspection in RFO 15. The maximum depth 

reported for the wear attributed to loose parts was 20 percent throughwall. Visual inspections at 

locations with either possible loose part indications or wear attributed to possible loose parts

resulted in either no loose part being identified or the presence of a sludge rock at the location.

One indication of wear attributed to secondary-side cleaning was identified during RFO 16. 

The maximum depth reported for this indication was 24 percent throughwall. There has been 

no change in this indication since the prior inspection in RFO 14.

One indication of outside-diameter stress corrosion cracking was detected in steam generator B 

in the tube in row 15, column 60 and was circumferentially oriented (a single circumferential 

indication), about 5 mm (0.2 in.) below the top of the tubesheet at the bottom of the expansion 

transition on the hot-leg side of the steam generator. The indication was detected with a 

rotating probe equipped with a plus-point coil and confirmed to be a flaw with a Ghent probe. 

The indication had a circumferential extent of 46.6 degrees, a maximum depth of 33 percent, 

and a calculated percent degraded area of 4.5 percent.

Inspection and maintenance on the secondary side of the steam generators were performed 

during RFO 16. Top of tubesheet sludge lancing and FOSAR were performed in all four steam 

generators. FOSAR inspections included the annulus and no-tube lane, including the 

peripheral tubes, possible loose part indications identified during the eddy current inspections, 

and locations where loose parts were known to exist.

On September 26, 2013, the steam generator portion of the Vogtle 2 technical specifications 

was revised making them consistent with TSTF-510 (ADAMS Accession No. ML13218B274).

3.3.6 Wolf Creek

Tables 3-28, 3-29, and 3-30 summarize the information discussed below for Wolf Creek. Table 

3-28 provides the number of full-length bobbin inspections and the number of tubes plugged 

and deplugged during each outage for each of the four steam generators. Table 3-29 lists the 

reasons why the tubes were plugged. Table 3-30 lists tubes plugged for reasons other than 

wear at the AVBs.
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Wolf Creek has four Westinghouse model F steam generators. The licensee numbers its tube 

supports from the hot-leg flow distribution baffle (FBH or BPH) to 7H on the hot-leg side of the 

steam generator and from FBC/BPC to 7C on the cold-leg side (Figure 2-4).

During RFO 12 in 2002, 100 percent of the tubes in steam generators B and C were inspected 

full length with a bobbin coil, with the exception of the U-bend region of tubes in rows 1 and 2. 

In addition to the bobbin coil inspections, a rotating probe equipped with a plus-point coil was 

used to inspect:

• 55 percent of the tubes (including all tubes in the periphery of the hot-leg) from 7.6 cm 

(3 in.) above to 7.6 cm (3 in.) below the top of the tubesheet on the hot-leg side in steam 

generators B and C

• the U-bend region of 50 percent of the row 1 and row 2 tubes in steam generators B and 

C

• all dents on the hot-leg side of the steam generator with bobbin voltage amplitudes 

greater than or equal to 5 volts in steam generators B and C

No tubes were inspected in steam generators A and D during RFO 12.

As a result of these inspections, nine tubes were plugged—8 for wear at the AVBs, and 1 for a 

circumferential anomaly (non-flaw like) just below the top of the tubesheet.

The only steam generator tube degradation mechanisms observed during RFO 12 were wear at 

the AVBs, wear attributed to loose parts, and wear attributed to maintenance activities.

During RFO 12, 711 indications of wear at the AVBs were detected in steam generator B, and 

480 indications of wear at the AVBs were detected in steam generator C. The maximum depth 

reported for the AVB wear indications was 52 percent throughwall.

Thirteen tubes were identified with indications of wear attributed to loose parts. Most of these 

indications were near the top of the tubesheet. Ultrasonic examination of one of these 

indications confirmed that the indication was volumetric and did not indicate cracking.

Nine tubes had indications of wear attributed to maintenance activities (i.e., prior application of 

PPC) during RFO 12. Most of these indications were at the flow distribution baffle.

The tube with the circumferential anomaly was identified during the rotating probe examination. 

This was the first time the top of tubesheet region of this tube had been inspected with a 

plus-point coil. The circumferentially oriented indication was reported just below the top of the 

tubesheet. Ultrasonic inspection confirmed that there was a geometric indication at this location 

because of a small dimple on the tube.

During RFO 12, sludge lancing also was performed. After sludge lancing, FOSAR was 

performed. All tubes with possible loose part indications, as well as adjacent tubes, were 

inspected with a rotating probe equipped with a plus-point coil and visually inspected.

On May 10, 2002, there were indications of an unusual noise followed by an alarm in the loose 

part monitoring system. The noise was coming from steam generator D. On May 13, 2002, a 

plant shutdown was commenced. After the plant was shut down, visual inspections in the 
3-129

channel head of steam generator D identified two loose parts. These parts were retrieved and 

characterized as a support pin nut and locking device (disc) from a guide tube support pin. 

There were no indications within the steam generator of serious damage to the tubes, 

tubesheet, welds, or the divider plate because of these loose parts. The skirts of the tube plugs 

were peened to various degrees. In addition, most of the entire inner surface of the channel 

head bowl was peened to various degrees. There was no indication of a foreign object present 

in any of the tubes; however, there were indications of scratching and displaced metal inside 

various tubes. These indications may have been the result of inspection equipment rather than 

a result of the loose parts. The objects removed were larger than the inside diameter of the 

tubing. No tubes were plugged because of damage from these loose parts.

In 2002, the bobbin coil data were reviewed to identify low-row (rows 1 through 10) tubes that 

potentially had high residual stress. None of the tubes exhibited an eddy current offset that 

would indicate the tubes had elevated residual stresses.

During RFO 13 in 2003, 100 percent of the tubes in steam generators A and D were inspected 

full length with a bobbin coil, with the exception of the U-bend region of tubes in rows 1 and 2. 

In addition to the bobbin coil inspections, a rotating probe equipped with a plus-point coil was 

used to inspect:

• 55 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the hot-leg side in steam generators A and D

• the U-bend region of 50 percent of the row 1 and row 2 tubes in steam generators A and 

D

• 100 percent of the dents and dings in the straight length portion of the tubes on the hotleg side of the steam generator with bobbin voltage amplitudes greater than 5 volts in 

steam generators A and D

No tube inspections were performed in steam generators B and C during RFO 13.

As a result of these inspections, 20 tubes were plugged—19 for wear at the AVBs, and 1 for an 

obstruction. 

The only steam generator tube degradation mechanisms observed during RFO 13 were wear at 

the AVBs, wear attributed to loose parts, and wear attributed to fabrication/maintenance 

activities.

During RFO 13, 430 indications of wear at the AVBs were detected in steam generator A, and 

723 indications of wear at the AVBs were detected in steam generator D. The maximum depth 

reported for the AVB wear indications was 66 percent throughwall.

Eighteen indications of wear at the flow distribution baffle were detected during RFO 13. These 

indications are attributed to prior maintenance activities (i.e., PPC). These indications have not 

appreciably changed in size since RFO 11.

Several volumetric indications were detected near the top of the tubesheet (four indications) and 

at a tube support plate (two indications). All but one of these volumetric indications were

attributed to wear associated with loose parts that are no longer present. The other volumetric 

indication was attributed to a geometric anomaly such as expansion into a burr or undercut 
3-130

remaining from the tubesheet drilling process. The indication was slightly below the top of the 

tubesheet.

The tube that was plugged with an obstruction had a remnant (bolt shank) of the split pin that 

failed following RFO 12 stuck inside the tube. Because the obstruction could not be removed, 

the tube was plugged.

During RFO 13, four previously installed mechanical tube plugs were replaced with welded

plugs. Loose parts damaged one of these four plugs that resulted in the May 2002 shutdown. 

Although the inspection revealed that the plug was intact and in acceptable condition for safe 

operation, the plug was replaced to limit the potential for any future primary-to-secondary 

leakage. The other three plugs that were replaced were plugs that were installed during 

fabrication of the steam generator.

FOSAR also was performed during RFO 13. FOSAR included all of the areas where possible

loose parts signals were reported in steam generators A and D. Visual inspection of the 

10 possible loose part locations indicated that six were a result of sludge rocks or collars of 

deposits and four were a result of small metallic pieces (metal chips or curls). These metallic 

pieces were removed from the steam generators. There were other small metallic objects 

identified during FOSAR that could not be removed from the steam generators. The metallic 

pieces remaining in the steam generators were evaluated and the licensee concluded it was 

acceptable to leave them in the steam generators. No tube degradation was associated with 

any of these foreign objects.

On April 28, 2005, the steam generator portion of the Wolf Creek technical specifications was 

revised to limit the extent of inspection in the hot-leg tubesheet region. Specificially, the 

technical specifications were revised to exclude the portion of tube that is more than 43.2 cm 

(17 in.) below the top of the tubesheet from inspection (i.e., approximately the lowermost 10.2 

cm (4 in.) of tube in the tubesheet on the hot-leg side was excluded from inspection, and hence 

any flaws that may exist in this region are permitted to remain in service). This revision was 

applicable only to RFO 14 and the subsequent operating cycle (ADAMS Accession No. 

ML051230044)

During RFO 14 in 2005, 100 percent of the tubes in steam generators B and C were inspected 

full length with a bobbin coil, with the exception of the U-bend region of tubes in rows 1 and 2. 

In addition to the bobbin coil inspections, a rotating probe equipped with a plus-point coil was 

used to inspect:

• 55 percent of the tubes (including all peripheral tubes, two tubes deep) at the top of the 

tubesheet on the hot-leg side

• the U-bend region of 25 percent of the tubes in rows 16 through 19

• 100 percent of the peripheral tubes, (i.e., 2 tubes deep) on the cold-leg side of the steam 

generator

• 20 percent of the bulges and overexpansions from the top of the tubesheet to 48.3 cm 

(19 in.) below the top of the tubesheet on the hot-leg side (but concentrated in the top 

25.4 cm (10 in.) of the tubesheet)
3-131

As a result of these inspections, eight tubes were plugged—four for wear at the AVBs, and four

for interaction between the tubes and a PPC nozzle used to clean the top of the tubesheet 

during RFO 7 in 1994.

The only steam generator tube degradation mechanisms observed during RFO 14 were wear at 

the AVBs, wear attributed to loose parts, and wear attributed to maintenance equipment.

A total of 770 indications of wear at the AVBs were detected in steam generator B, and 

approximately 510 indications of wear at the AVBs were detected in steam generator C during 

RFO 14. The maximum depth reported for the AVB wear indications was 44 percent

throughwall.

Wear attributed to loose parts was also detected during RFO 14. Two indications of wear were 

observed near tube support plates. These indications were attributed to loose parts that were 

no longer present. Twelve volumetric indications were reported near the top of the tubesheet. 

All of these indications were attributed to loose parts that were no longer present.

Wear attributed to maintenance equipment also was detected during RFO 14. This wear was 

observed about 38 to 41 cm (15 to 16 in.) above the top of the tubesheet. These indications 

were attributed to PPC conducted in 1994. These indications have not changed in size; 

however, a new sizing technique was applied in RFO 14, which resulted in several indications 

requiring repair since they exceeded the plugging limit. No indications of wear attributed to PPC

exist in steam generators A and D. Wear indications were also observed at the flow distribution 

baffle. Most of these indications were attributed to PPC conducted in 1994. These indications 

have not changed in size. However, during RFO 14, three new indications of wear at the flow 

distribution baffle were reported that may have been the result of PPC performed during the 

RFO.

Maintenance and visual inspections were performed on the secondary side of steam generators 

B and C during RFO 14. An ASCA was applied to steam generators B and C followed by PPC. 

In addition, visual inspections were performed at the top of the tubesheet, UBIB, and the upper 

steam drum. The steam drum inspection included assessing the general condition of the 

components (J-nozzles, moisture separators, etc.) and visual inspection of the top of the tube 

bundle, some AVBs, and a limited view of the uppermost tube support plate. These inspections 

did not identify anything significant. FOSAR was also performed during RFO 14. FOSAR 

included areas where possible loose parts signals were reported during the eddy current 

inspection of the tubes. FOSAR identified several small loose parts. These parts were not 

removed because of their insignificant potential for damage to the steam generator tubes. 

In addition, a small foreign object that was determined to be “fixed in place” in RFO 12, was 

dislodged during the ASCA/PPC process performed during RFO 14, and could not be during the 

FOSAR activities.

On May 8, 2006, Wolf Creek revised the steam generator portion of the technical specifications 

making them performance-based consistent with TSTF-449 (ADAMS Accession 

No. ML061280189).

On October 10, 2006, the steam generator portion of the Wolf Creek technical specifications 

was revised to limit the extent of inspection in the hot-leg tubesheet region. Specifically, the 

technical specifications were revised to exclude the portion of tube that is more than 43.2 cm 

(17 in.) below the top of the tubesheet from inspection (i.e., approximately the lowermost 10.2 

cm (4 in.) of tube in the tubesheet on the hot-leg side was excluded from inspection, and hence 
3-132

any flaws that may exist in this region are permitted to remain in service). This revision was 

applicable only to RFO 15 and the subsequent operating cycle (ADAMS Accession No. 

ML062580016).

During RFO 15 in 2006, 100 percent of the tubes in steam generators A and D were inspected 

full length with a bobbin coil, with the exception of the U-bend region of row 1 through row 4 

tubes. In addition to the bobbin coil inspections, a rotating probe equipped with a plus-point coil 

was used to inspect:

• 55 percent of the tubes (including all peripheral tube, two tubes deep) from 7.6 cm (3 in.) 

above to 7.6 cm (3 in.) below the top of the tubesheet on the hot-leg side in steam 

generators A and D

• 100 percent of the peripheral tubes (i.e., two tubes deep) from 7.6 cm (3 in.) above to 

7.6 cm (3 in.) below the top of the tubesheet on the cold-leg side in steam generators A 

and D

• 50 percent of the bulges and overexpansions from the top of the tubesheet to 43.2 cm 

(17 in.) below the top of the tubesheet on the hot-leg side (but concentrated in the top 

25.4 cm (10 in.) of the tubesheet) in steam generators A and D

• all previously uninspected and new hot-leg dents and dings with bobbin voltage 

amplitudes greater than 5 volts in steam generators A and D 

Low-frequency bobbin data and a sample of plus-point data also were acquired to support a 

scale-profiling analysis to supply information on the secondary-side deposit accumulation. 

In addition, all tube plugs were inspected visually and were in an acceptable condition.

As a result of these inspections, 23 tubes were plugged: 21 for wear at the AVBs, and 2 for 

geometric anomaly signals.

The only steam generator tube degradation mechanisms observed during RFO 15 were wear at 

the AVBs, wear attributed to loose parts, and wear attributed to maintenance equipment.

The maximum depth reported for the AVB wear indications was 52 percent throughwall. 

Wear indications were reported near the top of the tubesheet. All but one of these indications 

were attributed to loose parts that were no longer present. These indications have not changed 

in size. The other wear indication was attributed to a geometric anomaly such as expansion into 

a burr or undercut remaining from the tubesheet drilling process. The indication was slightly 

below the top of the tubesheet and has not changed in size. Wear indications also were 

detected at two tube support plate intersections. These indications were attributed to loose 

parts that were no longer present. These indications have not changed in size. Wear

indications were also observed at the flow distribution baffle. These indications were attributed 

to PPC. These indications have not changed in size.

The source of the geometric signals was determined to be an inner diameter ridge or scratch 

extending from within the tubesheet to a few inches above the tubesheet, and could be 

observed as far back as RFO 7 in 1994 (the first plus-point inspection of these tubes). Neither 

of the signals was determined to be an indication of degradation. 
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An ASCA maintenance cleaning was performed in steam generators A and D during RFO 15. 

In addition, a scale-profiling eddy current analysis was performed to evaluate the deposit levels 

in the steam generators and to compare these results with previous estimates from RFO 13 (the 

previous outage in which steam generators A and D were cleaned and inspected). The analysis 

consisted of a review of the low-frequency eddy current bobbin data, the rotating pancake coil 

inspection of selected tube-tube support plate intersections to evaluate potential quatrefoil 

blockage, and UBIB visual inspections. As a result, the licensee noted that the heaviest deposit 

levels were below the seventh tube support plate and up to the U-bend on the hot-leg side of 

the steam generator, there was a concentration of scale buildup between the top of the 

tubesheet and the flow distribution baffle in the cutout region, the morphology of the steam 

generator deposit patterns were remarkably consistent between steam generators A and D as 

well as that observed for steam generator B in RFO 14, and the ASCA visibly lowered the 

deposit levels (but the general pattern of the deposits before and after the ASCA were the 

same). In addition, the licensee noted that the deposit buildup was very low, posing no flow 

path blockage (even in areas where the freespan deposit levels were relatively high). Although 

some surface deposits were observed and some spalling was detected, the quatrefoil openings 

were essentially clean. The deposit inventories were estimated to be 1,363 pounds in steam 

generator A and 1,225 pounds in steam generator D.

The secondary side of steam generators A and D were inspected visually during RFO 15. 

Inspections were performed at the top of the tubesheet and in-bundle in the upper portion of the 

tube bundle. These inspections did not identify anything significant. The upper bundle 

inspections involved the inspection of selected columns of tubes from the top of tube support 

plate 3 to the bottom of tube support plate 7. FOSAR was also performed in steam generators 

A and D during RFO 15. FOSAR identified several foreign objects, most of which were benign 

items such as sludge rocks and scale. These objects were not retrieved. No objects that could 

damage the tubes were observed. Possible loose part signals from the eddy current inspection 

were visually inspected during FOSAR. No wear was associated with any of the possible loose 

part signals.

On April 4, 2008, the steam generator portion of the Wolf Creek technical specifications was 

revised to permit certain sized flaws near the tube end in both the hot- and cold-leg sides of the 

steam generator to remain in service. Specifically, the technical specifications were revised to 

(1) permit flaws having a circumferential component less than or equal to 203 degrees found in 

the portion of the tube below 43.2 cm (17 in.) from the top of the tubesheet and above 2.54 cm 

(1 in.) from the bottom of the tubesheet to remain in service, (2) require the removal from 

service all flaws having a circumferential component greater than 203 degrees found in the 

portion of the tube below 43.2 cm (17 in.) from the top of the tubesheet and above 2.54 cm 

(1 in.) from the bottom of the tubesheet, (3) require the removal from service all tubes with 

service-induced flaws between the top of the tubesheet and 43.2 cm (17 in.) below the top of 

the tubesheet, and (4) permit all axial indications found in the portion of the tube below 43.2 cm 

(17 in.) from the top of the tubesheet to remain in service. In addition, the technical 

specifications were modified to indicate that when more than one flaw with circumferential 

components is found in the portion of the tube below 43.2 cm (17 in.) from the top of the 

tubesheet and above 2.54 cm (1 in.) from the bottom of the tubesheet with the total of the 

circumferential components being greater than 203 degrees and the axial separation distance of 

less than 2.54 cm (1 in.), then the tube must be removed from service (overlapping portions of 

the flaws only need to be counted once in determining the total circumferential involvement of 

the flaws). For flaws within 2.54 cm (1 in.) of the bottom of the tubesheet, the technical 

specifications were modified to indicate (1) when one or more flaws with circumferential 

components are found and the total of the circumferential components exceeds 94 degrees, 
3-134

then the tube shall be removed from service and (2) when one or more flaws with 

circumferential components are found in the portion of the tube within 2.54 cm (1 in.) from the 

bottom of the tubesheet and within 2.54 cm (1 in.) axial separation distance of a flaw above 

2.54 cm (1 in.) from the bottom of the tubesheet, and the total of the circumferential components 

found in the tube exceeds 94 degrees, then the tube shall be removed from service (overlapping 

portions of the flaws only need to be counted once in determining the total circumferential 

involvement of the flaws). This revision to the technical specifications was applicable only to 

RFO 16 and the subsequent operating cycle (ADAMS Accession No. ML080840003).

There was no evidence of primary-to-secondary leakage during Cycle 16 (fall 2006 to spring 

2008).

During RFO 16 in 2008, 100 percent of the tubes in steam generators B and C were inspected 

full length with a bobbin coil, with the exception of the U-bend region of row 1 and row 2 tubes. 

In addition to the bobbin coil inspections, a rotating probe equipped with a plus-point coil was 

used to inspect:

• 55 percent of the tubes (including all peripheral tube, two tubes deep) from 7.62 cm 

(3 in.) above to 43.2 cm (17 in.) below the top of the tubesheet on the hot-leg side in 

steam generators B and C

• 100 percent of the peripheral tubes (i.e., two tubes deep) from 7.6 cm (3 in.) above to 

7.6 cm (3 in.) below the top of the tubesheet on the cold-leg side in steam generators B 

and C

• 20 percent of the tubes from the top of the tubesheet to the tube end on the hot-leg side

in steam generators B and C

• 100 percent of the tubes from the tube end to 2.54 cm (1 in.) above the tube end on the 

hot-leg side in steam generators B and C

• the U-bend region of 50 percent of the tubes in rows 1 and 2 in steam generators B and 

C

• all new hot-leg (including U-bend) dents and dings and 50 percent of existing dents with 

bobbin voltage amplitudes greater than or equal to 5 volts in steam generators B and C

Low-frequency bobbin data and a sample of plus-point data also were acquired to support a 

scale-profiling analysis to offer information on the secondary-side deposit accumulation. In 

addition to the inspections in steam generators B and C, 100 percent of the tubes in steam 

generator D and 30 percent of the tubes in steam generator A were inspected with a rotating 

probe equipped with a plus-point coil from the tube end to 2.54 cm (1 in.) above the tube end on 

the hot-leg side of the steam generator. In addition, all tube plugs were inspected visually, and 

they were present, and in an acceptable condition (no evidence of leakage).

As a result of these inspections, 29 tubes were plugged—20 for wear at the AVBs, 8 for 

indications of primary water stress corrosion cracking near the hot-leg tube ends, and 1

because it was not expanded into the tubesheet on the hot-leg side of the steam generator.

The only steam generator tube degradation mechanisms observed during RFO 16 were 

(1) wear at the AVBs, (2) wear attributed to loose parts, (3) wear attributed to maintenance 
3-135

activities, and (4) primary water stress corrosion cracking near the tube ends on the hot-leg side 

of the steam generator.

The maximum depth reported for the AVB wear indications was 54 percent throughwall. 

Wear indications were reported near the top of the tubesheet. These indications were attributed 

to loose parts that were no longer present. One of these indications was new. All of the wear 

indications near the top of the tubesheet that were present in prior inspections have not 

changed in size. Wear indications were also detected at two tube support plate intersections. 

These indications were attributed to loose parts that were no longer present. These indications 

have not changed in size. Wear indications were also observed at the flow distribution baffle. 

These indications were attributed to PPC. These indications have not changed in size.

Crack-like indications attributed to primary water stress corrosion cracking were observed near 

the tube ends in steam generators B, C, and D. All indications were within about 5 mm (0.2 in.)

of the tube end on the hot-leg side of the steam generator. Sixty-nine tubes had crack-like 

indications near the tube-end (25 in steam generator B, 27 in steam generator C, and 17 tubes 

in steam generator D). Eight of these tubes were plugged since the flaw size was larger than 

the acceptance limit. All of the crack-like indications in steam generator B were

circumferentially oriented whereas the crack-like indications in the other two steam generators 

included both axially and circumferentially oriented flaws.

The non-expanded tube that was plugged during RFO 16 was expanded into the bottom 5.1 cm 

(2 in.) of the tubesheet by mechanical rolling and then the plug was installed. This tube had no 

history of degradation.

An analysis of eddy current data were performed to evaluate the deposit levels in the steam 

generators and to compare these results with previous evaluations from RFO 14 (the previous 

outage in which steam generators B and C were cleaned and inspected). The analysis 

consisted of a review of the low-frequency bobbin coil data, rotating pancake coil data of 

tube-to-tube support plate intersections, and review of the available rotating probe data 

collected at the top of the tubesheet. Based on this analysis, the licensee noted that the scale 

distribution patterns in steam generators B and C were similar, the heaviest deposit levels were 

from the seventh tube support plate and extending upwards through the U-bend region on the 

hot-leg side of the steam generator, a concentration of scale buildup was observed between the 

top of the tubesheet and the flow distribution baffle in the cutout region of the flow distribution 

baffle, the lower tube support plate regions have tube scale occurring mainly in the periphery of 

the hot-leg side, the cold-leg side is relatively clean with the largest region of deposits occurring 

at the top tube support plate (i.e., number 7) near the tube lane region. In addition, the licensee 

noted that the review of the rotating probe data in steam generators B and C indicates that the 

tube-to-tube support plate intersections and the top of tubesheet region are relatively clean. 

The deposit inventories were estimated to be 1,746 pounds in steam generator B and 1,661 

pounds in steam generator C. Most of these deposits are in the U-bend region and at the upper 

tube support plates on the hot-leg side of the steam generator. The pattern of deposits in steam 

generator B remained consistent between RFO 14 and RFO 16; however, a decrease in the 

amount of deposits was observed primarily in the upper bundle and U-bend region on the hotleg side. This decrease was attributed to the ASCA and PPC that was performed during RFO 

14. Comparison data from RFO 14 for steam generator C was not available.

Visual inspections were performed on the secondary side of steam generators B and C during 

RFO 16. Inspections at the top of the tubesheet indicated a small area of deposits in the center 
3-136

of the tubesheet on the hot-leg side. Inspections also were planned for the upper interior 

portion of the tube bundle in steam generators B and C. These upper bundle inspections were 

intended to determine the general condition of the support plates, the quatrefoil openings in the 

support plate, the flow holes in the seventh tube support plate, the patch plate plug weld 

regions, and the tubes. The inspections were to be focused between the fourth and seventh

tube support plates; however, the inspections were canceled when the inspection tooling failed 

in steam generator C (i.e., the probe’s lens, lens head, and two small screws fell into the steam 

generator). Visual inspections also were performed throughout the mid deck, intermediate deck 

and lower deck of the steam drum in steam generator B. The locations inspected included the 

demister banks, swirl vanes, tangential nozzles, the central drain, elongated steam vents, drain 

lines, feedring, and associated components. Other than erosion in two J-nozzles, there were no 

other visible anomalies and a mild coating of magnetite was observed on all surfaces. Top 

down visual inspections were performed in the top portion of the tube bundle by inserting a 

video probe down through the swirl vanes. These inspections included the AVBs, AVB to tube 

interface, tube and support plate integrity, and general scale buildup. All visual inspections 

were considered acceptable by the licensee.

Sludge lancing and FOSAR also were performed in steam generators B and C during RFO 16. 

FOSAR identified several foreign objects. Most of the foreign objects identified were benign 

items such as sludge rocks and scale. The licensee performed an analysis of the foreign 

objects that could not be retrieved from the steam generators, concluding that these objects 

could remain in the steam generators at least until the next inspection. Possible loose part 

signals from the eddy current inspection were visually inspected during the FOSAR. No wear 

was associated with any of the possible loose part signals.

On October 19, 2009, the steam generator portion of the Wolf Creek technical specifications 

was revised to limit the extent of inspection in the tubesheet region. Specifically, the technical 

specifications were revised to exclude the portion of tube that is more than 33.27 cm (13.1 in.)

below the top of the tubesheet from inspection (i.e., approximately the lowermost 20.3 cm (8 in.)

of tube in the tubesheet was excluded from inspection, and hence any flaws that may exist in 

this region are permitted to remain in service). This revision was applicable only to RFO 17 and 

the subsequent operating cycle (ADAMS Accession No. ML092750606).

There was no evidence of primary-to-secondary leakage during Cycle 17 (spring 2008 to fall 

2009).

During RFO 17 in 2009, 100 percent of the tubes in steam generators A and D were inspected 

full length with a bobbin coil, with the exception of the U-bend region of row 1 and row 2 tubes. 

In addition to the bobbin coil inspections, a rotating probe equipped with a plus-point coil was 

used to inspect:

• 55 percent of the tubes (including all peripheral tube, two tubes deep) from 7.62 cm 

(3 in.) above to 33.27 cm (13.1 in.) below the top of the tubesheet on the hot-leg side in 

steam generators A and D

• 100 percent of the peripheral tubes (i.e., two tubes deep) from 7.6 cm (3 in.) above to 

7.6 cm (3 in.) below the top of the tubesheet on the cold-leg side in steam generators A 

and D

• the U-bend region of 50 percent of the tubes in rows 1 and 2 in steam generators A and 

D
3-137

• all new hot-leg (including U-bend) dents and 50 percent of existing dents with bobbin 

voltage amplitudes greater than 2 volts in steam generators A and D

• all new hot-leg (including U-bend) dings and 50 percent of existing dings with bobbin 

voltage amplitudes greater than 5 volts in steam generators A and D

In addition, all tube plugs were inspected visually and were in an acceptable condition.

As a result of these inspections, 18 tubes were plugged—16 for wear at the AVBs, and 2 for 

geometric anomalies.

The only steam generator tube degradation mechanisms observed during RFO 17 were wear at 

the AVBs, wear attributed to loose parts, and wear attributed to maintenance activities.

A total of 606 indications of wear at the AVBs were detected in 271 tubes in steam generator A 

and 980 indications of wear at the AVBs were detected in 401 tubes in steam generator D. The 

maximum depth reported for the AVB wear indications was 51 percent throughwall. 

Wear indications were reported near the top of the tubesheet. These indications were attributed 

to loose parts that were no longer present. No new wear indications at the top of the tubesheet 

were detected, and one previously reported wear indication was no longer present. All of the 

wear indications near the top of the tubesheet that were present in prior inspections have not 

changed in size. Wear indications were also detected at three tube support plate intersections. 

These indications were attributed to loose parts that were no longer present. These indications 

have not changed in size. Wear indications were also observed at the flow distribution baffle. 

These indications were attributed to PPC. These indications have not changed in size. 

Two tubes were plugged because of geometric anomalies. The two geometric anomalies were 

axially oriented, linear geometric signals running through the expansion transition region. 

Inspections of these locations with a Ghent probe did not confirm the presence of a flaw. One 

of the responses could be observed in historical data, while the other signal was not; however, 

the previous data quality for this latter location was limited, and the size of the signal was very 

small. The consensus of the data analysts was that both of these signals were geometric 

variations and not indications of degradation.

The secondary side of steam generators A and D were inspected visually during RFO 17. 

Sludge lancing, FOSAR, and an in-bundle visual inspection were performed in steam 

generators A and D. The upper steam drum in steam generator A was inspected visually to 

evaluate the condition of its components. Sludge lancing resulted in the removal of 21.5 pounds 

in steam generator A and 22 pounds in steam generator D. FOSAR in steam generators A and 

D resulted in identifying some minor foreign objects some of which were removed. Foreign 

objects left in the steam generators were evaluated to ensure they could remain. Minor 

degradation was observed during the upper steam drum inspections at a few of the J-nozzle to 

feedring interface locations. Visual inspections and ultrasonic measurements are performed at 

these locations to ensure they satisfy the acceptance criteria.

To identify tubes that have potentially high residual stress and therefore might be more 

susceptible to stress corrosion cracking, bobbin coil eddy current data were reviewed. As 

discussed above, no low-row tubes (i.e., tubes in rows 1 through 8) were identified as potentially 

being more susceptible to stress corrosion cracking based on a review of eddy current data for 

an offset between the data in the U-bend and in the straight span. In the higher-row tubes 
3-138

(i.e., tubes in rows 11 and higher), 59 tubes (31 in steam generator A, 11 in steam generator B, 

10 in steam generator C and 7 in steam generator D) were identified with an offset in the eddy 

current data between the U-bend and the straight region less than two standard deviations of 

the mean (i.e., minus 2 sigma). This lack of an offset in the eddy current data is indicative of 

potentially higher residual stresses in the straight span portion of the tube.

On April 6, 2011, the steam generator portion of the Wolf Creek technical specifications was 

revised to limit the extent of inspection in the tubesheet region. Specifically, the technical 

specifications were revised to exclude the portion of tube that is more than 38.6 cm (15.2 in.)

below the top of the tubesheet from inspection (i.e., approximately the lowermost 15.2 cm (6 in.)

of tube in the tubesheet was excluded from inspection, and hence any flaws that may exist in 

this region are permitted to remain in service). This revision was applicable only to RFO 18 and 

the subsequent operating cycle (ADAMS Accession No. ML110840590).

There was no evidence of primary-to-secondary leakage during Cycle 18 (fall 2009 to spring 

2011).

During RFO 18 in 2011, 25 percent of the tubes in each of the four steam generators were 

inspected full length with a bobbin coil, with the exception of the U-bend region of row 1 and row 

2 tubes. The bobbin coil was also used to inspect all prior indications except dents and dings, 

all tubes surrounding previously plugged tubes that are being monitored for potential long term 

damage propagation, and all tubes with potentially elevated residual stress. In addition to the 

bobbin coil inspections, a rotating probe equipped with a plus-point coil was used to inspect:

• 25 percent of the tubes from 7.62 cm (3 in.) above to 38.6 cm (15.2 in.) below the top of 

the tubesheet on the hot-leg side in each of the four steam generators

• 100 percent of the peripheral tubes (i.e., 2 tubes deep) from 7.62 cm (3 in.) above to 

38.6 cm (15.2 in.) below the top of the tubesheet on the hot-leg side in each of the four 

steam generators

• 100 percent of the peripheral tubes (i.e., 2 tubes deep) from 7.6 cm (3 in.) above to 

7.6 cm (3 in.) below the top of the tubesheet on the cold-leg side in each of the four 

steam generators

• the U-bend region of 25 percent of the tubes in rows 1 and 2 in each of the four steam 

generators

• all new hot-leg (including U-bend) dents and 25 percent of existing dents in steam 

generators A and D and 50 percent of existing dents in steam generators B and C with 

bobbin voltage amplitudes greater than 2 volts

• all new hot-leg (including U-bend) dings and 25 percent of existing dings with bobbin 

voltage amplitudes greater than 5 volts in each of the four steam generators

An additional 20 percent of the tubes in rows 15 and higher were inspected with a bobbin coil in 

steam generator B because of finding one tube that exceeded the plugging limit and had a 

growth rate of 25 percent throughwall over two cycles. In addition, all tube plugs were inspected 

visually. All plugs were in an acceptable condition.
3-139

As a result of these inspections, 15 tubes were plugged. All tubes were plugged for wear at the 

AVBs.

The only steam generator tube degradation mechanisms observed during RFO 18 were wear at 

the AVBs, wear attributed to loose parts, and wear attributed to maintenance activities.

A total of 599 indications of wear at the AVBs were detected in 273 tubes in steam generator A, 

951 indications of wear at the AVBs were detected in 421 tubes in steam generator B, 610 

indications of wear at the AVBs were detected in 270 tubes in steam generator C, and 990 

indications of wear at the AVBs were detected in 404 tubes in steam generator D. The 

maximum depth reported for the AVB wear indications was 45 percent throughwall. 

Wear indications were reported near the top of the tubesheet. These indications were attributed 

to loose parts that were no longer present. No new wear indications at the top of the tubesheet 

were detected. All of the wear indications near the top of the tubesheet that were present in 

prior inspections have not changed in size. Wear indications were also detected at three tube 

support plate intersections (in steam generator D only). These indications were attributed to 

loose parts that were no longer present. These indications have not changed in size. Wear 

indications were also observed at the flow distribution baffle. These indications were attributed 

to PPC. These indications have not changed in size.

Tubes with AVB wear are not necessarily stabilized before tube plugging. If a plugged tube 

continues to wear, the licensee has indicated that tube-to-tube contact is generally predicted in 

an adjacent tube before the plugged tube severing. The licensee has developed a model that is 

used to predict the operating time at which a tube plugged for AVB wear becomes at risk of 

severing, so that corrective action can be taken before that time. The model considers two 

possibilities: 1) determining if tube separation by fatigue occurs before a wearing tube (AVB 

wear) makes contact with its adjacent neighbor tubes, and 2) determining if (and when) the 

adjacent tube, if still in service, can attain a structurally limiting condition because of tube-totube contact before the next inspection. In effect, if a fatigue separation condition is not 

achieved before tube-to-tube contact, the adjacent tube (if active) serves as a means to monitor 

the progression of the wear in the initially plugged and wearing tube. Monitoring the adjacent 

tubes confirms the analysis and allows time for proper planning to de-plug and stabilize before

severance of the plugged tube. Thus, if the model predicts tube-to-tube contact with an active 

tube to occur at a particular time and physical observation by eddy current testing at that time 

confirms that no tube-to-tube contact wear is present, this leads to the conclusion that wear on 

the originally plugged tube is progressing slower than predicted and that the analysis is 

conservative. If the adjacent tube(s) are plugged, the licensee has indicated that the plugged 

tubes offer an effective permanent safety barrier because tube-to-tube contact wear results in 

an axial flaw on the tube if the adjacent tube is not severed. Axial flaws have been shown not to 

represent a risk for tube separation; thus, the adjacent tube itself does not represent a damage 

propagation mechanism. Furthermore, the depth wear rate on both the original and adjacent 

tubes becomes very small because of the increasing wear area and the limited energy input to 

the contact wear. During RFO 18, no wear indications were found on any tube adjacent to a 

tube that had previously been identified as potentially requiring stabilization because of

continuing wear after plugging for AVB wear.

During RFO 18, the secondary side of all four steam generators (except as noted) was

inspected visually. Sludge lancing, FOSAR, and an in-bundle visual inspection (in steam 

generators B and C only) were performed. To evaluate its components, the upper steam drums 

in steam generators B and C were visually inspected, including visual inspection of the J-
3-140

nozzles and ultrasonic inspection of selected feedring locations and J-nozzles. Sludge lancing 

resulted in the removal of 26 pounds in steam generator A, 34 pounds in steam generator B, 30 

pounds in steam generator C, and 27.5 pounds in steam generator D. FOSAR resulted in 

identifying some minor foreign objects some of which were removed. Foreign objects left in the 

steam generators were evaluated to ensure they could remain. Minor degradation was 

observed during the upper steam drum inspections in steam generators B and C at a few of the 

J-nozzle to feedring interface locations. All results were within acceptance criteria and no other 

degradation was observed during these secondary-side inspections.

On November 19, 2012, Wolf Creek revised the steam generator portion of their technical 

specifications making them consistent with TSTF-510 (ADAMS Accession No. ML12289A896).

On December 11, 2012, the steam generator portion of the Wolf Creek technical specifications 

was revised to limit the extent of inspection in the tubesheet region. Specifically, the technical 

specifications were revised to exclude the portion of tube that is more than 38.63 cm (15.21 in.)

below the top of the tubesheet from inspection (i.e., approximately the lowermost 15.2 cm (6 in.)

of tube in the tubesheet was excluded from inspection, and hence any flaws that may exist in 

this region are permitted to remain in service (ADAMS Accession No. ML12300A309)).

There was no evidence of primary-to-secondary leakage during Cycle 18 (spring 2011 to spring 

2013).

During RFO 19 in 2013, 25 percent of the tubes in each of the four steam generators were 

inspected full length with a bobbin coil, with the exception of the U-bend region of row 1 and row 

2 tubes. The bobbin coil was also used to inspect all prior indications except dents and dings, 

all tubes surrounding previously plugged tubes that are being monitored for potential long term 

damage propagation, and all tubes with potentially elevated residual stress. In addition to the 

bobbin coil inspections, a rotating probe equipped with a plus-point coil was used to inspect:

• 25 percent of the tubes from 7.62 cm (3 in.) above to 38.63 cm (15.21 in.) below the top 

of the tubesheet on the hot-leg side in each of the four steam generators

• 100 percent of the peripheral tubes (i.e., two tubes deep) from 7.62 cm (3 in.) above to 

38.63 cm (15.21 in.) below the top of the tubesheet on the hot-leg side in each of the 

four steam generators

• 100 percent of the peripheral tubes (i.e., two tubes deep) from 7.6 cm (3 in.) above to 

7.6 cm (3 in.) below the top of the tubesheet on the cold-leg side in each of the four 

steam generators

• the U-bend region of 25 percent of the tubes in rows 1 and 2 in each of the four steam 

generators

• all new hot-leg (including U-bend) dents and 25 percent of existing dents in steam 

generators A and D and 50 percent of existing dents in steam generators B and C with 

bobbin voltage amplitudes greater than 5 volts

• all new hot-leg (including U-bend) dings and 25 percent of existing dings with bobbin 

voltage amplitudes greater than 5 volts in each of the four steam generators
3-141

All bulges and overexpansions in steam generator B were inspected with a rotating probe 

equipped with a plus-point coil and at least 20 percent of the bulges and overexpansions were 

inspected in the other three steam generators. In addition, all tube plugs were inspected 

visually. All plugs were in an acceptable condition.

As a result of these inspections, 16 tubes were plugged—9 for wear at the AVBs, 1 for an 

obstruction (data quality), 5 for an eddy current signal that indicates high residual stress, and 1 

for a circumferential primary water stress corrosion cracking indication.

The only steam generator tube degradation mechanisms observed during RFO 19 were 

(1) wear at the AVBs, (2) wear at the tube support plates, (3) wear attributed to loose parts, 

(4) wear attributed to maintenance activities, and (5) circumferentially oriented primary water 

stress corrosion cracking at a bulge within the tubesheet.

A total of 633 indications of wear at the AVBs were detected in 282 tubes in steam generator A, 

953 indications of wear at the AVBs were detected in 420 tubes in steam generator B, 618 

indications of wear at the AVBs were detected in 274 tubes in steam generator C, and 

1,037 indications of wear at the AVBs were detected in 412 tubes in steam generator D. 

The maximum depth reported for the AVB wear indications was 44 percent throughwall. 

Wear indications were reported near the top of the tubesheet. These indications were attributed 

to loose parts that were no longer present. No new wear indications at the top of the tubesheet 

were detected. All of the wear indications near the top of the tubesheet that were present in 

prior inspections and have not changed in size. Wear indications were also detected at seven 

tube support plate intersections. The maximum depth reported for the tube support plate wear 

indications was 21 percent throughwall. Some of these indications were attributed to loose 

parts that were no longer present. Wear indications were also observed at the flow distribution 

baffle. These indications were attributed to PPC. These indications have not changed in size.

A circumferentially oriented primary water stress corrosion cracking indication was detected in a 

bulge in steam generator B about 15.9 cm (6.26 in.) below the top of the tubesheet on the hotleg side of the steam generator. The percent degraded area, with consideration of 

measurement uncertainty, was estimated at 11 percent.

One tube was plugged for an obstruction in the tube. A restriction/obstruction at the third AVB 

in this tube resulted in inspections with a smaller diameter probe. The restriction/obstruction 

was attributed to a large dent that has been present since the preservice inspection and that 

has not changed. Because the quality of the data was unsatisfactory for confident analysis, the 

tube was plugged.

As discussed above, a review of bobbin coil data was performed in 2002 to identify low-row

(rows 1 through 10) tubes that potentially had high residual stress (as evidenced by an eddy 

current offset). Although no tubes with an eddy current offset were identified at that time, more 

recent operating experience at another plant resulted in a re-review of the data before and 

during the RFO 19 outage. This review resulted in identifying five low-row tubes with an eddy 

current signal suggestive of high residual stresses. These five tubes were plugged.

During RFO 19, no wear indications were found on any tube adjacent to a tube that had 

previously been identified as potentially requiring stabilization because of continuing wear after 

plugging for AVB wear.
3-142

No significant deposit accumulation or other anomalies were detected in the eddy current 

inspections at the top tube support plate.

Inspections and assessments were performed during RFO 19 to ascertain the as-built condition 

of the U-bends with regard to AVB insertion depths to address the potential for fatigue of the 

U-bend region of the tube. Information from the EPRI provides generic information required to 

complete a plant specific U-bend analysis to determine susceptibility to fatigue failure not only 

for un-occluded quatrefoil support openings, but also for an assumed level of quatrefoil opening 

occlusion. During RFO 19, rotating probe inspections of some tube support plate locations were 

performed to obtain information for tubes that were shown to have unusual as-built AVB 

insertion patterns. The information obtained included deposit accumulation at the top tube 

support plate and identification of any precursors to fatigue. The results showed no significant 

deposit accumulation or any other anomalies at the top tube support plate.

During visual inspections of the steam generator A hot-leg channel head, a rust colored stain 

was identified at the divider plate to channel head weld. The stain was mainly toward the 

channel head side of the weld. The rust spot was 14.5 cm (5.7 in.) below the tubesheet, and an 

indication was sized with a depth of 2.54 mm (0.1 in.) and a depth of 5.1 cm (2.0 in.). 

An evaluation by the licensee indicated it was acceptable to leave the indication in service until 

at least RFO 20. Additional information is contained in NRC IN 2013-20, “Steam Generator 

Channel Head and Tubesheet Degradation.”

Visual inspections were performed on the secondary side of all four steam generators (except 

as noted) during RFO 19. Sludge lancing, FOSAR, and an in-bundle visual inspection (in steam 

generators A and D only) were performed. To evaluate its components, the upper steam drums 

in steam generators A and D were inspected, which included visual inspection of the J-nozzles 

and ultrasonic inspection of various steam drum components. Sludge lancing resulted in the 

removal of 44.75 pounds in steam generator A, 48.25 pounds in steam generator B, 45.25

pounds in steam generator C, and 92.25 pounds in steam generator D. FOSAR activities 

resulted in identifying some minor foreign objects some of which were removed. Foreign 

objects left in the steam generators were evaluated to ensure they could remain. Minor 

degradation was observed during the upper steam drum inspections in steam generators A and 

D at a few of the J-nozzle to feedring interface locations. All results were within acceptance 

criteria and no other degradation was observed during these secondary-side inspections.

3.4 Replacement Model Steam Generator Operating Experience

This section of the report provides inspection results for Indian Point 2, Point Beach 1, Robinson 

2, Salem 1, Surry 1 and 2, and Turkey Point 3 and 4. Salem 1 has model F steam generators 

but is included here because the flow conditions in the Salem steam generators could be 

different than in the other model F steam generators.

3.4.1 Indian Point 2

Tables 3-31, 3-32, and 3-33 summarize the information discussed below for Indian Point 2. 

Table 3-31 provides the number of full-length bobbin inspections and the number of tubes 

plugged and deplugged during each outage for each of the four steam generators. Table 3-32 

lists the reasons why the tubes were plugged. Table 3-33 lists tubes plugged for reasons other 

than wear at the AVBs.
3-143

Indian Point 2 has four Westinghouse model 44F steam generators. These steam generators 

were installed at the plant in December 2000. The tube supports are numbered as shown in 

Figure 2-6.

In 2001, low levels of secondary system activity were detected. Based on a review of 

fabrication records, the licensee considered tube end weld imperfections in steam generator B 

as the likely source of this activity because about 200 tube ends in this steam generator had 

weld repairs during fabrication. Although these welds were successfully tested for leak 

tightness before operation, the possibility exists that a minor flaw was missed or that the thermal 

stress of operation could have opened a subsurface flaw. The leak rate is estimated to be 

approximately 0.038 to 0.114 lpd (0.01 to 0.03 gpd) and did not change over the course of the 

cycle.

During RFO 15 in 2002, the first in-service inspection of the steam generators was performed. 

During RFO 15, 100 percent of the tubes in each of the four steam generators were inspected 

full length with a bobbin coil, with the exception of the U-bend region of the row 1 and 

row 2 tubes. In addition to the bobbin coil inspections, a rotating probe equipped with a 

plus-point coil was used to inspect:

• about 26 percent of the tubes on the hot-leg side from 7.6 cm (3 in.) above to 7.6 cm 

(3 in.) below the top of the tubesheet (which included all tubes on the periphery of the 

annulus and no-tube lane) in each of the four steam generators

• all tubes on the periphery of the annulus and no-tube lane (about 270 tubes per steam 

generator) on the cold-leg side from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top 

of the tubesheet in each of the four steam generators

• the U-bend region of 100 percent of the row 1 and row 2 tubes in each of the four steam 

generators

• 100 percent of the dings and dents with bobbin voltage amplitudes greater than or equal 

to 5 volts (23 tests) in each of the four steam generators

As a result of these inspections, 16 tubes were plugged, 13 tubes for wear at the AVBs, and 

3 tubes for volumetric indications.

The only steam generator tube degradation mechanism observed during RFO 15 was wear at 

the AVBs.

Only 13 tubes exhibited wear at the AVBs and all these tubes were plugged. The maximum 

depth reported for the AVB wear indications was 20 percent throughwall.

The three tubes that were plugged because of volumetric indications had indications that were 

attributed to deep buff marks that became indications after the sustained heating during the first 

cycle of operation (although damage because of a transient loose part could not be ruled out). 

Two of these three indications were above the fifth hot-leg tube support (in different steam 

generators), and one was above the top of the tubesheet on the hot-leg side of the steam 

generator.
3-144

To reduce the amount of sludge on the top of the tubesheet, sludge lancing was performed in 

each of the four steam generators. Forty-two pounds of sludge were removed from the steam 

generators.

After the sludge lancing, FOSAR was performed on the top of the tubesheet to identify and to 

remove foreign objects that may be found. FOSAR consisted of an in-bundle inspection in 

approximately every fifth column. Secondary-side visual inspections were performed at all 

locations where possible loose part indications were reported during the eddy current 

examination. As a result of these inspections, several loose objects were observed, some of 

which were removed. Some of the objects were not removed because of their small size and 

the time and personnel exposure required removing the objects. A licensee evaluation 

concluded that leaving the objects in the steam generators during operating cycles 16 and 17 

was acceptable.

In addition to FOSAR, an upper bundle inspection was performed in each of the four steam 

generators by looking up from the bottom of the steam generators. In addition, for one steam 

generator, the inspection port above the top support plate was removed, and an inspection 

looking downward was performed. Secondary-side visual inspections of the steam drum area in 

one steam generator were planned. These inspections were to include, but not be limited to, 

the J nozzles, feedring, and risers.

The RFO 15 bobbin coil eddy current data were reviewed to identify tubes that have potentially 

high residual stress and therefore might be more susceptible to stress corrosion cracking. 

Because of this review, no low-row (i.e., rows 1 through 8) tubes were identified as having 

potentially higher residual stresses as evidenced by the presence of an offset in the eddy 

current data as was observed at Seabrook.

On June 23, 2004, the steam generator portion of the Indian Point 2 technical specifications was 

revised to allow a one-time change to the maximum time interval between steam generator 

inspections. The change allowed the next steam generator inspection, which was to be 

performed no later than November 17, 2004, to be deferred until June 17, 2006 (ADAMS 

Accession No. ML041750603).

During RFO 16 in 2004, no steam generator tubes were inspected.

During cycles 16 and 17, very low levels of primary-to-secondary leakage were observed. The 

leakage was estimated to be about 0.114 lpd (0.03 gpd) and was not routinely detected 

because this rate of leakage is near the threshold of detection. The leakage is still attributed to 

leakage past one or more tube-to-tubesheet welds in steam generator B.

During RFO 17 in 2006, 50 percent of the tubes in each of the four steam generators were 

inspected full length with a bobbin coil, with the exception of the U-bend region of the row 1 and 

row 2 tubes. In addition to the bobbin coil inspections, a rotating probe equipped with a 

plus-point coil was used to inspect:

• 20 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the hot-leg side

• three tubes in from the annulus from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top 

of the tubesheet on both the hot- and cold-leg side
3-145

• all tubes in rows 1 and 2 from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on both the hot- and cold-leg side 

• a 20 percent sample of the overexpansions, bulges, and dents in the portion of tube 

within the tubesheet on the hot-leg side

• the U-bend region of 50 percent of the row 1 and row 2 tubes

• 100 percent of the hot-leg dings and dents with bobbin voltage amplitudes greater than 

or equal to 5 volts that were identified in RFO 15

• 20 percent of the hot-leg dings and dents with bobbin voltage amplitudes greater than or 

equal to 2 volts but less than 5 volts that were identified in RFO 17 

• all new hot-leg dings and dents with bobbin voltage amplitudes greater than or equal to 

2 volts that were identified in RFO 17

In addition to these eddy current inspections, all tube plugs and the channel heads were 

inspected visually in each of the four steam generators. All tube plugs were intact with no 

evidence of leakage. No abnormal conditions were noted during these visual inspections.

As a result of these inspections, seven tubes were plugged. All of these tubes were plugged for 

wear at the AVBs.

The only steam generator tube degradation mechanism observed during RFO 17 was wear at 

the AVBs.

Fifty-five indications of wear at the AVBs were detected in 23 tubes. Of these 23 tubes, all 

7 tubes with wear indications that penetrated more than 20 percent of the tube wall were 

plugged. The maximum depth reported for the AVB wear indications was 28 percent

throughwall. 

Thirteen tubes were identified with permeability variations during RFO 17. The tube locations 

with permeability variations were compared to historical inspections for any change in signal. 

The size of the permeability variation could limit the ability to detect degradation reliably if 

present; however, given the limited service time on the replacement steam generators and the 

inspection results from neighboring tubes without permeability variations, the licensee 

concluded no reason existed to suspect that degradation was occurring at these locations. 

The licensee’s long-term strategy is to keep tubes with permeability variations in service until 

degradation is anticipated at these locations at which time these tubes will be plugged unless 

new inspection techniques are developed that can reliably detect degradation at these locations.

To reduce the amount of sludge in the steam generators, sludge lancing was performed at the 

top of the tubesheet in each of the four steam generators and at the flow distribution baffle in 

steam generators C and D. About 23 pounds of sludge per steam generator were removed.

After the sludge lancing, FOSAR was performed at the annulus, no-tube lane, and 

approximately every fifth column in-bundle in each of the four steam generators. 

Secondary-side visual inspections were performed at all locations where possible loose part 

indications were reported during the eddy current examination. No indications of tube damage 

were observed during these visual inspections and no indications of tube damage were 
3-146

attributed to loose parts during the eddy current inspection; however, many foreign objects were 

observed. Some of the objects were a result of degradation of the moisture separator re-heater 

demister pads. These pads contain stainless steel wire components that migrated to the 

secondary side of the steam generator. Many of the foreign objects were removed from the 

steam generators. For the objects that were left in the steam generators, a licensee evaluation 

concluded that leaving the objects in the steam generators until RFO 19 was acceptable.

Visual inspections were also performed in steam generators C and D of the underside of the 

U-bend region of the tubes, the top of the sixth tube support plate for the full length of the tube 

lane, and along the length of 11 columns at the sixth tube support plate from the tube lane to the 

wrapper on both the hot- and cold-leg sides. No degradation was observed during these visual 

inspections. A very thin layer of deposits on the upper surface of the sixth tube support plate 

and between the tube hole land and the tubes was observed. The broached holes were free of 

deposits.

On February 13, 2007, Indian Point 2 revised the steam generator portion of their technical 

specifications making them performance-based consistent with TSTF-449 (ADAMS Accession 

No. ML063450333).

During RFO 18 in 2008, no steam generator tubes were inspected.

During the two cycles preceding RFO 19 (spring 2006 to spring 2010), no primary-to-secondary 

leakage was observed.

During RFO 19 in 2010, 50 percent of the tubes in each of the four steam generators were 

inspected full length with a bobbin coil, with the exception of the U-bend region of the row 1 and 

row 2 tubes. These inspections included all tubes not inspected during RFO 17. In addition, 

100 percent of the tubes in rows 22 and higher (approximately 675 additional tubes per steam 

generator) were inspected full length with a bobbin coil. In addition to the bobbin coil 

inspections, a rotating probe equipped with a plus-point coil was used to inspect:

• 20 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the hot-leg side

• three tubes in from the annulus (in the horizontal, vertical, and diagonal directions) from 

7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the tubesheet on both the hot- and 

cold-leg side

• all tubes in rows 1 and 2 from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on both the hot- and cold-leg side

• the U-bend region of 50 percent of the row 1 and row 2 tubes

• 100 percent of the hot-leg, U-bend, and cold-leg dings and dents with bobbin voltage 

amplitudes greater than or equal to 5 volts that were identified in RFO 15 and RFO 17

• 20 percent of the hot-leg, U-bend, and cold-leg dings and dents with bobbin voltage 

amplitudes greater than or equal to 2 volts but less than 5 volts that were identified in 

RFO 15 and RFO 17
3-147

• all new hot-leg dings and dents with bobbin voltage amplitudes greater than or equal to 

2 volts

In addition to these eddy current inspections, all tube plugs in each of the four steam generators

were inspected visually. All plugs were dry with no indications of leakage, unusual deposits, or 

weld cracks.

As a result of these inspections, nine tubes were plugged. All of these tubes were plugged for 

wear at the AVBs.

The only steam generator tube degradation mechanism observed during RFO 19 was wear at 

the AVBs.

A total of 207 indications of wear at the AVBs were detected in 103 tubes. The maximum depth 

reported for the AVB wear indications was 45 percent throughwall.

Secondary-side visual inspections were performed in all four steam generators during RFO 19. 

These visual inspections included FOSAR and in-bundle inspections. FOSAR was performed in

the annulus and no-tube lane after sludge lancing. The in-bundle inspections were performed 

after sludge lancing at the top of the tubesheet approximately every 10th column on both the 

hot- and cold-leg side of the steam generator. Because of FOSAR, many small foreign objects 

were detected and a number of them were removed from the steam generators. All objects left 

in the steam generators were small in size, evaluated (by the licensee), and determined to be 

too small to challenge tube integrity. No wear attributed to loose parts was observed during 

either the visual or eddy current inspections.

A review of the bobbin coil eddy current data of the high row tubes (i.e., rows 9 and above) to 

identify tubes that have potentially high residual stress and therefore might potentially be more 

susceptible to stress corrosion cracking was not performed. Such a review was not performed 

because the tubes susceptible to this phenomenon are primarily those from the Westinghouse 

Blairsville facility, and Sandvik fabricated the tubes at Indian Point 2.

During RFO 20 in 2012, no steam generator tubes were inspected.

During the two cycles preceding RFO 21 (spring 2010 to spring 2014), no primary-to-secondary 

leakage was observed.

On September 5, 2014, the steam generator portion of the Indian Point 2 technical 

specifications was revised to limit the extent of inspection in the tubesheet region. Specifically, 

the technical specifications were revised to exclude the portion of tube that is more than 48 cm 

(18.9 in.) below the top of the tubesheet from inspection (i.e., approximately the lowermost 7.62 

cm (3 in.) of tube in the tubesheet was excluded from inspection, and hence any flaws that may 

exist in this region are permitted to remain in service (ADAMS Accession No. ML14198A161 

and ML14252A679).

3.4.2 Point Beach 1

Tables 3-34, 3-35, and 3-36 summarize the information discussed below for Point Beach 1. 

Table 3-34 provides the number of full-length bobbin inspections and the number of tubes 

plugged and deplugged during each outage for each of the two steam generators. Table 3-35 
3-148

lists the reasons why the tubes were plugged. Table 3-36 lists tubes plugged for reasons other 

than wear at the AVBs.

Point Beach 1 has two Westinghouse model 44F steam generators. These steam generators 

were installed at the plant during RFO 11 in 1984. The tube supports are numbered as shown 

in Figure 2-6.

The RFO 26 bobbin coil eddy current data were reviewed to identify tubes that might have high 

residual stress and therefore might be more susceptible to stress corrosion cracking. Because 

of this review, no low-row (i.e., rows 1 through 8) tubes were identified as having potentially 

higher residual stresses as evidenced by the presence of an offset; however, 98 high-row tubes 

were identified as having potentially higher residual stresses in the straight span portion of the 

tube. Of these 98 tubes, 45 were in steam generator A.

During RFO 27 in 2003, no steam generator tubes were inspected.

During RFO 28 in 2004, 100 percent of the tubes in each of the two steam generators were 

inspected full length with a bobbin coil, with the exception of the U-bend region of all row 1 

tubes and seven row 2 tubes. In addition to the bobbin coil inspections, a rotating probe 

equipped with a plus-point coil was used to inspect:

• the hot-leg expansion transition region at the top of the tubesheet in 77 percent of the 

tubes (including all periphery tubes, two tubes deep) in each of the two steam 

generators

• the U-bend region of all row 1 tubes and the seven row 2 tubes that were not inspected 

with the bobbin coil in each of the two steam generators

• 100 percent of the dings, dents, and bulges with bobbin voltage amplitudes greater than 

or equal to 5 volts in each of the two steam generators

As a result of these inspections, no tubes were plugged.

The only steam generator tube degradation mechanisms observed during RFO 28 were 

(1) wear at the AVBs, (2) wear at the tube support plates, (3) wear attributed to loose parts, and 

(4) wear attributed to maintenance activities.

A total of 45 indications of wear at the AVBs were detected in steam generator A, and 

21 indications of wear at the AVBs were detected in steam generator B. The maximum depth 

reported for the AVB wear indications was 27 percent throughwall.

Three indications of wear were detected at the tube support plate elevations. All of the 

indications were in steam generator A, and the maximum depth reported was 18 percent

throughwall. 

Wear attributed to either transient loose parts that are no longer present or damage from 

sludge-lancing equipment was detected in 14 tubes in steam generator A and 1 tube in steam 

generator B. Based on visual examination, no objects were present at these locations. All of 

these indications were near the top of the tubesheet on the hot-leg side of the steam generator. 

The maximum depth reported for these indications was 11 percent throughwall.
3-149

Possible loose parts were identified on six tubes in steam generator B. No wear was detected 

on these tubes. After secondary-side cleaning, a secondary-side visual examination verified 

that no loose parts remained in the region of concern. 

During RFO 29 in 2005, approximately 50 percent of the tubes in steam generator A were 

inspected full length with a bobbin coil including all tubes with previous AVB wear indications 

and the 45 tubes (all in high rows) with potentially higher residual stresses. In addition to the 

bobbin coil inspections, a rotating probe equipped with a plus-point coil was used to inspect:

• 20 percent of the tubes from 7.62 cm (3 in.) above the top of the tubesheet to the tube 

end on the hot-leg side in steam generator A

• the U-bend region of 20 percent of the row 1 tubes in steam generator A

• 100 percent of freespan dings and dents with bobbin voltage amplitudes greater than 

5 volts in steam generator A

• 100 percent of dents and dings at supports with bobbin voltage amplitudes greater than 

2 volts in steam generator A

As a result of these inspections, no tubes were plugged.

The only steam generator tube degradation mechanisms observed during RFO 29 were 

(1) wear at the AVBs, (2) wear at the tube support plates, (3) wear attributed to loose parts, and 

(4) wear attributed to maintenance activities.

Fifty-two indications of wear at the AVBs were detected in 31 tubes in steam generator A. The 

maximum depth reported for the AVB wear indications was 27 percent throughwall.

Four indications of wear in four tubes were detected at the tube support plate elevations. All of 

the indications were in steam generator A, and the maximum depth reported was 16 percent

throughwall.

Wear attributed to either transient loose parts that are no longer present or damage from sludge 

lancing equipment was detected in 16 tubes in steam generator A. All of these indications 

(19 indications in 16 tubes) were present in prior inspection data (although two were not initially 

reported). Based on visual examination, no objects were present at these locations. All of 

these indications were near the top of the tubesheet on the hot-leg side of the steam generator. 

The maximum depth reported for these indications was 11 percent throughwall.

One tube in steam generator A (in row 38, column 69) was not expanded to the full length of the 

tubesheet. This tube is routinely inspected with a rotating probe equipped with a plus-point coil 

from the top of the tubesheet to the tube end. No degradation has been found in this tube.

Three dents were identified in steam generator A during RFO 29. These dents had voltages 

between 2.0 and 4.99 volts as measured with a bobbin coil. One hundred eighty-four dings 

were also identified in steam generator A during RFO 29. Of these dings, 131 had voltages 

between 2.0 and 4.99 volts, and 53 had voltages of 5 volts or greater as measured with a 

bobbin coil. Dents and dings are local reductions in the tube’s diameter. A dent is an indication 

with no history while a ding is an indication with history. For the three signals classified as 

dents, the previous data (i.e., first outage in which eddy current data were recorded on an 
3-150

optical disk) could not be retrieved so the indications were classified as dents. Both dings and 

dents can occur at structures.

Inspection and maintenance on the secondary side of steam generator A were also performed 

during RFO 29. To reduce the amount of sludge on the top of the tubesheet, sludge lancing 

was performed in steam generator A. About 31 pounds of sludge was removed from steam 

generator A. The post sludge lancing visual inspections confirmed that some hard adhering 

scale was not being washed off the tubesheet. Inspection of the upper support plate revealed 

no degradation; however, the inspection confirmed the presence of heavy scale on the outside 

of the tubes.

Sludge scale samples from steam generators A and B taken during RFO 28 had a copper 

content of about 16 percent (weight-percent). The copper content in the sludge collars at the 

top of the tubesheet is higher (about 22 percent). Because copper in steam generators can 

affect the eddy current data quality, the licensee records all bobbin coil signals attributed to 

copper deposits when the voltage is equal to or greater than 1 volt. No copper deposit signals 

were reported during recent inspections. The licensee planned to perform chemical cleaning in 

2008.

Visual inspections of the steam generator A steam drum revealed no significant degradation of 

the swirl vanes, moisture separators or feedring J nozzles. Although no significant degradation 

was found, two small areas of magnetite buildup were noted on the outside of two swirl vanes 

(about 5 cm (2 in.) high by 10.2 cm (4 in.) wide) between the vanes and the lower deck 

supporting plate. In addition, one of the perforated side plates of the secondary moisture 

separator in steam generator A had a slight bow. The offset is about 12.7 mm (0.5 in.). The 

bow is visible in earlier inspection video and the offset appears unchanged. The plate and 

welds were not cracked. The plate guides flow though the moisture separator by limiting cross 

flows. The steam pressure is balanced across the plate, and the slight offset should not affect 

performance of the plate or challenge its integrity. Minor weld burn through from construction 

was noted in two closely spaced J-nozzles. The licensee evaluated the condition and 

determined it would not affect nozzle function. No flow-induced corrosion was found.

One possible loose part indication was identified in steam generator A. No wear was 

associated with this possible loose part. A secondary-side visual examination verified that no 

loose part was present.

A small foreign object was found and retrieved during the secondary-side visual inspection near 

rows 1 and 2, column 78. The object was a small steel pin about 3.175 cm (1.25 in.) long, about 

6.35 mm (0.25 in.) in diameter. No degradation was observed in conjunction with this loose

part. The licensee concluded that the part was from steam generator maintenance equipment. 

Several fine wires (about 0.4 mm (one sixty-fourth inch) in diameter by 12.7 mm (0.5 in.) long) 

were left in steam generator A. The fine wires are believed to be residue from the 

secondary-side moisture separator reheater demisting pads. The pads have been removed 

from the moisture separators. For the objects left in the steam generator, the licensee 

performed an evaluation and concluded that leaving the objects in the steam generators was 

acceptable for at least two operating cycles.

Steam generator B was not cleaned or inspected during RFO 29.
3-151

On August 22, 2006, Point Beach 1 revised the steam generator portion of their technical 

specifications making them performance-based consistent with TSTF-449 (ADAMS Accession 

No. ML062050312 and ML062440008).

On April 4, 2007, the steam generator portion of the Point Beach 1 technical specifications was 

revised to limit the extent of inspection in the hot-leg tubesheet region. Specifically, the 

technical specifications were revised to exclude the portion of tube that is more than 43.2 cm 

(17 in.) below the top of the tubesheet from inspection (i.e., approximately the lowermost 10.2 

cm (4 in.) of tube in the tubesheet on the hot-leg side was excluded from inspection, and hence 

any flaws that may exist in this region are permitted to remain in service). This alternate tube 

repair criteria is not applicable to the tube at row 38, column 69, in steam generator A, which is 

not expanded the full length of the tubesheet. This revision was applicable only to RFO 30 and 

the subsequent operating cycle (ADAMS Accession No. ML070800705).

There was minimal primary-to-secondary leakage (less than 3.79 lpd (1 gpd)) during Cycle 30 

(fall 2005 to spring 2007).

During RFO 30 in 2007, about 54 percent of the tubes in steam generator B were inspected full 

length with a bobbin coil. Additionally, a bobbin coil was used to inspect the straight sections of 

181 tubes on the hot-leg side, the straight section of 51 tubes on the cold-leg side, and 81 tubes 

from the tube end on the cold-leg side to the top tube support plate on the hot-leg side. In 

addition to the bobbin coil inspections, a rotating probe equipped with a plus-point coil was used 

to inspect:

• 50 percent of the tubes from 43.2 cm (17 in.) below to 7.6, 15.2 and 20.3 cm (3, 6, and 

8 in.) above the top of the tubesheet (1,398, 205, and 7 tubes, respectively) on the hotleg side in steam generator B

• the U-bend region of 50 percent of the row 1 and row 2 tubes in steam generator B

• all dents and dings in the freespan regions with bobbin voltage amplitudes greater than 

or equal to 5 volts in steam generator B

• all dents and dings at tube support plate intersections and in the U-bend region with 

bobbin voltage amplitudes greater than or equal to 2 volts in steam generator B

No primary side tube inspections were performed in steam generator A during RFO 30.

As a result of these inspections, no tubes were plugged.

The only steam generator tube degradation mechanisms observed during RFO 30 were wear at 

the AVBs, wear attributed to loose parts, and wear attributed to maintenance activities.

Twenty-three indications of wear at the AVBs were detected in 13 tubes in steam generator B. 

The maximum depth reported for the AVB wear indications was 26 percent throughwall.

Wear attributed to either transient loose parts that are no longer present or damage from sludge 

lancing equipment was detected in one tube in steam generator B. This indication was present 

in the prior inspection data. Based on visual examination, no object was present at this location. 

This indication is near the top of the tubesheet on the hot-leg side of the steam generator. The 

maximum depth reported for this indication was 7 percent throughwall.
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The extent of the rotating probe exams above the top of the tubesheet were based on the height 

of the sludge. The highest estimated sludge level based on a review of RFO 28 (2004) eddy 

current data was 11.5 cm (4.55 in.). The inspection extent was increased above 11.5 cm 

(4.55 in.) to supply some margin.

One possible loose part indication was identified in steam generator B, but no wear was 

associated with it. A secondary-side visual examination identified several pieces of scale in this 

region and some of the pieces were retrieved.

Inspection and maintenance on the secondary side of steam generator B were also performed 

during RFO 30. To reduce the amount of sludge on the top of the tubesheet, sludge lancing 

was performed in steam generator B. Post sludge lancing visual inspections revealed adherent 

scale similar to that observed in steam generator A during RFO 29.

FOSAR was performed in steam generator B during RFO 30. FOSAR included the annulus, the 

no-tube lane, and select in-bundle columns. As a result of these inspections, a very small fine 

wire was detected. The wire was not removed from the steam generator, as the licensee 

determined that the wire would not adversely affect the steam generator for at least two 

operating cycles.

The uppermost (sixth) tube support plate in steam generator B was inspected visually. No 

anomalies were observed on the lower U-bends and no foreign objects were detected on the 

sixth tube support plate. Blockage of the quatrefoil shaped holes was observed. The degree of 

blockage within individual quatrefoils ranged from zero to 100 percent. Overall, the aggregate 

blockage of the quatrefoil openings is slightly less than that observed in steam generator A. 

During RFO 30, in steam generator A, visual inspections to assess the degree of quatrefoil 

blockage showed that the conditions did not appear to have changed since RFO 29. The 

degree of blockage within individual quatrefoils ranged from zero to 100 percent, and the overall 

aggregate is estimated at 40 percent blockage. Chemical cleaning was scheduled for the fall of 

2008 for both steam generators A and B. This cleaning was intended to eliminate or minimize 

this blockage.

Visual inspections of the steam drum (upper shell and upper internals including primary and 

secondary moisture separator assemblies), feedring, and J-nozzles were also performed in 

steam generator B during RFO 30. Flow impingement patterns were observed on the feedring 

and on the outside of some primary moisture separator riser barrels as well as under and 

around several J-nozzles. Erosion of the feedwater ring and riser barrel areas was not 

discernible by touch. Bowing was observed in one of the perforated plates of the secondary 

moisture separator. The bowing is similar to what was observed in steam generator A during 

RFO 29. Re-inspection of the bowed perforated plate in steam generator A during RFO 30 

revealed no change supporting a conclusion that these areas are from initial construction and 

are not service related. Melt-through was observed on the interior of some J-nozzles (where the 

J-nozzle is welded to the feedring) in steam generator B. This was also similar to what was 

observed in steam generator A during RFO 29. Re-inspection of these regions in steam 

generator A during RFO 30 indicated no change supporting a conclusion that these areas are 

from initial construction and are not service related.

On October 7, 2008, the steam generator portion of the Point Beach 1 technical specifications 

was revised to permit certain sized flaws near the tube end in both the hot- and cold-leg sides of 

the steam generator to remain in service. Specifically, the technical specifications were revised 
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to (1) permit flaws having a circumferential component less than or equal to 203 degrees found 

in the portion of the tube below 43.2 cm (17 in.) from the top of the tubesheet and above 

2.54 cm (1 in.) from the bottom of the tubesheet to remain in service, (2) require the removal 

from service all flaws having a circumferential component greater than 203 degrees found in the 

portion of the tube below 43.2 cm (17 in.) from the top of the tubesheet and above 2.54 cm 

(1 in.) from the bottom of the tubesheet, (3) require the removal from service all tubes with 

service-induced flaws between the top of the tubesheet and 43.2 cm (17 in.) below the top of 

the tubesheet, and (4) permit all axial indications found in the portion of the tube below 43.2 cm 

(17 in.) from the top of the tubesheet to remain in service. In addition, the technical 

specifications were modified to indicate that when more than one flaw with circumferential 

components is found in the portion of the tube below 43.2 cm (17 in.) from the top of the 

tubesheet and above 2.54 cm (1 in.) from the bottom of the tubesheet with the total of the 

circumferential components being greater than 203 degrees and the axial separation distance of 

less than 2.54 cm (1 in.), then the tube must be removed from service (overlapping portions of 

the flaws only need to be counted once in determining the total circumferential involvement of 

the flaws). For flaws within 2.54 cm (1 in.) of the bottom of the tubesheet, the technical 

specifications were modified to indicate (1) when one or more flaws with circumferential 

components are found and the total of the circumferential components exceeds 94 degrees, 

then the tube shall be removed from service and (2) when one or more flaws with 

circumferential components are found in the portion of the tube within 2.54 cm (1 in.) from the 

bottom of the tubesheet and within 2.54 cm (1 in.) axial separation distance of a flaw above 

2.54 cm (1 in.) from the bottom of the tubesheet, and the total of the circumferential components 

found in the tube exceeds 94 degrees, then the tube shall be removed from service (overlapping 

portions of the flaws only need to be counted once in determining the total circumferential 

involvement of the flaws). This revision to the technical specifications was applicable only to 

RFO 31 and the subsequent operating cycle (ADAMS Accession No. ML082540883).

There was minimal primary-to-secondary leakage (less than 3.79 lpd (1 gpd)) during Cycle 31 

(spring 2007 to fall 2008). The leak rate has not changed over several operating cycles.

During RFO 31 in 2008, 100 percent of the tubes in each of the two steam generators were 

inspected full length with a bobbin coil, with the exception of the U-bend region of the row 1 and 

row 2 tubes. In addition to the bobbin coil inspections, a rotating probe equipped with a pluspoint coil was used to inspect:

• 100 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the hot-leg side in steam generators A and B 

• 50 percent of the tubes from the hot-leg tube end to 7.62 cm (3 in.) above the top of the 

tubesheet on the hot-leg side in steam generator A 

• 22 percent of the tubes from the hot-leg tube end to 7.62 cm (3 in.) above the top of the 

tubesheet on the hot-leg side in steam generator B 

• 30 percent of the tubes from the hot-leg tube end to 12.7 cm (5 in.) above the hot-leg 

tube end in steam generator B (for these tubes, the uppermost 43.2 cm (17 in.) of the 

tube within the tubesheet was inspected during RFO 30)

• all peripheral tubes (approximately 530 tubes) from 7.6 cm (3 in.) above to 7.6 cm (3 in.)

below the top of the tubesheet on the cold-leg side of steam generators A and B
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• the U-bend region of 50 percent of the row 1 and row 2 tubes in steam generator A and 

20 percent of the tubes in steam generator B

• all dents and dings in the freespan regions with bobbin voltage amplitudes greater than 

or equal to 5 volts

• all dents and dings at structures (with bobbin voltage amplitudes greater than or equal to 

2 volts)

• all dents and dings in the U-bend region (with bobbin voltage amplitudes greater than or 

equal to 2 volts)

As a result of these inspections, one tube was plugged. This tube was plugged because it was 

not expanded for the full depth of the tubesheet (row 38, column 69 in steam generator A).

The only steam generator tube degradation mechanisms observed during RFO 31 were 

(1) wear at the AVBs, (2) wear at the tube support plate elevations, (3) wear attributed to loose 

parts, and (4) wear attributed to maintenance activities.

Eighty-nine indications of wear at the AVBs were detected in 48 tubes in steam generator A and 

64 indications of wear at the AVBs were detected in 43 tubes in steam generator B. The 

maximum depth reported for the AVB wear indications was 33 percent throughwall. 

Five indications of wear were detected in five tubes at the tube support plate elevations. Four of 

these indications were in steam generator A, and one was in steam generator B. The maximum 

depth reported was 14 percent throughwall.

Wear attributed to either transient loose parts that are no longer present or damage from sludge 

lancing equipment was detected in 27 tubes in steam generator A (34 indications) and 1 tube in 

steam generator B (1 indication). All of these indications were slightly above the top of the 

tubesheet on the hot-leg side of the steam generator. The maximum depth reported for these

indications was 19 percent throughwall. One indication of wear attributed to a loose part was 

detected in steam generator B. Visual inspections of the area around this tube did not identify 

any loose parts. The maximum depth of this indication was 17 percent throughwall.

Four possible loose part indications were identified in RFO 31 before chemical cleaning. After

chemical cleaning, only two of these indications remained. No wear was associated with these

possible loose parts. Secondary-side visual examinations in the vicinity of these possible loose 

parts did not identify any loose parts.

During RFO 31, 546 dings and dents with bobbin voltage amplitudes greater than or equal to 2 

volts were identified in 393 tubes. A comparison of these signals with data from 1995 revealed 

all but one of the signals was present in the 1995 data. This signal was classified as a dent 

(i.e., service induced). The dent was in a peripheral tube about 2.54 cm (1 in.) above the top of 

the tubesheet on the hot-leg side of steam generator A.

A full bundle chemical cleaning was performed in both steam generators during RFO 31. After

the chemical cleaning, sludge lancing was performed at the flow distribution baffle and the 

tubesheet. The total amount of material removed through chemical cleaning and sludge lancing 

was about 7,500 pounds and 225 pounds, respectively.
3-155

Visual inspections were performed of the steam drum (upper shell and upper internals including 

primary and secondary moisture separator assemblies), feedring, J-nozzles, top (sixth) tube 

support plate, flow distribution baffle, and top of tubesheet in both steam generators during RFO 

31.

The visual inspections of the steam drum and upper internals revealed residual dry chemical 

residue and rust coloring on many areas of the components. Flow impingement patterns were 

observed on the feedring and on the outside of some primary moisture separator riser barrels as 

well as under and around several J-nozzles. Erosion of the feedwater ring and riser barrel 

areas was not discernible by touch. Inside the feedring, possible wear marks were noted in 

steam generator B near the tee at the bottom concaved portion of the distribution ring. There 

was no discernible pattern associated with these wear marks. Thin wafers of rust colored debris 

were noted in-bundle of the primary separate riser barrels. These wafers were brittle and were 

considered by the licensee to be magnetite or scale pieces that had fallen from the riser tubes.

At the top tube support plate, no anomalies were observed on the lower U-bends and no foreign 

objects were detected on the sixth tube support plate. No blockage of the quatrefoil shaped 

holes was observed; however, some scale was visible in crevices, but no pattern was 

discernible for this scale. The flow distribution baffle was clean with no discernible scale on the 

tubes or in the crevice regions.

FOSAR visual inspections included the annulus, the no-tube lane, and select in-bundle 

columns. These inspections were performed after chemical cleaning and sludge lancing. The

annulus was free of debris and sludge. The no-tube lane contained some remnants of sludge 

ranging from 6.35 mm (0.25 in.) to 12.7 mm (0.5 in.) high and confined to the center stay rod 

area. In-bundle visual examination revealed some bridging deposits and collars in a few 

columns near the center of the previous sludge pile area. The highest estimated collar height is 

approximately 2.54 cm (1 in.).

During RFO 32 in 2010, no steam generator tubes were inspected.

There was minimal primary-to-secondary leakage (leak rate varied between 0.75 and 1.5 lpd 

(0.2 and 0.4 gpd)) during Cycle 33 (spring 2010 to fall 2011). Primary-to-secondary leakage 

has been evident since before the spring 1991 outage and has remained relatively constant.

During RFO 33 in 2011, 100 percent of the tubes in each of the two steam generators were 

inspected full length with a bobbin coil, with the exception of the U-bend region of the row 1 and 

row 2 tubes. In addition to the bobbin coil inspections, a rotating probe equipped with a pluspoint coil was used to inspect:

• 50 percent of the peripheral tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the 

top of the tubesheet on the hot-leg side in steam generator A

• 50 percent of the tubes from the hot-leg tube end to 7.62 cm (3 in.) above the top of the 

tubesheet on the hot-leg side in steam generator A 

• 100 percent of the tubes from the hot-leg tube end to 7.62 cm (3 in.) above the top of the 

tubesheet on the hot-leg side in steam generator B
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• 100 percent of the peripheral tubes (about 530 tubes per steam generator) from 7.6 cm 

(3 in.) above to 7.6 cm (3 in.) below the top of the tubesheet on the cold-leg side in 

steam generators A and B

• the U-bend region of 50 percent of the row 1 and row 2 tubes in steam generators A and 

B

In addition to these eddy current inspections, all tube plugs in each of the two steam generators

were inspected visually. All plugs were dry.

As a result of these inspections, two tubes were plugged. These tubes were plugged for 

circumferentially oriented primary water stress corrosion cracking indications near the tube 

ends.

The only steam generator tube degradation mechanisms observed during RFO 33 were 

(1) wear at the AVBs, (2) wear at the tube support plate elevations, (3) wear attributed to loose 

parts, (4) wear attributed to maintenance activities, and (5) circumferentially oriented primary 

water stress corrosion cracking near the hot-leg tube ends.

Ninety-four indications of wear at the AVBs were detected in 50 tubes in steam generator A, and 

73 indications of wear at the AVBs were detected in 51 tubes in steam generator B. The 

maximum depth reported for the AVB wear indications was 37 percent throughwall. 

Eight indications of wear in eight tubes were detected at the tube support plate elevations. Five 

of these indications were in steam generator A and three were in steam generator B. The 

maximum depth reported was 16 percent throughwall. The depths of the historic indications 

remain essentially unchanged. 

Wear attributed to either transient loose parts that are no longer present or damage from sludge 

lancing equipment was detected in 10 tubes in steam generator A (10 indications). The number 

of tubes with this type of indication has decreased from prior inspections because the licensee 

is no longer including geometric anomalies in this category and because some of the indications 

were no longer detectable/reportable. All of these indications were slightly above the top of the 

tubesheet on the hot-leg side of the steam generator. The maximum depth reported for these 

indications was 11 percent throughwall. One indication of wear attributed to a loose part was 

detected in steam generator B. The size of the indication remained essentially unchanged since 

the prior inspection in RFO 31. The maximum depth of this indication was 16 percent

throughwall.

The two tubes that were plugged for circumferentially oriented primary water stress corrosion 

cracking indications near the hot-leg tube ends were rolled before plugging to provide added 

assurance against leakage and pull-out if the cracking were to become more severe in the 

future. The indications had a circumferential extent of approximately 40-degrees and were 

about 2.54 mm (0.1 in.) above the tube end. These were the only two indications of cracking 

identified during RFO 33.

Inspection and maintenance on the secondary side of each of the steam generators also were 

performed during RFO 33. To reduce the amount of sludge on the top of the tubesheet, sludge 

lancing was performed. After the sludge lancing, FOSAR was performed in the annulus region 

and tube lane in each of the steam generators. During FOSAR, 11 objects (e.g., sludge rocks, 

slag, wire, and bristles) were identified. Five of these objects (slag, wire) were removed. A
3-157

licensee assessment concluded that it was acceptable to allow the objects that could not be 

removed from the steam generator to remain until the next inspection. All of the foreign objects 

identified were in steam generator A.

Visual inspections also were performed on several secondary-side components following 

modifications made in preparation for an extended power uprate. Before implementing the 

power uprate, these components were inspected visually to establish a baseline: feedring, Jnozzles, thermal sleeve, secondary moisture separator, primary moisture separator, mid-deck 

extension, hatch, hinges, riser barrel, top hats, and externals of the feedring and J-nozzles. 

Ultrasonic measurements also were performed on the feedring, primary moisture separators, 

and swirl vanes. All 35 J-nozzles were inspected. The interior of the feedring was clear of any 

foreign material. There was burn-through at the interface of the J-nozzle and feedring at four 

J-nozzles (J-nozzle 28 in steam generator A, and J-nozzles 7, 11, and 14 in steam generator B). 

These indications are a result of steam generator fabrication. All 112 primary moisture 

separators were inspected visually. There was a light coating of magnetite on all of the primary 

moisture separators. In addition, ultrasonic thickness measurements were made on the primary 

moisture separator swirl vanes and riser barrels and the feedring for trending. Ultrasonic 

measurements were taken at 56 locations on the steam generator A primary moisture 

separators, 64 locations on the steam generator A feedring, 55 locations on the steam 

generator B primary moisture separators, and 64 locations on the steam generator B feedring. 

No abnormal measurements were identified.

During RFO 33 in 2011, modifications were made to the steam generator to ensure moisture 

carryover remains less than or equal to 0.25 percent. These modifications were made as part of 

an extended power uprate, which was implemented during cycle 34. To confirm that the steam 

drum components are performing adequately under the extended power uprate conditions, a 

monitoring program was implemented that involves inspecting the steam generator steam drum 

components during RFO 34 and RFO 35.

Cycle 34 (fall 2011 to spring 2013) presented minimal primary-to-secondary leakage (leak rate 

varied between 0.0 and 0.75 lpd (0.0 and 0.2 gpd)). Primary-to-secondary leakage has been 

evident since before the spring 1991 outage and has remained relatively constant.

During RFO 34 in 2013, 100 percent of the tubes in each of the two steam generators were 

inspected full length with a bobbin coil, with the exception of the U-bend region of the row 1 and 

row 2 tubes. In addition to the bobbin coil inspections, a rotating probe equipped with a 

plus-point coil was used to inspect:

• 100 percent of the peripheral tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the 

top of the tubesheet on both the hot- and cold-leg side in steam generators A and B

• 50 percent of the tubes from the hot-leg tube end to 7.62 cm (3 in.) above the top of the 

tubesheet on the hot-leg side in steam generator A (i.e., the 50 percent not inspected 

during RFO 33)

• 100 percent of the tubes from the hot-leg tube end to 7.62 cm (3 in.) above the top of the 

tubesheet on the hot-leg side in steam generator B

• the U-bend region of 50 percent of the row 1 and row 2 tubes in steam generators A and 

B (for steam generator A, the 50 percent sample did not include tubes inspected during 
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RFO 33; for steam generator B, the 50 percent sample were the same tubes inspected 

in RFO 33)

• 50 percent of the dents and dings with bobbin voltage amplitudes greater than 5 volts 

In addition to these eddy current inspections, all tube plugs in each of the two steam generators

were inspected visually. All plugs were dry, in their proper location, and there was no evidence 

of degradation.

Visual Inspections of the hot- and cold-leg steam generator channel head regions were 

performed during RFO 34. No indication of cladding degradation was identified in the steam 

generator A channel head; however, discoloration was observed around the hot-leg manway in 

steam generator B. This discoloration was initially observed in RFO 30 and showed no 

indication of further degradation during the RFO 34 inspections.

As a result of these inspections, no tubes were plugged.

The only steam generator tube degradation mechanisms observed during RFO 34 were wear at 

the AVBs and wear at the tube support plate elevations.

A total of 102 indications of wear at the AVBs were detected in 57 tubes in steam generator A, 

and 74 indications of wear at the AVBs were detected in 51 tubes in steam generator B. The 

maximum depth reported for the AVB wear indications was 34 percent throughwall. The 95th

percentile growth rate for the AVB wear indications is less than 3 percent throughwall per 

effective full power year.

Eleven indications of wear in 10 tubes were detected at the tube support plate elevations. Six of 

these indications (in six tubes) were in steam generator A and five indications (in four tubes) 

were in steam generator B. The one tube with multiple indications had two indications at one 

tube support plate elevation (wear was associated with two different tube support plate lands). 

The maximum depth reported was 15 percent throughwall. The depths of the historic 

indications remain essentially unchanged.

The wear reported in prior outages attributed to either transient loose parts or sludge lancing 

equipment was not detected during RFO 34.

Inspection and maintenance on the secondary side of each of the steam generators also were 

performed during RFO 34. To reduce the amount of sludge on the top of the tubesheet, sludge 

lancing was performed. After the sludge lancing, FOSAR was performed in the annulus region 

and tube lane in each of the steam generators. Two objects, a piece of gasket and a sludge 

rock, were detected and removed from steam generator A. No objects were found in steam 

generator B.

Visual inspections also were performed on the feedring (from the inside and outside), J-nozzles 

(from the inside and outside), thermal sleeve, primary moisture separator, mid-deck extension, 

hatch, hinges, riser barrel, and top hats. All accessible areas of the moisture carryover 

modifications were inspected. No anomalies or degradation were detected. Ultrasonic 

measurements were also performed on the feedring, primary moisture separators, and swirl 

vanes. All 35 J-nozzles were inspected visually. No anomalous conditions were reported; 

however, there is weld “burn through” associated with J-nozzles 2, 3, and 28 in steam generator 

A and J-nozzles 7, 11, and 14 in steam generator B. All 112 primary moisture separators were 
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visually inspected. There was a light coating of magnetite on all of the primary moisture 

separators. No anomalous conditions or degradation were reported. In addition, ultrasonic 

thickness measurements were made on eight primary moisture separators and the feedring in 

both steam generators. There were no abnormal thickness measurements and there were no 

negative trends from the baseline measurements taken during RFO 33.

3.4.3 Robinson 2

Tables 3-37, 3-38, and 3-39 summarize the information discussed below for Robinson 2. Table 

3-37 provides the number of full-length bobbin inspections and the number of tubes plugged 

and deplugged during each outage for each of the three steam generators. Table 3-38 lists the 

reasons why the tubes were plugged. Table 3-39 lists tubes plugged for reasons other than 

wear at the AVBs.

Robinson 2 has three Westinghouse model 44F steam generators. These steam generators 

were installed at the plant in 1984. At the time of the replacement, the water chemistry program 

was changed from phosphate to all-volatile treatment. The tube supports are numbered as 

shown in Figure 2-6 (although the AVBs are numbered 01A, 02A, 03A, and 04A rather than 

AVB1, AVB2, AVB3, and AVB4, respectively).

Before entering RFO 21, no primary-to-secondary leakage existed.

During RFO 21 in 2002, about 50 percent of the tubes in each of the three steam generators

were inspected full length with a bobbin coil, including all peripheral tubes (two tubes deep). In 

addition to the bobbin coil inspections, a rotating probe equipped with a plus-point coil was used 

to inspect:

• the hot-leg expansion transition region of 50 percent of the tubes in each of the three 

steam generators

• the U-bend region of 50 percent of the row 1 and row 2 tubes in each of the three steam 

generators

• approximately 20 percent of the hot-leg manufacturing buff marks and dents in each of 

the three steam generators

As a result of these inspections, eight tubes were plugged—four for wear attributed to loose 

parts, one for a mechanical wear from interaction with maintenance equipment, and three for 

manufacturing anomalies.

The only steam generator tube degradation mechanisms observed during RFO 21 were wear at 

the AVBs, wear attributed to loose parts, and wear attributed to maintenance activities (e.g., 

modifications to the wrapper to permit sludge lancing equipment installation).

Six indications of wear at the AVBs were detected in three tubes. All of these indications were 

in steam generator C. The maximum depth reported for the AVB wear indications was 

13 percent throughwall.

Wear attributed to either transient loose parts that are no longer present or damage from sludge 

lancing equipment was detected in several tubes in each of the steam generators. In addition, 

one tube was identified with a wear indication associated with a possible loose part indication. 
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Visual inspections at the location of the wear scar/possible loose part indication were not 

performed. This tube was stabilized on the hot-leg side.

Inspection and maintenance on the secondary side of each of the three steam generators were 

also performed during RFO 21. To reduce the amount of sludge on the top of the tubesheet, 

chemical cleaning and sludge lancing were performed in each of the steam generators. The 

chemical cleaning and sludge lancing were done before the eddy current inspection of the 

tubes. After the sludge lancing, secondary-side visual inspections were performed in each of 

the three steam generators. The scope of the visual inspections included the annulus and 

blowdown lane. In addition, visual inspections were performed in eight selected columns within 

the tube bundle of steam generator C before and after the chemical cleaning/sludge lancing.

Before the shutdown for RFO 22, low levels of primary-to-secondary leakage were observed 

from steam generator B. Leakage was first detected on January 17, 2004. The leak rate 

peaked at about 13.2 lpd (3.5 gpd) and subsequently reduced to less than detectable. 

Immediately before shutdown, the leak rate was detectable but less than approximately 2.65 lpd 

(0.7 gpd). A secondary-side pressure test performed on steam generator B after plant 

shutdown identified one tube, at row 23, column 72, to be leaking from the hot-leg. At a 

secondary-side pressure of 2,758 kPa (400 psi), one drop was observed every 6 seconds. 

Further investigation identified the leak location as the fourth tube support on the hot-leg side, 

and eddy current inspection techniques identified a potential loose part at this location. Visual 

confirmation and removal of the loose part was not performed because the affected tube is in 

the interior of the tube bundle. The leaking tube and an adjacent tube, which was also affected 

by the loose part (the adjacent tube did not have a throughwall flaw), were plugged and 

stabilized.

During RFO 22 in 2004, about 50 percent of the tubes (including all of the peripheral tubes) in 

steam generators A and C, and 100 percent of the tubes in steam generator B were inspected 

full length with a bobbin coil. In addition to the bobbin coil inspections, a rotating probe 

equipped with a plus-point coil was used to inspect:

• 50 percent of the tubes from 10.2 cm (4 in.) above to 5 cm (2 in.) below the top of the 

tubesheet on the hot-leg side in each of the three steam generators

• the U-bend region of 50 percent of the row 1 and row 2 tubes in each of the three steam 

generators

• 10 percent of the dings with bobbin voltage amplitudes greater than 2 volts in each of the 

three steam generators

• a sample of benign indications, such as manufacturing buff marks in each of the three 

steam generators

In addition, a rotating probe equipped with a plus-point coil was used to inspect all peripheral 

tubes (one tube deep) from 10.2 cm (4 in.) above to 5 cm (2 in.) below the top of the tubesheet 

on the cold-leg side of steam generator B.

As a result of these inspections, seven tubes were plugged. All of these tubes were plugged for 

wear attributed to loose parts. One of these tubes had an indication that was only detected 

visually. This indication was slightly above the top of the tubesheet on the hot-leg side of the 

steam generator. This wear scar was not detected with a bobbin coil or rotating probe.
3-161

Wear from loose parts, maintenance equipment, and tube supports (including AVBs) are the 

only degradation mechanisms that have been identified in the steam generators since their 

installation, and no new forms of degradation were identified during RFO 22. 

Steam generator A had 38 tubes with wear indications near the top of the tubesheet; none of 

these indications were new. Steam generator A also had two tubes with wear indications at 

tube support plates and neither showed any change since the last outage. Steam generator B 

had 31 tubes with wear indications near the top of the tubesheet, and all were at peripheral 

tubes. Steam generator B also had seven tubes with wear indications at tube supports (i.e., 

tube support plates or flow distribution baffle). Steam generator C had nine tubes with wear 

indications near the top of the tubesheet, two tubes with wear indications at tube support plates, 

and three tubes with wear indications at AVBs (AVB wear was first detected in 1995); all of 

these indications exhibited no change from previous inspections.

The cause of the primary-to-secondary leak was reported to be wear attributed to a loose part. 

This loose part also resulted in wear on an adjacent tube. The wear on the leaking tube was at 

the fourth tube support plate on the hot-leg side, and the loose part was observed on the 

low-frequency eddy current examination data. The wear on the leaking tube was quantified as 

76 percent throughwall (although it is known to actually be 100 percent throughwall) with 

roughly equivalent axial and circumferential extents. The wear on the adjacent tube, which was 

also affected by this loose part, was quantified as 55 percent throughwall with approximately

6.35 mm (0.25 in.) axial extent and minimal circumferential extent. Sizing of these wear 

indications was performed using a rotating probe equipped with a plus-point coil.

In-situ pressure testing of the leaking tube (row 23, column 72 in steam generator B on the 

hot-leg side) was performed during RFO 22. At the normal operating differential pressure of 

11,720 kPa (1,700 psi) (corrected to account for the temperature difference between room 

temperature testing and operating conditions), no leakage was identified. In the process of 

increasing pressure to verify accident leakage integrity, an intermediate pressure (15,860 kPa or 

2,300 psi) holdpoint was attained, and no leakage was identified. At the corrected accident 

leakage integrity differential pressure of 20,680 kPa (3,000 psi) (equivalent to the steam line 

break differential pressure adjusted to account for the difference between the test temperature 

and the temperature associated with postulated accident conditions), the leak rate was 

0.0620 lpm (0.0164 gpm) (0.029 lpm (0.0078 gpm) corrected for temperature). Pressure was 

then reduced and testing was again performed at normal operating differential pressure 

(11,721 kPa, or 1,700 pounds per square inch gauge (psig)) to determine if the flaw deformed at 

the steam line break differential pressure. At this test pressure, leakage of 0.0473 lpm 

(0.0125 gpm) (0.0223 lpm (0.0059 gpm) corrected for temperature) was observed. Finally, the 

tube was tested at three times normal operating differential pressure (34,474 kPa or 5,000 psig) 

to determine tube structural integrity. The tube met the structural integrity criteria and did not 

burst. Post in-situ eddy current testing of the degraded tube showed no evidence of change at 

the leak location.

To identify tubes that have potentially high residual stress and therefore might be more 

susceptible to stress corrosion cracking, bobbin coil eddy current data were reviewed. Because 

of this review, no low-row (i.e., rows 1 through 8) tubes were identified as having potentially 

higher residual stresses as evidenced by the presence of an offset and 42 high row tubes were 

identified as having potentially higher residual stresses in the straight span portion of the tube. 

Of these 42 tubes, 5 are in steam generator A, 10 are in steam generator B, and 27 are in 

steam generator C. In steam generators A and C all of the tubes received a bobbin probe 
3-162

inspection and a rotating probe inspection of the expansion transition region. In steam 

generator B, 4 of the 10 tubes received a rotating probe of the expansion transition region.

Inspection and maintenance on the secondary side of each of the three steam generators also 

were performed during RFO 22. To reduce the amount of sludge on the top of the tubesheet, 

sludge lancing was performed. After the sludge lancing, FOSAR was performed in the 

blowdown lane and annulus region in each of the three steam generators. In addition, a visual 

inspection was performed of the entire top of the tubesheet region in steam generator B (the 

previous 100 percent top of the tubesheet visual examination of steam generator B was 

conducted in 1995).

During RFO 22, a number of small pieces of what appeared to be Flexitallic gaskets and small 

metal parts (wire & weld slag) were identified and removed from steam generator B. A piece of 

weld rod that had been observed during the previous outage (RFO 21) also was removed from 

steam generator B. The weld rod caused two small indications measuring 10 percent and 

18 percent throughwall. No change was observed in the amount of throughwall penetration in 

these two indications from what was identified in the previous outage. Four or five small 

metallic foreign objects were identified and removed from steam generators A and C during 

RFO 22. The number and extent of the foreign objects removed from the steam generators is 

consistent with the plant’s past experience.

During RFO 23 in 2005, no steam generator tubes were inspected.

On March 12, 2007, Robinson 2 revised the steam generator portion of the technical 

specifications making them performance-based consistent with TSTF-449 (ADAMS Accession 

No. ML070510368).

On April 9, 2007, the steam generator portion of the Robinson 2 technical specifications was 

revised to limit the extent of inspection in the tubesheet region. Specifically, the technical 

specifications were revised to exclude the portion of tube that is more than 43.2 cm (17 in.)

below the top of the tubesheet from inspection (i.e., approximately the lowermost 10.2 cm (4 in.)

of tube in the tubesheet was excluded from inspection, and hence any flaws that may exist in 

this region are permitted to remain in service). This revision was applicable until the end of 

cycle 25 (ADAMS Accession No. ML071060259).

There no evidence of primary-to-secondary leakage during Cycle 24 (fall 2005 to spring 2007).

During RFO 24 in 2007, about 60 percent of the tubes in each of the three steam generators 

were inspected full length with a bobbin coil (including all tubes not inspected in RFO 22), with 

the exception of the U-bend region of the tubes in rows 1 and 2. In addition to the bobbin coil 

inspections, a rotating probe equipped with a plus-point coil was used to inspect:

• approximately 50 percent of the tubes from 10.2 cm (4 in.) above to 5 cm (2 in.) below 

the top of the tubesheet on the hot-leg side in each of the three steam generators

• all peripheral (outer perimeter and tube lane) tubes (two rows deep) from 10.2 cm (4 in.)

above to 5 cm (2 in.) below the top of the tubesheet on the hot- and cold-leg sides in 

each of the three steam generators

• the U-bend region of approximately 50 percent of the row 1 and row 2 tubes in each of 

the three steam generators
3-163

For the tubes scheduled to be inspected with a rotating probe at the expansion transition on the 

hot-leg side of the steam generators, the extent of inspection was increased to include from 

10.2 cm (4 in.) above to 43.2 cm (17 in.) below the top of the tubesheet if the tubes contained 

overexpansions greater than 0.038 mm (1.5 mils) or bulges or dents with bobbin voltage 

amplitudes greater than 18 volts. The overexpansions, bulges, and dents were identified 

through a review of the bobbin coil data from RFO 19, RFO 20, RFO 21, and RFO 22. In 

addition, a rotating probe equipped with a plus-point coil was used to inspect the portion of the 

tube in row 1, column 47, in the tubesheet on the cold-leg side of steam generator A because

the tube was not expanded into the tubesheet, and the portion of the tube in row 25, column 10,

in the tubesheet on the cold-leg side of steam generator B because the tube was partially 

expanded into the tubesheet.

In addition to these eddy current inspections, all tube plugs in each of the three steam 

generators were inspected visually. No degradation or abnormal leakage was identified during 

the inspection of the plugs.

Each of the 42 tubes that have potentially high residual stress and therefore might be more 

susceptible to stress corrosion cracking was inspected full length with a bobbin coil. In addition 

to the bobbin coil inspections, a rotating probe equipped with a plus-point coil was used to 

inspect 38 of the 42 tubes from 10.2 cm (4 in.) above to 5 cm (2 in.) below the top of the 

tubesheet and the remaining 4 tubes were inspected from 10.2 cm (4 in.) above to 43.2 cm 

(17 in.) below the top of the tubesheet. No degradation was observed in any of these tubes.

As a result of these inspections, six tubes were plugged. All of these tubes were plugged for 

wear attributed to loose parts.

The only steam generator tube degradation mechanisms observed during RFO 24 were 

(1) wear at the AVBs, (2) wear at tube support plates, (3) wear attributed to loose parts, and 

(4) wear attributed to maintenance activities (e.g., modifications to the wrapper to permit sludge 

lancing equipment installation).

Steam generator A had 38 tubes with wear indications near the top of the tubesheet; none of 

these indications were new. Steam generator A also had two tubes with wear indications at 

tube support plates, one of which was new. Steam generator B had about 35 tubes with wear 

indications near the top of the tubesheet, and seven tubes with wear indications at tube 

supports (i.e., tube support plates or flow distribution baffle). Steam generator C had 10 tubes 

with wear indications near the top of the tubesheet, 1 tube with a wear indication at a tube 

support plate, and 3 tubes with wear indications at AVBs (AVB wear was first detected in 1995). 

Some of these tubes were plugged. The maximum depth reported for the wear attributed to 

loose parts was 38 percent throughwall. 

Inspection and maintenance on the secondary side of each of the three steam generators were

performed during RFO 24. FOSAR was performed on the top of the tubesheet in each of the 

three steam generators. All foreign objects that were left in the steam generators were 

determined to be acceptable to remain in the steam generators for the next two operating 

cycles. Visual inspections of the steam drum in steam generator B revealed no loose parts, 

foreign objects, or significant degradation; however, a pinhole was discovered in one of the 

structures that holds the moisture separators in place (the “pagoda”). The hole was attributed to 

a preexisting hole drilled through the pipe wall during original installation. Visual inspections 

and ultrasonic thickness measurements were performed in specific locations of the feedwater 

ring. Thickness measurements were obtained at 16 accessible locations around the feedring 
3-164

and all were within acceptable limits. Six J-tubes in steam generator B also were visually 

inspected. No anomalous conditions were found.

Primary-to-secondary leakage was observed in steam generator A in February 2008. The leak 

rate varied during the cycle averaging less than 0.08 lpd (0.020 gpd), and it never exceeded 

0.15 lpd (0.040 gpd) over a 5-month period. This leakage was detectable because of a leaking 

fuel assembly that increased the primary side source term. The leaking fuel assembly was 

removed during RFO 25. 

During RFO 25 in 2008, no steam generator tubes were inspected.

On May 7, 2010, the steam generator portion of the Robinson technical specifications was 

revised to limit the extent of inspection in the tubesheet region. Specifically, the technical 

specifications were revised to exclude the portion of tube that is more than 43.9 cm (17.28 in.)

below the top of the tubesheet from inspection (i.e., approximately the lowermost 10.2 cm (4 in.)

of tube in the tubesheet was excluded from inspection, and hence any flaws that may exist in 

this region are permitted to remain in service). This revision was only applicable for RFO 26 

and the subsequent operating cycle (i.e., until the end of cycle 27) (ADAMS Accession No. 

ML100990405).

No evidence existed of primary-to-secondary leakage during cycle 26 (fall 2008 to summer 

2010); however, leakage is postulated to exist in steam generator A below the minimum 

detectable level because of the primary-to-secondary leakage observed between February 2008 

and RFO 25.

During RFO 26 in 2010, 100 percent of the tubes in each of the three steam generators were 

inspected full length with a bobbin coil, with the exception of the U-bend region of the tubes in 

rows 1 and 2. In addition to the bobbin coil inspections, a rotating probe equipped with a pluspoint coil was used to inspect:

• about 50 percent of the tubes from 10.2 cm (4 in.) above to 5 cm (2 in.) below the top of 

the tubesheet on the hot-leg side in each of the three steam generators

• all peripheral (outer perimeter and tube lane) tubes (two rows deep) from 10.2 cm (4 in.)

above to 5 cm (2 in.) below the top of the tubesheet on the hot- and cold-leg sides in 

each of the three steam generators

• the U-bend region of 100 percent of the tubes in rows 1 and 2 in steam generator A and 

approximately 50 percent of the row 1 and row 2 tubes in steam generators B and C in 

each of the three steam generators

For the tubes scheduled to be inspected with a rotating probe at the expansion transition on the 

hot-leg side of the steam generators, the extent of inspection was increased to include from 

10.2 cm (4 in.) above to 43.9 cm (17.28 in.) below the top of the tubesheet if the tubes 

contained overexpansions, bulges, or dents (which resulted in inspecting 311 tubes in steam 

generator A, 271 tubes in steam generator B, and 179 tubes in steam generator C. In addition, 

a rotating probe equipped with a plus-point coil was used to inspect all 16 tubes whose bottom 

of expansion transition is greater than 12.7 mm (0.5 in.) below the top of the tubesheet.
3-165

As a result of these inspections, 12 tubes were plugged—1 for AVB wear, 10 for wear attributed 

to loose parts/maintenance activities, and 1 for presence of a foreign object. The maximum 

depth reported for these indications was 64 percent throughwall.

The only steam generator tube degradation mechanisms observed during RFO 26 were 

(1) wear at the AVBs, (2) wear at tube support plates, (3) wear attributed to loose parts, and 

(4) wear attributed to maintenance activities (e.g., modifications to the wrapper to permit sludge 

lancing equipment installation). No corrosion related degradation has ever been observed in 

the replacement steam generators.

Steam generator A had 62 indications (in 39 tubes) of wear near the top of the tubesheet; three

of these indications were new. Steam generator A also had two indications of wear (in 2 tubes) 

at the tube support plates. Steam generator B had 57 indications (in 39 tubes) of wear 

indications near the top of the tubesheet, 11 wear indications (in 11 tubes) at tube supports (i.e., 

tube support plates or flow distribution baffle), and 4 indications (in 3 tubes) with wear 

indications at AVBs. Steam generator C had 11 indications (in 9 tubes) of wear near the top of 

the tubesheet, 14 wear indications (in 14 tubes) at a tube support plate, and 13 indications (in 

7 tubes) with wear indications at AVBs. Most of the indications near the top of the tubesheet 

were detected in prior outages. For the wear indications at tube support plates, none of the 

indications in steam generator A were new, nine of the indications in steam generator B were 

new, and 13 indications in steam generator C were new. For the AVB indications, all the 

indications in steam generator B were new and six indications in steam generator C were new. 

The previously reported indications had no significant growth. The maximum depth reported for 

the AVB wear indications was 39 percent throughwall.

No indications were detected that could be attributed to the source of the primary-to-secondary 

leakage in steam generator A.

Inspection and maintenance on the secondary side of each of the three steam generators were

performed during RFO 26. FOSAR was performed on the top of the tubesheet in each of the 

three steam generators. All foreign objects that were left in the steam generators were 

determined to be acceptable to remain in the steam generators for the next two operating 

cycles. Sludge lancing was performed at the top of the tubesheet in all three steam generators. 

About 100 pounds of sludge was removed from each steam generator. A high volume bundle 

flush was performed in all three steam generators. This activity involved delivering about

3,785 lpm (1,000 gpm) of water to the upper steam drum swirl vanes, which then cascades over 

the tube bundle for the removal of loose deposits. Visual inspections in steam generator B in 

the region above the upper tube support plate before and after the flush indicated that the 

amount of loose sludge was reduced. This inspection revealed soft sludge on the top of the 

uppermost tube support plate and some loose scale.

Visual inspections of all accessible areas of the primary and secondary separators, mid-deck, 

feedring, feedring support structures, and J-nozzles were performed in steam generators A and 

B. In addition, an ultrasonic inspection was performed on all accessible areas of the feedwater 

ring in steam generator B. No anomalous conditions were identified during the visual 

inspections and the all ultrasonic dimensions were within acceptable limits.

During RFO 26, pinholes were identified in the pagoda supports for steam generators A and C, 

which were similar to the hole identified in the same structure in steam generator B during RFO 

24. These holes were attributed to pre-existing holes drilled through the pipe wall during original 

installation. The holes in the pagoda support pipes were evaluated and determined to not 
3-166

adversely affect its integrity. The pin-hole in the steam generator B pagoda was ultrasonically 

inspected in RFO 26 and found to be unchanged since RFO 24.

During RFO 27 in 2012, no steam generator tubes were inspected.

On August 29, 2013, the steam generator portion of the Robinson technical specifications was 

revised to limit the extent of inspection in the tubesheet region. Specifically, the technical 

specifications were revised to exclude the portion of tube that is more than 46 cm (18.11 in.)

below the top of the tubesheet from inspection (i.e., approximately the lowermost 7.62 cm (3 in.)

of tube in the tubesheet was excluded from inspection, and hence any flaws that may exist in 

this region are permitted to remain in service (ADAMS Accession No. ML13198A367)).

On August 29, 2013, the steam generator portion of the Robinson technical specifications was 

revised making them consistent with TSTF-510 (ADAMS Accession No. ML13198A367).

No evidence existed of primary-to-secondary leakage during cycle 28 (spring 2012 to fall 2013).

As of RFO 28, the steam generators had been analyzed with up to 6 percent of the tubes being 

plugged.

During RFO 28 in 2013, about 50 percent of the tubes in each of the three steam generators 

were inspected full length with a bobbin coil, with the exception of the U-bend region of the 

tubes in rows 1 and 2. These bobbin coil inspections included all tubes adjacent to plugged 

tubes, tubes with prior possible loose part and bobbin indications, all tubes having potentially 

higher residual stresses in the straight span portion of the tube, tubes in rows 1, 2, and 9 that 

were scheduled for inspection in the U-bend region with an array probe, and tubes planned to 

be preventatively plugged. In addition to the bobbin coil inspections, an array probe was used 

to inspect:

• 100 percent of the tubes from the hot-leg tube end to the first tube support plate on the 

hot-leg side, peripheral (outer perimeter and tube lane) tubes (two rows deep) from the 

cold-leg tube end to the first support on the cold-leg side in each of the three steam 

generators

• the U-bend region of 20 percent of the tubes in row 9 in each of the three steam 

generators

• all dents (identified during RFO 26 or RFO 28) with bobbin voltage amplitudes greater 

than 4.0 volts in each of the three steam generators

In addition, either a rotating probe equipped with a plus-point coil or an array probe was used to 

inspect the U-bend region of 50 percent of the row 1 and row 2 tubes in each of the three steam 

generators.

In addition to these eddy current inspections, all tube plugs in each of the three steam 

generators were inspected visually. All plugs were in their proper location and there was no 

evidence of leakage past the plugs.

Visual inspections of the hot- and cold-leg steam generator channel head regions were 

performed in all three steam generators during RFO 28. This included all clad surfaces. 

No degradation was detected during the primary channel head cladding inspections.
3-167

As a result of these inspections, four tubes were plugged because the bottom of the expansion 

transition was more than 2.54 cm (1 in.) from the top of the tubesheet.

The only steam generator tube degradation mechanisms observed during RFO 28 were 

(1) wear at the AVBs, (2) wear at tube support plates (all of which are a result of wear attributed 

to loose parts), (3) wear attributed to loose parts, (4) wear attributed to maintenance activities 

(e.g., modifications to the wrapper to permit sludge lancing equipment installation), and 

(5) circumferentially oriented primary water stress corrosion cracking near the tube ends. 

Steam generator A had 10 indications (in 10 tubes) of wear near the top of the tubesheet, and 

5 indications of wear (in 5 tubes) at the tube support plates (and all are a result of wear 

attributed to loose parts). Steam generator B had 13 indications (in 13 tubes) of wear 

indications near the top of the tubesheet, 9 wear indications (in 9 tubes) at tube supports (i.e., 

tube support plates or flow distribution baffle and all are a result of wear attributed to loose 

parts), and 4 indications (in 4 tubes) with wear indications at AVBs. Steam generator C had 2 

indications (in 2 tubes) of wear near the top of the tubesheet, 17 wear indications (in 17 tubes)

at a tube support plate (and all are a result of wear attributed to loose parts), and 11 indications 

(in 7 tubes) with wear indications at AVBs. Of these wear indications, 8 of the indications in 

steam generator A were new, 10 of the indications in steam generator B were new, and 8 of the 

indications in steam generator C were new. The maximum depth reported for wear indications 

attributed to loose parts and maintenance activities was 34 percent throughwall. The maximum 

depth reported for the AVB wear indications was 28 percent throughwall.

Two indications of circumferentially oriented primary water stress corrosion cracking were 

detected in two tubes during RFO 28. The circumferential primary water stress corrosion 

cracking indications were at the hot-leg tube end. This region of the tube had not been 

examined before with a probe capable of detecting cracking. These tubes were left in service 

since the indications were below the region of the tube required to be inspected as discussed 

above.

Eddy current data were taken to evaluate AVB insertion depth. A review of this data confirmed 

that a support structure was present at all tubes that should be supported by a particular AVB.

Inspection and maintenance on the secondary side of each of the three steam generators were

performed during RFO 28. Chemical cleaning and sludge lancing were performed during RFO 

28 before the eddy current inspections discussed above. The steam generators were 

chemically cleaned using the AREVA deposit minimization treatment. The chemical cleaning 

resulted in approximately 3600 to 3800 pounds of material being removed from the steam 

generators. Most of the material removed was iron, but some copper also was removed. 

Sludge lancing was performed at the top of the tubesheet and at the flow distribution baffle 

following the chemical cleaning in all three steam generators. The sludge lancing removed an 

additional 500 pounds of material. FOSAR was performed on the top of the tubesheet in each 

of the three steam generators, which included an in-bundle visual inspection near the top of the 

tubesheet using an AREVA system. The results were good. The visual inspection included the 

high flow velocity region, the peripheral tubes, open tube lane, and approximately five tubes into 

the tube bundle from the periphery. The inspections revealed six metallic objects (five Flexitallic 

gaskets and one small wire). All of these objects were removed.

After chemical cleaning, a visual inspection of the upper tube bundle region in steam generator 

A was performed. The inspections indicated the steam generator was very clean. Some tubes 
3-168

were very clean and some still had some deposits. No blockage of the tube support plate 

openings was identified. There was a noticeable improvement in the condition (deposit loading) 

of this steam generator since RFO 26.

A visual inspection of the steam drum in steam generator C revealed no evidence of erosion or 

corrosion.

As this report was being prepared, a primary-to-secondary leak occurred at Robinson 2. After

RFO 28, operation at Robinson 2 was commenced on November 4, 2013. On 

February 27, 2014, a primary-to-secondary leak was initially detected. The unit was shut down 

on March 7, 2014, because of this leakage. The primary-to-secondary leak rate was about

144 lpd (38 gpd) at the time of the shutdown. The leak was attributed to a loose part that was 

introduced into the feedwater system during maintenance performed in RFO 28. The affected 

tube had adequate structural integrity, and the steam generator had adequate leakage integrity 

(although an administrative issue with the plant technical specifications was identified with 

respect to the accident-induced leakage performance criterion).

3.4.4 Salem 1

Tables 3-40, 3-41, and 3-42 summarize the information discussed below for Salem 1. Table 

3-40 provides the number of full-length bobbin inspections and the number of tubes plugged 

and deplugged during each outage for each of the four steam generators. Table 3-41 lists the 

reasons why the tubes were plugged. Table 3-42 lists tubes plugged for reasons other than 

wear at the AVBs.

Salem 1 has four Westinghouse model F steam generators. These steam generators were 

installed at the plant in 1997. The steam generators at Salem 1 were replaced with the steam 

generators from the canceled Seabrook 2 plant. The licensee numbers its tube supports from 

the hot-leg flow distribution baffle (FBH or BPH) to 7H on the hot-leg side of the steam 

generator and from FBC/BPC to 7C on the cold-leg side (Figure 2-4).

During RFO 15 in 2002, 100 percent of the tubes in each of the four steam generators were 

inspected full length with a bobbin coil, except for the U-bend region of those tubes in rows 1 

and 2 that were inspected with a rotating probe. In addition to the bobbin coil inspections, a 

rotating probe equipped with a plus-point coil was used to inspect:

• the U-bend region of 20 percent of the row 1 and row 2 tubes in each of the four steam 

generators

• 100 percent of hot-leg dents and dings with bobbin voltage amplitudes greater than 

5 volts (as determined from the RFO 14 data) in each of the four steam generators 

(dents are a reduction in tube diameter at a support (e.g., tube support plate, AVB), and 

a ding is a reduction in tube diameter in the freespan)

• all previously identified tubesheet expansion anomalies (over expansions and under 

expansions) in each of the four steam generators

• 30 percent of the tubes from 5.1 cm (2 in.) above to 7.62 cm (3 in.) below the top of the 

tubesheet on the hot-leg side in steam generators A and C.
3-169

In addition to these eddy current inspections, all tube plugs in each of the four steam generators

were inspected visually. This inspection resulted in identifying one tube plug in steam generator 

D at row 4, column 69, on the hot-leg side with slightly more boron accumulation than the other 

tube plugs. The light coating of boron was removed from the plug and the plug location was 

monitored for a period of time. No leakage or other boric acid was observed during the review 

period; therefore, the licensee concluded that the minor boron observed on the plug was 

because of plug surface conditions rather than service-induced degradation of the plug.

As a result of these inspections, 33 tubes were plugged. All of these tubes were plugged for 

wear at the AVBs.

The only steam generator tube degradation mechanisms observed during RFO 15 were wear at 

the AVBs and wear at tube support plates.

During RFO 15, 1,387 indications of wear at the AVBs were identified. The maximum depth 

reported for the AVB wear indications was 54 percent throughwall. Wear at the AVBs was 

reported if the indication’s depth exceeded 10 percent throughwall.

Wear at the tube support plates was observed in one tube during RFO 15. This was the first 

instance of wear at a tube support plate at Salem 1. This tube was plugged because of a wear 

indication at an AVB that exceeded the plugging limit.

To identify tubes that could have high residual stress and therefore might be more susceptible 

to stress corrosion cracking, a review was performed of all low-row (i.e., rows 1 through 10) 

RFO 14 bobbin coil eddy current data. As a result of this review, no low-row tubes were 

identified as having potentially higher residual stresses as evidenced by the presence of an 

offset in the eddy current data in the U-bend. Although no tubes were identified with an offset in 

the U-bend region, three tubes were identified in steam generator D with an eddy current 

signature that was different than the bulk of the population reviewed (i.e., there was an offset in 

the eddy current data above the second tube support plate). The tubes are in row 2, column 85;

row 4, column 75; and row 10, column 83. A review of the preservice data (1996) showed that 

the eddy current signal from these tubes has been the same since manufacture. In addition,

one higher-row tube in steam generator D was identified with a similar type of signal as those 

discussed above, although the offset was between the fifth AVB and the cold-leg tangent point. 

This tube was at row 49, column 54. These four tubes in steam generator D are being tracked 

for future observation.

During the preservice inspection, 37,855 manufacturing burnish mark indications were identified 

using reporting criteria more conservative than the standard criteria. The standard guideline for 

reporting manufacturing burnish marks during an in-service inspection examination would 

require the indication to be greater than 12.7 mm (0.5 in.) in length, greater than 2 volts, and 

less than 90 degrees in the 150 kilohertz absolute channel. During RFO 13 and 14, these 

indications were reviewed to determine whether the phase angle changed by more than 15 

degrees or the voltage amplitude changed by more than 0.5 volts. If the indications changed 

(per this criteria), they were inspected with a rotating probe. No degradation was detected at 

locations where change was observed. During RFO 15, the signals were not monitored for 

change; rather the data were screened for “degradation” in the primary screening channel.

During RFO 15, one permeability variation indication was identified. The location was inspected 

with a magnetically biased rotating probe equipped with a plus-point coil and no degradation

was detected.
3-170

Several possible loose part indications were identified during RFO 15. All of the indications 

were slightly above the top of the tubesheet on the hot-leg side. There were five possible 

loose-part indications in steam generator A and five indications in steam generator C. Because

the secondary sides of the steam generators were not opened during RFO 15, no visual 

examinations were performed to determine if these possible loose part indications were actual 

loose parts or if they were sludge related. Neither the tubes containing the possible loose part 

signals nor the adjacent tubes had indications of wear. Because there were no wear indications 

and because the secondary-side flow conditions at the locations of these signals would result 

only in small vibration amplitudes at the secondary face of the tubesheet, the licensee 

concluded it was acceptable to leave these tubes in service. These locations were scheduled to 

be visually inspected during RFO 16 in 2004. There were also two tubes in steam generator D 

(row 42, column 62, and row 42, column 63) with possible loose part indications in RFO 15. 

These tubes had similar indications during the prior outage (RFO 14). Visual inspections during 

RFO 14 attributed the possible loose part indications to a small machine curl that could not be 

removed. There was no wear at the location of the possible loose part indications.

Sludge lancing was not performed during RFO 15; however, sludge mapping of each steam 

generator was performed by means of an automated data analysis program utilizing the low 

frequency bobbin coil data. A total of 197 tubes were identified with sludge, of which 28 were in 

steam generator A, 43 were in steam generator B, 61 were in steam generator C, and 65 were 

in steam generator D. The maximum height of sludge deposits was 4.85 cm (1.91 in.).

During RFO 16 in 2004, 100 percent of the tubes in each of the four steam generators were 

inspected full length with a bobbin coil, except for the U-bend region of those tubes in rows 1 

and 2 that were inspected with a rotating probe. In addition to the bobbin coil inspections, a 

rotating probe equipped with a plus-point coil was used to inspect:

• about 50 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of 

the tubesheet on the hot-leg side in each of the four steam generators

• the U-bend region of 20 percent of the row 1 and row 2 tubes in each of the four steam 

generators

• 20 percent of hot-leg dents and dings with bobbin voltage amplitudes greater than 

5 volts in each of the four steam generators

• 100 percent of the dents and dings in the U-bend region with bobbin voltage amplitudes 

greater than or equal to 2 volts in each of the four steam generators

• all previously identified tubesheet anomalies in each of the four steam generators

As a result of these inspections, 37 tubes were plugged—28 for wear at the AVBs, 3 for wear 

from a loose part, 3 for permeability variations, 1 for a data quality issue in the U-bend region, 

and 2 for eddy current offsets that could indicate high residual stress (and therefore more 

susceptible to stress corrosion cracking).

The only steam generator tube degradation mechanisms observed during RFO 16 were wear at 

the AVBs and wear attributed to loose parts.

The maximum depth reported for the AVB wear indications was 49 percent.
3-171

Three tubes were identified with wear attributed to loose parts during RFO 16. These three 

tubes were plugged. The indications were above the tubesheet on the cold-leg side of steam 

generator A, and the maximum depth of these indications was 8 percent throughwall. The loose 

part was removed from the steam generator.

To identify tubes that might have high residual stress and therefore might be more susceptible 

to stress corrosion cracking, all high-row (row 11 and higher) RFO 15 bobbin coil eddy current 

data were reviewed. As a result of this review, about 185 high-row tubes were identified as 

having potentially higher residual stresses. Two of these tubes were noted as having noticeably 

smaller voltage offsets than the other tubes. Although no degradation was detected, these 

tubes were plugged.

On October 14, 2005, Salem 1 revised the steam generator portion of the technical 

specifications making them performance-based consistent with TSTF-449 (ADAMS Accession 

No. ML052900201).

During RFO 17 in 2005, no steam generator tubes were inspected.

On March 27, 2007, the steam generator portion of the Salem 1 technical specifications was 

revised to limit the extent of inspection in the tubesheet region. Specifically, the technical 

specifications were revised to exclude the portion of tube that is more than 43.2 cm (17 in.)

below the top of the tubesheet from inspection (i.e., approximately the lowermost 10.2 cm (4 in.)

of tube in the tubesheet was excluded from inspection, and hence any flaws that may exist in 

this region are permitted to remain in service). This revision was only applicable for RFO 18 

and the subsequent operating cycle (ADAMS Accession No. ML070790081).

There was no evidence of primary-to-secondary leakage during Cycle 18 (fall 2005 to spring 

2007).

During RFO 18 in 2007, 100 percent of the tubes in each of the four steam generators were 

inspected full length with a bobbin coil. In addition to these bobbin coil inspections, a rotating 

probe equipped with a plus-point coil was used to inspect:

• 20 percent of bulges with bobbin voltage amplitudes greater than or equal to 18 volts

(about 236 bulges) and overexpansions greater than or equal to 0.038 mm (1.5 mils) 

(about 489 overexpansions) within the top 43.2 cm (17 in.) of the tubesheet on the hotleg side 

• all hydraulic overexpansions at the top of the tubesheet on both the hot- and cold-leg 

side of the steam generators

• all dents and dings with bobbin voltage amplitudes greater than 5 volts on the hot- and 

cold-leg sides in 62 tubes with potentially elevated residual stresses

• all dents and dings in the U-bend region with bobbin voltage amplitudes greater than or 

equal to 2 volts in 62 tubes with potentially elevated residual stresses

• all indications of AVB wear that were reported during the bobbin coil inspection in 

62 tubes with potentially elevated residual stresses
3-172

In addition to these eddy current inspections, all tube plugs in each of the four steam 

generators, including plugs installed during RFO 18, were inspected visually.

As a result of these inspections, 96 tubes were plugged—95 for wear at the AVBs, and 1 for a 

permeability variation.

The only steam generator tube degradation mechanism observed during RFO 18 was wear at 

the AVBs.

Of the 1,649 indications of wear at the AVBs detected during RFO 18, 356 were in steam 

generator A, 319 were in steam generator B, 630 were in steam generator C, and 344 were in 

steam generator D. Of the 1,649 indications, 447 were removed from service. The maximum 

depth reported for the AVB wear indications was 71 percent throughwall. This indication 

exceeded the condition monitoring limit. As a result, a full tube in-situ pressure test was 

performed. No leakage occurred at any of the in-situ test pressures including the three time 

normal operating differential pressure. This tube was stabilized and plugged. Because of this 

indication, wear indications attributed to AVB wear were removed from service if the depth was 

greater than or equal to 33 percent throughwall.

During RFO 18, one permeability variation indication was identified. The location was inspected 

with a magnetically biased rotating probe equipped with a plus-point coil and no degradation 

was detected. This tube was plugged.

Secondary-side maintenance and inspections were also performed during RFO 18. A 

high-volume upper bundle flush and sludge lancing at the top of the tubesheet were performed 

in each of the four steam generators. Visual inspections were performed after these activities to 

assess the amount of remaining sludge and fouling in the U-bend region, tube support plates 

and at the top of the tubesheet. These inspections indicated that there was no significant 

fouling or blockage in the U-bends or at the broached tube support plates. These inspections

were performed from the seventh tube support plate down to approximately the third tube 

support plate. The inspections also indicated that the sludge lancing was effective at removing 

most of the sludge at the top of the tubesheet. After sludge lancing, FOSAR was performed at 

the top of the tubesheet. These inspections included the no-tube lane, the annulus, and inner 

bundle inspections on the hot- and cold-leg sides of the steam generators. These inspections 

also included a visual examination of the tube locations where possible loose part indications 

were identified during the review of the eddy current data. No tube wear from foreign objects 

was observed during the review of the eddy current data or during the visual inspections. All 

foreign objects left in the steam generator were assessed, and the licensee concluded that they 

were not likely to cause tube wear on any tube for the remaining life of the plant.

During RFO 19 in 2008, no steam generator tubes were inspected.

On March 29, 2010, the steam generator portion of the Salem 1 technical specifications was 

revised to limit the extent of inspection in the tubesheet region. Specifically, the technical 

specifications were revised to exclude the portion of tube that is more than 33.27 cm (13.1 in.)

below the top of the tubesheet from inspection (i.e., approximately the lowermost 20.3 cm (8 in.)

of tube in the tubesheet was excluded from inspection, and hence any flaws that may exist in 

this region are permitted to remain in service). This revision was only applicable for RFO 20 

and the subsequent operating cycles (ADAMS Accession No. ML100570452).
3-173

There was no evidence of primary-to-secondary leakage during Cycle 20 (fall 2008 to spring 

2010).

During RFO 20 in 2010, 100 percent of the tubes in each of the four steam generators were 

inspected full length with a bobbin coil. In addition to these bobbin coil inspections, a rotating 

probe equipped with a plus-point coil was used to inspect:

• 100 percent of the tubes containing bulges with bobbin voltage amplitudes greater than 

or equal to 18 volts and overexpansions greater than or equal to 6.35 mm (0.25 in.) from 

7.62 cm (3 in.) above to 33.27 cm (13.1 in.) below the top of the tubesheet on the hot-leg 

side 

• all hydraulic overexpansions (bottom of the expansion transition is above the top of the 

tubesheet) on both the hot- and cold-leg side of the steam generators (the inspections 

axially bounded the anomaly and were no less than 7.62 cm (3 in.) above to 5.1 cm 

(2 in.) below the top of the tubesheet)

• all hydraulic underexpansions (bottom of the expansion transition is greater than or 

equal to 10.16 mm (0.4 in.) below the top of the tubesheet) on both the hot- and cold-leg 

side of the steam generators (the inspections axially bounded the anomaly and were no 

less than 7.62 cm (3 in.) above to 5.1 cm (2 in.) below the top of the tubesheet)

• the first three outer periphery tubes including the no-tube lane tubes from 7.62 cm (3 in.)

above to 5.1 cm (2 in.) below the top of the tubesheet on both the hot- and cold-leg side 

of the steam generators

• 20 percent of the tubes from 7.62 cm (3 in.) above to 5.1 cm (2 in.) below the top of the 

tubesheet on the hot-leg side of the steam generator (some of these exams were 

accomplished because of the previously mentioned exams in the tubesheet region) 

• 20 percent of the dents and dings with bobbin voltage amplitudes greater than or equal 

to 2 volts in the hot-leg and U-bend region 

• the U-bend region of 20 percent of the tubes in rows 1 and 2 (performed only in tubes 

not inspected during RFO 15 and RFO 16)

In addition to these eddy current inspections, all tube plugs in each of the four steam generators

were inspected visually. No degradation of the plugs was observed.

As a result of these inspections, 14 tubes were plugged—7 for wear at the AVBs, 6 for loose 

parts (either an irretrievable loose part or wear attributed to a loose part), and 1 for a 

permeability variation.

The only steam generator tube degradation mechanisms observed during RFO 20 were wear at 

the AVBs, wear at the tube support plates, and wear attributed to loose parts.

Of the 1,396 indications (in 712 tubes) of wear at the AVBs detected during RFO 20, 365 were 

in steam generator A (in 179 tubes), 287 were in steam generator B (in 148 tubes), 438 were in 

steam generator C (in 218 tubes), and 306 were in steam generator D (in 167 tubes). Of the 

1,396 indications, 27 were removed from service. The maximum depth reported for the AVB 

wear indications was 44 percent throughwall. Tubes with AVB wear indications were removed 
3-174

from service if the depth was greater than 35 percent throughwall or the wear indications 

exhibited a greater than 19 percent increase in depth. In addition, one AVB wear indication was 

plugged since it was associated with a dent.

Of the 11 indications of wear at the tube support plates (in 10 tubes) detected during RFO 20, 

1 was in steam generator A (in 1 tube), 3 were in steam generator C (in 4 tubes), and 7 were in 

steam generator D (in 6 tubes). The maximum depth reported for the tube support wear 

indications was 11 percent throughwall.

Four indications of wear attributed to loose parts were detected during RFO 20 including 1 

indication (in 1 tube) in steam generator B, 1 indication (in 1 tube) in steam generator C, and 

2 indications (in 2 tubes) in steam generator D.

No crack-like indications were detected during RFO 20.

Secondary-side maintenance and inspections were also performed during RFO 20. Sludge 

lancing at the top of the tubesheet was performed in each of the four steam generators. The 

sludge lancing was effective at removing deposits on the top of the tubesheet. In steam 

generator A, about 31.5 pounds of sludge were removed. In steam generator B, about 26 

pounds of sludge were removed, and in steam generator D, about 40.5 pounds of sludge were 

removed. Visual inspections including FOSAR were performed after sludge lancing at the top of 

the tubesheet in each of the steam generators. These inspections were performed to identify 

and remove any loose parts and to assess the effectiveness of the sludge lancing. These 

inspections included the no-tube lane, the annulus, and inner bundle inspections on the hot- and 

cold-leg sides of the steam generators. Several long (from a couple of inches to several 

inches), but narrow (approximately 0.4 mm (one sixteenth inch) to 0.8 mm (one thirty-second 

inch)) strips of a brittle material were found resting on the third and fourth tube support plate in 

steam generator D. The strips broke apart when contacted by the video camera.

Visual inspections were also performed from the seventh (uppermost) tube support plate to the 

third tube support plate. These inspections showed that there were negligible deposits on the 

tubes and tube support plate surfaces and that the broached flow openings are not significantly 

fouled. Deposit mapping of the entire tube surface was performed during RFO 20 with the 

bobbin coil data.

During RFO 21 in 2011, no steam generator tubes were inspected.

On March 28, 2013, the steam generator portion of the Salem 1 technical specifications was 

revised to limit the extent of inspection in the tubesheet region. Specifically, the technical 

specifications were revised to exclude the portion of tube that is more than 38.63 cm (15.21 in.)

below the top of the tubesheet from inspection (i.e., approximately the lowermost 15.2 cm (6 in.)

of tube in the tubesheet was excluded from inspection, and hence any flaws that may exist in 

this region are permitted to remain in service (ADAMS Accession No. ML13072A105)).

There was no evidence of primary-to-secondary leakage during Cycle 22 (fall 2011 to spring 

2013).

During RFO 22 in 2013, 100 percent of the tubes in each of the four steam generators were 

inspected full length with a bobbin coil. In addition to these bobbin coil inspections, an array 

probe (X-probe) was used to inspect:
3-175

• the first three outer periphery tubes including the tubes surrounding the no-tube lane 

from the first hot-leg tube support to 38.63 cm (15.21 in.) below the top of the tubesheet 

on the hot-leg side of the steam generators 

• the first three outer periphery tubes including the no-tube lane tubes from the first coldleg tube support to 5.1 cm (2 in.) below the top of the tubesheet on the cold-leg side of 

the steam generators

• all hydraulic overexpansions (bottom of the expansion transition is above the top of the 

tubesheet) on the hot-leg side of the steam generators from 7.62 cm (3 in.) above to 

38.63 cm (15.21 in.) below the top of the tubesheet

• all hydraulic overexpansions (bottom of the expansion transition is above the top of the 

tubesheet) on the cold-leg side of the steam generators from 7.62 cm (3 in.) above to 

5.1 cm (2 in.) below the top of the tubesheet 

• all hydraulic underexpansions (bottom of the expansion transition greater than 10 mm 

(0.4 in.) below the top of the tubesheet) on the hot-leg side from 7.62 cm (3 in.) above to 

38.63 cm (15.21 in.) below the top of the tubesheet

• all hydraulic underexpansions (bottom of the expansion transition greater than 10 mm 

(0.4 in.) below the top of the tubesheet) on the cold-leg side from 7.62 cm (3 in.) above 

to 5.1 cm (2 in.) below the top of the tubesheet

• 50 percent of the hot-leg bulges with bobbin voltage amplitudes greater than or equal to 

18 volts and overexpansions with an axial length greater than or equal to 6.35 mm 

(0.25 in.) and a profile deviation equal to 0.038 mm (0.0015 in.) or greater from the 

average of the expanded tubesheet region profile from 7.62 cm (3 in.) above to 38.63 cm 

(15.21 in.) below the top of the tubesheet on the hot-leg side of the steam generator

• and 50 percent of the tubes from 7.62 cm (3 in.) above to 38.63 cm (15.21 in.) below the 

top of the tubesheet on the hot-leg side of the steam generator

In addition to the bobbin and array probe inspections, a rotating probe equipped with a pluspoint coil was used to inspect 50 percent of the dents and dings reported in RFO 20 with bobbin 

voltage amplitudes greater than or equal to 2 volts in the hot-leg and U-bend region, 100

percent of the dents and dings reported in RFO 22 with bobbin voltage amplitudes greater than 

or equal to 2 volts, and the U-bend region of 20 percent of the tubes in rows 1 and 2.

In addition to these eddy current inspections, all tube plugs in each of the four steam generators

were inspected visually. No degradation of the plugs was observed and all plugs were in their 

proper location.

During RFO 22, the hot- and cold-leg steam generator channel head regions were inspected 

visually in all four steam generators. As part of the inspections, the entire channel head internal 

surfaces including the channel head cladding, tubesheet cladding, divider plate, and associated 

welds. No degradation was identified.

As a result of these inspections, 13 tubes were plugged—8 for wear at the AVBs, and 5 for wear 

attributed to loose parts.
3-176

The only steam generator tube degradation mechanisms observed during RFO 22 were wear at 

the AVBs, wear at the tube support plates, and wear attributed to loose parts.

Of the 1,472 indications (in 737 tubes) of wear at the AVBs detected during RFO 22, 389 were 

in steam generator A (in 186 tubes), 303 were in steam generator B (in 151 tubes), 455 were in 

steam generator C (in 229 tubes), and 325 were in steam generator D (in 171 tubes). The 

maximum depth reported for the AVB wear indications was 37 percent throughwall.

Of the 20 indications of wear at the tube support plates and flow distribution baffle detected (in 

19 tubes) during RFO 22, 3 were in steam generator A (in 3 tubes), 2 were in steam generator B 

(in 2 tubes), 5 were in steam generator C (in 5 tubes), and 10 were in steam generator D (in 

9 tubes). The maximum depth reported for the tube support/flow distribution baffle wear 

indications was 12 percent throughwall.

Six indications of wear attributed to loose parts were detected during RFO 22 including 1 

indication (in 1 tube) in steam generator B, 4 indications (in 3 tubes) in steam generator C, and 

1 indication (in 1 tube) in steam generator D. All of these tubes were plugged.

No crack-like indications were detected during RFO 22.

Secondary-side maintenance and inspections were also performed during RFO 22. These 

inspections consisted of both visual inspections and ultrasonic testing. The visual inspections 

were performed to identify the general condition of the components including the feedwater ring 

components and supports, drain pipes, and primary and secondary separators. The internal 

feedwater ring visual inspection was performed to check for erosion of the carbon steel in the 

area near the J-nozzle connection to the feedwater ring (which is made from carbon steel). All 

the J-nozzles were replaced with an improved design before operating Salem 1 with the 

replacement steam generators. The new design includes Alloy 600 J-nozzles with carbon steel 

sleeve buttered with Alloy 82/182 cladding and weld. This improved design eliminated the 

potential for flow accelerated corrosion with the J-nozzles. The visual inspections of the Jnozzles are performed to validate their resistance to flow accelerated corrosion. Ultrasonic 

testing was performed on the feedrings in all four steam generators including tees, elbows, and 

reducers. Ultrasonic testing was also performed on several of the primary moisture separator 

riser barrels for impingement erosion from J-nozzle overspray on those locations identified from 

the visual inspections.

The visual inspections identified several primary moisture separator riser barrels with signs of 

impingement erosion from J-nozzle overspray. The ultrasonic inspections of the feedwater rings 

identified minor (or no) signs of flow accelerated corrosion. No flow accelerated corrosion was 

observed on the J-nozzles.

Visual inspections of the upper tube support plates were performed in all four steam generators. 

The inspections did not identify any conditions adverse to quality and the broached holes had 

relatively minor deposits.

3.4.5 Surry 1

Tables 3-43, 3-44, and 3-45 summarize the information discussed below for Surry 1. Table 

3-43 provides the number of full-length bobbin inspections and the number of tubes plugged 

and deplugged during each outage for each of the three steam generators. Table 3-44 lists the 
3-177

reasons why the tubes were plugged. Table 3-45 lists tubes plugged for reasons other than 

wear at the AVBs.

Surry 1 has three Westinghouse model 51F steam generators. These steam generators were 

installed at the plant in 1981. The tube supports are numbered as shown in Figure 2-8.

There was less than 3.79 lpd (1 gpd) primary-to-secondary leakage during the cycle preceding 

RFO 13 (i.e., fall 2001 to spring 2003).

During the cycle preceding RFO 13, a chemistry excursion occurred because of an issue with 

the condenser. Because of this excursion, a much greater amount of sludge was expected in 

the steam generator compared to past inspections.

During RFO 13 in 2003, 100 percent of the tubes in steam generator B were inspected full 

length with a bobbin coil, except for the U-bend region of the row 1 tubes. In addition, about

20 tubes in steam generator C were partially inspected with a bobbin coil from the tube end to 

either the flow distribution baffle or the first tube support plate on both the hot- and cold-leg side 

of the steam generators. These latter inspections were performed in tubes that were potentially 

affected by sludge lancing equipment used during RFO 11 in 2000. In addition to the bobbin 

coil inspections, a rotating probe equipped with a plus-point coil was used to inspect:

• 20 percent of the tubes (including the tubes in the sludge zone, periphery and other 

random locations) from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the hot-leg side

• the U-bend region of 100 percent of the row 1 tubes

• approximately 20 percent of the dents with bobbin voltage amplitudes greater than 

2 volts (including all dents with amplitudes greater than 5 volts)

The above rotating probe inspections were performed in steam generator B. In addition to 

these eddy current inspections, all tube plugs were inspected visually.

As a result of these inspections, 11 tubes were plugged—8 for mechanical wear from sludge 

lancing equipment, 2 for dents, and 1 for a permeability variation that could mask an indication.

The only steam generator tube degradation mechanisms observed during RFO 13 were wear at 

the AVBs and wear attributed to maintenance activities (sludge lance monorail system).

In steam generator B, there were 16 indications of wear detected at the AVBs. These 16

indications were in 11 tubes. The maximum depth reported for the AVB wear indications was 

22 percent throughwall. The average growth rate of the wear indications at the AVBs in steam 

generator B is approximately 1.7 percent throughwall per cycle.

Eight tubes were plugged for wear that occurred because of the latches on the monorail 

sections of the sludge lancing equipment contacting the tubes. This wear occurred during RFO 

11 in 2000. The most significant indication was 41 percent throughwall and 3.8 cm (1.5 in.)

long. The degradation was in the same area as that observed on steam generator A during 

RFO 12 in 2001.
3-178

In steam generator B, 416 dents (in 340 tubes) with bobbin voltage amplitudes greater than 

2 volts were detected. Of the 416 dents, 356 dents (in 304 tubes) had bobbin voltage 

amplitudes between 2.0 and 4.99 volts, 54 dents (in 46 tubes) had bobbin voltage amplitudes 

between 5.0 and 19.99 volts, and 6 dents (in 6 tubes) had bobbin voltage amplitudes greater 

than 20 volts. Three dents were new (i.e., not present in prior inspections). About 29 of the 

416 dents were concentrated in the periphery of the tube bundle near wedge regions and were 

at (or near) the edges of the support plates. The voltage amplitude of these dents is considered 

low.

One tube was plugged because of a freespan dent between the first and second tube support 

plates. The bobbin voltage amplitude associated with this dent was 55 volts. This dent was 

previously reported in 1994 and in 1998 and exhibited essentially no change in voltage. The 

dent could not be inspected with the normal sized rotating probe (most likely because of the 

geometry of the rotating probe motor unit) so a smaller diameter probe (a 1.73 cm (0.680 in.)

diameter rotating probe) was used to inspect this location. No degradation was identified during 

this inspection. The tube was plugged because the 1.73-cm (0.680-in.) rotating probe is not a 

qualified probe size for inspecting outside the U-bend region.

One tube was plugged because of a dent near the expansion transition whose bobbin voltage 

amplitude was 108 volts. This dent was present in 1998, but it was not identified because of its

close proximity to the expansion transition. The dent was not present in the 1994 data. 

Because of the magnitude of the dent voltage and the lack of history confirmation, this location 

was inspected with a rotating probe equipped with a plus-point coil. A 1.78-cm (0.700-in.) pluspoint probe was able to pass the dent location, and no degradation was detected. Even though

the 1.78-cm (0.700-in.) probe is a “qualified” technique and no degradation was noted, this tube 

was preventatively plugged since the location was considered to have increased susceptibility to 

corrosion-induced degradation because of the location of the dent, the potential for 

secondary-side sludge buildup, and an increase in stress near the expansion transition because 

of the dent.

To identify areas that may have unusual stress conditions, manufacturing records were 

reviewed before the outage. This review identified 49 locations with manufacturing anomalies 

(i.e., drilling or machining imperfections and related tube bulges) within the tubesheet in steam 

generator B. The screening criterion applied during fabrication was whether the bulge resulted 

in an increase in the diameter of the tube of 0.28 mm (11 mils). These 49 locations were spread 

between the hot-leg and cold-leg. Although these locations were shot peened, follow-up 

inspections were deemed appropriate. During RFO 13, 20 of these locations were inspected 

with a rotating probe equipped with a plus-point coil. No degradation was detected. Similar 

indications/locations were not reported in the manufacturing records in steam generators A and 

C.

Inspection and maintenance on the secondary side of each of the three steam generators were

also performed during RFO 13. Sludge lancing and FOSAR were performed in each of the 

three steam generators. Visual inspections of the steam drum and feedring were also 

performed in each of the three steam generators. Ultrasonic inspection of the feedrings was 

performed to determine if degradation from flow-accelerated corrosion was present. The 

licensee found no evidence of loose parts.

To identify tubes that might have high residual stress and therefore might be more susceptible 

to stress corrosion cracking, the bobbin coil eddy current data were reviewed. As a result of this 

review, no evidence of an eddy current offset was identified in any tubes in steam generator B.
3-179

During RFO 14 in 2004, no steam generator tubes were inspected.

There was less than 3.79 lpd (1 gpd) primary-to-secondary leakage during the cycle preceding 

RFO 15 (fall 2004 to spring 2006).

During RFO 15 in 2006, 100 percent of the tubes in steam generators A and C were inspected 

full length with a bobbin coil, except for the U-bend region of the row 1 tubes. In addition to 

these bobbin coil inspections, a rotating probe equipped with a plus-point coil was used to 

inspect:

• 20 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the hot-leg side in steam generators A and C

• the nine tubes that were either partially expanded or not expanded into the tubesheet on 

the hot-leg side from the tube end to 7.62 cm (3 in.) above the tubesheet in steam 

generators A and C

• the U-bend region of 100 percent of the row 1 tubes, and 20 percent of the dents with 

bobbin voltage amplitudes greater than 2 volts in steam generators A and C

In steam generator A, an additional 20 percent of the tubes were inspected with a rotating probe 

equipped with a plus-point coil from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on both the hot- and cold-leg side of the steam generator. This expansion was 

performed because of finding two indications (attributed to loose parts) with depths exceeding 

the 40 percent throughwall plugging limit which were only detected with a rotating probe (and 

not the bobbin probe).

During RFO 15, no rotating probe examinations were performed in the lower 5.1 cm (2 in.) of 

the tubes. The licensee did not consider an inspection in the bottom 5.1 cm (2 in.) necessary 

because the expected time to develop cracking in that region has not yet been reached given 

the low operating temperature compared to other plants that have observed cracking in this 

region. The licensee also indicated that cracking was not observed in other locations within the 

tubesheet (e.g., overexpansions) as had been detected at another plant (i.e., Catawba 2). 

As a result of these inspections, 16 tubes were plugged: 1 for wear at the AVBs, 8 for wear 

attributed to loose parts, and 7 for permeability variations.

The only steam generator tube degradation mechanisms observed during RFO 15 were 

(1) wear at the AVBs, (2) wear at the tube support plates, (3) wear attributed to loose parts, and 

(4) historic pit-like indications.

Forty-six indications of wear were detected at the AVBs in steam generators A and C (34 in 

steam generator A and 12 in steam generator C). These indications were in 34 tubes (27 tubes 

in steam generator A and 7 tubes in steam generator C). The average growth rate of the AVB 

wear indications since the last inspection (RFO 12 in 2001 for steam generator A, and RFO 11 

in 2000 for steam generator C) was 2.4 percent throughwall per cycle in steam generator A and 

0.8 percent throughwall per cycle in steam generator C. The growth rate of these indications is 

decreasing with time. The average growth rate considering all AVB previous data from all three 

steam generators is 2.3 percent throughwall per cycle. The maximum depth reported for the 

AVB wear indications was 27 percent throughwall. The tube with this 27 percent throughwall
3-180

indication was plugged. Indications of wear at the AVBs are reported when the depth of the 

indication exceeds 10 percent throughwall.

One indication of tube support plate wear was detected during RFO 15. This indication was in 

steam generator A at the sixth cold-leg tube support plate. The maximum depth reported for 

this indication was 14 percent throughwall.

Eleven wear indications were attributed to loose parts. Of these 11 indications, 8 had foreign 

objects adjacent to the affected location as confirmed through secondary-side visual

inspections. These objects were removed from the steam generator. The other three wear 

indications attributed to loose parts were within the flow openings of the quatrefoil tube support 

plates (steam generator C row 38 column 62 and row 15 column 62) or at the top of the flow 

distribution baffle plate (steam generator A row 27, column 84). No eddy current indications of 

loose parts were observed in the three tubes; therefore, no secondary-side visual examinations 

were attempted. The indications were not attributed to intergranular attack or pitting (which 

provide similar eddy current signals) because the locations of the flaws suggested to the 

licensee that these mechanisms were not the cause of the flaws. Intergranular attack and 

pitting normally occur in crevice and sludge pile locations where more aggressive chemistry 

environments can develop. These three indications occurred in the open tube support plate 

flow openings and at the top of the flow distribution baffle (a non-supporting structure with large 

tube holes to allow water flow), both of which are regions where deposit accumulation has not 

been identified.

Two of the tubes with indications attributed to loose parts were in-situ pressure tested. The 

indications in these tubes were attributed to a nut. The nut was removed during the outage. 

Two methods were used to size these indications. One of these tubes exceeded the in-situ 

pressure test screening criteria regardless of which sizing method was used (i.e., row 35,

column 68, in steam generator A) while the other tube (row 35, column 69, in steam generator 

A) exceeded the in-situ pressure test screening criteria based on the size estimate from only 

one of the sizing methods. The tube in row 35, column 68, was last inspected during the 2001 

refueling outage. Based on a review of the 2001 data during RFO 15, it was concluded that 

there was a wear indication in this tube that should have been called using the bobbin probe 

data analysis guidelines existing at that time. Both tubes were subjected to a full tube length 

in-situ pressure test. Neither tube leaked at the main steam line break differential pressure hold 

point. The tube in row 35, column 69, did not leak or burst at the three times normal operating 

differential pressure hold point (i.e., a pressure of 35,850 kPa (5,200 psi) at room temperature,

which accounts for the difference in material strength at normal operating temperature); 

however, the tube in row 35, column 68, began to leak at a pressure of 32,060 kPa (4,650 psi). 

The leakage rate reached 0.30 lpm (0.08 gpm) when applied pressure reached the maximum 

test pressure of 35,850 kPa (5,200 psi). This pressure was held for 5 minutes before 

terminating the test. During the 5-minute hold, the leakage continued to increase, reaching a 

maximum measured leakage rate of 3.7 lpm (0.98 gpm). Although the licensee concluded that 

the tube satisfied the structural integrity performance criteria, NRC staff expressed concerns 

during a conference call on May 10, 2006, on whether the licensee adequately demonstrated 

that the tube had adequate integrity since the leak rate was not stable at the time the test was 

concluded. Additional information is included in a letter to the licensee dated December 4, 2006 

(ADAMS Accession No. ML063380371).

A couple of pit-like indications were detected during RFO 15. No tubes were pulled to confirm 

the nature of these indications; instead, the licensee relied on knowledge gained from prior tube 

pulls (presumably from other facilities), ultrasonic testing, and rotating probe data from similar 
3-181

indications to characterize these indications as pit-like. The indications do not appear to be 

growing and are stable during normal operation.

In steam generator A, 756 dents (in 573 tubes) with bobbin voltage amplitudes greater than or 

equal to 2 volts were detected. Of the 756 dents, 677 (in 501 tubes) had bobbin voltage 

amplitudes between 2 and 4.99 volts, 69 (in 55 tubes) had bobbin voltage amplitudes between 

5.0 and 9.99 volts, and 10 (in 9 tubes) had bobbin voltage amplitudes greater than or equal to 

10 volts.

In steam generator C, 502 dents (in 339 tubes) with bobbin voltage amplitudes greater than or 

equal to 2 volts were detected during RFO 15. Of the 502 dents, 400 (in 298 tubes) had bobbin 

voltage amplitudes between 2 and 4.99 volts, 79 (in 62 tubes) had bobbin voltage amplitudes 

between 5.0 and 9.99 volts, and 23 (in 20 tubes) had bobbin voltage amplitudes greater than or 

equal to 10 volts.

Some of the dents in steam generators A (80 dents) and C (176 dents) are at the sixth and 

seventh tube support plate. Many of the dents at these two support plates are predominantly in 

peripheral tubes and are near tube support wedge locations. Historical data reviews of the 

dents reported at these locations in 2006 confirmed that none of the reported indications were 

new (i.e., all were present previously); however, two of the dents in steam generator A 

demonstrated change. These two dents were inspected with a rotating probe equipped with a 

plus-point coil and no degradation was detected.

Three bulges were identified in steam generator A during RFO 15. Two were slightly above the 

seventh tube support plate on the hot-leg side and the third was at an AVB. All of the bulges 

were examined with plus-point probes. No degradation was reported. A review of historical 

eddy current data indicates that these bulges have not increased in size (suggesting that the 

bulges occurred during fabrication of the steam generators).

Local anomalies were detected during RFO 15 and are distributed throughout the steam 

generator tube bundle. These anomalies were caused by original manufacturing and insertion 

of tubes in the support plates. They indicate scrapes and indentations on the tubes. These 

indications are tracked from outage to outage. These indications were resolved through 

reviewing historical data or plus-point examination. No cracking or other types of degradation 

were observed to be associated with these indications.

To identify tubes that might have high residual stress and therefore might be more susceptible 

to stress corrosion cracking, bobbin coil eddy current data were reviewed. As a result of this 

review, no low-row tubes (i.e., tubes in rows 1 through 8) were identified as potentially being 

more susceptible to stress corrosion cracking. A previous evaluation (i.e., before RFO 15) of 

high-row U-bend offset signals identified 19 tubes in steam generator A and 3 tubes in steam 

generator C that could have high residual stress.

In steam generator A, 282 overexpansions (in 200 tubes) were identified on the hot-leg side of 

the steam generator during RFO 15. An overexpansion is a local tube diameter increase (i.e., 

a bulge) within the tubesheet. An overexpansion is reported if the voltage exceeds 18 volts 

peak-to-peak. In steam generator A, one tube was identified where the tube was hydraulically 

expanded more than 7.6 mm (0.3 in.) above the top of the tubesheet on the hot-leg side of the 

steam generator. In steam generator C, 421 overexpansions (in 330 tubes) were identified on 

the hot-leg side of the steam generator. No tubes were identified in steam generator C that 
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were hydraulically expanded above the top of the tubesheet on the hot-leg side; however, two 

tubes were identified with this condition on the cold-leg side of the steam generator.

Two tubes in steam generator A were not expanded for the full length of the tubesheet. 

In addition, seven tubes in steam generator C were either not expanded for the full length of the 

tubesheet or were only partially expanded for the full length of the tubesheet.

Inspection and maintenance on the secondary side of the steam generators were performed 

during RFO 15. Secondary-side visual inspections were performed in all three steam 

generators including in-bundle column inspections. Sludge lancing was performed in steam 

generators A and C, which involved a trial application of a new secondary-side cleaning 

technique (i.e., inner bundle lance (IBL)) that is reported to be more effective than regular

sludge lancing along the open tube lane. Inspections were performed that confirmed that the 

IBL process did not result in any tube damage.

On March 29, 2007, Surry 1 revised the steam generator portion of their technical specifications 

making them performance-based consistent with TSTF-449 (ADAMS Accession No. 

ML070880618).

As of 2007, the licensee’s loss-of-coolant-accident analysis assumed that the average 

equivalent level of tube plugging was 15 percent in any one steam generator with no greater

than a 5 percent differential between any two steam generators expressed in terms of the 

number of tubes per steam generator.

Primary-to-secondary leakage was less than 3.79 lpd (1 gpd) during the cycle preceding RFO 

16 (spring 2006 to fall 2007).

During RFO 16 in 2007, 100 percent of the tubes in steam generator B were inspected full 

length with a bobbin coil, except for the U-bend region of the row 1 tubes. In addition to these 

bobbin coil inspections, a rotating probe equipped with a plus-point coil was used to inspect:

• 20 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the hot-leg side in steam generator B

• 50 percent of the overexpansions on the hot-leg side in steam generator B

• 20 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the cold-leg side (focusing on tube in the periphery) in steam generator B

• the largest overexpansions on the cold-leg side in steam generator B

• the U-bend region of 100 percent of the row 1 tubes in steam generator B

• 20 percent of the dents with bobbin voltage amplitudes greater than 2 volts (including all 

dents with amplitudes greater than or equal to 5 volts) in steam generator B

The tubes inspected because of overexpansions were inspected from the overexpansion to the 

tube end (i.e., 199 tube end inspections on the hot-leg and 11 on the cold-leg).
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In addition to these eddy current inspections, all tube plugs were inspected visually. These 

inspections revealed no evidence of leakage, cladding damage, tube end damage, or foreign 

objects. In addition, all plugs were verified to be in their correct position.

As a result of these inspections, one tube was plugged. This tube was plugged for a 

permeability variation.

The only steam generator tube degradation mechanisms observed during RFO 16 were wear at 

the AVBs, wear attributed to loose parts, and wear attributed to maintenance activities 

(e.g., sludge lancing).

Thirteen indications of wear were detected at the AVBs in 10 tubes in steam generator B. The 

average growth rate of the AVB wear indications in steam generator B was 1.7 percent

throughwall per cycle before RFO 16 and 1.4 percent throughwall per cycle after considering the 

RFO 16 data. The growth rate at 95 percent probability and 50 percent confidence for Surry 1 is 

5.8 percent throughwall per cycle. The growth rate associated with the wear indications at the 

AVBs is declining and no new indications were detected during RFO 16. The maximum depth 

reported for the AVB wear indications was 22 percent throughwall.

Four tubes with wear attributed to loose parts or maintenance activities were identified in steam 

generator B. Three of these tubes were in close proximity to each other, and the wear was

attributed to foreign objects that were near the affected tubes (one foreign object was 

approximately one tube away from this three-tube cluster, and two other objects were 

approximately 3 and 6 tubes away from the cluster). Two of these three indications were 

traceable to inspections performed in 1998 and have not changed in size since that time. The 

other indication was not detectable with the technique used in 1998, but the licensee concluded 

it was most likely caused by the same foreign object. Because of the clustered relationship of 

the affected tubes, their location near the periphery where sludge does not tend to accumulate, 

and the identification of the foreign objects, the licensee concluded a foreign object caused the 

indications. The fourth indication of wear is in the tube in row 1, column 7, and was attributed to 

secondary-side maintenance (e.g., sludge lancing or secondary-side inspections).

During RFO 16, 501 dents with bobbin voltage amplitudes greater than or equal to 2 volts were 

detected in steam generator B. These dents were in 389 tubes. The dents appear to be 

randomly distributed throughout the tube bundle and have a strong bias toward tube supports 

6 or 7 or the wedge regions. None of the dents detected in RFO 16 were new and none 

revealed evidence of increasing magnitude.

About 800 overexpansions are present within the tubesheet (i.e., hot- and cold-leg side of the 

steam generator).

In steam generator B, no low-row tubes (i.e., tubes in rows 1 through 8) were identified as 

potentially being more susceptible to stress corrosion cracking based on a review of eddy 

current data for an offset between the data in the U-bend and in the straight span. However, 

22 tubes were identified in steam generator B, which could have high residual stress based on a 

review of the eddy current data. The dents and the expansion transitions on the hot-leg in these 

22 tubes were inspected with a rotating probe.

Twelve tubes in steam generator B were identified with permeability variation signals. These 

locations were inspected with rotating probes equipped with a plus-point coil and in some cases 

with magnetically biased plus-point coils. No degradation was identified during these 
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inspections. In one tube, the permeability signal could not be adequately suppressed so the 

tube was plugged.

All tubes in steam generator B are expanded for the full length of the tubesheet.

Inspection and maintenance on the secondary side of the steam generators were performed 

during RFO 16. An upper bundle flush was performed in all three steam generators. After the 

upper bundle flush, the top surface of the flow distribution baffle was cleaned using a 

20,680-kPa (3,000-psi), high-flow rate static lance. This lancing was followed by a similar 

lancing process at the top of the tubesheet. About 200 pounds of sludge were removed from 

the three steam generators (56 in steam generator A, 54 in steam generator B, and 102 in 

steam generator C). After sludge lancing, FOSAR was performed in all three steam generators 

in the annulus and no-tube lane at the top of the tubesheet. In addition, in-bundle visual 

examinations were performed in all three steam generators to evaluate the effectiveness of the 

high pressure, high flow lancing process and to determine if the dimethylamine soak during shut 

down helped to reduce deposits on the tubesheet. These inspections showed that although 

some hard deposits remain in all three steam generators, a significant reduction of the tube 

collars and the bridging deposits was observed, particularly in steam generators A and C.

The upper bundle region in steam generator B was inspected visually before the upper bundle 

flush. These inspections included portions of the upper tube bundle and the uppermost 

(seventh) tube support plate. These inspections indicated that deposit accumulation and 

bridging at the AVB-to-tube intersections continues to increase as has the amount of deposits 

on the tubes in the AVB region and at the seventh tube support plate. Some deposits were also 

observed within the broached hole openings of the seventh tube support plate and light-tomoderate deposits were observed on the surface of the seventh tube support plate in the 

inner-bundle regions.

After the upper bundle flush, visual inspections were performed in steam generator A. These 

examinations revealed that the amount of deposits was somewhat reduced when compared 

with the initial conditions observed in steam generator B. Accumulation and bridging of deposits 

at the AVB-to-tube intersections were still present. No deposits were observed on the tube 

surface just above the seventh tube support plate in tubes in the periphery (unlike the pre upper 

bundle flush inspections in steam generator B). No deposit build up was seen on the lower 

edge of the broached openings in the periphery of the tube bundle as was observed in steam 

generator B before the upper bundle flush.

Portions of the feedring in all three steam generators also were inspected during RFO 16. In 

steam generator B, the internal J-nozzle feedring weld interfaces was inspected visually to 

monitor for flow assisted corrosion. These inspections revealed minor evidence of flow assisted 

corrosion with minimal evidence of change from the previous visual examination performed in 

this steam generator in April 2003. To monitor for the progression of flow assisted corrosion in 

the feedrings, ultrasonic thickness measurements were performed in all three steam generators. 

The inspections indicated that the wall thicknesses were acceptable. The largest rate of 

thickness reduction since the last inspection was at the inlet reducer of steam generator A 

(3.66 mm (144 mils) per cycle); however, there is some uncertainty on whether the exact same 

location was inspected during RFO 15 and 16. The next largest rate of thickness reduction was 

observed in the right side elbow of steam generator A (0.99 mm (39 mils) per cycle). The most 

limiting component based on current rate of progression and allowable minimum thickness is 

the downstream portion of the inlet reducer in steam generator A, which will require remediation 
3-185

or reinspection in RFO 17. The next most limiting component is the crossover pipe in steam 

generator B, which will require remediation or reinspection in RFO 20.

On April 8, 2009, the steam generator portion of the Surry 1 technical specifications was revised 

to permit certain sized flaws near the tube end in both the hot- and cold-leg sides of the steam 

generator to remain in service. Specifically, the technical specifications were revised to 

(1) permit flaws having a circumferential component less than or equal to 203 degrees found in 

the portion of the tube below 43.2 cm (17 in.) from the top of the tubesheet and above 2.54 cm 

(1 in.) from the bottom of the tubesheet to remain in service, (2) require the removal from 

service all flaws having a circumferential component greater than 203 degrees found in the 

portion of the tube below 43.2 cm (17 in.) from the top of the tubesheet and above 2.54 cm 

(1 in.) from the bottom of the tubesheet, (3) require the removal from service all tubes with 

service-induced flaws between the top of the tubesheet and 43.2 cm (17 in.) below the top of 

the tubesheet, and (4) permit all axial indications found in the portion of the tube below 43.2 cm 

(17 in.) from the top of the tubesheet to remain in service. In addition, the technical 

specifications were modified to indicate that when more than one flaw with circumferential 

components is found in the portion of the tube below 43.2 cm (17 in.) from the top of the 

tubesheet and above 2.54 cm (1 in.) from the bottom of the tubesheet with the total of the 

circumferential components being greater than 203 degrees and the axial separation distance of 

less than 2.54 cm (1 in.), then the tube must be removed from service (overlapping portions of 

the flaws only need to be counted once in determining the total circumferential involvement of 

the flaws). For flaws within 2.54 cm (1 in.) of the bottom of the tubesheet, the technical 

specifications were modified to indicate (1) when one or more flaws with circumferential 

components are found and the total of the circumferential components exceeds 94 degrees, 

then the tube shall be removed from service and (2) when one or more flaws with 

circumferential components are found in the portion of the tube within 2.54 cm (1 in.) from the 

bottom of the tubesheet and within 2.54 cm (1 in.) axial separation distance of a flaw above 

2.54 cm (1 in.) from the bottom of the tubesheet, and the total of the circumferential components 

found in the tube exceeds 94 degrees, then the tube shall be removed from service (overlapping 

portions of the flaws only need to be counted once in determining the total circumferential 

involvement of the flaws). This revision to the technical specifications was applicable only to 

RFO 22 and the subsequent operating cycle (ADAMS Accession No. ML090860735 and 

ML091040065).

On May 7, 2009, the steam generator portion of the Surry 1 technical specifications was revised 

to allow tubes in steam generator B with permeability variation indications that may mask flaws 

in the bottom 2.54 cm (1 in.) of the tubesheet to remain in service. In addition, the technical 

specifications were revised to limit the primary-to-secondary leakage in steam generator B to 

75.7 lpd (20 gpd). These changes were applicable only to RFO 22 and the subsequent 

operating cycle (ADAMS Accession No. ML091260386).

There was no evidence of primary-to-secondary leakage (i.e., leakage is less than 3.79 lpd 

(1 gpd)) during the cycle prior to RFO 17 (fall 2007 to spring 2009).

During RFO 17 in 2009, 100 percent of the tubes in steam generators A and C were inspected 

full length with a bobbin coil, except for the U-bend region of the tubes in rows 1 and 2. In 

addition to these bobbin coil inspections, a rotating probe equipped with a plus-point coil was 

used to inspect:

• 58 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the hot-leg side in steam generators A and C
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• 50 percent of the overexpansions on the hot-leg side (between the tube end and 

7.62 cm (3 in.) above the top of the tubesheet on the hot-leg side) including the five 

largest indications (by voltage amplitude) in steam generators A and C

• 50 percent of the tubes from the hot-leg tube end to 10.2 cm (4 in.) above the hot-leg 

tube end in steam generators A and C

• all tier 1 high-stress tubes (described below) from the hot-leg tube end to 7.62 cm (3 in.)

above the top of the tubesheet on the hot-leg side in steam generators A and C

• the 20 largest overexpansions (by voltage amplitude) on the cold-leg side in steam 

generators A and C

• the U-bend region of 100 percent of the row 1 and row 2 tubes in steam generators A 

and C

• 50 percent of the dents in the straight section of the hot-leg including the five largest 

dents based on bobbin voltage amplitude in steam generators A and C

Because of the initial inspection results, the scope of the tube end inspections (from the tube 

end to 10.2 cm (4 in.) above the tube end) was expanded to include 100 percent of the hot-leg 

tube ends in all three steam generators, 20 percent of the cold-leg tube ends in steam 

generators A and C, and 100 percent of the cold-leg tube ends in steam generator B.

To identify tubes that could have high residual stress and therefore might be more susceptible 

to stress corrosion cracking, pre-2009 bobbin coil eddy current data were reviewed to identify

offsets in the eddy current data between the straight span and the U-bend region of the tubing. 

The tubes were characterized based on whether one (tier 2) or both (tier 1) legs of the eddy 

current data exhibited the eddy current offset attributed to potentially elevated residual stresses. 

After applying these criteria to all three steam generators, 19 tubes, 22 tubes, and 3 tubes were 

identified as tier 1 tubes in steam generators A, B, and C, respectively. In addition, about 160

tubes, 110 tubes, and 117 tubes were identified as tier 2 tubes in steam generators A, B, and C, 

respectively. Because of finding a crack at the expansion transition in a tier 1 tube (see below), 

all tier 1 and 2 tubes in all three steam generators were inspected with a bobbin coil. In 

addition, a rotating probe was used to inspect 100 percent of the tier 1 tubes and 20 percent of 

the tier 2 tubes from the hot-leg tube end to 7.62 cm (3 in.) above the top of the tubesheet on 

the hot-leg side and from the cold-leg tube end to 7.62 cm (3 in.) above the top of the tubesheet 

on the cold-leg side in all three steam generators. In addition, a rotating probe was used to 

inspect 80 percent of the tier 2 tubes in steam generator B from 7.6 cm (3 in.) above to 7.6 cm 

(3 in.) below the top of the tubesheet on the hot-leg side, and all locations where there were 

non-quantifiable signals (including those with previous history), dents, bulges overexpansions, 

tube support plate elevations, and manufacturing burnishing marks in tier 1 tubes in all three 

steam generators.

As a result of these inspections, 15 tubes were plugged: 2 for wear attributed to a loose part, 1 

for an axially oriented primary water stress corrosion crack at the expansion transition, and 

12 for circumferentially oriented primary water stress corrosion cracking near the tube ends.

The only steam generator tube degradation mechanisms observed during RFO 17 were 

(1) wear at the AVBs, (2) wear at the tube support plates, (3) wear attributed to loose parts, 
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(4) wear attributed to maintenance activities (e.g., sludge lancing), pitting, and (5) primary water 

stress corrosion cracking at the tube-end and at the expansion transition (top-of-tubesheet).

Thirty indications of wear were detected at the AVBs in 24 tubes in steam generator A, and 

19 indications of wear were detected at the AVBs in 13 tubes in steam generator C. The 

maximum depth reported for the AVB wear indications was 22 percent throughwall.

One indication of tube wear at a tube support plate was detected in steam generator A. The 

maximum depth reported was 14 percent throughwall.

Ten tubes with indications of wear attributed to loose parts were observed in the three steam 

generators. Of the indications in these 10 tubes, most were present in prior inspections and had 

not changed.

One indication of wear was attributed to secondary-side maintenance activities. This indication 

had not changed since the prior inspection.

Two indications of pitting were identified in steam generator A. These indications were detected 

in prior inspections and there was no change in the signal.

Primary water stress corrosion cracking was detected near the hot-leg tube ends in all three 

steam generators. Axially and circumferentially oriented primary water stress corrosion cracking 

was observed in steam generators A and C. Only circumferentially oriented primary water 

stress corrosion cracking was observed in steam generator B. Several of the circumferential

indications were plugged whereas others were allowed to remain in service per the inspection 

and repair criteria discussed above. The inspections in these two SGs resulted in identifying 

five tubes in SG C and approximately seven tubes in SG A that would require plugging since the 

circumferential indications in these tubes are near the tube-end and exceed the 94-degree 

circumferential extent criterion.

One indication of axially oriented primary water stress corrosion cracking was observed in 

steam generator A during RFO 17. The indication is partially above and partially below the top 

of the tubesheet. The indication was about 1.6 cm (0.64 in.) long and .81 cm (0.32 in.) above 

the top of the tubesheet on the hot-leg side of the steam generator. Portions of the indication 

were estimated to be 100 percent throughwall. This tube was classified as a tier 1 tube. The

tube was in-situ pressure tested to verify its integrity. No leakage was observed under accident 

conditions, and the tube did not burst at loading conditions associated with the structural 

integrity performance criteria. A bladder was used for the structural integrity in-situ pressure 

test.

During the tube-end inspections in steam generator B, a large number of tubes (2,343 

indications in 1,473 tubes) were identified with permeability variations in the eddy current data 

near the tube end. These indications were on the hot- (1,083 indications in 1,056 tubes) and 

cold-leg side (1,243 indications in 1,260 tubes), were dispersed throughout the tube bundle, and 

were within 5 mm (0.2 in.) of the tube end. These permeability variations were large enough to 

affect the ability to inspect the tubes. This was the first outage in which the tube ends were 

inspected with a probe sensitive to tube degradation. Because of this finding, magnetically 

biased probes were used to reduce the size of the permeability variations. The magnetically 

biased probes reduced the magnitude of the permeability variations in half, but the size of these 

signals was still too large that it could compromise the inspection of these locations. As a result, 

an amendment to the license was pursued that allowed tubes with permeability variations within 
3-188

2.54 cm (1 in.) of the tube end to remain in service for one operating cycle. This amendment 

relied, in part, on the tube being held in place by the interference fit between the tube and the 

tubesheet (see above). Similar permeability variations were not observed in the other two SGs 

in which 100 percent of the hot-leg tube ends and 20 percent of the cold-leg tube ends were 

inspected with a rotating probe.

Inspection and maintenance on the secondary side of the steam generators were performed 

during RFO 17. A deposit minimization treatment was performed in all three steam generators. 

The process was intended to reduce the potential for tube corrosion, tube support broached 

hole blockage, and steam pressure loss because of heat transfer surface fouling. In addition, 

sludge lancing was performed on the baffle plate and the top of the tubesheet in all three steam 

generators. The deposit minimization treatment and sludge lancing removed 2,217 pounds of 

iron oxide from the steam generators. After sludge lancing, FOSAR was performed in all three 

steam generators at the top of the tubesheet. The effectiveness of the sludge lancing was 

assessed in all three steam generators through visual inspections of the top of the tubesheet 

and the baffle plate. In-bundle visual examinations were performed in all three steam 

generators to evaluate the effectiveness of the deposit minimization treatment and the 

3,000 pounds per square inch water lancing on legacy hard deposits. 

The steam drum decks, primary and secondary separators, swirl vanes, drain pipes, deck 

attachment welds, ladders, and other components in steam generator A were visually inspected 

and found to be acceptable. A portion of the upper tube bundle containing the AVBs, the 

periphery of the seventh tube support plate, and the periphery of the sixth tube support plate in 

steam generator A also were visually inspected. These inspections were performed after the 

deposit minimization treatment. The quantity of tube deposits, loose deposit material on the 

AVB surfaces within the bundle, and bridging of deposits at the AVB/tube inspections was 

reduced. There was a decrease in the amount of deposits on the sixth and seventh tube 

support plates and in the broached openings. No degradation was observed As a result of 

these inspections. Visual inspections of the internal feed-ring J-nozzle interfaces were also 

performed in steam generator A. Only minor material reduction because of flow assisted 

corrosion was observed.

The flow distribution baffle was visually inspected following the deposit minimization treatment 

and before the water/sludge lancing.

On November 5, 2009, the steam generator portion of the Surry 1 technical specifications was 

revised to limit the extent of inspection in the tubesheet region. Specifically, the technical 

specifications were revised to exclude the portion of tube that is more than 42.4 cm (16.7 in.)

below the top of the tubesheet from inspection (i.e., approximately the lowermost 10.2 cm (4 in.)

of tube in the tubesheet was excluded from inspection, and hence any flaws that may exist in 

this region are permitted to remain in service). This revision was only applicable for RFO 23

and the subsequent operating cycle (ADAMS Accession No. ML092960484).

There was no evidence of primary-to-secondary leakage (i.e., leakage is less than 3.79 lpd 

(1 gpd)) during the cycle prior to RFO 18 (spring 2009 to fall 2010).

During RFO 18 in 2010, 100 percent of the tubes in steam generator B were inspected full 

length with a bobbin coil, except for the U-bend region of the tubes in rows 1 and 2. About

150 tubes in steam generators A and C were also inspected with a bobbin coil. In addition to 

these bobbin coil inspections, a rotating probe equipped with a plus-point coil was used to 

inspect:
3-189

• 100 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the hot-leg side in steam generators A and C 

• 75 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the hot-leg side in steam generator B

• 20 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the cold-leg side in steam generators A and C

• 50 percent of the overexpansions on the hot-leg side (between 44.95 cm (17.7 in.) below 

the top of the tubesheet and 7.62 cm (3 in.) above the top of the tubesheet on the hotleg side) in steam generator B

• 100 percent of the tier 1 high stress tubes in all three steam generators from 44.95 cm 

(17.7 in.) below the top of the tubesheet to 7.62 cm (3 in.) above the top of the tubesheet 

on the hot-leg side

• 100 percent of the tier 2 high stress tubes in all three steam generators from 7.62 cm 

(3 in.) below the top of the tubesheet to 7.62 cm (3 in.) above the top of the tubesheet on 

the hot-leg side

• 50 percent of the peripheral tubes (5 tubes deep) in steam generator B from 7.62 cm 

(3 in.) below the top of the tubesheet to 7.62 cm (3 in.) above the top of the tubesheet on 

the cold-leg side 

• the 20 largest overexpansions in steam generator B from 44.95 cm (17.7 in.) below the 

top of the tubesheet to 7.62 cm (3 in.) above the top of the tubesheet on the cold-leg 

side

• the U-bend region of 100 percent of the row 1 and row 2 tubes, 57 percent of the hot-leg 

dents with bobbin voltage amplitudes greater than 2 volts (161 dents were examined)

• a small number of cold leg and U-bend dents with bobbin voltage amplitudes greater 

than 2 volts 

In addition to these eddy current inspections, visual inspections were performed on all tube 

plugs and the divider plate weld region in all three steam generators. These inspections 

revealed no anomalous conditions associated with the plugs or the divider plate.

As a result of these inspections, 20 tubes were plugged—2 for wear attributed to a loose part, 

17 because the bottom of the expansion transition was more than 2.54 cm (1 in.) below the top 

of the tubesheet, and 1 for a circumferentially oriented outside-diameter stress corrosion crack 

at the expansion transition.

The only steam generator tube degradation mechanisms observed during RFO 18 were 

(1) wear at the AVBs, (2) wear at the tube support plates, (3) wear attributed to loose parts, 

(4) wear attributed to prior maintenance activities (e.g., sludge lancing), (5) pitting, and 

(6) circumferentially oriented outside-diameter stress corrosion cracking at the expansion 

transition (top-of-tubesheet).
3-190

Twenty indications of wear were detected at the AVBs in 15 tubes in steam generator B. The 

maximum depth reported for the AVB wear indications was 20 percent throughwall.

One indication of tube wear at a tube support plate was detected in steam generator A. The 

maximum depth reported was 22 percent throughwall. This indication has not changed in size 

since originally reported.

Seventeen indications of wear attributed to loose parts were observed in the three steam 

generators. Of these indications, all but two were evident in prior inspection data (although 

some were not identified until RFO 18). Most of these 17 indications have not changed since 

the prior inspection.

One indication of wear was attributed to secondary-side maintenance activities (sludge lancing). 

This indication had not changed since the prior inspection.

One indication of pitting was identified in steam generator A. This indication was detected in 

prior inspections and there has been no change in the signal since it was originally reported. 

There was another pitting indication reported in RFO 17; however, this indication was 

reclassified as a wear indication attributed to a foreign object during RFO 18 because of its 

proximity to a piece of wire that is lodged in place.

One indication of circumferentially oriented outside-diameter stress corrosion cracking was 

observed in steam generator C during RFO 18. The indication was detected in the expansion 

transition portion of a tube near the top of the tubesheet on the hot-leg side of the steam 

generator. The indication was estimated to have a circumferential extent of 73 degrees, 

amplitude of 0.62 volt, a percent degraded area of 3.5 percent, and was 0.76 mm (0.03 in.)

below the top of the tubesheet.

Prior cycle bobbin coil eddy current data were reviewed to determine the location of the bottom 

of the expansion transition relative to the top of the tubesheet because the tubesheet repair 

criterion (referred to as H*) assumes the bottom of the expansion transition is within 7.6 mm 

(0.3 in.) of the top of the tubesheet. This evaluation identified 869 hot-leg and 61 cold-leg 

expansion transitions where the bottom of the expansion transition was greater than 7.6 mm 

(0.3 in.) below the top of the tubesheet in steam generator A. In steam generator B there were 

33 hot-leg and 256 cold-leg expansion transitions that were greater than 7.6 mm (0.3 in.) below 

the top of the tubesheet, and in steam generator C there were 198 hot-leg and 10 cold-leg 

expansion transitions that were greater than 7.6 mm (0.3 in.) below the top of the tubesheet. 

Of these, there were eight tubes where the bottom of the expansion transition was greater than 

2.54 cm (1 in.) below the top of the tubesheet (six in the hot-leg of steam generator A and two in 

the cold-leg of steam generator B). In addition, there were nine tubes identified that had no tube 

expansions, all in steam generator C. All tubes where the bottom of the expansion transition 

was greater than 2.54 cm (1 in.) from the top of the tubesheet, including the tubes with no tube 

expansions, were plugged. The maximum measured bottom of expansion transition was 3.9 cm 

(1.55 in.) below the top of the tubesheet in the hot-leg of steam generator A, 8.89 mm (0.35 in.)

below the top of the tubesheet in the cold-leg of steam generator A, 10.4 mm (0.41 in.) below 

the top of the tubesheet in the hot-leg of steam generator B, 3.4 cm (1.34 in.) below the top of 

the tubesheet in the cold-leg of steam generator B, 1.68 cm (0.66 in.) below the top of the 

tubesheet in the hot-leg of steam generator C, and 11.68 mm (0.46 in.) below the top of the 

tubesheet in the cold-leg of steam generator C.
3-191

Inspection and maintenance on the secondary side of the steam generators were performed

during RFO 18. To address flow assisted corrosion in the feedrings, the feedrings were 

replaced in all three steam generators. General visual inspection of the feedring region after 

replacement of the feedrings did not identify any degradation. The top of the tubesheet was 

inspected visually in all three steam generators, and at select flow distribution baffle plate 

locations in steam generators B and C. No adverse conditions were noted. FOSAR was 

performed in all three steam generators at the top of the tubesheet, in the annulus, and in the 

no-tube lane after the replacement of the feedrings. The inspections of localized areas of the 

upper surface of the flow distribution baffle during the investigation of possible loose part 

indications identified during the eddy current inspections in steam generators B and C revealed

an accumulation of exfoliated scale. In-bundle visual examinations were performed in steam 

generator A to evaluate the general location of the hard-collar region. FOSAR identified several 

areas of interest in each steam generator during RFO 18. Some areas had foreign objects that

could not be removed. In some cases eddy current possible loose part indications were 

attributed to tube scale or sludge rocks.

On April 17, 2012, the steam generator portion of the Surry 1 technical specifications was 

revised to limit the extent of inspection in the tubesheet region. Specifically, the technical 

specifications were revised to exclude the portion of tube that is more than 45.44 cm (17.89 in.)

below the top of the tubesheet from inspection (i.e., approximately the lowermost 7.62 cm (3 in.)

of tube in the tubesheet was excluded from inspection, and hence any flaws that may exist in 

this region are permitted to remain in service (ADAMS Accession No. ML120730304 and 

ML12109A270).

There was no evidence of primary-to-secondary leakage (i.e., leakage is less than 3.79 lpd 

(1 gpd)) during the cycle prior to RFO 19 (fall 2010 to spring 2012). 

During RFO 19 in 2012, 100 percent of the tubes in steam generators A and C were inspected 

full length with a bobbin coil, except for the U-bend region of the tubes in rows 1 and 2. In 

addition to these bobbin coil inspections, a rotating probe equipped with a plus-point coil was 

used to inspect the U-bend region of 100 percent of the row 1 and row 2 tubes in steam 

generators A and C. In addition to these inspections, an array probe was used to inspect:

• 100 percent of the tubes in steam generators A and C from the hot-leg tubesheet to the 

first tube support on the hot-leg side of the steam generator

• 36 percent of the tubes in steam generator B from the hot-leg tubesheet to the first tube 

support on the hot-leg side of the steam generator

• approximately 36 percent of the tubes in steam generators A and C from the cold-leg 

tubesheet to the first tube support on the cold-leg side of the steam generator

In addition to these eddy current inspections, visual inspections were performed on all tube 

plugs, the divider plate weld region, and the bottom of the steam generator channel head (under 

dry conditions) in all three steam generators. These visual inspections revealed no anomalous 

conditions.

As a result of these inspections, no tubes were plugged.

Tube degradation mechanisms observed during RFO 19 were tube wear at the AVBs and the 

tube support plates, mechanical wear attributed to loose parts, mechanical wear attributed to 
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prior maintenance activities (e.g., sludge lancing), and pitting. No stress corrosion cracking was 

detected.

Thirty-two indications of wear were detected at the AVBs in 27 tubes in steam generator A, and 

20 indications of were at the AVBs were detected in 13 tubes in steam generator C. The 

maximum depth reported for the AVB wear indications was 26 percent throughwall. Two

indications of tube wear at a tube support plate were detected in two tubes (1 in steam 

generator A and 1 in steam generator C). The maximum depth reported was 19 percent

throughwall. Sixteen indications of wear attributed to loose parts were observed in the three 

steam generators. Of these indications, all but one were evident in prior inspection data. Most 

of these 16 indications have not changed since the prior inspection. One indication of wear was 

attributed to secondary-side maintenance activities (sludge lancing). This indication had not 

changed since the prior inspection. One indication of pitting was identified in steam generator 

A. This indication was detected in prior inspections and there has been no change in the signal 

since it was originally reported.

Two tubes were identified as having restrictions, one in steam generator A and one in steam 

generator C. The restriction in the tube in steam generator A is caused by a dent between the 

fourth and fifth tube support plates on the cold-leg side of the steam generator. The dent 

prevents the passage of the 1.83-cm (0.720-in.) diameter bobbin probe; however this region can 

be examined with a 1.78-cm (0.700-in.) diameter bobbin probe. The dent was first reported in 

1997 and has been examined with the bobbin probe during each inspection since RFO 9 in 

1997. The bobbin probe signal has exhibited no change during the subsequent inspections. 

In addition, this region of the tube has been examined with a rotating probe equipped with a 

plus-point coil during four outages since 1997 and no degradation has been identified at this 

location. The restriction in the tube in steam generator C is at the U-bend tangent point on the 

hot-leg. This location was examined with a 1.78-cm (0.700-in.) bobbin probe and was 

confirmed to be free of degradation.

Inspection and maintenance on the secondary side of the steam generators were performed 

during RFO 19. Sludge lancing was performed in all three steam generators. After sludge 

lancing, visual examination of the top of the tubesheet and the no-tube lane was performed in all 

three steam generators. In addition, regions with known foreign objects from prior inspections 

and accessible locations having eddy current indications attributed to foreign objects were 

inspected visually. In steam generator A, visual inspections were performed on all accessible 

steam drum components and structures including the feedring exterior, the upper tube bundle 

and the seventh tube support plate. No adverse conditions or degradation were noted during 

the inspections.

On January 28, 2013, the steam generator portion of the Surry 1 technical specifications was 

revised making them consistent with TSTF-510 (ADAMS Accession No. ML13018A086, 

ML13032A206, and ML13099A106).

There was no evidence of primary-to-secondary leakage (i.e., leakage is less than 3.79 lpd 

(1 gpd)) during the cycle prior to RFO 20 (spring 2012 to fall 2013).

During RFO 20 in 2013, 100 percent of the tubes in steam generator B were inspected full 

length with a bobbin coil, except for the U-bend region of the tubes in rows 1 and 2. In addition 

to these bobbin coil inspections, a rotating probe equipped with a plus-point coil was used to 

inspect the U-bend region of 100 percent of the row 1 and row 2 tubes in steam generator B. 

In addition to these inspections, an array probe was used to inspect:
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• 100 percent of the tubes in steam generator B from the tube end on the hot-leg to the 

first tube support on the hot-leg side of the steam generator

• 100 percent of the tubes in steam generator B from the cold-leg tube end to the first tube 

support on the cold-leg side of the steam generator

• 50 percent of all dents in steam generator B with bobbin voltage amplitudes greater than 

2 volts (including the five largest voltage dents)

In addition to these eddy current inspections, visual inspections were performed on all tube 

plugs, the divider plate weld region, and the bottom of the steam generator channel head (under 

dry conditions) in steam generator B. These visual inspections revealed no anomalous 

conditions. No degradation was observed at the bottom of the steam generator channel head.

As a result of these inspections, no tubes were plugged.

The only steam generator tube degradation mechanisms observed during RFO 20 were wear at 

the AVBs, wear attributed to loose parts, and wear attributed to prior maintenance activities 

(e.g., sludge lancing).

Twenty-seven indications of wear were detected at the AVBs in 22 tubes in steam generator B. 

The maximum depth reported for the AVB wear indications was 24 percent throughwall. Of 

these 27 indications, 9 were not reported in the prior inspection. The quantity and the depth of 

the newly reported indications are within industry experience. The identification of these new 

indications is attributed to the threshold of detection for this degradation mechanism (i.e., they 

may have been present, but undetectable, during prior inspections).

Nine indications of wear attributed to loose parts were observed in steam generator B. All of

these indications were detected in prior inspections and none have changed since the prior 

inspection.

Two volumetric indications were observed during RFO 20. There has been no change in these 

signals since 1994. These two indications have been attributed to manufacturing anomalies.

One additional indication of wear was observed and attributed to secondary-side maintenance 

activities (sludge lancing). This indication had not changed since the prior inspection.

Inspection and maintenance on the secondary side of the steam generators were performed 

during RFO 20. Visual inspections of all accessible steam drum components and structures 

including the feedring exterior, the upper tube bundle, and the seventh tube support plate were 

performed in steam generators B and C. No adverse/abnormal conditions were noted during 

the inspections. FOSAR was not performed during RFO 20 since no possible loose part 

indications were identified during the eddy current examination.

3.4.6 Surry 2

Tables 3-46, 3-47, and 3-48 summarize the information discussed below for Surry 2. Table 

3-46 provides the number of full-length bobbin inspections and the number of tubes plugged 

and deplugged during each outage for each of the three steam generators. Table 3-47 lists the 
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reasons why the tubes were plugged. Table 3-48 lists tubes plugged for reasons other than 

wear at the AVBs.

Surry 2 has three Westinghouse model 51F steam generators. These steam generators were 

installed at the plant in 1980. The tube supports are numbered as shown in Figure 2-8.

There was no evidence of primary-to-secondary leakage during the cycle preceding RFO 13 

(fall 2000 to spring 2002).

During RFO 13 in 2002, 100 percent of the tubes in steam generator A were inspected full 

length with a bobbin coil, except for the U-bend region of the row 1 tubes. In addition to these

bobbin coil inspections, a rotating probe equipped with a plus-point coil was used to inspect:

• 20 percent of the tubes (667 tubes) from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the 

top of the tubesheet on the hot-leg side in steam generator A

• the U-bend region of 100 percent of the row 1 tubes in steam generator A

• 200 tubes from 2.54 cm (1 in.) above to 2.54 cm (1 in.) below the top of the tubesheet on 

the cold-leg side (concentrated in the low-flow area and sludge pile periphery) in steam 

generator A

In addition to these eddy current inspections, all tube plugs in steam generator A were 

inspected visually. No degradation or abnormal leakage was identified during the inspection of 

the plugs. 

As a result of these inspections, one tube was plugged. This tube was plugged for wear at the 

AVBs.

The only steam generator tube degradation mechanisms observed during RFO 13 were wear at 

the AVBs and wear attributed to loose parts.

Fourteen indications of wear were detected at the AVBs in 11 tubes in steam generator A. The 

maximum depth reported for the AVB wear indications was 24 percent throughwall. The 

average growth rate of the AVB wear indications in steam generator A was 1.35 percent

throughwall per cycle. The growth rate at 95 percent probability and 50 percent confidence for 

steam generator A is 3.47 percent throughwall per cycle. Although one tube was plugged 

because of wear at the AVBs, the indication in this tube did not exceed the plugging limit. The 

tube was plugged because of the projected growth rate of the indication and since the wear 

indication was at a non-typical location (i.e., it was associated with the tip of the AVB).

Two indications of wear attributed to a foreign object were detected in two tubes. The two tubes 

were next to each other. Visual inspection of the area did not identify any loose parts near the 

affected tubes.

In previous outages, pit-like indications were identified in steam generators A and C on the 

cold-leg, above the tubesheet secondary face. During RFO 13, 200 tubes were inspected from 

2.54 cm (1 in.) above to 2.54 cm (1 in.) below the top of tubesheet on the cold-leg side. No 

pit-like indications were identified in steam generator A during RFO 13.
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During RFO 13, 412 dents were detected in steam generator A with approximately 80 percent of 

the total having voltages between 2 and 4 volts as measured by the bobbin probe. With the 

exception of a limited number of dents at the upper supports in steam generator C (see below), 

nearly all of the dents were induced during manufacture. The dents resulted from handling of 

the tubes before and during installation into the generators. All of these dent indications were 

previously identified.

Minor denting was previously identified in steam generator C at tube support plates 6 and 7. 

These dents are in the peripheral tubes and resulted from the interaction of the tube with the 

lands of the quatrefoil hole. These dents had bobbin voltage amplitudes ranging from 2 to 8 

volts. The dents at the seventh tube support plate in steam generator C are predominantly at 

rows 10 through 30 and columns 80 through 94. These dents were characterized as minor 

because a nominal-sized probe passed through the dented tubes without difficulty. The 

licensee considered a dent free of degradation if two consecutive inspections (with a bobbin 

probe) show that the dent has not changed or if a rotating probe inspection does not identify any 

degradation. If the voltage of a dent indication changes by 0.25 volt as measured with a bobbin 

probe, then the dent is examined with an alternate probe such as a rotating probe.

Inspection and maintenance on the secondary side of the steam generators were performed 

during RFO 13. To reduce the amount of sludge on the top of the tubesheet, sludge lancing 

was performed in each of the three steam generators. After the sludge lancing, FOSAR was 

performed in each of the three steam generators. In steam generator A, visual inspections were 

performed in the steam drum, inside the feedring at the J-nozzle interfaces, and at the seventh

tube support plate (access was gained through the swirl vanes). Ultrasonic thickness 

measurements were performed at the feedring tee and in adjacent components susceptible to 

degradation. In addition, in-bundle, secondary-side visual inspections were performed before 

and after sludge lancing at the top of the tubesheet on the hot- and cold-leg sides in steam 

generator A.

During RFO 14 in 2003, 100 percent of the tubes in steam generator B were inspected full 

length with a bobbin coil, except for the U-bend region of the row 1 tubes. In addition to these 

bobbin coil inspections, a rotating probe equipped with a plus-point coil was used to inspect:

• 71 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the hot-leg side (including the sludge zone, periphery, and all tubes not 

previously inspected with a rotating probe) in steam generator B

• the U-bend region of 100 percent of the row 1 tubes in steam generator B

• approximately 25 percent of the dents with bobbin voltage amplitudes greater than 

2 volts (these inspections included dents that had changed and also included all row 

2 tubes with bulges near the tangent point) in steam generator B

• the entire portion of the tube within the tubesheet for the four tubes that were not 

completely expanded for the full length of the tubesheet in steam generator B

As a result of these inspections, three tubes were stabilized and plugged. All of these tubes 

were plugged for wear attributed to a foreign object.

The only steam generator tube degradation mechanisms observed during RFO 14 were wear at 

the AVBs and wear attributed to loose parts.
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Six indications of wear in six tubes were detected at the AVBs in steam generator B. The 

maximum depth reported for the AVB wear indications was 19 percent throughwall. The 

average growth rate of the AVB wear indications in steam generator B since the last inspection 

in RFO 10 (1997) was 0.8 percent throughwall per cycle. The growth rate at 95 percent

probability and 50 percent confidence for steam generator B is 6.46 percent throughwall per 

cycle. The average growth rate of the AVB wear indications in all steam generators is 2.51

percent throughwall per cycle, with a 95/50 growth rate of 5.26 percent throughwall per cycle.

Five indications of wear attributed to a foreign object were detected in five tubes. Two of these 

indications were near the top of the tubesheet. These indications were attributed to a foreign 

object that most likely was removed during sludge lancing operations. The indications were 

detected only with a rotating probe because of their close proximity to the expansion transition 

and top of the tubesheet. This was the first inspection of these tubes with a rotating probe. This 

location was not inspected visually. The other three indications were at the second cold-leg 

support and resulted in the tubes being stabilized and plugged as discussed above. A visual 

inspection of this region confirmed the presence of a loose part, which was not removed. The 

part apparently has been in this position since at least 1993 because a volumetric indication 

was reported in one of the tubes during the 1993 inspections.

During RFO 14, 479 dents (in 335 tubes) with bobbin voltage amplitudes between 2 and 4.99 

volts, 208 dents (in 108 tubes) with bobbin voltage amplitudes between 5 and 19.99 volts, and 

2 dents (in 2 tubes) with bobbin voltage amplitudes greater than 20 volts were detected in steam 

generator B. Of the 689 dents, 124 were at the sixth and seventh tube support plates. These 

dents are predominantly in the periphery and near the wedge locations. The bobbin coil voltage 

associated with these dents is small, and all dents permit the passage of the standard size 

bobbin and rotating probes. This is consistent with the findings in steam generator C.

As a result of the bobbin coil inspections, 37 bulges were identified near the U-bend tangent 

point of the tubes in rows 1 and 2. The bulge indications were attributed to the manufacturing or 

fabrication practices used to produce the U-bend. The eddy current signals associated with 

these bulges have not changed. 

The noise levels in the eddy current data were measured for a sample of tubes. These 

measurements were made at the tubesheet expansion, freespan above the top of the 

tubesheet, tube support plate elevations, AVBs, U-bend, and the freespan.

The rotating probe inspections near the top of the tubesheet are focused typically in the center 

of the bundle coincident with the low-velocity region below the baffle plate. This is the area of 

the bundle where the largest accumulation of sludge and particulate fallout occurs as the bundle 

flow is directed upward through the baffle hole opening. This condition could result in sludge 

and scale pockets that could increase the potential for secondary-side tube corrosion. This area 

is typically bounded by row 1, columns 27 to 67, and row 30, columns 37 to 57. This is 

somewhat larger than the baffle hole opening to account for the extent of the actual sludge pile.

During RFO 15 in 2005, 100 percent of the tubes in steam generator C were inspected full 

length with a bobbin coil, except for the U-bend region of the row 1 tubes. In addition to these 

bobbin coil inspections, a rotating probe equipped with a plus-point coil was used to inspect:

• 60 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the hot-leg side in steam generator C
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• the 20 largest hot-leg overexpansions within the tubesheet in steam generator C

• the nine largest over-rolls above the top of the tubesheet on the hot-leg side in steam 

generator C

• the 10 largest over-rolls above the top of the tubesheet on the cold-leg side in steam 

generator C

• the U-bend region of 100 percent of the row 1 tubes in steam generator C

• 20 percent of the dents with bobbin voltage amplitudes greater than 2 volts (these 

inspections included dents that had changed) in steam generator C

• the entire portion of the tube within the tubesheet for the two tubes that were not 

completely expanded for the full length of the tubesheet in steam generator C

In steam generator B, a rotating probe equipped with a plus-point coil was used to inspect six 

tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the tubesheet on the hot-leg 

side. These latter inspections were performed as a result of visually identifying potential 

damage to one tube during secondary-side inspection activities in steam generator B. No other 

eddy current inspections were performed in steam generator B during RFO 15.

As a result of these inspections, eight tubes were plugged. All of these tubes were plugged for 

wear attributed to loose parts. Two of these eight tubes were also stabilized.

The only steam generator tube degradation mechanisms observed during RFO 15 were wear at 

the AVBs, wear at the tube support plates, and wear attributed to loose parts.

Thirty-seven indications of wear in 24 tubes were detected at the AVBs in steam generator C. 

The maximum depth reported for the AVB wear indications was 27 percent throughwall. The 

average growth rate of the AVB wear indications in steam generator C since the last inspection 

in the fall of 2000 was 0.85 percent throughwall per cycle. The historical average growth rate 

considering all of the data from steam generator C is 2.29 percent throughwall per cycle. The 

corresponding growth rate at 95 percent probability and 50 percent confidence for steam 

generator C is 5.08 percent throughwall per cycle. The growth rate has been decreasing with 

time. The average growth rate of the AVB wear indications in all steam generators is 2.20

percent throughwall per cycle, with a 95/50 growth rate of 5.03 percent throughwall per cycle.

One tube had a wear indication attributed to interaction with the tube support plate.

Twenty-eight tubes had wear attributed to loose parts. These indications were attributed to 

loose parts because the indications were clustered and in the periphery and because, in some 

cases, some possible loose part indications were identified near the affected tubes during the 

eddy current inspections. Of these 28 tubes, 27 had indications near to top of the tubesheet on 

the hot-leg side and the remaining tube had an indication at the baffle plate on the hot-leg side 

of the steam generator. All of these locations were inspected visually with the exception of the 

location of the baffle plate indication. The eddy current inspection of the tube with the indication 

at the baffle plate did not exhibit a possible loose part indication. Visual inspection identified 

several foreign objects including the object next to the two tubes that were stabilized. No 

foreign objects remain near the tubes that were left in service with wear attributed to foreign 

objects. Eight tubes were plugged for wear attributed to loose parts. The wear indications were 
3-198

attributed to interaction with loose parts that were likely present during past operating cycles 

with most of the postulated loose parts being removed during sludge lancing operations. One of 

the loose parts causing the damage was lodged in place and was left in the steam generator. 

This loose part was adjacent to the two tubes that were stabilized. The wear and loose part 

were near the top of the tubesheet on the hot-leg side of the steam generator.

In steam generator B, a volumetric indication, which was initially identified visually, was 

detected. This indication (a scratch mark) could be the result of a foreign object, initial 

fabrication, or damage during removal of the wrapper plate cruciform in the late 1990s.

During RFO 15, 620 dents (in 458 tubes) with bobbin voltage amplitudes between 2 and 

4.99 volts, 171 dents (in 126 tubes) with bobbin voltage amplitudes between 5 and 9.99 volts, 

and 55 dents (in 41 tubes) with bobbin voltage amplitudes greater than 10 volts were detected 

in steam generator C. The size of the dents has not changed significantly since the 2000 

outage (RFO 12). A dent signal is one that does not rotate to the flaw plane. A ding signal 

rotates and is influenced by changes in resistivity because of localized impact deformation.

As a result of the bobbin coil inspections, 19 bulges were identified with 13 near the U-bend 

tangent point of the row 1 tubes. The bulge indications were attributed to the manufacturing or 

fabrication practices used to produce the U-bend. The eddy current signals associated with 

these bulges have not changed.

In steam generator C, no low-row tubes (i.e., tubes in rows 1 through 8) were identified as 

potentially being more susceptible to stress corrosion cracking based on a review of eddy 

current data for an offset between the data in the U-bend and in the straight span. Some 

high-row tubes in steam generator C were identified (based on a review of eddy current data) as 

potentially having high residual stress. A rotating probe was used to inspect a sample of these 

tubes at dents and the expansion transitions.

During RFO 15, secondary-side visual inspections were performed. This included inner bundle 

inspections on both the hot- and cold-leg side of the steam generator (i.e., camera passes down 

the tube columns out to the bundle periphery). Twenty-three columns on the hot-leg and seven

columns on the cold-leg were inspected. 

There was no evidence of primary-to-secondary leakage during the cycle preceding RFO 16 

(spring 2005 to fall 2006).

During RFO 16 in 2006, 100 percent of the tubes in steam generator A were inspected full 

length with a bobbin coil, except for the U-bend region of the row 1 tubes. In addition to these 

bobbin coil inspections, a rotating probe equipped with a plus-point coil was used to inspect:

• about 62 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of 

the tubesheet on the hot-leg side in steam generator A

• 21 percent of the hot-leg overexpansions within the tubesheet (i.e., the 28 largest) in 

steam generator A

• the U-bend region of 100 percent of the row 1 tubes (including 28 bulges in these tubes)

in steam generator A
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• bulges with bobbin voltage amplitudes greater than 11 volts (a total of 11 bulges) in 

steam generator A

• at least 20 percent of the dents with bobbin voltage amplitudes greater than 2 volts in 

steam generator A

• the entire portion of the tube within the tubesheet for the two tubes that were not 

completely expanded for the full length of the tubesheet in steam generator A

As a result of these inspections, four tubes were plugged—three for wear attributed to loose 

parts, and one tube for damage near the tube end as a result of removing a plug from this tube

in a previous outage.

The only steam generator tube degradation mechanisms observed during RFO 16 were wear at 

the AVBs and wear attributed to loose parts.

Thirteen indications of wear in 10 tubes were detected at the AVBs in steam generator A. The 

maximum depth reported for the AVB wear indications was 29 percent throughwall. Since the 

last inspection in RFO 13 (2002), the average growth rate of the AVB wear indications in steam 

generator A was 0.64 percent throughwall per cycle. The growth rate at 95 percent probability 

and 50 percent confidence for steam generator A is 3.25 percent throughwall per cycle. The 

average growth rate of the AVB wear indications in all steam generators is 2.11 percent

throughwall per cycle, with a 95/50 growth rate of 4.94 percent throughwall per cycle. The 

growth rates continue their decreasing trend when compared to prior inspections.

Volumetric indications (other than wear at the AVBs and the tube with tube-end damage) were 

detected in 10 tubes. Two of the indications were near the top of the tubesheet on the hot-leg 

side and were attributed to loose parts or a manufacturing operation. The indications in these 

tubes have not changed since the last inspection. Wear indications were identified in a cluster 

of tubes near the top of the tubesheet on the cold-leg side. No loose parts were identified in this 

region during visual or eddy current inspections. These indications were attributed to a loose 

part that is no longer present. Another cluster of damage was also observed near the top of the 

tubesheet on the cold-leg side. The affected tubes were damaged by a loose part that had 

resulted in a primary-to-secondary leak from an adjacent tube in 1986, when the loose part was 

removed. The damage to these tubes was judged at the time to be insignificant, and the tubes 

were left in service. In 2006, based on the depth estimate using current sizing techniques, one 

of the tubes in this cluster was plugged. Eddy current testing of the tubes with volumetric 

indications (10 tubes total) did not indicate the presence of any loose parts at the locations 

where these indications were found. In addition, visual inspections were performed at all 

locations except for the two tubes with shallow indications and these inspections also confirmed 

the absence of any loose parts (therefore, no known loose parts remain adjacent to any of the 

volumetric flaws left in service). Of the 10 volumetric indications, only 4 were detected with a 

bobbin coil probe.

During RFO 16, 614 dents (in 403 tubes) with bobbin voltage amplitudes greater than 2 volts 

were detected in steam generator A. There has been no significant change in the size of the 

dents since the 2002 outage (RFO 13). There is a pattern of dents calls at the sixth and 

seventh tube support plates. These dents are predominantly in peripheral tubes and tend to be 

near tube support plate wedge locations.
3-200

As a result of the bobbin coil inspections, 60 bulges (in 42 tubes) were identified. The number 

of bulges and the size of the bulges have not changed with time indicating that the bulges 

occurred during fabrication of the steam generators. Most of these bulges were at the sixth and 

seventh support plate in rows 1 and 2.

In steam generator A, no low-row tubes (i.e., tubes in rows 1 through 8) were identified as 

potentially being more susceptible to stress corrosion cracking based on a review of eddy 

current data for an offset between the data in the U-bend and in the straight span.

A rust stain was noted in the tube end of one tube in steam generator A. The hot-leg portion of 

this tube was inadvertently plugged in 1986. This tube was subsequently deplugged in 1991 by 

drilling. Visual and rotating probe inspections revealed that the tube appeared to have been 

drilled off-center, longitudinally from the tube end for a distance of about 4.45 cm (1.75 in.) The 

tube wall was perforated over a circumferential distance of about 2.3 cm (0.9 in.) The hydraulic 

expansion throughout the tubesheet above the tube damage was normal based on bobbin coil 

profiling and the expansion transition was properly positioned near the top of the tubesheet. No 

other tubes have been deplugged and left in service. The affected tube was plugged with a 

deep roll plug. This plug had three individual roll expansions: the deep roll, the normal roll, and 

the shallow roll. The deep roll was installed above the damaged area in a location where the 

tube was fully intact. This roll was the structural joint between the outside surface of the plug 

and the inside surface of the tube. The other two rolls in the deep roll plug were not credited as 

structural joints and were installed to isolate the exposed carbon steel of the tubesheet. The 

shallow roll, which was near the short section of tubing at the tube end, would present a 

tortuous leakage path allowing little or no primary coolant to contact the tubesheet material. 

Nonetheless, it was assumed that leakage would occur resulting in corrosion of the exposed 

tubesheet material. This assessment led the licensee to conclude that the amount of corrosion 

would be limited and would not affect the tubesheet ligament between the tubes since the 

exposed area is oriented toward the channel head periphery and away from the neighboring 

tubes. This plug will be visually inspected during future steam generator tube inspection 

outages.

Degradation of the channel head was also observed. Ultrasonic examination of the 

tubesheet-to-channel-head transition region confirmed that no degradation extended into the 

base material. The licensee concluded that the condition is acceptable for continued service 

without repair for the licensed life of the unit. This location will be monitored during future steam 

generator tube inspection outages.

On March 29, 2007, Surry 2 revised the steam generator portion of their technical specifications 

making them performance-based consistent with TSTF-449 (ADAMS Accession No. 

ML070880618).

As of 2007, the licensee’s loss-of-coolant-accident analysis assumed that the average 

equivalent level of tube plugging was 15 percent in any one steam generator with no greater 

than a 5 percent differential between any two steam generators expressed in terms of the 

number of tubes per steam generator.

On May 16, 2008, the steam generator portion of the Surry 2 technical specifications was 

revised to permit certain sized flaws near the tube end in both the hot- and cold-leg sides of the 

steam generator to remain in service. Specifically, the technical specifications were revised to 

(1) permit flaws having a circumferential component less than or equal to 203 degrees found in 

the portion of the tube below 43.2 cm (17 in.) from the top of the tubesheet and above 2.54 cm 
3-201

(1 in.) from the bottom of the tubesheet to remain in service, (2) require the removal from 

service all flaws having a circumferential component greater than 203 degrees found in the 

portion of the tube below 43.2 cm (17 in.) from the top of the tubesheet and above 2.54 cm 

(1 in.) from the bottom of the tubesheet, (3) require the removal from service all tubes with 

service-induced flaws between the top of the tubesheet and 43.2 cm (17 in.) below the top of 

the tubesheet, and (4) permit all axial indications found in the portion of the tube below 43.2 cm 

(17 in.) from the top of the tubesheet to remain in service. In addition, the technical 

specifications were modified to indicate that when more than one flaw with circumferential 

components is found in the portion of the tube below 43.2 cm (17 in.) from the top of the 

tubesheet and above 2.54 cm (1 in.) from the bottom of the tubesheet with the total of the 

circumferential components being greater than 203 degrees and the axial separation distance of 

less than 2.54 cm (1 in.), then the tube must be removed from service (overlapping portions of 

the flaws only need to be counted once in determining the total circumferential involvement of 

the flaws). For flaws within 2.54 cm (1 in.) of the bottom of the tubesheet, the technical 

specifications were modified to indicate (1) when one or more flaws with circumferential 

components are found and the total of the circumferential components exceeds 94 degrees, 

then the tube shall be removed from service and (2) when one or more flaws with 

circumferential components are found in the portion of the tube within 2.54 cm (1 in.) from the 

bottom of the tubesheet and within 2.54 cm (1 in.) axial separation distance of a flaw above 

2.54 cm (1 in.) from the bottom of the tubesheet, and the total of the circumferential components 

found in the tube exceeds 94 degrees, then the tube shall be removed from service (overlapping 

portions of the flaws only need to be counted once in determining the total circumferential 

involvement of the flaws). This revision to the technical specifications was applicable only to 

RFO 21 (which corresponds to RFO 17 since steam generator replacement) and the 

subsequent operating cycle (ADAMS Accession No. ML081340106).

There was no evidence of primary-to-secondary leakage during the cycle preceding RFO 17 

(fall 2006 to spring 2008).

During RFO 17 in 2008, 100 percent of the tubes in steam generators B and C were inspected 

full length with a bobbin coil, except for the U-bend region of the row 1 tubes. In addition to 

these bobbin coil inspections, a rotating probe equipped with a plus-point coil was used to 

inspect:

• 20 percent of the tubes from 7.62 cm (3 in.) above the top of the tubesheet on the hotleg side to the hot-leg tube end (this sample included a minimum of 50 percent of the 

tubes in the sludge pile region) in steam generators B and C

• 100 percent of the tubes from the hot-leg tube end to 10.2 cm (4 in.) above the hot-leg 

tube end in steam generators B and C

• 100 percent of the overrolls in the hot-leg in steam generators B and C

• 50 percent of the hot-leg overexpansions within the tubesheet in steam generators B 

and C

• the 10 largest cold-leg overexpansions within the tubesheet in steam generators B and 

C

• the U-bend region of 100 percent of the row 1 tubes in steam generators B and C
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• 100 percent of the dents and dings in the hot-leg with bobbin voltage amplitudes greater 

than 5 volts in steam generators B and C

• 20 percent of the dents and dings with bobbin voltage amplitudes greater than 2 volts 

but less than 5 volts in steam generators B and C

• the entire portion of the tube within the tubesheet for any tubes that were not completely 

expanded for the full length of the tubesheet in steam generators B and C (4 tubes were 

not expanded in the hot-leg in steam generator B, 3 tubes were not expanded in the hotleg in steam generator C, and 4 tubes were not expanded in the cold-leg of steam 

generator C). 

Because of finding crack-like indications near the hot-leg tube ends in steam generators B and 

C, 100 percent of the tubes in steam generator A were inspected with a rotating probe equipped 

with a plus-point from the hot-leg tube end to 10.2 cm (4 in.) above the hot-leg tube end. In 

addition to these eddy current inspections, all tube plugs in steam generators B and C were 

inspected visually.

As a result of these inspections, nine tubes were plugged—six for circumferentially oriented 

primary water stress corrosion cracking indications at the hot-leg tube end. Three others were 

stabilized and plugged for wear attributed to a loose part (which was unable to be removed from 

the steam generator).

The only steam generator tube degradation mechanisms observed during RFO 17 were wear at 

the AVBs, wear attributed to loose parts, and axially and circumferentially oriented primary 

water stress corrosion cracking at the tube ends.

Nine indications of wear in eight tubes were detected at the AVBs in steam generator B. 

Forty-three indications of wear in 30 tubes were detected at the AVBs in steam generator C. 

The maximum depth reported for the AVB wear indications was 29 percent throughwall. 

Minimal growth of existing AVB wear indications was observed in steam generators B and C. 

No new wear indications at the AVBs were detected.

Fifteen tubes have wear attributed to loose parts. Seven of these fifteen tubes had indications 

that were reported in previous inspections.

Inside diameter initiated axial and circumferential indications were detected near the hot-leg 

tube end in all three steam generators. All indications were within 5 mm (0.2 in.) from the tube 

end. In steam generator A, 60 indications (3 axial and 57 circumferential) were detected in 

60 tubes. In steam generator B, 39 indications (9 axial and 30 circumferential) were detected in 

37 tubes. In steam generator C, 21 indications (6 axial and 15 circumferential) were detected in 

20 tubes.

Seventeen loose parts were detected in steam generators B and C. Seven of these loose parts 

were associated with potential loose part indications from the eddy current inspection. In steam 

generator C, all loose parts (other than sludge rocks and scale) were removed from the steam 

generator. In steam generator B, a metal remnant and a short piece of wire were not retrieved. 

Both of these loose parts were fixed in place. The metal remnant is wedged between the 

tubelane blocking device and the tubes in row 1, column 12, and row 1, column 23. This loose 

part has been present since 2005 and has not resulted in any tube wear. The wire is embedded 

in the sludge pile. All possible loose part indications from the eddy current inspection were 
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inspected visually for the presence of a loose part with the exception of the three tubes with 

possible loose part indications at the baffle plate. These latter tubes were stabilized and 

plugged.

In steam generators B and C, no low-row tubes (i.e., tubes in rows 1 through 8) were identified 

as potentially being more susceptible to stress corrosion cracking based on a review of eddy 

current data for an offset between the data in the U-bend and in the straight span. In steam 

generator B, two high row tubes were identified (based on a review of eddy current data) as 

potentially having high residual stress. In steam generator C, 14 tubes were identified (based 

on a review of eddy current data) as potentially having high residual stress.

Inspection and maintenance on the secondary side of the steam generators were performed 

during RFO 17. To reduce the amount of sludge on the top of the tubesheet, sludge lancing 

was performed in each of the three steam generators. Sludge lancing was also performed on 

the baffle plate in each of the three steam generators. FOSAR was performed in each of the 

three steam generator, and sludge samples were retrieved for chemical analysis. In steam 

generators A and B, an upper bundle flush was performed along with a visual inspection of the 

upper bundle and the seventh tube support plate. In steam generator B, visual inspections were 

performed of the steam drum and in the interior of the bundle at the top of the tubesheet. The 

visual inspections in steam generator B at the seventh tube support plate revealed a uniform 

layer of scale. Inspections of the periphery of the tube bundle showed minimal evidence of 

powdery sludge and no evidence of loose scale on the support plate or in the broached tube 

support plate holes. Inspection of the J-tubes indicated some flow accelerated corrosion. 

The J-tubes are inspected every third outage.

On November 5, 2009, the steam generator portion of the Surry 2 technical specifications was 

revised to limit the extent of inspection in the tubesheet region. Specifically, the technical 

specifications were revised to exclude the portion of tube that is more than 42.42 cm (16.7 in.)

below the top of the tubesheet from inspection (i.e., approximately the lowermost 10.2 cm (4 in.)

of tube in the tubesheet was excluded from inspection, and hence any flaws that may exist in 

this region are permitted to remain in service). This revision was only applicable for RFO 22 

and the subsequent operating cycle (ADAMS Accession No. ML092960484).

There was no evidence of primary-to-secondary leakage (i.e., leakage is less than 3.79 lpd 

(1 gpd)) during the cycle preceding RFO 18 (spring 2008 to fall 2009).

During RFO 18 in 2009, 100 percent of the tubes in steam generator A were inspected full 

length with a bobbin coil, except for the U-bend region of the tubes in rows 1 and 2. In addition 

to these bobbin coil inspections, a rotating probe equipped with a plus-point coil was used to 

inspect:

• the U-bend region of 100 percent of the row 1 and row 2 tubes in steam generator A

• 50 percent of the outermost five peripheral tubes from 7.6 cm (3 in.) above to 7.6 cm 

(3 in.) below the top of the tubesheet on the cold-leg side of steam generator A

• 60 percent of the overexpansions from 7.62 cm (3 in.) above to 42.42 cm (16.7 in.)

below the top of the tubesheet on the hot-leg side of steam generator A

• 30 percent of the overexpansions from 7.62 cm (3 in.) above to 42.42 cm (16.7 in.)

below the top of the tubesheet on the cold-leg side of steam generator A 
3-204

In addition to the specific inspections performed in steam generator A, a rotating probe 

equipped with a plus-point coil was used to inspect the following in all three steam generators: 

• approximately 61 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below 

the top of the tubesheet on the hot-leg side of the steam generator

• all Tier 1 high-stress tubes (Tier 1 tubes have an eddy current offset in both the hot- and 

cold-leg data and Tier 2 tubes have an offset in either the hot- or cold-leg data, but not 

both) from the hot-leg tube end to 7.62 cm (3 in.) above the top of the tubesheet on the 

hot-leg side of the steam generator (there are no tier 1 tubes in steam generator A)

• approximately 75 percent of the Tier 1 high stress tubes at the hot-leg tube support plate 

elevations (100 percent in steam generator B and 50 percent in steam generator C)

• 50 percent of all dents with bobbin voltage amplitudes greater than or equal to 2 volts

In addition to these eddy current inspections, all tube plugs and the divider plate weld region

were inspected visually. These visual inspections revealed no anomalous conditions with the 

plugs and there was no change in the corrosion degradation observed in the channel head area 

and in an unplugged tube. This latter degradation was initially identified during RFO 16 in 2006 

in the hot-leg of steam generator A.

As a result of these inspections, 30 tubes were plugged—19 for wear attributed to loose parts 

(or the presence of a loose part with no wear present) and 11 because the tube had not been 

expanded into the tubesheet.

The only steam generator tube degradation mechanisms observed during RFO 18 were wear at 

the AVBs, wear at the tube support plates, and wear attributed to loose parts.

Twenty-three indications of wear were detected at the AVBs in 17 tubes in steam generator A. 

The maximum depth reported for the AVB wear indications was 28 percent throughwall. Of 

these 23 indications, 11 were not reported in the prior inspection. All of these indications are 

near the reporting threshold for this mechanism (10 percent throughwall). The growth rate 

associated with AVB wear has decreased since its initial detection in the 1980s. As of RFO 18, 

55 tubes were in service with wear at the AVBs in the three steam generators (17 in steam 

generator A, 8 in steam generator B, and 30 in steam generator C). The wear rate at 95

percent probability and 50 percent confidence is approximately 1.5 percent throughwall per 

cycle.

Two indications of wear were detected in two tubes at the tube support plate elevations during 

RFO 18. One of the indications was in steam generator A; the other was in steam generator C. 

The maximum depth reported for the tube support plate wear indications was 14 percent

throughwall.

Forty-five tubes had indications of wear attributed to loose parts in the three steam generators. 

Most of these indications were present in prior outages.

Overexpansions and overrolls exist in all three steam generators. An overexpansion is an area 

of the tube that is hydraulically expanded more than 0.5 mm (0.02 in.) greater than the diameter 

of the unexpanded portion of the tube. An overroll is an area of the tube that is hydraulically 

expanded more than 6.35 mm (0.25 in.) above the top of the tubesheet. There are 650
3-205

overexpansions (in 505 tubes) within the top 42.42 cm (16.7 in.) of the tube within the tubesheet 

on the hot-leg side of the steam generators (126 in steam generator A, 466 in steam generator 

B, and 58 in steam generator C). There are 506 overexpansions (in 388 tubes) within the top 

42.42 cm (16.7 in.) of the tube within the tubesheet on the cold-leg side of the steam generators 

(79 in steam generator A, 340 in steam generator B, and 87 in steam generator C). There are 

nine overrolls (in nine tubes) on the hot-leg side of the steam generators (three in steam 

generator A, one in steam generator B, and five in steam generator C). There are four overrolls 

(in 4 tubes) on the cold-leg side of the steam generators (all in steam generator C).

The positions of the bottoms of both the hot- and cold-leg expansion transitions were

determined during RFO 18. Other than 11 tubes that were not expanded within the tubesheet, 

no other tubes had significant deviation of the location of the bottom of the expansion transition 

with respect to the top of the tubesheet.

Two Tier 1 tubes are in steam generator B and 14 Tier 1 tubes are in steam generator C. There 

are 173 Tier 2 tubes in steam generator A, 189 in steam generator B, and 134 in steam 

generator C.

Inspection and maintenance on the secondary side of the steam generators were performed 

during RFO 18. Sludge lancing and FOSAR were performed in all three steam generators. 

After sludge lancing, the top of the tubesheet and baffle plates received quick visual inspections

to determine the effectiveness of the lancing. In addition, the steam drum, select J-nozzle 

interfaces (performed from the inside of the feedring), and the top of the tube bundle (through

the primary moisture separator risers) were inspected visually in steam generator C. All 

components examined in the steam drum (upper two decks, primary and secondary separators, 

swirl vanes, drain pipes, deck attachment welds, ladders, etc.) and upper tube bundle regions 

were sound with no evidence of erosion or corrosion. No structural anomalies were noted. 

Minor flow accelerated corrosion was observed at some J-nozzle/feedring interfaces. During 

the prior inspection of the steam generator C upper internals in 2005, localized throughwall flow 

accelerated corrosion degradation was observed on a capped-off, unused J-nozzle stub. This 

degradation was repaired by welding in 2005. During RFO 18 (2009), this location was found to 

be in good condition.

On May 20, 2011, the steam generator portion of the Surry 2 technical specifications was 

revised to limit the extent of inspection in the tubesheet region. Specifically, the technical 

specifications were revised to exclude the portion of tube that is more than 45.06 cm (17.74 in.)

below the top of the tubesheet from inspection (i.e., approximately the lowermost 7.62 cm (3 in.)

of tube in the tubesheet was excluded from inspection, and hence any flaws that may exist in 

this region are permitted to remain in service). This revision was only applicable for RFO 23 

and the subsequent operating cycle (ADAMS Accession No. ML11090A000 and 

ML111810163).

There was no evidence of primary-to-secondary leakage (i.e., leakage is less than 3.79 lpd 

(1 gpd)) during the cycle preceding RFO 19 (fall 2009 to spring 2011). 

During RFO 19 in 2011, 100 percent of the tubes in steam generators B and C were inspected 

full length with a bobbin coil, except for the U-bend region of the tubes in rows 1 and 2. In 

addition to these bobbin coil inspections, a rotating probe equipped with a plus-point coil was 

used to inspect the following in steam generators B and C: 

• the U-bend region of 100 percent of the tubes in rows 1 and 2
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• 58 percent of the tubes from 7.6 cm (3 in.) above to 7.6 cm (3 in.) below the top of the 

tubesheet on the hot-leg side

• all Tier 1 high stress tubes from 7.62 cm (3 in.) above to 45.7 cm (18 in.) below the top 

of the tubesheet on the hot-leg side 

• 50 percent of the outermost five peripheral tubes from 7.6 cm (3 in.) above to 7.6 cm 

(3 in.) below the top of the tubesheet on the cold-leg side

• 50 percent of the overexpansions from 7.62 cm (3 in.) above to 45.7 cm (18 in.) below 

the top of the tubesheet on the hot-leg side

• the 20 largest overexpansions from 7.62 cm (3 in.) above to 45.7 cm (18 in.) below the 

top of the tubesheet on the cold-leg side

• 50 percent of all dents with bobbin voltage amplitudes greater than or equal to 2 volts

In addition to these eddy current inspections, all tube plugs and the divider plate weld region

were inspected visually, revealing no anomalous conditions.

As a result of these inspections, no tubes were plugged.

The only steam generator tube degradation mechanisms observed during RFO 19 were wear at 

the AVBs, wear at the tube support plates, and wear attributed to loose parts.

Sixty-four indications of wear were detected at the AVBs in steam generators B and C 

(10 indications in 9 tubes in steam generator B and 54 indications in 36 tubes in steam 

generator C). The maximum depth reported for the AVB wear indications was 33 percent

throughwall. Of these 64 indications, 11 were not reported in the prior inspection (1 in steam 

generator B and 10 in steam generator C).

Four indications of wear were detected in two tubes in steam generator C at the tube support 

plate elevations during RFO 19. The maximum depth reported for the tube support plate wear 

indications was 20 percent throughwall. Three of these indications were new.

Thirty-two indications of wear attributed to loose parts were detected in steam generators B and 

C (3 indications in 3 tubes in steam generator B and 29 indications in 26 tubes in steam 

generator C). Most of these indications were present in prior outages.

Inspection and maintenance on the secondary side of the steam generators were performed 

during RFO 19. FOSAR was performed in each steam generator at the top of the tubesheet, 

the annulus, and no-tube lane. Visual inspections were performed at the top of the tubesheet in 

steam generators B and C and at select flow distribution baffle plate locations in steam 

generator C. No adverse conditions were noted. The feedrings in all three steam generators 

were replaced with feedrings fabricated from flow accelerated corrosion resistant stainless steel. 

During the feedring replacement work in steam generator A, a hole in one of the primary 

moisture separator riser barrels was identified coincident with a J-nozzle overspray location. 

The riser barrel region is configured into two concentric circles. The outer circle consists of 

12 evenly spaced riser barrels on the outside of the feedring (between the feedring and inside 

diameter of the steam drum). The remaining four riser barrels, forming the inner circle, are on 

the inside of the feedring. Ultrasonic wall thickness measurements were performed on 6 of the 
3-207

16 riser barrels in steam generator A, which showed evidence of overspray. The regions, which 

had reduced wall thickness, were addressed by welding an Inconel patch plate over the affected 

areas. Inconel patch plates were previously installed on the susceptible riser barrels in steam 

generators B and C. The J-nozzles on the replacement feedrings in all three steam generators 

are oriented such that the spray does not impinge on the riser barrels.

On April 17, 2012, the steam generator portion of the Surry 2 technical specifications was 

revised to limit the extent of inspection in the tubesheet region. Specifically, the technical 

specifications were revised to exclude the portion of tube that is more than 45.44 cm (17.89 in.)

below the top of the tubesheet from inspection (i.e., approximately the lowermost 7.62 cm (3 in.)

of tube in the tubesheet was excluded from inspection, and hence any flaws that may exist in 

this region are permitted to remain in service - refer to ADAMS Accession No. ML120730304 

and ML12109A270).

There was no evidence of primary-to-secondary leakage (i.e., leakage is less than 3.79 lpd 

(1 gpd)) during the cycle preceding RFO 20 (spring 2011 to fall 2012).

During RFO 20 in 2012, 100 percent of the tubes in steam generator A were inspected full 

length with a bobbin coil, except for the U-bend region of the tubes in rows 1 and 2. In addition

to these bobbin coil inspections, a rotating probe equipped with a plus-point coil was used to 

inspect the U-bend region of 100 percent of the row 1 and row 2 tubes in steam generator A. 

In addition, an array probe was used to inspect (1) 100 percent of the tubes from the hot-leg 

tube end to the first tube support on hot-leg side in steam generator A, and (2) 100 percent of 

the tubes from the cold-leg tube end to the first tube support on cold-leg side in steam generator 

A. In the tubesheet region, the array probe data were evaluated only for the top 45.44 cm 

(17.89 in.) of the tube. No inspections of the steam generator tubes were performed in steam 

generators B and C.

In addition to these eddy current inspections, visual inspections were performed on all tube 

plugs, the divider plate weld region, and the channel head in steam generator A. These visual 

inspections revealed no anomalous conditions with the plugs or the divider plate weld region. 

During the visual inspections of the channel head, it was verified that no change had occurred in 

the localized cladding degradation that was observed in 2006 in the hot-leg channel head of 

steam generator A. During RFO 16 in 2006, the licensee characterized and evaluated the 

channel head degradation. Ultrasonic examination of the tubesheet-to-channel head transition 

region indicated that no degradation extended into the base material and that the condition is 

acceptable for continued service without repair for the remaining licensed life of the unit. 

Similarly, during RFO 20 in 2012, the hot-leg primary manway flange face was re-examined and 

there was no advancement of the localized region of corrosion between the gasket seating 

surface and the bolt circle that was observed during RFO 16 in 2006. The degradation was 

attributed to gasket leakage at some point before 2006.

As a result of these inspections, no tubes were plugged.

The only steam generator tube degradation mechanisms observed during RFO 20 were wear at 

the AVBs, wear at the tube support plates, and wear attributed to loose parts.

Thirty-one indications of wear in 23 tubes were detected at the AVBs in steam generator A. The 

maximum depth reported for the AVB wear indications was 27 percent throughwall. Of these 

31 indications, 10 were not reported in the prior inspection.
3-208

One indication of wear was detected at the tube support plate elevations during RFO 20. The 

maximum depth reported for the tube support plate wear indications was 7 percent throughwall.

Ten indications of wear attributed to loose parts were detected in steam generator A. Most of 

these indications were present in prior outages and have not changed in size.

Inspection and maintenance on the secondary side of the steam generators were performed 

during RFO 20. Sludge lancing and FOSAR was performed in all three steam generators. The 

visual inspection included the annulus and divider lane (no-tube lane) region on the top of the 

tubesheet. In addition, an inner bundle hot- and cold-leg inspection was performed in steam 

generator A. A visual inspection was also performed of the upper steam drum moisture 

separator components, feedring components, and the top of the U-bend region components in 

steam generator A. No degradation of these components was detected; however, two large 

foreign objects on the upper deck of the steam drum were identified. The objects were later 

determined to be foreign material exclusion barriers that were used during the feedring 

replacement project in 2011 (RFO 19). The objects were removed and rub marks were 

observed at points that were in contact with the barriers. No reduction of material thickness was 

observed. Because of these findings, the steam drums in steam generators B and C were 

inspected to determine if similar objects were present. No foreign objects were identified in 

steam generators B and C.

On January 28, 2013, the steam generator portion of the Surry 2 technical specifications was 

revised making them consistent with TSTF-510 (ADAMS Accession No. ML13018A086, 

ML13032A206, and ML13099A106).

3.4.7 Turkey Point 3

Tables 3-49, 3-50, and 3-51 summarize the information discussed below for Turkey Point 3. 

Table 3-49 provides the number of full-length bobbin inspections and the number of tubes 

plugged and deplugged during each outage for each of the three steam generators. Table 3-50 

lists the reasons why the tubes were plugged. Table 3-51 lists tubes plugged for reasons other 

than wear at the AVBs.

Turkey Point 3 has three Westinghouse model 44F steam generators. They were installed at 

the plant in 1982. The tube supports are numbered as shown in Figure 2-6. Minor denting 

occurred at the upper tube support plates during manufacturing of these steam generators. The 

denting affects no more than 341 intersections in each steam generator hot leg. In addition, 

overexpansion of the tubesheet joint occurred on a maximum of 300 tubes in each hot leg when 

the hydraulic expansion tool was set at a depth exceeding the thickness of the tubesheet. The 

tool made a slight bulge in the tube at the top of the tubesheet. This anomalous condition 

produces residual stresses in the affected locations, making them more susceptible to cracking 

than non-overexpanded areas. Based on accident analysis considerations, a maximum of 

20 percent of the tubes in the three steam generators can be plugged.

During RFO 19 in 2003, it was determined that one tube in steam generator C had not been 

inspected during RFO 18. The tube was not inspected because of an encoding error attributed 

to human error. The manipulator was not verified to be at the correct tube location at the time 

the eddy current data were acquired (resulting in the wrong tube being inspected).

During RFO 19 in 2003, 100 percent of the tubes in each of the three steam generators were 

inspected full length with a bobbin coil, except for the U-bend region of the tubes in rows 1 and 
3-209

2. In addition to these bobbin coil inspections, a rotating probe equipped with a plus-point coil 

was used to inspect:

• 100 percent of the tubes at the hot-leg expansion transition region

• the U-bend region of 50 percent of the row 1 and row 2 tubes (which included all those 

not inspected during RFO 18)

• about 50 percent of the dents in the hot-leg with bobbin voltage amplitudes greater than 

or equal to 5 volts

As a result of these inspections, three tubes were plugged—one for wear at the AVBs, one for a 

manufacturing indication, and one because a plus-point coil inspection could not be performed 

in the U-bend region.

The only steam generator tube degradation mechanisms observed during RFO 19 were wear at 

the AVBs and wear attributed to loose parts.

Six indications of wear were detected at the AVBs in six tubes in steam generator A. Thirteen 

indications of wear were detected at the AVBs in 6 tubes in steam generator B, and 

40 indications of wear were detected at the AVBs in 26 tubes in steam generator C. The 

maximum depth reported for the AVB wear indications was 35 percent throughwall.

One indication of wear attributed to a loose part was detected during RFO 19. The maximum 

depth reported for this indication was 29 percent throughwall.

The manufacturing indication in the tube that was plugged was volumetric in nature and in the 

U-bend region of a row 21 tube. The indication has been present since the preservice 

inspection and has not changed.

The restriction that led to a tube being plugged because it prevented a plus-point coil inspection 

was in a row 1 tube. The RFO 19 inspection was the first time the U-bend region of this tube 

was scheduled to be inspected with a plus-point probe. This region of the tube had been 

inspected with a bobbin probe in prior outages. The restriction was attributed to tube ovalization 

because of the bending process during manufacturing of the tubes. During the RFO 18 

inspections in 2001, another row 1 tube could not be inspected in the U-bend region with a pluspoint coil. Similar to the tube plugged during RFO 19, the RFO 18 inspections were the first 

scheduled inspections with a plus-point coil. Although the tube in RFO 18 allowed passage of 

the plus-point coil (unlike the tube in RFO 19, which did not permit passage), the probe did not 

rotate properly through the entire U-bend region. The U-bend region of this tube had also been 

inspected with a bobbin probe in prior outages.

Three new dents were identified during RFO 19—two in steam generator B and one in steam 

generator C. One of the dents was in the freespan between the fifth and sixth supports of a 

peripheral tube on the cold-leg side of the steam generator. The other two dents were slightly 

above the secondary face of the tubesheet.

To identify tubes that have potentially high residual stress and therefore might be more 

susceptible to stress corrosion cracking, bobbin coil eddy current data were reviewed. As a 

result of this review, no low-row tubes (i.e., tubes in rows 1 through 8) were identified as being 

more susceptible to stress corrosion cracking. In the higher row tubes (i.e., tubes in rows 9 and 
3-210

higher), 18 tubes were identified with a voltage offset of less than 2 volts between the eddy 

current data in the U-bend and the straight region. This lack of an offset in the eddy current 

data is indicative of potentially higher residual stresses in the straight span portion of the tube. 

This 2-volt criterion was revised in 2004 to a voltage offset less than two standard deviations of 

the mean (i.e., minus 2 sigma). There are 59 tubes that satisfy the minus 2 sigma criterion.

During RFO 20 in 2004, 100 percent of the tubes in each of the three steam generators were 

inspected full length with a bobbin coil, except for the U-bend region of the tubes in rows 1 and 

2. In addition to these bobbin coil inspections, a rotating probe equipped with a plus-point coil 

was used to inspect the following in each of the three steam generators:

• 100 percent of the tubes from 7.62 cm (3 in.) above to 5.1 cm (2 in.) below the top of the 

tubesheet on the hot-leg side

• the U-bend region of 50 percent of the row 1 and row 2 tubes

• 50 percent of the dents in the hot-leg with bobbin voltage amplitudes greater than or 

equal to 5 volts

• 50 percent of the dents in the U-bend region with bobbin voltage amplitudes greater than 

or equal to 3 volts

In addition to these eddy current inspections, all tube plugs in each of the three steam 

generators were inspected visually.

As a result of these inspections, no tubes were plugged.

The only steam generator tube degradation mechanisms observed during RFO 20 were wear at 

the AVBs, wear at the tube supports, and wear attributed to loose parts.

Seventeen indications of wear were detected at the AVBs in 14 tubes in steam generator A. 

Thirty indications of wear were detected at the AVBs in 18 tubes in steam generator B, and 

eighty nine indications of wear were detected at the AVBs in 59 tubes in steam generator C. 

The maximum depth reported for the AVB wear indications was 33 percent throughwall.

Seven additional indications attributed to wear were also detected during RFO 20. Of these, 

three were attributed to wear against a tube support plate and four were attributed to wear from 

loose parts. Of the three tube support plate wear indications, two were newly detected during 

RFO 20 and one was detected in the prior inspection and allowed to remain in service. Three of 

the four indications attributed to wear from a loose part were near the top of the tubesheet. 

There were no possible loose part indications detected at these locations during the eddy 

current inspection and a FOSAR near these tubes did not find any loose parts. The fourth 

indication attributed to wear from a loose part was at the second tube support plate on the coldleg side of the steam generator. This indication was attributed to a loose part because there 

was a possible loose part indication identified at this location during the eddy current inspection. 

This indication has remained in service for 14 years.

A FOSAR inspection was performed in all three steam generators. Small objects were identified 

in all three steam generators.

During RFO 21 in 2006, no steam generator tubes were inspected.
3-211

On November 1, 2006, the steam generator portion of the Turkey Point 3 technical 

specifications was revised to limit the extent of inspection in the tubesheet region. Specifically, 

the technical specifications were revised to exclude the portion of tube that is more than 

43.2 cm (17 in.) below the top of the tubesheet on the hot-leg side from inspection (i.e., 

approximately the lowermost 10.2 cm (4 in.) of tube in the tubesheet on the hot-leg side was 

excluded from inspection, and hence any flaws that may exist in this region are permitted to 

remain in service). This revision was only applicable for RFO 22 and the subsequent operating 

cycles (ADAMS Accession No. ML062990193).

On April 27, 2007, Turkey Point 3 revised the steam generator portion of their technical 

specifications making them performance-based consistent with TSTF-449 (ADAMS Accession 

No. ML071080444).

During RFO 22 in 2007, 100 percent of the tubes in each of the three steam generators were 

inspected full length with a bobbin coil, except for the U-bend region of the tubes in rows 1 and 

2. In addition to these bobbin coil inspections, a rotating probe equipped with a plus-point coil 

was used to inspect the following in each of the three steam generators:

• 100 percent of the tubes from 7.62 cm (3 in.) above to 43.2 cm (17 in.) below the top of 

the tubesheet on the hot-leg side

• all tubes that were not expanded into the tubesheet on the hot-leg side (one tube in 

steam generator A, two tubes in steam generator B, and five tubes in steam generator 

C) for the full length of the tubesheet

• 100 percent of the tubes in the peripheral high-flow regions (two outermost tubes 

exposed to the annulus, and the row 1 and row 2 tubes in columns 1 through 10 and 

columns 83 through 92) and the remaining row 1 and row 2 tubes (not in the high-flow 

region) from 7.62 cm (3 in.) above to 5.1 cm (2 in.) below the top of the tubesheet on the 

cold-leg side

• all tubes that were not expanded into the tubesheet on the cold-leg side (one tube in 

steam generator B – this tube is also one of the tubes that was not expanded on the hotleg side) for the full length of the tubesheet

• the U-bend region of 50 percent of the row 1 and 2 tubes (which included all tubes not 

inspected during RFO 20)

• 50 percent of the freespan dents/dings in the hot-leg with bobbin voltage amplitudes 

greater than 5 volts (which included all such dents/dings not inspected during RFO 20)

• 50 percent of the dents/dings in the U-bend region (which included all dents/dings not 

inspected during RFO 20)

• 50 percent of the dents/dings at structures on the hot-leg (which included all such 

dents/dings not inspected during RFO 21)

In addition to these eddy current inspections, all tube plugs in each of the three steam 

generators were inspected visually. No degradation was identified during the inspection of the 

plugs, and all plugs were verified to be present and in the correct locations.
3-212

As a result of these inspections, one tube was plugged for an outside-diameter initiated 

volumetric indication about 15 cm (6 in.) below the top of the tubesheet on the hot-leg side of 

the steam generator. Because this indication is within the tubesheet and the tube-to-tubesheet 

crevice is closed, the licensee concluded this indication was not service-induced and most likely 

a result of steam generator manufacturing/installation.

The only steam generator tube degradation mechanisms observed during RFO 22 were 

(1) wear at the AVBs, (2) wear at the tube support plates, (3) wear at the flow distribution baffle, 

and (4) wear attributed to loose parts.

Twenty-one indications of wear were detected at the AVBs in 17 tubes in steam generator A. 

Thirty-one indications of wear were detected at the AVBs in 19 tubes in steam generator B, and 

99 indications of wear were detected at the AVBs in 66 tubes in steam generator C. The 

maximum depth reported for the AVB wear indications was 35 percent throughwall.

In addition to the volumetric indications attributed to wear at the AVBs, 11 additional volumetric 

indications were also detected during RFO 22. Of these 11 indications, 5 were attributed to 

wear against a tube support plate (1 in steam generator A, 1 in steam generator B, and 3 in 

steam generator C), 3 were attributed to wear against the baffle plate (all in steam generator B), 

2 were attributed to wear from a loose part (1 in steam generator A and 1 in steam generator B), 

and 1 was in the tubesheet region (this tube was plugged and in steam generator C). Both of 

the wear indications attributed to loose parts had been detected in previous outages.

Inspection and maintenance on the secondary side of the steam generators were performed 

during RFO 22. An upper bundle flush and sludge lancing was performed in each of the three 

steam generators. FOSAR was also performed in each of the three steam generators. In 

addition, visual inspections of the upper tube bundle region was performed in steam generator A 

before the upper bundle flushing, and visual inspections of the upper internals were also 

performed in steam generator B.

Sludge lancing removed about 35 pounds of sludge from each steam generator. FOSAR was 

performed after the sludge lancing and upper bundle flush. No tube degradation was observed

during the visual inspections. In addition to known foreign objects that were left in the steam 

generators, seven new objects were identified during RFO 22. Four of these objects were 

removed. The remaining objects were evaluated for their effect on steam generator operation 

and will be tracked during future inspections.

The visual inspection of the upper tube bundle in steam generator A revealed a thin layer of

deposits and all tube support flow holes were fully open. No abnormal conditions or 

degradation was observed. In steam generator B, the steam separation equipment, feedring, 

J-tubes, and J-tube bore holes were inspected visually. Ultrasonic inspections were also 

performed of the feedring and feedring distribution box. No abnormal conditions or degradation 

were observed.

During RFO 23 in 2009, no steam generator tubes were inspected.

On October 30, 2009, the steam generator portion of the Turkey Point 3 technical specifications 

was revised to limit the extent of inspection in the tubesheet region. Specifically, the technical 

specifications were revised to exclude the portion of tube that is more than 43.89 cm (17.28 in.)

below the top of the tubesheet from inspection (i.e., approximately the lowermost 10.2 cm (4 in.)
3-213

of tube in the tubesheet was excluded from inspection, and hence any flaws that may exist in 

this region are permitted to remain in service). This revision was only applicable for RFO 24 

and the next operating cycle (ADAMS Accession No. ML092990489).

There was no evidence of primary-to-secondary leakage during the cycle preceding RFO 24 

(spring 2009 to fall 2010).

During RFO 24 in 2010 (referred to as TP3-25 RFO by the licensee), 100 percent of the tubes in 

each of the three steam generators were inspected full length with a bobbin coil, except for the 

U-bend region of the tubes in rows 1 and 2. In addition to these bobbin coil inspections, a 

rotating probe equipped with a plus-point coil was used to inspect the following in each of the 

three steam generators:

• 50 percent of the tubes from 7.62 cm (3 in.) above to 43.89 cm (17.28 in.) below the top 

of the tubesheet on the hot-leg side (includes 50 percent of the bulges and 

overexpansions in the tubesheet)

• the two outermost peripheral tubes (annulus and tube-lane) from 7.62 cm (3 in.) above 

to 5.1 cm (2 in.) below the top of the tubesheet on the cold-leg side

• the U-bend region of 50 percent of the tubes in rows 1 and 2 

• 50 percent of the freespan dings in the hot-leg with bobbin voltage amplitudes greater 

than 5 volts

• 50 percent of the dings in the U-bend region

• 50 percent of the dents/dings at hot-leg structures. 

As a result of these inspections, 14 tubes were plugged—1 for wear at an AVB, 2 for wear at a 

tube support, 2 for wear attributed to a loose part, and 9 because the tubes were not expanded 

into the tubesheet.

The only steam generator tube degradation mechanisms observed during RFO 24 were 

(1) wear at the AVBs, (2) wear at the tube support plates, (3) wear at the flow distribution baffle, 

and (4) wear attributed to loose parts.

Wear at the AVBs was identified at 22 locations in 17 tubes in steam generator A, at 24

locations in 19 tubes in steam generator B, and at 119 locations in 80 tubes in steam generator 

C (not including the 2 indications in 1 tube that was plugged). The maximum depth reported for 

the AVB wear indications was 37 percent throughwall.

For wear at the tube support plates (including the flow distribution baffle), two indications were 

detected in two tubes in steam generator A, six indications were detected in six tubes in steam 

generator B, and nine indications were detected in nine tubes in steam generator C (not 

including the two indications in two tubes that were plugged. The maximum depth reported for 

the tube support plate wear indications was 37 percent throughwall.

Three indications of wear in three tubes were attributed to loose parts. One of these indications 

(with an estimated depth of 8 percent) is in the freespan about 7.62 cm (3 in.) above the top of 

the tubesheet in steam generator A. No loose part or possible loose part indication has ever 
3-214

been identified at this location, but the wear is attributed to a loose part. The other two 

indications of wear attributed to a loose part were identified in steam generator B on the top of 

the second cold-leg tube support. The location of the possible loose part was not accessible for 

visual inspection to confirm/retrieve the part. The possible loose part has been at this location 

since at least 1990, and the projected wear rate for these two wear indications is less than or 

equal to 1 percent throughwall per effective full power year. These latter two tubes were 

plugged.

Inspections and maintenance activities were performed on the secondary side of the steam 

generators during RFO 24. An upper bundle flush and sludge lancing were performed in each 

of the three steam generators resulting in 49, 70, and 66 pounds of sludge being removed from 

steam generators A, B, and C, respectively. Steam generator B was inspected visually before

the upper bundle flush. These inspections included the U-bend region and the center flow slot 

regions of the tube supports. The inspections revealed very light deposit accumulation so no 

post-bundle flush inspections were performed.

After sludge lancing at the top of the tubesheet in each of the three steam generators, FOSAR

was performed. During these inspections, three objects (e.g., weld slag) could not be removed 

and six objects were removed (e.g., wire, metallic pin). There was no tube wear associated with 

the loose part/possible loose part indications except for the two wear indications associated with 

the two tubes that were plugged (this loose part is not included in the three objects left in the 

steam generator since the tubes were plugged). Evaluations by the licensee indicated that the 

parts that could not be removed were acceptable to leave in the steam generators until the next 

scheduled inspection. 

During RFO 24, one tube was deplugged, inspected, stabilized, and re-plugged. This tube was 

stabilized to mitigate the possibility of tube-to-tube contact for extended (60 years) operation.

On March 6, 2011, Turkey Point 3 was shut down in response to high-sodium concentrations 

(greater than 250 parts per billion) in the steam generators. The sodium intrusion was caused a 

leak in the main condenser.

During RFO 25 in 2012, no steam generator tubes were inspected.

On November 5, 2012, the steam generator portion of the Turkey Point 3 technical 

specifications was revised to limit the extent of inspection in the tubesheet region. Specifically,

the technical specifications were revised to exclude the portion of tube that is more than 46 cm 

(18.11 in.) below the top of the tubesheet from inspection (i.e., approximately the lowermost 

10.2 cm (4 in.) of tube in the tubesheet was excluded from inspection, and hence any flaws that 

may exist in this region are permitted to remain in service (ADAMS Accession No. 

ML12292A342)).

On November 6, 2012, Turkey Point 3 revised the steam generator portion of their technical 

specifications making them consistent with TSTF-510 (ADAMS Accession No. ML12297A240).

3.4.8 Turkey Point 4

Tables 3-52, 3-53, and 3-54 summarize the information discussed below for Turkey Point 4. 

Table 3-52 provides the number of full-length bobbin inspections and the number of tubes 

plugged and deplugged during each outage for each of the three steam generators. Table 3-53 
3-215

lists the reasons why the tubes were plugged. Table 3-54 lists tubes plugged for reasons other 

than wear at the AVBs.

Turkey Point 4 has three Westinghouse model 44F steam generators. These steam generators 

were installed at the plant in 1983. The tube supports are numbered as shown in Figure 2-6. 

Minor denting occurred at the upper tube support plates during manufacturing of these steam 

generators. The denting affects no more than 341 intersections in each steam generator hot 

leg. In addition, overexpansion of the tubesheet joint occurred on a maximum of 300 tubes in 

each hot leg when the hydraulic expansion tool was set at a depth exceeding the thickness of 

the tubesheet. The tool made a slight bulge in the tube at the top of the tubesheet. This 

anomalous condition produces residual stresses in the affected locations, making them more 

susceptible to cracking than non-overexpanded areas. Based on accident analysis 

considerations, a maximum of 20 percent of the tubes in the three steam generators can be 

plugged.

During RFO 19 in 2002, no steam generator tubes were inspected; however, secondary-side

inspections were performed in steam generator A to identify debris and damage. No reportable 

indications were identified.

During RFO 20 in 2003, 100 percent of the tubes in each of the three steam generators were 

inspected full length with a bobbin coil, except for the U-bend region of the tubes in rows 1 and 

2. In addition to these bobbin coil inspections, a rotating probe equipped with a plus-point coil 

was used to inspect the following in each of the three steam generators:

• 100 percent of the tubes from 7.62 cm (3 in.) above to 5.1 cm (2 in.) below the top of the 

tubesheet on the hot-leg side

• the U-bend region of 30 percent of the row 1 and row 2 tubes

• a minimum of 30 percent of the dings in the hot-leg with bobbin voltage amplitudes 

greater than or equal to 5 volts

• a minimum of 30 percent of the dings in the hot-leg U-bend region with bobbin voltage 

amplitudes greater than or equal to 3 volts

As a result of these inspections, four tubes were plugged—one for wear attributed to a loose 

part, one for mechanical damage caused during loose part retrieval activities during the outage, 

and two tubes for pit-shaped wear indications.

The only steam generator tube degradation mechanisms observed during RFO 20 were 

(1) wear at the AVBs, (2) wear at the tube support plates, (3) wear at the flow distribution baffle, 

(4) wear attributed to loose parts, and (5) wear attributed to maintenance activities.

Wear at the AVBs was identified at 7 locations in 5 tubes in steam generator A, at 12 locations 

in 10 tubes in steam generator B, and at 11 locations in 10 tubes in steam generator C. The 

maximum depth reported for the AVB wear indications was 28 percent throughwall.

Two indications of wear at the tube support plates were detected in two tubes. The maximum 

depth reported for the tube support plate wear indications was 9 percent throughwall.
3-216

The wear indications were detected at the flow distribution baffle during RFO 20. These two 

indications were pit-shaped and were both at the lower edge of the baffle plate (which has 

circular holes). Similar pit-like wear indications have been reported in other steam generators, 

primarily Westinghouse steam generators with preheaters.

There was one indication of wear attributed to a loose part. This indication was at the flow 

distribution baffle.

The damage caused to the one tube during loose part retrieval activities was about 2 cm 

(0.8 in.) long (axially), 0.6 cm (0.24 in.) wide (circumferentially), and had a maximum depth of 

27 percent throughwall. 

Eleven new dents were identified during RFO 20: three in steam generator A, five in steam 

generator B, and three in steam generator C. Most of these dents are within 12.7 cm (5 in.) of 

the top (secondary face) of the tubesheet. Two of these dents were in the freespan region: one 

between the third and fourth hot-leg tube supports and one in the U-bend region.

Inspections on the secondary side of steam generator A were performed during RFO 20. 

A sample of the J-tubes and the feedring piping were inspected visually and ultrasonically, with 

no reportable indications identified. In addition, FOSAR was performed on the top of the 

tubesheet in the annulus and blowdown lane in all three steam generators.

During RFO 21 in 2005, no steam generator tubes were inspected; however, secondary-side

inspections were performed in steam generator C to identify debris and damage. Visual 

inspections of the feedring J-nozzles were performed and ultrasonic thickness measurements of 

the tee were performed.

On November 1, 2006, the steam generator portion of the Turkey Point 4 technical 

specifications was revised to limit the extent of inspection in the tubesheet region. Specifically, 

the technical specifications were revised to exclude the portion of tube that is more than 

43.2 cm (17 in.) below the top of the tubesheet on the hot-leg side from inspection (i.e., 

approximately the lowermost 10.2 cm (4 in.) of tube in the tubesheet on the hot-leg side was 

excluded from inspection, and hence any flaws that may exist in this region are permitted to 

remain in service). This revision was only applicable for RFO 22 and the subsequent operating 

cycles (ADAMS Accession No. ML062990193).

During RFO 22 in 2006, 100 percent of the tubes in each of the three steam generators were 

inspected full length with a bobbin coil, except for the U-bend region of the tubes in rows 1 and 

2. In addition to these bobbin coil inspections, a rotating probe equipped with a plus-point coil 

was used to inspect the following in each of the three steam generators:

• 100 percent of the tubes from 7.62 cm (3 in.) above to 43.2 cm (17 in.) below the top of 

the tubesheet on the hot-leg side

• the U-bend region of 50 percent of the tubes in rows 1 and 2

• 50 percent of the dings in the hot-leg and U-bend region with bobbin voltage amplitudes 

greater than or equal to 5 volts

• 50 percent of the dents/dings at hot-leg structures with bobbin voltage amplitudes 

greater than or equal to 5 volts
3-217

As a result of these inspections, six tubes were plugged. All of these tubes were plugged for 

wear attributed to a loose part. 

The only steam generator tube degradation mechanisms observed during RFO 22 were 

(1) wear at the AVBs, (2) wear at the tube support plates, (3) wear at the flow distribution baffle, 

and (4) wear attributed to loose parts.

Wear at the AVBs was identified at 7 locations in 5 tubes in steam generator A, at 13 locations 

in 10 tubes in steam generator B, and at 19 locations in 18 tubes in steam generator C. The 

maximum depth reported for the AVB wear indications was 27 percent throughwall.

One indication of wear at the tube support plates was detected in one tube in steam generator 

A, two indications were detected in two tubes in steam generator B, and one indication was 

detected in one tube in steam generator C. The maximum depth reported for the tube support 

plate wear indications was 16 percent throughwall.

One indication of wear at the flow distribution baffle was detected in one tube in steam 

generator B.

There were six tubes with wear attributed to a loose part. All of these tubes were in the same 

general region of the tube bundle, and the loose part was no longer present at the location. The 

indications in these tubes were in close proximity to the expansion transition region on the coldleg side of the steam generator. The maximum depth reported was 51 percent throughwall. 

A historical review of prior outage eddy current data for the two largest indications indicated they 

were present in the prior inspection outage (2003) but were not identified. Of the six indications 

detected in the plugged tubes, only the largest indication (i.e., the 51 percent throughwall 

indication) was identified with the bobbin probe. Specifically, a multi-frequency mix (referred to 

as a turbomix) permitted identification of the indication. The remaining five indications were 

detected when a rotating probe was used to inspect the tubes surrounding the tube with the 

51 percent throughwall indication.

Inspections and maintenance were performed on the secondary side of the steam generators 

during RFO 22. A high-volume bundle flush was performed in each of the three steam 

generators to rinse deposits from the upper bundle regions before lancing the sludge from the 

top of the tubesheet. After sludge lancing at the top of the tubesheet in each of the three steam 

generators, FOSAR was performed on the top of the tubesheet in the annulus and blowdown 

lane. During these inspections, three objects (two wires and one weld rod) were identified that 

could not be removed, and six objects were removed (Flexitallic gaskets and wire). Evaluations 

by the licensee indicated that the parts that could not be removed were acceptable to leave in 

the steam generators until the next scheduled inspection. After the high-volume bundle flush, a 

visual inspection of the upper tube bundle region including the tube supports, feedring, and 

moisture separation equipment was performed in steam generator B. Such inspections are 

performed in at least one steam generator on a rotating basis and have shown very low deposit 

accumulation and un-blocked tube support flow holes.

On April 27, 2007, Turkey Point 4 revised the steam generator portion of their technical 

specifications making them performance-based consistent with TSTF-449 (ADAMS Accession 

No. ML071080444).

During RFO 23 in 2008, no steam generator tubes were inspected.
3-218

On October 30, 2009, the steam generator portion of the Turkey Point 4 technical specifications 

was revised to limit the extent of inspection in the tubesheet region. Specifically, the technical 

specifications were revised to exclude the portion of tube that is more than 43.89 cm (17.28 in.)

below the top of the tubesheet from inspection (i.e., approximately the lowermost 10.2 cm (4 in.)

of tube in the tubesheet was excluded from inspection, and hence any flaws that may exist in 

this region are permitted to remain in service). This revision was only applicable for RFO 24

and the subsequent operating cycles (ADAMS Accession No. ML092990489).

There was no evidence of primary-to-secondary leakage during the cycle preceding RFO 24 

(spring 2008 to fall 2009).

During RFO 24 in 2009, 100 percent of the tubes in each of the three steam generators were 

inspected full length with a bobbin coil, except for the U-bend region of the tubes in rows 1 and 

2. In addition to these bobbin coil inspections, a rotating probe equipped with a plus-point coil 

was used to inspect the following in each of the three steam generators:

• 100 percent of the tubes from 7.62 cm (3 in.) above to 43.89 cm (17.28 in.) below the top 

of the tubesheet on the hot-leg side

• the two outermost peripheral tubes (annulus and tube-lane) from 7.62 cm (3 in.) above 

to 5.1 cm (2 in.) below the top of the tubesheet on the cold-leg side

• the U-bend region of 100 percent of the tubes in rows 1 and 2

• 100 percent of the dings in the hot-leg with bobbin voltage amplitudes greater than or 

equal to 5 volts

• 100 percent of the dings in the U-bend region

• 100 percent of the dents/dings at hot-leg structures

As a result of these inspections, 11 tubes were plugged—9 because they were not expanded in

the tubesheet region, 1 because the bottom of the expansion transition on the hot-leg side of the 

steam generator was 2.72 cm (1.07 in.) below the top of the tubesheet, and 1 for wear at an 

AVB that was associated with a dent signal.

The only steam generator tube degradation mechanisms observed during RFO 24 were wear at 

the AVBs, wear at the tube support plates, and wear at the flow distribution baffle.

Wear at the AVBs was identified at 9 locations in 6 tubes in steam generator A, at 16 locations 

in 12 tubes in steam generator B, and at 26 locations in 24 tubes in steam generator C. The 

maximum depth reported for the AVB wear indications was 34 percent throughwall. Although 

no qualified sizing technique exists for wear at an AVB associated with a dent, the maximum 

depth of the indication was estimated as 34 percent throughwall.

One indication of wear at the tube support plates was detected in one tube in steam generator 

A, three indications were detected in three tubes in steam generator B, and one indication was 

detected in one tube in steam generator C. The maximum depth reported for the tube support 

plate wear indications was 18 percent throughwall.
3-219

Two indications of wear at the flow distribution baffle were detected in two tubes in steam 

generator A, and 3 indications were detected at the flow distribution baffle in 2 tubes in steam 

generator B.

The lowest bottom of expansion transition remaining in the steam generators is about 12.7 mm 

(0.5 in.) below the top of the tubesheet.

Inspections and maintenance were performed on the secondary side of the steam generators 

during RFO 24. A high-volume bundle flush and sludge lancing were performed in each of the 

three steam generators resulting in 26.5, 24.5, and 17.0 pounds of sludge being removed from 

steam generators A, B, and C, respectively. Visual inspections before and after the upper 

bundle flush (of the center flow slot regions of tube supports 3 through 6) in steam generator C 

indicated that the steam generators are relatively clean with no significant buildup of deposits, 

and that the tube support flow holes remain open.

After sludge lancing at the top of the tubesheet in each of the three steam generators, FOSAR

was performed on the top of the tubesheet in the annulus and blowdown lane. During these 

inspections, seven objects (e.g., wires, weld rod) were identified that could not be removed and 

five objects were removed (Flexitallic gaskets, wire, and rod shaped objects). No tube wear 

was associated with the loose parts/possible loose part indications. Evaluations by the licensee 

indicated that the parts that could not be removed were acceptable to leave in the steam 

generators until the next scheduled inspection. 

During RFO 25 in 2011, no steam generator tubes were inspected.

On November 5, 2012, the steam generator portion of the Turkey Point 4 technical 

specifications was revised to limit the extent of inspection in the tubesheet region. Specifically, 

the technical specifications were revised to exclude the portion of tube that is more than 46 cm 

(18.11 in.) below the top of the tubesheet from inspection (i.e., approximately the lowermost 

10.2 cm (4 in.) of tube in the tubesheet was excluded from inspection, and hence any flaws that 

may exist in this region are permitted to remain in service (ADAMS Accession No. 

ML12292A342)).

On November 6, 2012, Turkey Point 4 revised the steam generator portion of their technical 

specifications making them consistent with TSTF-510 (ADAMS Accession No. ML12297A240).

There was no evidence of primary-to-secondary leakage during the cycle preceding RFO 26

(spring 2011 to fall 2012).

During RFO 26 (referred to as TP4-27 RFO by the licensee) in 2013, 100 percent of the tubes in 

each of the three steam generators were inspected full length with a bobbin coil, except for the 

U-bend region of the tubes in rows 1 and 2. In addition to these bobbin coil inspections, a 

rotating probe equipped with a plus-point coil was used to inspect the following in each of the 

three steam generators:

• 50 percent of the tubes from 7.62 cm (3 in.) above to 46 cm (18.11 in.) below the top of 

the tubesheet on the hot-leg side (includes 50 percent of the bulges and overexpansions 

in the tubesheet)

• the two outermost peripheral tubes (annulus and tube-lane) from 7.62 cm (3 in.) above 

to 5.1 cm (2 in.) below the top of the tubesheet on the cold-leg side
3-220

• the U-bend region of 50 percent of the tubes in rows 1 and 2

• 50 percent of the freespan dings in the hot-leg with bobbin voltage amplitudes greater 

than 5 volts, 50 percent of the dings in the U-bend region (regardless of their bobbin 

voltage amplitude)

• 50 percent of the dents/dings at hot-leg structures (regardless of their bobbin voltage 

amplitude)

As a result of these inspections, one tube was stabilized and plugged. This tube was plugged

for wear attributed to a loose part at a tube support plate elevation.

The only steam generator tube degradation mechanisms observed during RFO 26 were 

(1) wear at the AVBs, (2) wear at the tube support plates, (3) wear at the flow distribution baffle, 

(4) wear attributed to loose parts, and (5) axially oriented primary water stress corrosion 

cracking near the tube ends.

Wear at the AVBs was identified at 16 locations in 11 tubes in steam generator A, at 20

locations in 15 tubes in steam generator B, and at 26 locations in 24 tubes in steam generator 

C. The maximum depth reported for the AVB wear indications was 28 percent throughwall.

One indication of wear at the tube support plates was detected in one tube in steam generator 

A, eight indications were detected in eight tubes in steam generator B, and one indication was

detected in one tube in steam generator C. The maximum depth reported for the tube support 

plate wear indications was 16 percent throughwall.

Two indications of wear at the flow distribution baffle were detected in two tubes in steam 

generator A, five indications were detected in three tubes in steam generator B, and one

indication was detected in one tube in steam generator C. The maximum depth reported for the 

flow distribution baffle wear indications was 11 percent throughwall.

One indication of wear attributed to a loose part was detected. This tube was plugged as 

discussed above.

Eleven indications indicative of primary water stress corrosion cracking were identified near the 

hot-leg tube end during RFO 26. All of 11 indications (in 11 tubes) were axially oriented and 

greater than 46 cm (18.11 in.) below the top of the tubesheet; therefore, the tubes were not 

required to be plugged. This was the first inspection of the lower portion of the tubesheet.

To identify tubes that have potentially high residual stress and therefore might be more 

susceptible to stress corrosion cracking, bobbin coil eddy current data were reviewed. As of 

RFO 26, 58 tubes in service had an offset that could indicate a tube that is more susceptible to 

stress corrosion cracking. Fifty-seven of the tubes are in the high rows (rows 9 and higher) and 

one tube is in the low rows (i.e., rows 1 through 8). The high-row tubes have an offset less than 

two standard deviations from the mean offset of all the data (i.e., minus 2 sigma). There are 

14 “minus 2 sigma” tubes in steam generator A, 18 in steam generator B, and 25 in steam 

generator C. The tube with the offset in the low rows is in steam generator C. This tube has an 

eddy current offset that does not match that of other low-row tubes nor does it match the typical 

offset that was observed at Seabrook. This tube was classified as potentially having high 

residual stresses for tracking purposes. No low-row tubes have a voltage-offset condition 

similar to what was observed at Seabrook.
3-221

Inspections and maintenance were performed on the secondary side of the steam generators 

during RFO 26. An upper bundle flush and sludge lancing were performed in each of the three 

steam generators resulting in 27, 27, and 24 pounds of sludge being removed from steam 

generators A, B, and C, respectively. After sludge lancing at the top of the tubesheet in each of 

the three steam generators, FOSAR was performed. During these inspections, five objects 

(e.g., wires, weld rod) were identified that could not be removed and eight objects were 

removed (e.g., wire, weld slag, and rod shaped objects). No tube wear was associated with the 

loose parts/possible loose part indications except for the one wear indication associated with the 

tube that was plugged. Evaluations by the licensee indicated that the parts that could not be 

removed were acceptable to leave in the steam generators until the next scheduled inspection.
3-222

Table 3-1: Braidwood 2: Summary of Bobbin Inspections and Tube Plugging

Insp. Plug DePl Insp. Plug DePl Insp. Plug DePl Insp. Plug DePl

Pre-op 1 2 0 3 6 0 

RFO 1 04/26/1990 1.18 4569 0 4568 0 4570 2 4567 0 2 0 

RFO 2 11/11/1991 2.3 2285 4 2284 0 1 2284 7 2284 0 11 1 

RFO 3 04/13/1993 3.42 2440 6 2374 1 2370 8 2430 1 16 0 

RFO 4 10/25/1994 4.58 4568 0 4553 6 6 0 

RFO 5 04/12/1996 5.85 4559 17 4568 2 4547 4 4566 12 35 0 

RFO 6 10/20/1997 7.19 4542 7 4566 3 4543 12 4554 6 28 0 

RFO 7 05/05/1999 8.57 4535 0 4563 1 4531 4 4548 1 6 0 

RFO 8 10/28/2000 9.97 4535 8 4562 1 4527 1 4547 1 11 0 

RFO 9 04/25/2002 11.33 4527 2 2 0 

RFO 10 11/12/2003 12.78 4525 8 4561 39 4526 10 4546 1 58 0 

RFO 11 04/26/2005 14.16 4517 4 4522 0 4516 2 4545 0 6 0 

RFO 12 10/25/2006 15.6 4513 9 4522 1 4514 4 4545 0 14 0 

RFO 13 05/05/2008 17.05 4504 17 4521 0 4510 5 4545 1 23 0 

RFO 14 10/31/2009 18.42 4487 0 4521 5 4505 1 4544 0 6 0 

RFO 15 05/11/2011 19.856 4487 12 4516 7 4504 2 4544 9 30 0 

RFO 16 11/08/2012 21.268 4475 5 4509 2 4502 2 4535 2 11 0 

RFO 17 05/22/2014 22.72 4470 0 4507 3 4500 2 4533 3 8 0 

Totals: 100 0 67 1 72 0 40 0 279 1

Plant Data Acronyms

Model: D5 Pre-op = prior to operation

T-hot (approximate): 611 °F Cumul. = cumulative

Tubes per steam generator: 4570 Insp. = number of tubes inspected

Number of steam generators: 4 Plug = number of tubes plugged

DePl = number of tubes deplugged

RFO = refueling outage

Notes

1. All tubes in each steam generator were examined through the U-bend.

2. The U-bend region of the row 1 and 2 tubes was not inspected with a bobbin coil. The U-bend region of 25% of the row 1 and 2 tubes was inspected with a 

3. The U-bend region of the row 1 and 2 tubes was not inspected with a bobbin coil. The U-bend region of 50% of the row 1 and 2 tubes was inspected with a 

Outage

Completion 

Date

Cumul. 

EFPY

SG A SG B SG C SG D Total 

DePl

Total 

Plug
3-223

Table 3-2: Braidwood 2: Causes of Tube Plugging

1990 1991 1993 1994 1996 1997 1999 2000 2002 2003 2005 2006 2008 2009 2011 2012 2014

Pre-Op RFO 1 RFO 2 RFO 3 RFO 4 RFO 5 RFO 6 RFO 7 RFO 8 RFO 9 RFO 10 RFO 11 RFO 12 RFO 13 RFO 14 RFO 15 RFO 16 RFO 1

AVB 2 11 16 6 29 12 6 10 2 10 5 10 6 1 5 2 

Preheater TSP (D5) 2 2 

TSP 

Confirmed 2 1 42 

Not confirmed, 

periphery 1 4 6 2 

Not confirmed, not 

periphery 1 2 1 16 4 

From PSI, no 

progression 

Service-induced 

Preservice 6 -1 

Other 15 3 2 

Probe lodged 

Data quality 

Dent/geometry 

Permeability 1 

Not inspected 

Top of tubesheet 1 

Freespan 1 

TSP 2 

Other/not reported 

ID 16 

OD 3 1 1 

TOTALS 6 2 10 16 6 35 28 6 11 2 58 6 14 23 6 30 11 

Notes: 1 2 3 4 5 6

Notes

1. One tube deplugged during RFO 2.

2. Fifteen tubes plugged with circumferential indications at hot-leg top of tubesheet reclassified as manufacturing anomalies based on tube pulls from Byron 2. All were stabilized.

3. 3 low row tubes were preventatively plugged due to potentially high residual stress. The 3 outside diameter stress corrosion cracking indications were axially oriented and located at tube support plate elevations in high row tubes.

4. The primary water stress corrosion cracking indications were near the tube end (bottom 1-inch of tubing) and exceeded the iARC acceptance criteria.

5. One tube was plugged for 3 indications of axial outside diameter stress corrosion cracking at the hot-leg tube support plate elevations (nonoptimal tube processing).

6. Two tubes were plugged due to non-optimal tube processing. One tube was plugged for 3 indications of axial ODSCC (2 at hot-leg tube support plates, and 1 in the freespan).

Manufacturing 

Flaws

Inspection 

Issues

Other

SCC

Year

Wear

Loose Parts

Obstruction 

Restriction

Cause of Tube Plugging/Outage
3-224

Table 3-3: Braidwood 2: Tubes Plugged for Indications Other Than AVB Wear

STEAM GENERATOR A

Tube Location RFO # Characterization Stabilized

1-22 TEH+0.06 13 Primary water stress corrosion cracking (PWSCC)

(SCI) – near tube end

N

1-23 TEH+0.11 13 PWSCC (single circumferential indication (SCI)) – near tube end N

1-26 TEH+0.09 13 PWSCC (multiple circumferential indication (MCI)) – near tube end N

1-28 TEH+0.00 13 PWSCC (SCI) – near tube end N

1-44 TEH+0.00 13 PWSCC (SCI) – near tube end N

1-45 TEH+0.00 13 PWSCC (MCI) – near tube end N

1-46 TEH+0.00 13 PWSCC (MCI) – near tube end N

1-47 TEH+0.15 13 PWSCC (SCI) – near tube end N

1-74 TEH+0.07 13 PWSCC (MCI) – near tube end N

1-75 TEH+0.03 13 PWSCC (SCI) – near tube end N

1-79 TEH+0.06 13 PWSCC (SCI) – near tube end N

1-84 TEH+0.10 13 PWSCC (MCI) – near tube end N

1-87 TEH+0.09 13 PWSCC (MCI) – near tube end N

1-88 TEH+0.11 13 PWSCC (SCI) – near tube end N

1-89 TEH+0.16 13 PWSCC (MCI) – near tube end N

2-23 10 Preventative – nonoptimal tube processing N

2-96 10 Preventative – nonoptimal tube processing N

5-67 7H-0.03 16 PLP – 18% wall thinning (not periphery) Y

8-86 7H-0.74 15 PLP – 10% wall thinning (not periphery) Y

10-50 7H 15 PLP – no wear (not periphery) Y

10-51 7H-0.96 15 PLP – 11% wall thinning (not periphery) Y

10-79 TEH+0.02 13 PWSCC (SCI) – near tube end N

11-50 7H-0.67 15 PLP – 16% wall thinning (not periphery) Y

11-51 7H-1.01 15 PLP – 31% wall thinning (not periphery) Y

12-70 5H-0.77 12 PLP - 16% wall thinning (not periphery) Y

13-18 16 Nonoptimal tube processing

13-108 5H-0.72 16 PLP – 16% wall thinning (not periphery) Y

25-42 3H+0.13 10 Outside diameter stress corrosion cracking (ODSCC) (Axial) –

nonoptimal tube processing

N

30-84 9H+0.82 15 PLP – 39% wall thinning (not periphery) Y

30-85 9H 15 PLP – no wear (not periphery) Y

31-53 1H 5 Volumetric

31-84 9H 15 PLP – no wear (not periphery) Y

31-85 9H 15 PLP – no wear (not periphery) Y

43-22 2C+1.01 10 Confirmed loose part (CLP) - 38% wall thinning Y

43-23 2C+1.05 10 PLP Y

44-23 2C+0.87 10 PLP Y
3-225

Table 3-3: Braidwood 2: Tubes Plugged for Indications Other Than AVB Wear (cont’d)

STEAM GENERATOR B

Tube Location RFO # Characterization Stabilized

1-45 U-bend 8 Permeability

3-30 7H-0.75 16 PLP – 17% wall thinning (periphery) Y

6-8 5H-0.8 15 PLP – 21% wall thinning (not periphery) Y

7-22 7H-0.64 15 PLP – 20% wall thinning (not periphery) Y

8-39 7H-0.72 16 PLP – 39% wall thinning (not periphery) Y

13-38 7H-0.7 14 PLP – 18% wall thinning (not periphery) Y

15-7 7H-0.7 15 PLP – 16% wall thinning (periphery) Y

19-67 5H-0.78 14 PLP – 19% wall thinning (periphery) Y

21-65 5H-0.63 14 PLP – 34% wall thinning (periphery) Y

21-79 2C 10 CLP - Weld slag (not periphery) Y

21-80 2C 10 CLP - Weld slag (not periphery) Y

22-79 2C 10 CLP - Weld slag (not periphery) Y

22-80 2C 10 CLP - Weld slag (not periphery) Y

24-68 5H-0.79 15 PLP – 24% wall thinning (periphery) Y

29-95 5H-0.74 15 PLP – 22% wall thinning (not periphery) Y

30-56 7H-0.74 14 PLP – 15% wall thinning (periphery) Y

32-56 5H-0.7 15 PLP – 15% wall thinning (periphery) Y

43-22 2C 10 CLP (backing bar) or Preventative (tube near backing bar) Y

43-23 2C 10 CLP (backing bar) or Preventative (tube near backing bar) Y

43-92 2C 10 CLP (backing bar) or Preventative (tube near backing bar) Y

43-93 2C 10 CLP (backing bar) or Preventative (tube near backing bar) Y

44-23 2C 10 CLP (backing bar) or Preventative (tube near backing bar) Y

44-24 2C 10 CLP (backing bar) or Preventative (tube near backing bar) Y

44-88 2C 10 CLP (backing bar) or Preventative (tube near backing bar) Y

44-89 2C 10 CLP (backing bar) or Preventative (tube near backing bar) Y

44-90 2C 10 CLP (backing bar) or Preventative (tube near backing bar) Y

44-91 2C 10 CLP (backing bar) or Preventative (tube near backing bar) Y

44-92 2C 10 CLP (backing bar) or Preventative (tube near backing bar) Y

45-24 2C 10 CLP (backing bar) or Preventative (tube near backing bar) Y

45-25 2C 10 CLP (backing bar) or Preventative (tube near backing bar) Y

45-26 2C 10 CLP (backing bar) or Preventative (tube near backing bar) Y

45-88 2C 10 CLP (backing bar) or Preventative (tube near backing bar) Y

45-90 2C 10 CLP (backing bar) or Preventative (tube near backing bar) Y

45-91 2C+1.59 10 CLP - 5% wall thinning (backing bar) Y

46-26 2C 10 CLP (backing bar) or Preventative (tube near backing bar) Y

46-27 2C 10 CLP (backing bar) or Preventative (tube near backing bar) Y

46-88 2C 10 CLP (backing bar) or Preventative (tube near backing bar) Y
3-226

Table 3-3: Braidwood 2: Tubes Plugged for Indications Other Than AVB Wear (cont’d)

STEAM GENERATOR B

Tube Location RFO # Characterization Stabilized

46-89 2C 10 CLP (backing bar) or Preventative (tube near backing bar) Y

47-27 2C+0.98

2C+1.25

10 CLP - 28% and 21% wall thinning (backing bar) Y

47-28 2C 10 CLP (backing bar) or Preventative (tube near backing bar) Y

47-29 2C 10 CLP (backing bar) or Preventative (tube near backing bar) Y

47-30 2C 10 CLP (backing bar) or Preventative (tube near backing bar) Y

47-86 2C 10 CLP (backing bar) or Preventative (tube near backing bar) Y

47-87 2C 10 CLP (backing bar) or Preventative (tube near backing bar) Y

47-88 2C 10 CLP (backing bar) or Preventative (tube near backing bar) Y

48-29 2C 6 Volumetric (reclassified as CLP - 39% wall thinning (backing bar) in 

RFO 10)

48-30 2C 10 CLP (backing bar) or Preventative (tube near backing bar) Y

48-31 2C 10 CLP (backing bar) or Preventative (tube near backing bar) Y

48-84 2C 10 CLP (backing bar) or Preventative (tube near backing bar) Y

48-85 2C 10 CLP (backing bar) or Preventative (tube near backing bar) Y

48-86 2C 10 CLP (backing bar) or Preventative (tube near backing bar) Y

49-31 2C 10 CLP (backing bar) or Preventative (tube near backing bar) Y

49-61 7C-0.19 12 Preheater wear - 44% wall thinning Y

49-84 2C 10 CLP (backing bar) or Preventative (tube near backing bar) Y
3-227

Table 3-3: Braidwood 2: Tubes Plugged for Indications Other Than AVB Wear (cont’d)

STEAM GENERATOR C

Tube Location RFO # Characterization Stabilized

3-85 5C+2.98 13 PLP – 11% wall thinning (periphery) Y

6-68 10 Preventative – nonoptimal tube processing N

8-18 7H-0.81 12 PLP - 22% wall thinning (not periphery) Y

10-3 8H-0.98 14 PLP – 20% wall thinning (periphery) Y

21-50 3H+0.21

5H +0.36

10 ODSCC (Axial) – nonoptimal tube processing N

30-28 16 Nonoptimal tube processing

35-44 8H-0.76 11 PLP - 24% wall thinning (not periphery) Y

38-20 7H+0.02 10 ODSCC (Axial) – nonoptimal tube processing N

44-47 3H+0.3

5H-0.09

5H-1.88

16 ODSCC (Axial) - at tube support plate (TSP) and in freespan (FS)

(nonoptimal tube processing)

49-63 7C-0.22 12 Preheater wear - 46% wall thinning Y

49-65 7C-0.03 15 Preheater wear – 41% wall thinning Y

STEAM GENERATOR D

Tube Location RFO # Characterization Stabilized

1-11 U-bend 5 Single axial indication

2-35 3H-0.05

7H+0.33

9H+0.17

15 ODSCC (Axial) - at TSPs (nonoptimal tube processing)

7-61 8H-0.83 15 PLP - 40% wall thinning (not periphery) Y

13-20 7H-0.65 16 PLP - 22% wall thinning (not periphery) Y

13-76 5H-0.64 15 PLP - 38% wall thinning (not periphery) Y

17-72 9H-0.02 15 PLP - 20% wall thinning (not periphery) Y

21-110 4C+6.57 16 PLP - 22% wall thinning (periphery) Y

30-48 1H 5 Volumetric

36-60 TSH 5 Volumetric

43-72 8H 5 CLP (part could not be retrieved)

43-73 8H 5 CLP (part could not be retrieved)

43-86 7H-0.7 15 PLP - 21% wall thinning (periphery) Y

44-73 8H+0.57 15 PLP - 23% wall thinning (not periphery) Y

47-74 7H-0.61 15 PLP - 16% wall thinning (periphery) Y

47-75 7H-0.51 15 PLP - 28% wall thinning (periphery) Y

49-63 7C+0.14 15 Preheater wear – 38% wall thinning N
3-228

Table 3-4: Byron 2: Summary of Bobbin Inspections and Tube Plugging

Insp. Plug DePl Insp. Plug DePl Insp. Plug DePl Insp. Plug DePl

Pre-op 4 2 4 1 11 0 

RFO 1 01/01/1989 1.192 2278 2 2277 6 2279 3 2284 0 11 0 

RFO 2 09/01/1990 2.354 2270 1 2268 17 2272 1 2273 2 21 0 

RFO 3 03/01/1992 3.484 2252 9 2215 9 2235 5 2223 6 29 0 

RFO 4 10/02/1993 4.674 2259 6 2239 23 2260 7 2264 0 36 0 

RFO 5 03/01/1995 5.902 2398 9 2386 8 2456 7 2448 5 29 0 

RFO 6 09/01/1996 7.217 4539 11 4505 10 4543 6 4556 3 30 0 

RFO 7 05/05/1998 8.629 4528 7 4495 26 4537 5 4553 0 38 0 

RFO 8 11/04/1999 10.038 4521 1 4469 8 4532 3 4553 2 14 0 

RFO 9 04/13/2001 11.426 4461 4 4 0 

Mid-cycle 06/25/2002 12.583 11 3 3 0 

RFO 10 09/25/2002 12.823 4520 2 4457 0 4526 9 4551 3 14 0 

RFO 11 04/02/2004 14.285 4518 92 4457 0 4517 0 4548 0 92 0 

RFO 12 10/05/2005 15.738 4426 0 4457 10 4517 4 4548 3 17 0 

RFO 13 04/13/2007 17.191 4426 2 4447 4 4513 11 4545 0 17 0 

RFO 14 10/16/2008 18.578 4424 2 4443 5 4502 3 4545 3 13 0 

RFO 15 05/07/2010 20.052 4422 0 4438 1 4499 0 4542 0 1 0 

RFO 16 10/09/2011 21.397 4422 8 4437 6 4499 3 4542 11 28 0 

RFO 17 04/29/2013 0 0 

Totals: 156 0 139 0 74 0 39 0 408 0

Plant Data Acronyms

Model: D5 Pre-op = prior to operation

T-hot (approximate): 611 °F Cumul. = cumulative

Tubes per steam generator: 4570 Insp. = number of tubes inspected

Number of steam generators: 4 Plug = number of tubes plugged

DePl = number of tubes deplugged

RFO = refueling outage

Notes

1. All tubes in each steam generator were examined through the U-bend.

2. Forced outage due to leakage.

3. Only 1 tube was inspected full length. The other 10 tubes were only partially inspected (mainly in the preheater region) with either a bobbin and/or a rotating 

4. The U-bend region of the row 1 and 2 tubes were not inspected with a bobbin probe. The U-bend region of 25% of the row 1 and 2 tubes were inspected w

5. No steam generator tube inspections were performed.

Total 

Plug 

Outage

Completion 

Date

Cumul. 

EFPY

SG A SG B SG C SG D 

Total 

DePl
3-229

Table 3-5: Byron 2: Causes of Tube Plugging

1989 1990 1992 1993 1995 1996 1998 1999 2001 2002 2002 2004 2005 2007 2008 2010 2011 20

Pre-Op RFO 1 RFO 2 RFO 3 RFO 4 RFO 5 RFO 6 RFO 7 RFO 8 RFO 9 Mid-cycle RFO 10 RFO 11 RFO 12 RFO 13 RFO 14 RFO 15 RFO 16 RFO 

AVB 2 19 25 33 21 19 1 9 2 1 1 3 1 1 

Preheater TSP (D5) 1 1 6 3 7 

TSP 

Confirmed 4 1 4 3 1 3 11 91 3 1 

Not confirmed, 

periphery 1 1 1 7 1 3 2 7 13 4 9 

Not confirmed, not 

periphery 1 1 9 

From PSI, no 

progression 

Service-induced 

Preservice 11 

Other 29 3 1 1 1 

Probe lodged 

Data quality 1 

Dent/geometry 1 1 1 

Permeability 

Not inspected 

Top of tubesheet 2 

Freespan 1 3 4 1 

TSP 1 2 2 3 1 

Other/not reported 

ID 

OD 

TOTALS 11 11 21 29 36 29 30 38 14 4 3 14 92 17 17 13 1 28 

Notes: 1,2,3 4 5 6 7 8 9 10 11 12 13 14

Notes

1. Data quality: Signal-to-noise indication indicative of SCC in U-bend of row 1 tube.

2. Dent/Geometry: Large dent in U-bend of row 1 tube from PSI.

3. Loose Parts: Loose part in B at TSH in R49C55 and R49C56 was confirmed (see RFO 5 report), Part in C at 8H in R49C54 and R49C55 confirmed during RFO 5. Suspect part in C at 5H in R38C56 (see RFO 5 report).

4. Loose Part: Loose part in C at 5H R39C56, stabilized in RFO 5.

5. Loose Parts: Confirmed presence with magnet in B at R12C4, R12C5, R13C4, R13C5, R14C5. Suspect part in C at 5H in R40C56 and R41C56. All 7 plugged.

6. Leaker outage. Stabilized A-R16C110 in CL.

7. Three tubes pulled with circumferential indications at top of tubesheet indicated 29 circumferential indications were manufacturing related indications rather than service-induced degradation.. All 29 were stabilized.

8. Three tubes with PLPs were stabilized: B-R15C5, R15C6, R14C6. Stabilized tube with pre-heater wear B-R49C51.

9. Stabilized tubes with PLPs in B-R14C7 and B-R15C7. Plugged tube with confirmed loose part since part was removed in B-R20C56.

10. Ninety one tubes were stabilized and plugged as a result of wear (1 tube) or the potential for continued degradation of the waterbox cap plate region (90 tubes).

11. 2 tubes were preventatively plugged due to large bulges. 1 tube was preventatively plugged since the tube was not hydraulically expanded in the tubesheet.

12. One tube was preventatively plugged due to a large bulge.

13. One tube was preventatively plugged since it had an oversized tubesheet bore hole larger than analyzed in the tubesheet repair criteria analysis.

14. One tube was preventatively plugged since it had a manufacturing geometric indication

Year

Wear

Loose Parts

Obstruction 

Restriction

Cause of Tube Plugging/Outage

Manufacturing 

Flaws

Inspection 

Issues

Other

SCC
3-230

Table 3-6: Byron 2: Tubes Plugged for Indications Other Than AVB Wear

STEAM GENERATOR A

Tube Location RFO # Characterization Stabilized

11 PLP1 Y

1-87 U-bend 1 Large dent

1-110 U-bend 1 Signal to noise indication indicative of PWSCC

15-109 TSC 6 CLP (part removed)

15-110 TSC 6 CLP (part removed)

15-111 TSC 6 CLP (part removed)

16-110 TSC 6 CLP (part removed) - leaker Y (cold)

30-11 5C 16 PLP – surround a PLP

30-12 5C 16 PLP – surround a PLP

30-13 5C 16 PLP – surround a PLP

31-11 5C 16 PLP – surround a PLP

31-12 5C+0.53 16 PLP – 38% wall thinning (periphery) Y

32-12 5C 16 PLP – surround a PLP

32-13 5C 16 PLP – surround a PLP

34-47 14 Preventative – oversized tubesheet bore hole N

36-43 16 PLP – loose part present, but no wear

44-67 2C 7 Outside diameter (OD) initiated volumetric

46-67 Freespan (FS)

(2C)

6 Scale/deposits

47-66 FS (2C) 6 Scale/deposits

48-74 FS (2C) 6 Scale/deposits

49-50 2C+0.76 11 CLP (part retrieved) - 57% wall thinning (waterbox cap plate, backing 

bar)

Y

49-74 FS (2C) 6 Scale/deposits

1. Ninety tubes were preventatively stabilized and plugged during RFO 11 because of the possibility of backing bars becoming loose in the 

steam generator waterbox.
3-231

Table 3-6: Byron 2: Tubes Plugged for Indications Other Than AVB Wear (cont’d)

STEAM GENERATOR B

Tube Location RFO # Characterization Stabilized

1-2 U-bend 6 Geometry change

2-57 U-bend 7 Geometry change

6-7 5H+0.68 14 PLP – preventative Y

6-8 5H+0.61 14 PLP – preventative Y

7-7 5H+0.67 15 PLP – 28% wall thinning Y

7-8 5H+0.78 14 PLP – 15% wall thinning (location could not be accessed) Y

9-5 5H+0.75 12 PLP - 10% wall thinning (location could not be accessed) Y

9-6 5H+0.76 12 PLP - 13% wall thinning (location could not be accessed) Y

10-5 5H+0.70 12 PLP - 10% wall thinning (location could not be accessed) Y

10-6 5H+0.69 12 PLP - 33% wall thinning (location could not be accessed) Y

12-4 5H 5 Possible loose part (PLP) (orientation by magnet) Y

12-5 5H 5 PLP (orientation by magnet) Y

13-4 5H 5 PLP (orientation by magnet) Y

13-5 5H 5 PLP (orientation by magnet) Y

14-5 5H 5 PLP (orientation by magnet) Y

14-6 5H 8 PLP Y

14-7 5H 9 PLP Y

15-5 5H 8 PLP Y

15-6 5H 8 PLP Y

15-7 5H 9 PLP Y

20-56 2C 9 CLP (removed in RFO 5) N

20-57 2C 6 OD volumetric (CLP removed in RFO 5)

20-90 TSC+3.00 12 Bulge Y

21-55 2C 7 CLP removed in RFO 5

25-7 TSH 1 Mechanism not reported

25-11 7H+0.68 13 PLP – 19% wall thinning (location could not be accessed) Y

25-20 7H-0.63 14 PLP – 38% wall thinning (location could not be accessed) Y

26-10 7H+0.58 12 PLP - 22% wall thinning (location could not be accessed) Y

26-11 7H+0.62 12 PLP - 12% wall thinning (location could not be accessed) Y

27-8 TSH 1 Mechanism not reported

27-11 7H+0.76 13 PLP – 12% wall thinning (location could not be accessed) Y

28-25 1H 7 CLP (removed - outage not specified)

28-26 1H 4 Volumetric

37-67 FS (2C) 9 OD volumetric

37-95 TSH+0.08 13 Bulge Y
3-232

Table 3-6: Byron 2: Tubes Plugged for Indications Other Than AVB Wear (cont’d)

STEAM GENERATOR B

Tube Location RFO # Characterization Stabilized

47-76 2C 8 OD volumetric

48-50 7C+0.08 16 Preheater wear – 40% wall thinning Y

48-53 7C+0.36 16 Preheater wear – 29% wall thinning Y

48-54 7C+0.58 16 Preheater wear – 32% wall thinning Y

48-55 7C-0.03 14 Preheater wear – 45% wall thinning Y

48-59 7C-0.03 16 Preheater wear – 33% wall thinning Y

49-50 7C-0.08 12 Preheater wear – 43% wall thinning Y

49-51 7C 8 Preheater wear Y

49-52 7C+0.47 16 Preheater wear – 33% wall thinning Y

49-53 7C+0.11 12 Preheater wear – 44% wall thinning Y

49-54 TSH 5 CLP (removed in RFO 1)

49-55 TSH 1 Not reported (CLP in RFO 5, part removed in RFO 1)

49-56 TSH 1 PLP (CLP in RFO 5, part removed in RFO 1)

49-63 7C+0.14 16 Preheater wear – 36% wall thinning Y
3-233

Table 3-6: Byron 2: Tubes Plugged for Indications Other Than AVB Wear (cont’d)

STEAM GENERATOR C

Tube Location RFO # Characterization Stabilized

2-19 16 Preventative – manufacturing geometric indication

3-47 8H-0.83 16 PLP – 30% wall thinning (periphery) Y

9-39 FS (10C)

FS (10H)

3 ODI

17-25 1H+0.42 10 CLP (part removed) - 22% wall thinning N

18-25 1H 7 OD volumetric

19-27 1H 7 OD volumetric

21-29 1H 4 Volumetric 

22-29 1H 6 OD volumetric

22-30 1H+0.42 10 CLP (part removed) - 4% wall thinning N

23-30 1H+0.46 10 CLP (part removed) - 30% wall thinning N

23-31 1H+0.41 10 CLP (part removed) - 11% wall thinning N

24-33 1H+0.41 10 CLP (part removed) - 3% wall thinning N

25-15 TEC+11.66 12 Bulge N

25-33 1H+0.47 10 CLP (part removed) - 15% wall thinning N

32-65 13 Preventative – surround non-stabilized tubes near a PLP Y

32-66 8H 13 Preventative – surround non-stabilized tubes near a PLP Y

32-67 8H 13 Preventative – surround non-stabilized tubes near a PLP Y

33-63 8H 14 Preventative – CLP in vicinity Y

33-64 8H+0.77 13 PLP Y

33-65 8H+0.69 13 PLP – 27% TW indication Y

33-66 8H 2 Pit (Reclassified as wear because of a loose part in RFO 13) N

33-67 8H 13 Preventative – surround non-stabilized tubes near a PLP Y

34-59 TSH+0.12 10 CLP (part removed) - 8% wall thinning N

34-63 8H 14 Preventative – CLP in vicinity Y

34-64 8H 14 Preventative – CLP in vicinity Y

34-65 8H+0.72 13 PLP Y

34-66 8H 7 OD volumetric (Reclassified as wear because of a loose part in RFO 

13)

N

34-67 8H 13 Preventative – surround non-stabilized tubes near a PLP Y

35-65 8H 13 Preventative – surround non-stabilized tubes near a PLP Y

35-66 8H 13 Preventative – surround non-stabilized tubes near a PLP Y

35-67 8H 13 Preventative – surround non-stabilized tubes near a PLP Y

38-56 5H 1 Narrow circumferential indication (PLP in RFO 5) Y RFO 5

39-56 5H 4 PLP Y RFO 5

40-56 5H 5 PLP Y
3-234

Table 3-6: Byron 2: Tubes Plugged for Indications Other Than AVB Wear (cont’d)

STEAM GENERATOR C

Tube Location RFO # Characterization Stabilized

41-56 5H 5 PLP Y

43-22 2C+0.49 Midcycle 

(2002)

CLP (part removed in RFO 10) - 37% wall thinning Y

43-23 2C+0.53 Midcycle 

(2002)

CLP (part removed in RFO 10) - leaking tube Y

43-24 2C+0.46

2C+0.85

Midcycle 

(2002)

CLP (part removed in RFO 10) - 11% and 13% wall thinning Y

48-36 2C+0.5 10 Preheater wear- 17% wall thinning N

49-34 2C+0.41 10 CLP (part removed) - 24% wall thinning N

49-48 7C-0.52 12 Preheater wear - 39% wall thinning Y

49-53 8H 7 CLP (part removed in RFO 5)

49-54 8H 1 Narrow circ (CLP removed in RFO 5)

49-55 8H 1 Narrow circ (CLP removed in RFO 5)

49-62 7C-0.08 12 Preheater wear - 49% wall thinning Y

49-63 7C-0.22 12 Preheater wear - 49% wall thinning Y

49-70 7C+0.0 16 Preheater wear – 36% wall thinning Y
3-235

Table 3-6: Byron 2: Tubes Plugged for Indications Other Than AVB Wear (cont’d)

STEAM GENERATOR D

Tube Location RFO # Characterization Stabilized

1-55 6C+0.26 12 PLP - 26% wall thinning (location could not be accessed) Y

13-84 7H 16 PLP – surround a PLP

13-85 7H 16 PLP – surround a PLP

13-86 7H 16 PLP – surround a PLP

14-84 7H 16 PLP – surround a PLP

14-85 7H-0.68 16 PLP – 11% wall thinning (not periphery) Y

14-86 7H 16 PLP – surround a PLP

15-48 12 Tube not hydraulically expanded in tubesheet on hot-leg side N

15-84 7H 16 PLP – surround a PLP

15-85 7H 16 PLP – surround a PLP

15-86 7H 16 PLP – surround a PLP

20-34 FS (6C)

FS (9C)

3 Outside diameter indication (ODI) -manufacturing burnishing mark 

(MBM)

22-37 10H 3 ODI – MBM

24-69 5H-0.67 14 27% wall thinning (attributed to loose part, but no loose part present, 

location could not be accessed)

Y

35-99 2C+0.48 10 CLP (part removed) - 32% wall thinning N

36-59 10H-1.17 16 PLP – 20% wall thinning (periphery) Y

36-99 2C+0.41 10 CLP (part removed) - 14% wall thinning N

37-17 FS (9H)

FS (11H)

3 ODI

37-99 2C+1.09 10 CLP (part removed) - 19% wall thinning N

44-74 FS (5H)

FS (9H)

2 ODI

49-52 7C+0.43 12 Preheater wear - 39% wall thinning Y

49-67 7C+0.05

8C+0.05

14 Preheater wear – 41% and 26% wall thinning Y

49-69 7C+0.41 14 Preheater wear – 41% wall thinning Y
3-236

Table 3-7: Catawba 2: Summary of Bobbin Inspections and Tube Plugging

Insp. Plug DePl Insp. Plug DePl Insp. Plug DePl Insp. Plug DePl

Pre-op 1 7 1 5 14 0 

Mid-Cycle 08/26/1987 0 0 0 0 

RFO 1 02/12/1988 0.92 1133 4 546 1 515 0 1215 2 7 0 

RFO 2 04/01/1989 1.7 1456 2 1519 5 1443 1 1542 0 8 0 

RFO 3 07/01/1990 2.6 3274 9 3230 1 3243 2 3265 7 19 0 

RFO 4 11/20/1991 3.55 4554 7 4556 0 4566 4 4556 1 12 0 

RFO 5 03/01/1993 4.57 4547 14 4556 6 4562 13 4555 10 43 0 

RFO 6 06/01/1994 5.61 4533 6 4550 11 4549 5 4545 9 31 0 

RFO 7 11/01/1995 6.78 2569 10 2476 2 2419 5 2596 6 23 0 

RFO 8 04/01/1997 7.98 2624 1 2520 5 2447 0 2628 4 10 0 

RFO 9 09/01/1998 9.29 2501 1 2317 5 2273 1 2485 2 9 0 

RFO 10 03/01/2000 10.52 4303 0 4401 4 4313 2 4309 1 7 0 

RFO 11 10/15/2001 11.92 2210 0 1890 0 1807 0 2071 0 0 0 

RFO 12 03/26/2003 13.23 2518 3 2356 3 2283 6 2730 21 33 0 

RFO 13 10/24/2004 14.68 2614 2 2594 32 2492 5 2606 9 48 0 

RFO 14 04/23/2006 16.06 2508 1 2499 9 2376 2 2601 2 14 0 

RFO 15 11/14/2007 17.43 2706 0 2618 8 2569 0 2767 0 8 0 

RFO 16 04/18/2009 18.73 4509 0 4471 7 4523 1 4491 2 10 0 

RFO 17 10/20/2010 20.13 4509 0 4464 0 4522 1 4489 0 1 0 

RFO 18 04/17/2012 21.5 4509 0 4464 0 4521 4 4489 1 5 0 

RFO 19 10/17/2013 22.89 4509 0 4464 3 4517 4 4488 0 7 0 

Totals: 61 0 109 0 57 0 82 0 309

Plant Data Acronyms

Model: D5 Pre-op = prior to operation

T-hot (approximate): 615 °F Cumul. = cumulative

Tubes per steam generator: 4570 Insp. = number of tubes inspected

Number of steam generators: 4 Plug = number of tubes plugged

DePl = number of tubes deplugged

RFO = refueling outage

Notes

1. Assumed based on other information.

2. Licensee elected to inspect 2 of the steam generators during an unplanned maintenance outage to limit the inspections during the subsequent refueling outa

3. The U-bend region of the row 1 through 5 tubes was not inspected with a bobbin probe. The U-bend region of 35% of the row 1 through 5 tubes was inspec

4. The U-bend region of the row 1 through 5 tubes was not inspected with a bobbin probe. The U-bend region of 100% of the row 1 tubes, 35% of the row 2 th

 and 20% of the row 10 tubes was inspected with a rotating probe.

Total 

DePl

Total 

Plug Outage

Completion 

Date

Cumul. 

EFPY

SG A SG B SG C SG D 
3-237

Table 3-8: Catawba 2: Causes of Tube Plugging

1988 1989 1990 1991 1993 1994 1995 1997 1998 2000 2001 2003 2004 2006 2007 2009 2010 2012 

Cause of Tube Plugging/Outage Pre-Op RFO 1 RFO 2 RFO 3 RFO 4 RFO 5 RFO 6 RFO 7 RFO 8 RFO 9 RFO 10 RFO 11 RFO 12 RFO 13 RFO 14 RFO 15 RFO 16 RFO 17 RFO 18 RFO 

AVB 14 6 2 1 1 2 1 1 1 

Preheater TSP (D5) 1 6 

TSP 2 1 

Confirmed 2 18 9 

Not confirmed, 

periphery 6 5 4 

Not confirmed, not 

periphery 2 7 1 

From PSI, no 

progression 

Service-induced 

Preservice 14 

Other 1 4 1 

Probe lodged 2 

Data quality 1 17 

Dent/geometry 1 1 

Permeability 2 1 2 1 

Not inspected 1 2 

Top of tubesheet 3 4 2 3 2 

Freespan 3 4 1 30 20 10 1 

TSP 2 3 3 5 6 6 5 1 

Other/not reported 1 2 2 5 1 

ID 16 6 

OD 8 3 

TOTALS 14 7 8 19 12 43 31 23 10 9 7 0 33 48 14 8 10 1 5 

Notes: 1 2 3 4 5 6

Notes

1. Since no tubes were plugged during the 1987 mid-cycle outage, reference is just made to RFO 1 in this table.

2. Fifteen tubes were preventatively plugged due to a dent and manufacturing burnishing mark at the same location (data quality). Two tubes were plugged for lift off at the U-bend tangent.

 One low row tube was plugged for an eddy current offset. No information was provided on whether loose parts were visually identified.

3. One tube was plugged due to potential damage from a stabilizer installation error.

4. Three tubes were plugged since they were expanded significantly above the top of the tubesheet. One tube was plugged for not being expanded into the tubesheet. One tube was plugged for a geometry indication.

5. Axial indications in hot leg at top of tubesheet in sludge pile.

6. Six tubes plugged for ID indications near the tube end, three tubes were plugged for OD indications at the HL TSPs, and one tube was plugged for a bulge at the top of the tubesheet.

Other

SCC

Year

Wear

Loose Parts

Obstruction 

Restriction

Manufacturing 

Flaws

Inspection 

Issues
3-238

Table 3-9: Catawba 2: Tubes Plugged for Indications Other Than AVB Wear

STEAM GENERATOR A

Tube Location RFO # Characterization Stabilized

1-5 FS(12)

4+.9

7 ODI, Volumetric

1-6 4+.8 7 ODI, Volumetric

1-7 4+.6 7 ODI, Volumetric

1-100 8H+9.41 12 Data Quality—Probe liftoff in U-bend region

1-106 8H+9.07 12 Data Quality—Probe liftoff in U-bend region

3-9 FS(12,13,15-

19)

15+1.5

16-1.0

TSC

19+1.5

7 Absolute drift indication (ADI), non-quantifiable indication (NQI), 

Volumetric, ODI

7-12 ? 5 ?

8-107 FS(7,8,10) 6 NQI, ODI, Volumetric

15-50 FS(10) 8 Bobbin indication greater than 40 percent throughwall, no degradation 

found (NDF) with rotating probe

15-77 FS(2,5) 1 ODI, location not indicative of PLP

16-72 TSH 6 Inside diameter indication

17-82 TSC 14 Preventative—over-rolled tube at top of tubesheet Y

19-102 ? 7 ?

21-105 FS(10) 5 ODI, Volumetric

24-67 3 1 ODI, location not indicative of PLP

24-68 3 2 OD

24-69 3 2 OD

24-104 FS(10) 5 ODI, NQI

24-108 FS(7,8)

8-1.4

6 NQI, ODI, Volumetric

25-19 FS(3,5,6,7,9,10

)

7 NQI, Volumetric, ODI

25-86 ? 7 ?

25-100 FS(4,11,17) 5 ODI, Volumetric, NQI

28-102 FS (3, 7) 5 ODI, Volumetric, NQI

29-24 FS(7) 6 NQI, ODI

29-70 FS (2) 5 ODI, Volumetric

29-96 FS (10) 5 ODI, Volumetric

34-18 2H+34.35 (DNT)

2H+33.92 (VOL)

12 Data Quality—Overlapping dent and manufacturing burnish mark

34-91 ? 7 ?

39-41 TSH+0.10 13 PLP Y

40-41 TSH+0.09 13 PLP Y
3-239

Table 3-9: Catawba 2: Tubes Plugged for Indications Other Than AVB Wear (cont’d)

STEAM GENERATOR A

Tube Location RFO # Characterization Stabilized

40-72 TSH 6 NQI

43-68 FS(10) 9 Permeability

44-49 FS (5,6,7,10) 7 NQI, ODI, Volumetric

48-43 18+.4 5 ODI, preheater

48-44 18+.5 5 ODI, preheater

49-38 7+/-.1 3 OD

49-39 7 1 ODI, Location not indicative of PLP

49-40 7+.1 3 OD

49-41 7+.65 5 ODI, NQI

49-42 7+.6 4 OD

49-44 18+.8 5 ODI, preheater

49-54 FS (12) 1 ODI, Location not indicative of PLP

49-64 7+.6 4 OD

49-65 7+.7 4 OD

49-66 7+.1 3 OD

49-68 18-.02 5 Multiple axial indication (MAI), Single axial indication (SAI), preheater

49-77 18+.03 5 MAI, preheater
3-240

Table 3-9: Catawba 2: Tubes Plugged for Indications Other Than AVB Wear (cont’d)

STEAM GENERATOR B

Tube Location RFO # Characterization Stabilized

1-22 TEH+0.11

TEH+0.24

13 SCC (SAI and SCI)—Tube End (originally classified as indication in weld 

extending into tube)

N

1-25 TEH 16 SCC (circumferential)

1-37 TEH 16 SCC (circumferential)

1-47 TEH+0.17 13 SCC (SAI)—Tube End (originally classified as indication in weld 

extending into tube)

N

1-55 TEH+0.12

TEH+0.22

13 SCC (MAI and MCI)—Tube End (originally classified as indication in 

weld extending into tube)

N

1-56 TEH 16 SCC (circumferential)

1-57 TEH 16 SCC (circumferential)

1-61 FS(9) 9 Dent signal change

1-63 TEH 16 SCC (circumferential)

2-52 TEH+0.80 13 SCC (SCI)—Tube End N

2-57 TEH +0.69 13 SCC (SCI)—Tube End N

2-63 TEH+0.18 13 SCC (SAI)—Tube End (originally classified as indication in weld 

extending into tube)

2-71 5H-0.83 13 PLP Y

2-99 U-bend 10 Plus-point lodged in U-bend

3-45 TEH+0.62 13 SCC (SCI)—Tube End N

3-52 TEH+0.64 13 SCC (SCI)—Tube End N

3-58 TEH+0.62 13 SCC (MCI)—Tube End N

4-52 TEH+0.70 13 SCC (MCI)—Tube End N

4-61 TSH-6.79 

TSH-7.30 

TSH-7.34

13 SCC (MCI)—Overexpansion in tubesheet N

5-12 TSH+0.02 13 PLP Y

6-12 TSH+0.01 13 PLP Y

7-71 TEH+0.44 13 SCC (SCI)—Tube End N 

8-27 TEH+0.21 13 SCC (SAI)—Tube End (originally classified as indication in weld 

extending into tube)

N 

8-31 FS (1, 16) 5 ODI, Volumetric

10-17 6H+15.19 (DNT)

6H+14.93 (VOL)

12 Data Quality—Overlapping dent and manufacturing burnish mark

13-64 TEH+0.16 13 SCC (SAI)—Tube End (originally classified as indication in weld 

extending into tube)

N 

15-27 1H+0.64 14 CLP Y

15-29 1H+0.51 14 CLP Y
3-241

Table 3-9: Catawba 2: Tubes Plugged for Indications Other Than AVB Wear (cont’d)

STEAM GENERATOR B

Tube Location RFO # Characterization Stabilized

15-45 TEH+0.14

TEH+0.72

13 SCC (SAI and MCI)—Tube End N

15-79 TSH+0.41 15 SCC (SAI)—OD initiated, top of tubesheet Y

16-27 1H+0.47

1H+0.59

14 CLP Y

16-28 1H+0.52 14 CLP Y

16-29 1H+.5 10 Wear, no size available—PLP

16-30 1H+0.54 14 CLP Y

16-31 1H+0.64 14 CLP Y

17-27 1H 14 CLP Y

17-28 TSH+0.32 15 SCC (SAI)—OD initiated, top of tubesheet Y

17-41 10C-0.67 13 PLP—41 percent wall thinning Y

17-90 14+1.4 2 OD

18-28 1H 14 CLP Y

18-41 10C-0.59 13 PLP—27 percent wall thinning Y

18-71 TSH+0.49 15 SCC (SAI)—OD initiated, top of tubesheet Y

19-29 TSH+0.07 15 SCC (SAI)—OD initiated, top of tubesheet Y

20-104 TSH 9 MBM/PLP wear

21-62 8-.3 2 OD

24-31 10C+10.40

12C+10.77

12 Permeability variation

24-44 TSH+0.12 15 SCC (SAI)—OD initiated, top of tubesheet Y

24-62 2H+0.39 16 SCC (SAI)—ODSCC at TSP (nonoptimal tube processing)

24-72 TSH+0.33 15 SCC (SAI)—OD initiated, top of tubesheet Y

25-38 TSH+0.24 15 SCC (SAI)—OD initiated, top of tubesheet Y

25-40 FS(18) 5 ODI

26-26 FS(3) 5 ODI, Volumetric

26-64 TSH+0.57 15 SCC (MAI)—OD initiated, top of tubesheet Y

26-81 TEH 16 SCC (circumferential)

27-23 4H+0.69 19 PLP—14 percent wall thinning (not periphery)

28-23 19 PLP

28-24 4H+1.27

4H+1.78

19 PLP—27 percent and 6 percent wall thinning (not periphery)

28-106 TSH 5 ODI, Volumetric

29-23 FS(9,11) 5 ODI, Volumetric

29-87 FS(7) 6 ODI, Volumetric
3-242

Table 3-9: Catawba 2: Tubes Plugged for Indications Other Than AVB Wear (cont’d)

STEAM GENERATOR B

Tube Location RFO # Characterization Stabilized

29-105 TSH 8 MBM/PLP wear

30-12 TSC 14 Tube not hydraulically expanded in tubesheet on cold-leg side N

30-90 FS(4) 6 ODI, Volumetric

31-89 17-.1

17+2.2

2 OD

32-44 1H+0.33 13 CLP—42 percent wall thinning Y

33-42 1H+0.26 13 CLP—10 percent wall thinning Y

33-43 1H+0.30 13 CLP—54 percent wall thinning Y

33-44 1H+0.30 13 CLP—47 percent wall thinning Y

33-68 8+1.63 6 ODI

33-74 8+1.52 6 ODI

33-78 8+1.41 6 ODI

34-42 1H+.5 10 Wear, no size available—PLP

34-43 1H+0.31 13 CLP—30 percent wall thinning Y

34-44 1H+0.28 13 CLP—12 percent wall thinning Y

35-38 FS(11) 7 ODI, Volumetric

35-41 1H+.5 9 MBM/PLP wear

35-42 1H+0.38 13 CLP—1 percent wall thinning Y

36-36 FS(10) 5 ODI

36-53 TEH+0.63 13 SCC (SCI)—Tube End N

36-56 TSH 7 NQI, Volumetric, Pit

37-35 FS(10) 6 ODI, NQI

38-69 11C+10.63 

(DNT)

11C+29.01 

(VOL)

12 Data Quality—Overlapping dent and manufacturing burnish mark

38-82 FS(2,3)

AVB

6 NQI, ODI, Volumetric, Wear

39-85 FS(10,11,17) 8 Lack of rotating probe data

39-97 U-bend 8 Permeability

40-19 TSH 8 MBM/PLP wear

40-64 1+0.56 6 ODI, Volumetric

41-20 TSH 1 CLP (removed)

41-64 1+0.57 6 ODI, Volumetric

42-45 18C+0.49 13 CLP—31 percent wall thinning Y

42-46 18C+0.53 13 CLP—17 percent wall thinning Y

43-22 TSH 8 MBM/PLP wear
3-243

Table 3-9: Catawba 2: Tubes Plugged for Indications Other Than AVB Wear (cont’d)

STEAM GENERATOR B

Tube Location RFO # Characterization Stabilized

43-91 18C+0.57 13 CLP—20 percent wall thinning N

43-92 18C+0.45 13 CLP—34 percent wall thinning N

45-37 19+0.43 6 ODI, Volumetric

46-54 1H+.5 9 Wear, no size available

47-80 FS(8) 6 ODI

48-39 17C+.15 9 Wear, no size available

48-67 18+1.7 2 OD

49-67 18+1.3

18+2.5

2 OD
3-244

Table 3-9: Catawba 2: Tubes Plugged for Indications Other Than AVB Wear (cont’d)

STEAM GENERATOR C

Tube Location RFO # Characterization Stabilized

1-5 ? 2 ?

1-22 U-bend 10 No plus-point exam in U-bend

2-30 U-bend 10 Probe lodged in U-bend

4-77 12 Preventative—High residual stress

7-109 4H-0.75 14 CLP Y

9-35 TSH 6 SAI

11-93 TSC 14 Preventative—over-rolled tube at top of tubesheet Y

13-15 10-1.7 7 ODI, Volumetric

15-90 TSH+0.13 13 PLP Y

16-90 TSH+0.14 13 PLP Y

18-45 TSH 7 ODI, Volumetric

18-85 TSH+3.39 (DNT)

TSH+3.37 (VOL)

12 Data Quality—Overlapping dent and manufacturing burnish mark

19-85 ? 7 ?

20-109 ? 7 ?

22-74 4H+3.71 (DNT)

4H+3.71 (VOL)

12 Data Quality—Overlapping dent and manufacturing burnish mark

23-37 18C+9.26 (DNT)

18C+9.23 (VOL)

12 Data Quality—Overlapping dent and manufacturing burnish mark

24-12 13 Potential damage from stabilizer installation error in nearby tube N

24-53 18C+9.61 (DNT)

18C+9.66 (VOL)

12 Data Quality—Overlapping dent and manufacturing burnish mark

25-11 18C+0.45 13 CLP—16 percent wall thinning Y

26-11 18C+0.60 13 CLP—10 percent wall thinning Y

27-16 FS(1) 5 ODI, Volumetric

28-72 10C+37.24 

(DNT)

10C+37.51 

(VOL)

12 Data Quality—Overlapping dent and manufacturing burnish mark

31-77 TSH 5 SAI

32-79 9-1.34 7 ODI, Volumetric

33-24 FS(4,10,12)

9-0.86

9-2.96

6 ODI, Volumetric

39-20 FS(9,12,13,15) 6 NQI, ODI, Volumetric

39-41 TSH+0.78 16 Bulge

39-47 FS(11,13) 6 NQI, Volumetric

39-67 FS(9,10,11,13)

9+1.47

5 NQI, ODI, Volumetric
3-245

Table 3-9: Catawba 2: Tubes Plugged for Indications Other Than AVB Wear (cont’d)

STEAM GENERATOR C

Tube Location RFO # Characterization Stabilized

39-71 8+1.4

FS(12)

5 ODI, Volumetric, Absolute drift signal (ADS)

39-75 U-bend

FS(12)

5 ODI, NQI

39-87 FS(1)

18+.4

4 OD

41-65 16+.9

16+1.4

FS(8,10,18)

5 NQI, ODI, Volumetric

42-61 FS(6)

9+1.6

5 ODI

42-92 18+.8

18+2.4

5 ODI, Volumetric

42-93 ? 5 ?

43-34 U-bend

FS(2,5,13)

5 ODI, ADS

43-91 FS(10) 5 ODI

45-78 19 PLP (periphery)

45-79 15C+0.46 19 PLP—42 percent wall thinning (periphery)

46-59 FS(1,13) 5 ODI, Volumetric

46-78 15C+0.71 19 PLP—4 percent wall thinning (periphery)

46-79 15C+0.79 18 PLP—31 percent wall thinning

46-80 18 PLP

46-87 FS(10) 6 ODI

47-78 15C+0.65 19 PLP—10 percent wall thinning (periphery)

47-79 18 PLP—downstream of PLP

47-80 18 PLP—downstream of PLP

49-59 13C+0.76 17 TSP wear—39 percent wall thinning

49-61 5+.7 4 OD

49-62 5+.7 4 OD
3-246

Table 3-9: Catawba 2: Tubes Plugged for Indications Other Than AVB Wear (cont’d)

STEAM GENERATOR D

Tube Location RFO # Characterization Stabilized

1-5 16C+0.28 12 PLP—53 percent wall thinning

1-6 16C+0.62 12 PLP

1-57 TSH 14 Preventative—tube expansion geometry indication at top of tubesheet Y

2-1 FS(14) 7 ODI, Volumetric

2-46 FS(16) 5 NQI, Volumetric

4-13 8H+1.81 (DNT)

8H+1.87 (VOL)

12 Data Quality—Overlapping dent and manufacturing burnish mark 

4-43 FS(3,15) 6 Absolute drift indication (ADI), ODI, Volumetric

4-94 1H+1.70 (DNT)

1H+2.23 (VOL)

12 Data Quality—Overlapping dent and manufacturing burnish mark 

4-113 14C+2.4 (DNT)

14C+2.4 (VOL)

12 Data Quality—Overlapping dent and manufacturing burnish mark 

6-19 FS(8,10) 7 NQI, Volumetric

6-81 FS(12) 8 Data Quality

7-26 FS(7,10,12,13,1

4)

7 NQI, ODI, Volumetric

9-2 9+1.1

FS(7,10)

5 NQI, ODI

13-35 TSH+0.02 13 PLP Y

14-4 FS(7,10) 5 ADS, ODI

15-29 FS(12) 7 ADI, Volumetric

15-108 TSH 6 NQI

16-54 1H+0.52 12 PLP

16-62 8-1.1

FS(7,10)

6 ADI, ODI, Volumetric

17-53 1H+0.41 12 PLP

17-54 1H+0.49 12 PLP—35 percent wall thinning

17-103 FS(1,4,13) 5 NQI, ODI, Volumetric

18-52 1H+0.34 12 PLP

19-65 TSH 10 No rotating probe exam at TTS

20-40 FS(12) 7 ODI, Volumetric

20-46 FS(12) 7 ODI, Volumetric

20-89 FS(18) 5 ODI

21-107 FS(18) 5 ODI, Volumetric

21-110 FS(18) 6 ODI, Volumetric

23-71 12C+25.90

12C+26.06

12 Permeability Variation
3-247

Table 3-9: Catawba 2: Tubes Plugged for Indications Other Than AVB Wear (cont’d)

STEAM GENERATOR D

Tube Location RFO # Characterization Stabilized

24-104 11C+2.00 (DNT)

11C+2.00 (VOL)

12 Data Quality—Overlapping dent and manufacturing burnish mark 

25-43 FS(11,12,13,16

)

5 ADS, NQI, Volumetric

25-44 FS(7,10) 5 ODI

27-55 13C+7.36 13 Permeability Variation N

28-81 9-1.2

9-2.4

FS(10)

6 ODI, Volumetric

29-64 4H+1.24 18 PLP—21 percent wall thinning

29-96 ? 3 ?

30-59 9-0.6

FS(7)

6 ODI

33-16 7H+.3 9 Wear, no sizing

33-48 10+/-1.1

10+0.7

FS(10)

6 ODI, Volumetric

35-93 U-bend 8 Permeability in U-bend

38-72 16C+11.85 

(DNT)

16C+11.85 

(VOL)

12 Data Quality—Overlapping dent and manufacturing burnish mark 

38-77 1H+16.30 (NQI)

1H+16.30 (VOL)

12 Data Quality—Overlapping dent and manufacturing burnish mark 

40-67 FS(8,10) 6 ODI, Volumetric

41-43 U-bend

FS(9,11)

6 NQI, ODI, Volumetric

41-55 3H, 4H, 5H 16 SCC—axial ODSCC at TSP (nonoptimal tube processing)

41-59 3H, 5H 16 SCC—axial ODSCC at TSP (nonoptimal tube processing)

41-60 TSC 14 Preventative—over-rolled tube at top of tubesheet Y

41-69 2H+16.91 (DNT)

2H+16.91 (VOL)

12 Data Quality—Overlapping dent and manufacturing burnish mark 

42-24 FS(10) 5 ODI, Volumetric

43-50 18C+0.50 13 CLP—18 percent wall thinning N

43-62 FS(3) 1 ODI, Location not indicative of PLP

47-30 TSH+0.11 13 PLP Y

48-47 13 CLP Y

48-48 13 CLP Y

48-51 13C+0.46 12 Preheater wear—no depth provided

48-55 13C+0.00 12 Preheater wear—42 percent wall thinning

48-60 13C+0.35 12 Preheater wear—33 percent wall thinning
3-248

Table 3-9: Catawba 2: Tubes Plugged for Indications Other Than AVB Wear (cont’d)

STEAM GENERATOR D

Tube Location RFO # Characterization Stabilized

48-75 TSH 9 MBM, PLP wear

48-86 TSH+0.29

TSH+0.39

13 PLP Y

49-34 ? 3 ?

49-47 13 CLP Y

49-48 13 CLP Y

49-52 13C+0.00 12 Preheater wear—50 percent wall thinning

49-53 13C+0.00

13C+0.31

12 Preheater wear—51 percent wall thinning

49-56 13C+0.34 12 Preheater wear—43 percent wall thinning

49-63 TSH 5 SAI

49-64 TSH 1 CLP (Loose part washed away)
3-249

Table 3-10: Comanche Peak 2: Summary of Bobbin Inspections and Tube Plugging

Insp. Plug DePl Insp. Plug DePl Insp. Plug DePl Insp. Plug DePl

Pre-op 0 5 3 3 9 20 0 

RFO 1 11/01/1994 0.9096 1104 0 1078 0 1062 0 1125 0 0 0 

RFO 2 03/15/1996 2.0901 2149 0 2161 0 0 0 

RFO 3 11/14/1997 3.4894 3867 3 4567 5 4567 0 2389 0 8 0 

RFO 4 04/09/1999 4.706 914 1 914 0 914 0 914 4 5 0 

RFO 5 10/09/2000 6.1375 1927 3 3609 1 4 0 

RFO 6 04/14/2002 7.5195 4562 4 4567 7 11 0 

RFO 7 10/24/2003 8.8247 3427 3 2513 1 4 0 

RFO 8 04/13/2005 10.2034 2605 5 2696 2 2742 4 3382 2 13 0 

RFO 9 10/25/2006 11.639 0 0 

RFO 10 04/18/2008 13.044 2795 1 2708 7 2845 3 2842 2 13 0 

RFO 11 11/01/2009 14.502 0 0 

RFO 12 04/25/2011 15.906 3253 0 3108 2 3185 1 3297 0 3 0 

RFO 13 11/01/2012 17.33 0 0 

RFO 14 04/26/2014 18.709 1554 2 1554 10 1554 0 1554 0 12 0 

Totals: 23 0 33 0 18 0 19 0 93 0

Plant Data Acronyms

Model: D5 Pre-op = prior to operation

T-hot (approximate): 618 °F Cumul. = cumulative

Tubes per steam generator: 4570 Insp. = number of tubes inspected

Number of steam generators: 4 Plug = number of tubes plugged

DePl = number of tubes deplugged

RFO = refueling outage

Notes

1. The U-bend region of the row 1 and row 2 tubes was not inspected with a bobbin probe. The U-bend region of 100% of the row 1 and 2 tubes was inspected 

2. The U-bend region of the row 1 and row 2 tubes was not inspected with a bobbin probe. The U-bend region of 50% of the row 1 and 2 tubes was inspected 

3. No steam generator tube inspections were performed.

Total 

Plug 

Outage

Completion 

Date

Cumul. 

EFPY

SG A SG B SG C SG D 

Total 

DePl
3-250

Table 3-11: Comanche Peak 2: Causes of Tube Plugging

1994 1996 1997 1999 2000 2002 2003 2005 2006 2008 2009 2011 2012 2014

Pre-Op RFO 1 RFO 2 RFO 3 RFO 4 RFO 5 RFO 6 RFO 7 RFO 8 RFO 9 RFO 10 RFO 11 RFO 12 RFO 13 RFO 14 

AVB 5 4 4 4 3 2 

Preheater TSP (D5) 1 

TSP 

Confirmed 2 2 

Not confirmed, 

periphery 2 3 2 

Not confirmed, not 

periphery 1 5 2 3 

From PSI, no 

progression 1 

Service-induced 1 1 

Preservice 20 

Other 4 7 

Probe lodged 

Data quality 

Dent/geometry 

Permeability 

Not inspected 

Top of tubesheet 1 

Freespan 

TSP 

Other/not reported 

ID 13 

OD 

TOTALS 20 0 0 8 5 4 11 4 13 0 13 0 3 0 12 

Notes: 1 2 3

Notes

1. Three tubes had indications in the freespan attributed to laps and one tube had an indication attributed to a manufacturing anomaly.

2. Hot-leg tube end indications.

3. Seven tubes were plugged due to non-optimal tube processing.

Year

Wear

Loose Parts

Obstruction 

Restriction

Cause of Tube Plugging/Outage

Manufacturing 

Flaws

Inspection 

Issues

Other

SCC
3-251

Table 3-12: Comanche Peak 2: Tubes Plugged for Indications Other Than AVB Wear

STEAM GENERATOR A

Tube Location RFO # Characterization Stabilized

4-109 8 Restriction

5-111 1C+0.14 8 Manufacturing anomaly 

33-54 TEH+0.08 10 SCC (SAI)—tube end (nonoptimal tube processing)

34-96 TSH 4 Pit, manufacturing artifact, PLP

49-53 8H 3 CLP

49-54 8H 3 CLP

STEAM GENERATOR B

Tube Location RFO # Characterization Stabilized

1-21 TEH+0.1 10 SCC (SAI)—tube end

1-32 TEH+0.35 10 SCC (SAI)—tube end

1-44 TEH+0.05 10 SCC (SAI)—tube end

1-45 TEH+0.08 10 SCC (SAI)—tube end

1-74 TEH+0.15 10 SCC (SAI)—tube end

5-93 TEH+0.14 10 SCC (SAI)—tube end

7-15 10H+0.09 6 PLP—14 percent wall thinning N

10-31 TEH+0.03 10 SCC (SAI)—tube end

12-23 6C+0.35 14 PLP—10 percent wall thinning Y

12-24 6C+0.55 14 PLP—19 percent wall thinning Y

13-23 6C+0.39 14 PLP—6 percent wall thinning Y

14-67 TSC 3 Restricted Tube

16-79 7C+8.84 8 Freespan (manufacturing lap)

24-37 1H+0.43 6 CLP—28 percent wall thinning N

36-59 TSH+0.55 6 CLP—9 percent wall thinning (part not removed) Y

43-32 TSH+0.01 6 PLP—28 percent wall thinning N
3-252

Table 3-12: Comanche Peak 2: Tubes Plugged for Indications Other Than AVB Wear 

(cont’d)

STEAM GENERATOR C

Tube Location RFO # Characterization Stabilized

1-47 TEH+0.11 10 SCC (MCI)—tube end

1-48 TEH+0.07 10 SCC (MCI)—tube end

6-33 6C+0.41 8 PLP—SVI (18% wall thinning) Y

6-80 11H+12.3 6 PLP—46% wall thinning (at U-bend apex) N

7-33 6C+0.37 8 PLP—SVI (22% wall thinning) Y

8-33 6C+0.49 6 Preheater baffle wear (5% throughwall) – reclassified as loose part wear in 

RFO 8

N

9-33 6C+0.46 6 Preheater baffle wear (6% throughwall) – reclassified as loose part wear in 

RFO 8

N

12-30 6C+0.49 6 Preheater baffle wear (11% throughwall)

36-60 TEH+0.08 10 SCC (SAI)—tube end

37-55 TSH+0.18 6 PLP—44% wall thinning N

38-55 TSH+0.43 6 PLP—43% wall thinning N

38-56 TSH+0.34 6 PLP—26% wall thinning N

48-40 2C+0.57 8 PLP—SVI (19% wall thinning) N

48-41 2C+0.39 8 PLP—SVI (34% wall thinning) N

STEAM GENERATOR D

Tube Location RFO # Characterization Stabilized

1-30 TEH+0.09 10 SCC (SCI)—tube end

12-92 6C 4 PLP

20-106 10H 4 Restricted tube/dent

21-69 TEH+0.11 10 SCC (SCI)—tube end

24-89 8H+0.73 8 Freespan (manufacturing lap)

27-74 1H+16.67 8 Freespan (manufacturing lap)

36-59 TTS 4 PLP

37-59 TTS 4 PLP
3-253

Table 3-13: Callaway: Summary of Bobbin Inspections and Tube Plugging (Thermally Treated 

Insp. Plug DePl Insp. Plug DePl Insp. Plug DePl Insp. Plug DePl

Pre-op 2 0 0 2 4 0 

RFO 1 0 0 

Mid-Cycle 04/07/1987 243 0 243 0 0 0 

RFO 2 10/02/1987 728 1 728 0 1 0 

RFO 3 04/24/1989 1214 0 1214 1 1 0 

RFO 4 10/23/1990 1211 0 1212 0 0 0 

RFO 5 04/28/1992 1214 0 1213 1 1 0 

RFO 6 10/28/1993 1211 0 1212 0 0 0 

RFO 7 05/01/1995 0 1214 2 1212 1 1 4 0 

RFO 8 11/11/1996 1211 1 2 1 1211 1 5 0 

RFO 9 04/01/1998 0 1210 0 1210 0 0 0 0 

RFO 10 11/05/1999 1210 0 0 0 1210 0 0 0 

RFO 11 05/21/2001 0 1210 0 1210 1 0 1 0 

RFO 12 11/21/2002 1210 1 0 0 1210 1 2 0 

RFO 13 06/09/2004 1209 0 1210 1 1209 1 1209 0 2 0 

RFO 14 11/18/2005 0 0 

Totals: 5 0 5 0 6 0 5 0 21 0

Plant Data Acronyms

Model: F Pre-op = prior to operation

T-hot (approximate): 618 °F Cumul. = cumulative

Tubes per steam generator: 5626 (1214 are TT) Insp. = number of tubes inspected

Number of steam generators: 4 Plug = number of tubes plugged

DePl = number of tubes deplugged

RFO = refueling outage

TT = thermally treated

Notes

1. Inspection reports for RFO 1 could not be readily located. Based on information contained in other reports, no TT tubes were plugged.

2. Assumed 20% of TT tubes were inspected since 20% of steam generator (SG) was inspected.

 Licensee elected to perform SG inspections during a planned maintenance outage.

3. Assumed 60% of TT tubes were inspected since 60% of steam generator was inspected.

4. Various portions of tubes in all steam generators were inspected with a rotating probe.

5. Three tubes were repaired with laser welded sleeves: 1 in steam generator A, 2 in steam generator C.

6. Three tubes in steam generator C were repaired by electrosleeving.

7. Some tubes were not inspected in the U-bend area with a bobbin coil. Some of these tubes were inspected in the U-bend area with a rotating probe.

8. During RFO 14, Callaway replaced their steam generators with Framatome steam generators containing thermally treated Alloy 690 tubes.

Total 

Plug 

Outage

Completion 

Date

Cumul. 

EFPY

SG A SG B SG C SG D 

Cum

Plug

Total 

DePl
3-254

Table 3-14: Callaway: Causes of Tube Plugging (Thermally Treated Tubes Only)

1987 1987 1989 1990 1992 1993 1995 1996 1998 1999 2001 2002 2004 2005

Pre-Op RFO 1 Mid-CycleRFO 2 RFO 3 RFO 4 RFO 5 RFO 6 RFO 7 RFO 8 RFO 9 RFO 10 RFO 11 RFO 12 RFO 13 RFO 14 

AVB 

Preheater TSP (D5) 

TSP 2 

Confirmed 

Not confirmed, 

periphery 2 

Not confirmed, not 

periphery 

From PSI, no 

progression 

Service-induced 

Preservice 4 

Other 

Probe lodged 

Data quality 

Dent/geometry 

Permeability 

Not inspected 

Top of tubesheet 3 1 

Freespan 1 2 2 

TSP 1 1 2 

Other/not reported 

ID 

OD 

TOTALS 4 0 0 1 1 0 1 0 4 5 0 0 1 2 2 

Notes: 1 2 3

Notes

1. Three thermally treated tubes were repaired by inserting laser welded sleeves. These tubes are not reflected in the totals.

2. Three thermally treated tubes were repaired by electrosleeving. These tubes are not reflected in the totals.

3. During RFO 14, Callaway replaced the steam generators with Framatome steam generators containing thermally treated Alloy 690 tubes.

Year

Wear

Loose Parts

Obstruction 

Restriction

Cause of Tube Plugging/Outage

Manufacturing 

Flaws

Inspection 

Issues

Other

SCC
3-255

Table 3-15: Callaway: Tubes Plugged for Indications Other Than AVB Wear

(Thermally Treated Tubes Only)

STEAM GENERATOR A

Tube Location RFO # Characterization Stabilized

1-34 1C-0.45

1C-0.47

12 TSP wear (6% and 7% wall thinning) N

2-87 TSH+3.47 8 Single volumetric indication N

3-44 7H 2 45% throughwall indication

8-115 TSH-0.06 8 Laser welded sleeve, single circumferential indication

STEAM GENERATOR B

Tube Location RFO # Characterization Stabilized

1-100 TSH-0.11 8 Single circumferential indication Y

1-119 TSH+3.89 8 Single volumetric indication N

1-120 TSC+4.02 7 38% wall thinning, PLP N

1-121 TSC+3.66 7 45% wall thinning, PLP N

4-1 6C-0.52 13 Single volumetric indication N
3-256

Table 3-15 Callaway: Tubes Plugged for Indications Other Than AVB Wear (cont’d)

(Thermally Treated Tubes only)

STEAM GENERATOR C

Tube Location RFO # Characterization Stabilized

1-1 1C 7 Obstruction, damage because of chemical cleaning equipment N

1-5 TSH+0.12 10 8′′ Electrosleeve, single volumetric indication

1-35 1H-0.19 13 Single volumetric indication N

2-6 TSH+0.07 8 Single axial indication N

2-10 TSH-0.01 11 Single axial indication N

2-98 7C+1.5 5 Undefined indication 1.5 inches above 7th cold-leg tube support

4-11 FBC 3 Single axial indication

9-64 TSH+0.24 10 8′′ Electrosleeve, single volumetric indication

10-48 TSH+0.17 8 Laser welded sleeve, single volumetric indication

10-70 TSH-0.08 8 Laser welded sleeve, single circumferential indication

10-93 TSH+0.23 to 

0.91

10 8′′ Electrosleeve, single volumetric indication

STEAM GENERATOR D

Tube Location RFO # Characterization Stabilized

1-1 TSC+17.25 7 Dent, damage because of chemical cleaning equipment N

5-70 3C+0.50 12 TSP wear (16% wall thinning) N

7-102 TSH+0.18 8 Single volumetric indication N
3-257

Table 3-16: Millstone 3: Summary of Bobbin Inspections and Tube Plugging

Insp. Plug DePl Insp. Plug DePl Insp. Plug DePl Insp. Plug DePl

Pre-op 3 3 3 1 10 0 

RFO 1 11/24/1987 1.341 543 1 501 0 506 0 504 1 2 0 

RFO 2 05/29/1989 2.420 2431 4 2358 0 4 0 

RFO 3 02/21/1991 3.725 3555 0 3546 5 5 0 

RFO 4 08/21/1993 5.188 4350 6 3660 1 7 0 

RFO 5 05/09/1995 6.544 4237 1 4236 10 11 0 

Mid-Cycle 10/01/1996 7.309 5622 2 2 0 

RFO 6 05/17/1999 7.981 5612 12 5620 2 42 0 14 0 

RFO 7 02/18/2001 9.561 5622 0 5609 51 51 0 

RFO 8 09/22/2002 10.982 5600 8 5618 3 11 0 

RFO 9 04/17/2004 12.430 5622 0 5558 10 10 0 

RFO 10 10/12/2005 13.777 5592 2 5615 0 2 0 

RFO 11 04/24/2007 15.191 5622 0 5548 4 4 0 

RFO 12 10/31/2008 16.600 5590 2 12 5615 11 1 26 0 

RFO 13 05/18/2010 17.900 5610 4 5543 3 7 0 

RFO 14 11/22/2011 19.300 5588 11 5604 0 11 0 

RFO 15 05/17/2013 20.700 5606 5 5540 5 10 0 

Totals: 49 0 25 0 22 0 91 0 187 0

Plant Data Acronyms

Model: F Pre-op = prior to operation

T-hot (approximate): 622 °F Cumul. = cumulative

Tubes per steam generator: 5626 Insp. = number of tubes inspected

Number of steam generators: 4 Plug = number of tubes plugged

DePl = number of tubes deplugged

RFO = refueling outage

Notes

1. Licensee elected to perform steam generator tube inspections during an extended shutdown period.

2. The U-bend region of some row 1 tubes was not inspected with a bobbin probe. The U-bend region of 50% of the row 1 and row 2 tubes were inspected with a ro

3. The U-bend region of the row 1 and row 2 tubes was not inspected with a bobbin probe. The U-bend region of 80% of the row 1 and row 2 tubes were inspected 

4. The U-bend region of the row 1 and row 2 tubes was not inspected with a bobbin probe. The U-bend region of 100% of the row 1 and row 2 tubes were inspected 

5. The tube-ends in steam generators B and D were examined with a rotating probe.

Total 

DePl

Total 

Plug 

Outage

Completion 

Date

Cumul. 

EFPY

SG A SG B SG C SG D 
3-258

Table 3-17: Millstone 3: Causes of Tube Plugging

1987 1989 1991 1993 1995 1996 1999 2001 2002 2004 2005 2007 2008 2010 2011 201

Pre-Op RFO 1 RFO 2 RFO 3 RFO 4 RFO 5 Mid-Cyc. RFO 6 RFO 7 RFO 8 RFO 9 RFO 10 RFO 11 RFO 12 RFO 13 RFO 14 RFO 15 

AVB 2 3 5 7 11 2 13 15 7 1 2 2 1 1 3 

Preheater TSP (D5) 

TSP 

Confirmed 1 2 2 2 2 

Not confirmed, 

periphery 1 6 2 5 2 

Not confirmed, not 

periphery 1 1 1 

From PSI, no 

progression 

Service Induced 1 

Preservice 10 

Other 2 7 

Probe lodged 

Data quality 1 

Dent/geometry 

Permeability 

Not inspected 

Top of tubesheet 13 

Freespan 1 3 

TSP 13 

Other/not reported 

ID 23 

OD 

TOTALS 10 2 4 5 7 11 2 14 51 11 10 2 4 26 7 11 1

Notes: 1 2 3 4

Notes

1. One tube had both a volumetric indication at the top of the tubesheet and an AVB wear indication. The tube was included under "Other, Top of Tubesheet."

2. Two tubes plugged due to degradation attributed to hand-hole installation during fabrication.

3. All SCC indications are near the tube-end.

4. Seven tubes were plugged since the bottom of the expansion transition is greater than 1-inch below the top of the tubesheet.

Other

Year

Manufacturing 

Cause of Tube Plugging/Outage

Wear

Flaws

SCC

Loose Parts

Obstruction 

Restriction

Inspection 

Issues
3-259

Table 3-18: Millstone 3: Tubes Plugged for Indications Other Than AVB Wear

STEAM GENERATOR A

Tube Location RFO # Characterization Stabilized

14 7 tubes plugged since bottom of expansion transition greater than 2.54 

cm (1 in.) below top of tubesheet

1-122 8H+10.56 2 36% throughwall, distorted eddy current signal

4-122 TSH+0.65 8 Loose part wear—47% wall thinning N

5-122 TSH+0.54

TSH+1.01

TSH+1.66

12 CLP—42% wall thinning

10-116 TSH+0.26 8 Loose part wear—64% wall thinning N

20-6 TSH+0.07 6 Volumetric—possible loose part

46-83 6C-0.59 14 PLP—22% wall thinning (not periphery) Y

STEAM GENERATOR B

Tube Location RFO # Characterization Stabilized

2-93 5C-0.64 15 TSP wear—33% wall thinning

3-113 5C-1.17 13 PLP—13% wall thinning (periphery)

3-114 5C-0.56

5C-0.80

13 PLP—18% and 33% wall thinning (periphery)

5-53 TEH+0.02 12 PWSCC (SCI)—near tube end

6-61 TEH+0.10 12 PWSCC (MCI)—near tube end

6-63 TEH+0.06 12 PWSCC (MCI)—near tube end

7-48 TEH+0.08 12 PWSCC (MCI)—near tube end

7-78 TEH+0.07 12 PWSCC (SCI)—near tube end

9-77 TEH+0.06 12 PWSCC (SCI)—near tube end

10-81 TEH+0.06 12 PWSCC (MCI)—near tube end

11-73 TEH+0.08 12 PWSCC (MCI)—near tube end

16-71 TEH+0.06 12 PWSCC (SCI)—near tube end

22-80 8C-0.99 15 TSP wear—47% wall thinning

27-70 TEH+0.04 12 PWSCC (MCI)—near tube end

27-92 5H-0.71 15 TSP wear—18% wall thinning

27-93 5H-0.63

5H-0.64

15 TSP wear—30% and 11% wall thinning

31-67 8C-0.98 15 TSP wear—24% wall thinning

37-68 3H-0.54 13 PLP—31% wall thinning (not periphery)

38-47 TEH+0.09 12 PWSCC (SCI)—near tube end

40-69 TEH+0.06 12 PWSCC (SCI)—near tube end
3-260

Table 3-18: Millstone 3: Tubes Plugged for Indications Other Than AVB Wear (cont’d)

STEAM GENERATOR C

Tube Location RFO # Characterization Stabilized

1-4 TSC+2.86 8 CLP—16% wall thinning (part could not be retrieved) Y

1-56 TEH+0.06

TEH+0.13

12 PWSCC (SCI + SAI)—near tube end

1-68 TEH+0.07

TEH+0.08

12 PWSCC (MCI)—near tube end

1-78 TEH+0.05

TEH+0.07

12 PWSCC (MCI)—near tube end

1-79 TEH+0.09

TEH+0.15

TEH+0.19

12 PWSCC (SCI + MAI)—near tube end

1-87 TEH+0.09

TEH+0.09

12 PWSCC (SCI + SAI)—near tube end

1-92 TEH+0.05

TEH+0.07

12 PWSCC (SCI + SAI)—near tube end

1-93 TEH+0.08 12 PWSCC (MCI)—near tube end

1-95 TEH+0.07 12 PWSCC (SCI)—near tube end

1-96 TEH+0.06 12 PWSCC (SCI)—near tube end

1-115 TEC+7.29 8 Obstruction N

16-90 TEH+0.54 12 PWSCC (MCI)—near tube end

54-65 TSH+0.13 12 CLP—41% wall thinning
3-261

Table 3-18: Millstone 3: Tubes Plugged for Indications Other Than AVB Wear (cont’d)

STEAM GENERATOR D

Tube Location RFO # Characterization Stabilized

13 Inside diameter (ID) chatter (noise)

1-1 8H+1.63 9 Attributed to handhole installation during fabrication – 29% wall thinning

1-50 U-bend 15 Restriction

1-119 TSH+13.94 7 Volumetric N

1-120 TSH+14.11 7 Volumetric N

1-121 TSH+14.09 7 Volumetric N

5-1 8H+4.13 9 Attributed to handhole installation during fabrication – 54% wall thinning

6-47 TEH+0.43 12 PWSCC (MCI)—near tube end

9-42 6C-0.74 13 CLP—41% wall thinning

15-18 TSH+0.27 7 Possible loose part (not in periphery of bundle) N

26-98 8C-0.94 15 TSP wear—27% wall thinning

35-23 TSH+0.09 7 Volumetric—possibly manufacturing related N

37-23 TSH+0.15 7 Volumetric—possibly manufacturing related N

37-24 TSH+0.15 7 Volumetric—possibly manufacturing related N

38-107 1C+1.45 7 Volumetric—possible loose part N

39-107 1C+1.52 7 Volumetric—possible loose part N

41-56 6H-0.83 15 TSP wear—24% wall thinning

42-23 TSH+0.16 7 Volumetric—possibly manufacturing related N

43-23 TSH+0.11 7 Volumetric—possible manufacturing related and AVB Wear N

43-24 TSH+0.14 7 Volumetric—possibly manufacturing related N

44-23 TSH+0.13 7 Volumetric—possibly manufacturing related N

44-24 TSH+0.14 7 Volumetric—possibly manufacturing related N

44-85 8C-0.90 15 TSP wear—23% wall thinning

44-89 8C-0.62 15 TSP wear—45% wall thinning

45-23 TSH+0.15 7 Volumetric—possibly manufacturing related N

45-24 TSH+0.13 7 Volumetric—possibly manufacturing related N

50-33 1H+0.53 9 Loose part wear—26% wall thinning N

50-34 1H+0.45 9 PLP N

51-32 1H+0.48 9 PLP N

51-33 1H+0.48 9 PLP—25% wall thinning N

51-34 1H+0.49 9 Loose part wear—16% wall thinning N

52-43 1H+0.53 13 CLP—52% wall thinning

52-53 TSC+0.81 7 Volumetric (not in periphery of bundle) N

52-54 TSC+0.25 7 Volumetric (not in periphery of bundle) N
3-262

Table 3-18: Millstone 3: Tubes Plugged for Indications Other Than AVB Wear (cont’d)

STEAM GENERATOR D

Tube Location RFO # Characterization Stabilized

52-61 TSH-0.05

TSH-0.04

9 CLP—48% wall thinning (part removed)

52-79 1C+0.79

1C+0.85

11 CLP—25% wall thinning (part removed)

53-54 TSC+0.01 7 Volumetric (not in periphery of bundle) N

53-61 TSH-0.01 9 CLP—86% wall thinning (part removed)

53-79 1C+0.9 7 Volumetric—possible loose part N

53-80 1C+0.34

1C+0.38

11 CLP—47% wall thinning (part removed)

54-45 1C+0.5 7 Volumetric N

54-79 1C+0.51 7 Possible loose part N

54-80 1C+0.43 7 Volumetric—possible loose part N

54-81 1C+0.48 7 Possible loose part N

55-45 1C+0.58 7 Volumetric N

55-46 1C+0.77 7 Volumetric N

57-74 1C+1.01 7 Volumetric—possible loose part N

57-75 1C+0.58 7 Possible loose part N

57-79 1H+0.91 7 Volumetric—possible loose part N

58-54 1C+0.56 7 Volumetric N

58-55 1C+0.70 7 Volumetric—possible loose part N

58-56 1C+0.69 7 Volumetric N

58-74 7 Possible loose part N

58-75 1C+0.64 7 Volumetric—possible loose part N

59-55 1C+0.68 7 Possible loose part N

59-56 1C+0.61 7 Possible loose part N
3-263

Table 3-19: Seabrook: Summary of Bobbin Inspections and Tube Plugging

Insp. Plug DePl Insp. Plug DePl Insp. Plug DePl Insp. Plug DePl

Pre-op 4 4 5 0 13 0 

RFO 1 08/28/1991 0.91 1797 0 1761 1 1747 8 1884 1 10 0 

RFO 2 10/01/1992 1.79 2409 0 2400 0 0 0 

RFO 3 05/12/1994 2.99 2327 1 2337 0 1 0 

RFO 4 11/27/1995 4.20 2424 8 2443 4 12 0 

RFO 5 06/10/1997 5.58 5620 9 5613 4 13 0 

RFO 6 04/20/1999 7.07 5614 5 5621 20 25 0 

RFO 7 11/09/2000 8.47 5611 7 5609 9 16 0 

RFO 8 05/24/2002 9.71 5609 13 5604 0 5600 0 5601 22 35 0 

RFO 9 10/29/2003 11.00 5596 1 5604 1 5600 2 5579 11 15 0 

RFO 10 04/30/2005 12.40 0 0 

RFO 11 10/18/2006 13.80 5595 0 5603 1 5598 18 5568 2 21 0 

RFO 12 05/07/2008 15.20 0 0 

RFO 13 11/09/2009 16.53 5595 3 5602 1 5580 4 5566 4 12 0 

RFO 14 05/22/2011 17.84 0 0 

RFO 15 10/29/2012 18.95 5592 3 5601 2 5576 3 5562 1 9 0 

RFO 16 04/23/2014 20.36 1125 0 5599 0 1125 3 1125 0 3 0 

Totals: 37 0 27 0 56 0 65 0 185 0

Plant Data Acronyms

Model: F Pre-op = prior to operation

T-hot (approximate): 621 °F since 2005 (618 °F prior to 2005) Cumul. = cumulative

Tubes per steam generator: 5626 Insp. = number of tubes inspected

Number of steam generators: 4 Plug = number of tubes plugged

DePl = number of tubes deplugged

RFO = refueling outage

Notes

1. Based on data contained in RFO 4 reports.

2. The U-bend region of the row 1 and row 2 tubes was not inspected with a bobbin probe. The U-bend region of 50% of the row 1 and 2 tubes was inspected 

3. The U-bend region of the row 1 and row 2 tubes was not inspected with a bobbin probe. The U-bend region of 20% of the row 1 and 2 tubes was inspected 

4. The U-bend region of the row 1 and row 2 tubes was not inspected with a bobbin probe. The U-bend region of 30% of the row 1 and 2 tubes was inspected 

5. Only rotating probe inspections were performed at the top of the tubesheet on the hot-leg side of the steam generator.

6. The U-bend region of the row 1 and row 2 tubes was not inspected with a bobbin probe.

Total 

Plug 

Outage

Completion 

Date

Cumul. 

EFPY

SG A SG B SG C SG D 

Total 

DePl
3-264

Table 3-20: Seabrook: Causes of Tube Plugging

1991 1992 1994 1995 1997 1999 2000 2002 2003 2005 2006 2008 2009 2011 2012 201

Pre-Op RFO 1 RFO 2 RFO 3 RFO 4 RFO 5 RFO 6 RFO 7 RFO 8 RFO 9 RFO 10 RFO 11 RFO 12 RFO 13 RFO 14 RFO 15 RFO 16 

AVB 4 1 12 7 25 13 11 9 3 11 6 

Preheater TSP (D5) 

TSP 

Confirmed 4 4 

Not confirmed, 

periphery 1 9 16 

Not confirmed, not 

periphery 2 2 1 

From PSI, no 

progression 

Service-induced 

Preservice 13 

Other 3 1 

Probe lodged 1 

Data quality 

Dent/geometry 

Permeability 

Not inspected 

Top of tubesheet 

Freespan 2 

TSP 

Other/not reported 

ID 

OD 15 3 1 2 

TOTALS 13 10 0 1 12 13 25 16 35 15 0 21 0 12 0 9 

Notes: 1 2 3 4 5

Notes

1. Fifteen low row tubes with crack-like indications at tube support plates (non-optimal tube processing).

2. Three low row (stress relieved in the U-bend) tubes were preventatively plugged and three low row tubes with crack-like indications at tube support plates (all tubes have non-optimal tube processing).

3. One high row (non-stress relieved in the U-bend) tube was plugged due to non-optimal tube processing.

4. One tube was plugged for axially oriented ODSCC at the expansion transtion.

5. Two tubes were plugged for axially oriented ODSCC (one at dented HL TSP elevation, one in freespan on hot-leg side of steam generator). One tube was plugged for a lodged probe head in a row 1 tube.

Year

Wear

Loose Parts

Obstruction 

Restriction

Cause of Tube Plugging/Outage

Manufacturing 

Flaws

Inspection 

Issues

Other

SCC
3-265

Table 3-21: Seabrook: Tubes Plugged for Indications Other Than AVB Wear

STEAM GENERATOR A

Tube Location RFO # Characterization Stabilized

5-1 8 Preventative—surround a tube/tubes affected by a PLP N

5-2 8 Preventative—surround a tube/tubes affected by a PLP N

5-3 8 Preventative—surround a tube/tubes affected by a PLP N

6-1 8 Preventative—surround a tube/tubes affected by a PLP N

6-2 5H+1.39 8 PLP with associated tube wear N

6-3 8 Preventative—surround a tube/tubes affected by a PLP N

7-2 5H+1.39 8 PLP N

7-3 8 Preventative—surround a tube/tubes affected by a PLP N

STEAM GENERATOR B

Tube Location RFO # Characterization Stabilized

1-116 U-bend tangent 15 Probe head lodged in tube

4-122 1H+5.83

1H+10.42

1H+11.53

15 SCC—Axial ODSCC in freespan

27-24 FS (6H) 1 37% throughwall, high wall loss indication—MBM

29-97 11 Preventative—high residual stress

43-97 TSH 5 Confirmed loose part—part not removed

43-98 TSH 5 Confirmed loose part—part not removed

43-99 TSH 5 Confirmed loose part—part not removed

43-100 TSH 5 Confirmed loose part—part not removed
3-266

Table 3-21: Seabrook: Tubes Plugged for Indications Other Than AVB Wear (cont’d)

STEAM GENERATOR C

Tube Location RFO # Characterization Stabilized

1-11 TSH + 19.06 7 Volumetric—possible loose part

11-120 FS (7C) 1 High wall loss

18-116 8H-0.24 15 SCC (SAI)—ODSCC at dent

22-12 5C 5 Volumetric—possible loose part (not in periphery of bundle)

22-13 5C 5 Volumetric—possible loose part (not in periphery of bundle)

27-61 TSH-0.26 13 SCC (SAI)—ODSCC at expansion transition

31-12 1 Confirmed loose part—part not removed

31-13 1 Confirmed loose part—part not removed

32-12 1 Confirmed loose part—part not removed

32-13 1 Confirmed loose part—part not removed

43-28 TSH + 0.04 7 Volumetric—possible loose part (not in periphery of bundle)

44-28 TSH + 0.06 7 Possible loose part (not in periphery of bundle)

57-53 11 Preventative—surround a tube/tubes affected by a PLP N

57-54 11 Preventative—surround a tube/tubes affected by a PLP N

57-55 11 PLP N

57-56 11 Preventative—surround a tube/tubes affected by a PLP N

57-57 11 Preventative—surround a tube/tubes affected by a PLP N

57-58 11 Preventative—surround a tube/tubes affected by a PLP N

58-53 11 Preventative—surround a tube/tubes affected by a PLP N

58-54 1C+0.51 11 PLP—39% wall thinning (location could not be accessed) N

58-55 11 PLP N

58-56 11 PLP N

58-57 11 PLP N

58-58 11 Preventative—surround a tube/tubes affected by a PLP N

59-55 11 PLP N

59-56 11 PLP N

59-57 1C 11 PLP—48% wall thinning (location could not be accessed) N

59-58 11 Preventative—surround a tube/tubes affected by a PLP N
3-267

Table 3-21: Seabrook: Tubes Plugged for Indications Other Than AVB Wear (cont’d)

STEAM GENERATOR D

Tube Location RFO # Characterization Stabilized

4-63 2H, 3H, 4H 8 ODSCC (Axial)—nonoptimal tube processing

4-64 2H+0.10

3H-0.08 

5H-0.31

9 ODSCC (Axial)—nonoptimal tube processing

4-65 2H, 3H, 4H, 6H 8 ODSCC (Axial)—nonoptimal tube processing

5-62 3H, 4H, 5H, 3C 8 ODSCC (Axial)—nonoptimal tube processing – pulled tube (hot leg)

5-80 3H, 4H, 3C 8 ODSCC (Axial)—nonoptimal tube processing

5-81 3H, 4H, 6H 8 ODSCC (Axial)—nonoptimal tube processing

5-82 3H, 4H, 5C 8 ODSCC (Axial)—nonoptimal tube processing

5-83 2H, 4H, 3C, 5C 8 ODSCC (Axial)—nonoptimal tube processing

5-86 2H, 3H 8 ODSCC (Axial)—nonoptimal tube processing

5-87 4H+0.14 9 ODSCC (Axial)—nonoptimal tube processing

5-88 3H 8 ODSCC (Axial)—nonoptimal tube processing

6-81 3H 8 ODSCC (Axial)—nonoptimal tube processing

6-85 3H 8 ODSCC (Axial)—nonoptimal tube processing

7-91 9 Preventative—High residual stress

9-24 3H, 4H 8 ODSCC (Axial)—nonoptimal tube processing

9-25 2H-0.18

3H+0.03

4H+0.25

9 ODSCC (Axial)—nonoptimal tube processing

9-26 3H, 4H 8 ODSCC (Axial)—nonoptimal tube processing

9-28 9 Preventative—High residual stress

9-62 2H, 3H, 4H, 5H, 

6H

8 ODSCC (Axial)—nonoptimal tube processing

9-63 3H, 4H, 5H, 4C 8 ODSCC (Axial)—nonoptimal tube processing – pulled tube (cold leg)

10-22 9 Preventative—High residual stress

11-102 6C-0.74 11 40% wall thinning attributed to a “transient” loose part

13-3 1C+0.19 8 PLP—46% wall thinning (part may have been removed during sludge 

lancing)
3-268

Table 3-22: Vogtle 1: Summary of Bobbin Inspections and Tube Plugging

Insp. Plug DePl Insp. Plug DePl Insp. Plug DePl Insp. Plug DePl

Pre-op 0 0 2 4 6 0 

RFO 1 10/22/1988 1.14 754 1 821 0 1 0 

RFO 2 03/11/1990 2.28 1514 0 2357 4 2403 0 1471 0 4 0 

RFO 3 10/08/1991 3.61 1067 0 1050 0 1078 0 1011 0 0 0 

RFO 4 04/03/1993 4.85 2951 0 2934 4 4 0 

RFO 5 10/01/1994 6.17 4224 0 4213 4 4231 5 4220 3 12 0 

RFO 6 03/22/1996 7.52 3387 4 3395 0 4 0 

RFO 7 10/05/1997 8.78 5618 3 5615 6 5619 6 15 0 

RFO 8 03/15/1999 10.11 5621 0 5613 0 0 0 

RFO 9 10/11/2000 11.57 5615 0 5609 2 2 0 

RFO 10 03/27/2002 12.93 5621 1 5613 1 2 0 

RFO 11 10/14/2003 14.33 5615 0 5607 3 3 0 

RFO 12 04/02/2005 15.68 5620 0 5612 2 2 0 

RFO 13 10/25/2006 17.08 3 5615 3 5604 3 10 19 0 

RFO 14 04/20/2008 18.4 5617 6 1 3 5600 37 47 0 

RFO 15 10/17/2009 19.8 12 5611 4 5598 5 50 4 25 0 

RFO 16 03/31/2011 21.2 5599 1 5559 1 2 0 

RFO 17 10/17/2012 22.6 5607 2 5593 1 3 0 

RFO 18 04/11/2014 24 5598 0 0 0 5558 10 10 0 

Totals: 28 0 21 0 34 0 78 0 161 0

Plant Data Acronyms

Model: F Pre-op = prior to operation

T-hot (approximate): 618 °F Cumul. = cumulative

Tubes per steam generator: 5626 Insp. = number of tubes inspected

Number of steam generators: 4 Plug = number of tubes plugged

DePl = number of tubes deplugged

RFO = refueling outage

Notes

1. The U-bend region of the row 1 and row 2 tubes was not inspected with a bobbin probe. The U-bend region of 60% of the row 1 and 2 tubes was inspected w

2. The U-bend region of the row 1 and row 2 tubes was not inspected with a bobbin probe. The U-bend region of 50% of the row 1 and 2 tubes was inspected w

3. Only the tubesheet region on the hot-leg was examined in steam generators A and D.

4. Only the tubesheet region on the hot-leg was examined in steam generators B and C.

5. Rotating probe inspections were performed at the top of the tubesheet on the hot-leg side of the steam generator and in the U-bend region.

6. The U-bend region of the row 1 and row 2 tubes was not inspected with a bobbin probe. The U-bend region of 100% of the row 1 and 2 tubes was inspected 

7. Approximately 50 tubes in steam generator D were inspected with a bobbin probe. The tubes selected surrounded the tubes plugged as a result of the 2008 t

 operation at Row 11, Column 62.

Total 

Plug Outage

Completion 

Date

Cumul. 

EFPY

SG A SG B SG C SG D 

C

P

Total 

DePl
3-269

Table 3-23: Vogtle 1: Causes of Tube Plugging

1988 1990 1991 1993 1994 1996 1997 1999 2000 2002 2003 2005 2006 2008 2009 2011 2012 2

Pre-Op RFO 1 RFO 2 RFO 3 RFO 4 RFO 5 RFO 6 RFO 7 RFO 8 RFO 9 RFO 10 RFO 11 RFO 12 RFO 13 RFO 14 RFO 15 RFO 16 RFO 17 RFO 

AVB 4 4 12 4 12 1 1 2 2 3 

Preheater TSP (D5) 

TSP 

Confirmed 1 

Not confirmed, 

periphery 1 1 

Not confirmed, not 

periphery 1 

From PSI, no 

progression 

Service-induced 2 1 

Preservice 6 

Other 

Probe lodged 

Data quality 

Dent/geometry 2 1 34 

Permeability 1 

Not inspected 

Top of tubesheet 1 

Freespan 1 

TSP 

Other/not reported 

ID 2 1 

OD 18 11 20 1 

TOTALS 6 1 4 0 4 12 4 15 0 2 2 3 2 19 47 25 2 3 

Notes: 1 2 3 4 5, 6 7 8 

Notes

1. Two tubes were plugged due to difficulty in passing a rotating coil through the U-bend.

2. One tube was plugged due to difficulty in passing a rotating coil through the U-bend.

3. Two inside diameter initiated circumferential cracks in bulges within the tubesheet.

4. Seventeen tubes were plugged for circumferential ODSCC at expansion transition and one tube was plugged for an axial ODSCC at/below expansion transition.

5. Ten tubes were plugged for circumferential ODSCC at expansion transition and one tube was plugged for axial ODSCC at/below expansion transition.

6. Thirty three tubes were plugged as a result of damage during a tube removal effort.

7. Twenty tubes were plugged for circumferential ODSCC at the hot-leg expansion transition. One tube was plugged for axial PWSCC at the hot-leg expansion transition.

8. One tube was plugged for axial ODSCC below the bottom of the expansion transition.

9. One tube was plugged for circumferential PWSCC in a bulge in hot-leg tubesheet region. Eight tubes were plugged for circumferential ODSCC at the hot-leg expansion transition.

Year

Wear

Loose Parts

Obstruction 

Restriction

Cause of Tube Plugging/Outage

Manufacturing 

Flaws

Inspection 

Issues

Other

SCC
3-270

Table 3-24: Vogtle 1: Tubes Plugged for Indications Other Than AVB Wear

STEAM GENERATOR A

Tube Location RFO # Characterization Stabilized

1-103 TSH 13 ODSCC (SCI) Y

1-122 U-bend 10 Data Quality- difficulty in passing rotating probe through U-bend (0.500-

inch rotating probe did not adequately rotate through U-bend)

2-113 TSH 15 SCC—circumferential ODSCC at hot-leg expansion transition

3-103 TSH 13 ODSCC (SCI) Y

3-108 TSH 15 SCC—circumferential ODSCC at hot-leg expansion transition

3-119 TSH 13 ODSCC (SCI) Y

5-110 TSH 15 SCC—circumferential ODSCC at hot-leg expansion transition

6-110 TSH 14 ODSCC (SCI/MCI)

7-35 15 Permeability variation

7-106 TSH 15 SCC—circumferential ODSCC at hot-leg expansion transition

7-117 TSH 15 SCC—circumferential ODSCC at hot-leg expansion transition

8-112 TSH 14 ODSCC (SCI)

8-115 TSH 15 SCC—circumferential ODSCC at hot-leg expansion transition

10-104 TSH 15 SCC—circumferential ODSCC at hot-leg expansion transition

10-112 TSH 15 SCC—circumferential ODSCC at hot-leg expansion transition

10-114 TSH 14 ODSCC (SCI)

11-118 TSH 14 ODSCC (SCI)

12-120 TSH 15 SCC—circumferential ODSCC at hot-leg expansion transition

13-96 TSH 14 ODSCC (SCI)

15-115 TSH 15 SCC—circumferential ODSCC at hot-leg expansion transition

26-110 2H-0.23 16 PLP (periphery) N

28-37 5H+7.0

4C+38.0

1 39% throughwall indication

44-60 TSH+2.66 15 Restriction

STEAM GENERATOR B

Tube Location RFO # Characterization Stabilized

2-109 TSH 13 ODSCC (SCI) Y

2-113 TSH 13 ODSCC (SCI) Y

34-104 TSH 14 ODSCC (SCI)

39-46 Flow 

Distribution 

Baffle (FDB) –

cold leg

13 Loose part wear—42% wall thinning (transient loose part)
3-271

Table 3-24: Vogtle 1: Tubes Plugged for Indications Other Than AVB Wear (cont’d)

STEAM GENERATOR C

Tube Location RFO # Characterization Stabilized

1-20 7H+3.1 15 SCC—axial PWSCC at hot-leg tangent

1-36 U-bend 11 Data Quality- 0.520-inch rotating probe did not adequately rotate through 

U-bend

2-106 TSH 13 ODSCC (SCI) Y

2-109 TSH 15 SCC—circumferential ODSCC at expansion transition

3-106 TSH 15 SCC—circumferential ODSCC at expansion transition

4-81 TSC+9.82 11 Volumetric indication (loose part impact or mechanical change in tube 

(cold lap breaking off))

5-118 TSH 13 ODSCC (SCI) Y

6-112 TSH 13 ODSCC (SCI) Y

6-114 TSH 15 SCC—circumferential ODSCC at expansion transition

6-119 TSH 14 ODSCC (SCI)

7-113 TSH 15 SCC—circumferential ODSCC at expansion transition

13-107 TSH 14 ODSCC (SCI)

21-13 TSH+0.21 9 Volumetric

42-52 TEH 14 Preventative—geometric discontinuity
3-272

Table 3-24: Vogtle 1: Tubes Plugged for Indications Other Than AVB Wear (cont’d)

STEAM GENERATOR D

Tube Location RFO # Characterization Stabilized

14 33 tubes near 11-62 were plugged (and some stabilized) because of

incomplete tube cut during tube pull operation.

1-31 U-bend 7 Obstruction to a 0.520-inch probe (foreign object potentially lodged in 

tube near U-bend)

2-1 U-bend 10 Data Quality—0.500-inch rotating probe did not adequately rotate 

through U-bend

3-105 TSH 15 SCC—circumferential ODSCC at hot-leg expansion transition

4-3 TSH 7 Confirmed Loose Part inside tube - part not removed

4-4 U-bend 7 Obstruction to a 0.520-inch probe (foreign object potentially lodged in 

tube near U-bend)

4-107 TSH 13 ODSCC (SCI) Y

4-113 TSH 15 SCC—circumferential ODSCC at hot-leg expansion transition

4-117 TSH 15 SCC—circumferential ODSCC at hot-leg expansion transition

4-122 TSH 15 SCC—circumferential ODSCC at hot-leg expansion transition

5-68 TSH 13 ODSCC (SAI) Y

6-101 TSH-0.4 12 PWSCC (SCI) - in 109 volt bulge Y

6-105 TSH 13 ODSCC (MCI) Y

8-57 TSH-0.19 16 SCC—axial ODSCC at/below the bottom of the expansion transition N

8-106 TSH 13 ODSCC (SCI) Y

8-108 TSH 13 ODSCC (MCI) Y

8-113 TSH 13 ODSCC (SCI) Y

9-107 TSH 13 ODSCC (SCI) Y

11-62 TSH 14 ODSCC (SAI)—pulled tube

11-88 TSH-1.7 12 PWSCC (MCI)—in 170 volt bulge Y

11-115 TSH 13 ODSCC (MCI) Y

12-98 TSH 14 ODSCC (SCI)—pulled tube

22-51 TSH 14 ODSCC (SCI/MCI)

22-84 TSH 13 ODSCC (SCI) Y

25-51 TSH 13 ODSCC (MCI) Y
3-273

Table 3-25: Vogtle 2: Summary of Bobbin Inspections and Tube Plugging

Insp. Plug DePl Insp. Plug DePl Insp. Plug DePl Insp. Plug DePl

Pre-op 2 4 1 8 15 0 

RFO 1 10/03/1990 1.25 1143 0 1130 0 1139 0 1135 0 0 0 

RFO 2 03/30/1992 2.48 1056 0 1570 0 1066 0 1061 0 0 0 

RFO 3 10/02/1993 3.79 2984 0 3008 0 0 0 

RFO 4 03/16/1995 5.08 4382 3 4576 0 3 0 

RFO 5 09/30/1996 6.52 5624 1 5618 5 6 0 

RFO 6 04/02/1998 7.92 5619 0 5625 0 0 0 

RFO 7 10/22/1999 9.32 5623 1 5613 4 5 0 

RFO 8 04/24/2001 10.74 5619 0 5625 0 0 0 

RFO 9 10/20/2002 12.18 5622 0 5609 2 2 0 

RFO 10 05/10/2004 13.49 1 5619 5 5625 3 2 11 0 

RFO 11 10/05/2005 14.78 5621 0 5605 0 0 0 

RFO 12 04/18/2007 16.06 5614 0 5622 0 0 0 

RFO 13 10/15/2008 17.2 5621 1 5605 0 1 0 

RFO 14 04/06/2010 18.5 5614 2 5622 0 2 0 

RFO 15 10/11/2011 20 5620 0 5605 1 1 0 

RFO 16 04/02/2013 21.3 5612 1 5622 1 2 0 

Totals: 6 0 15 0 5 0 22 0 48 0

Plant Data Acronyms

Model: F Pre-op = prior to operation

T-hot (approximate): 618 °F Cumul. = cumulative

Tubes per steam generator: 5626 Insp. = number of tubes inspected

Number of steam generators: 4 Plug = number of tubes plugged

DePl = number of tubes deplugged

RFO = refueling outage

Notes

1. The U-bend region of the row 1 and row 2 tubes was not inspected with a bobbin probe. The U-bend region of 60% of the row 1 and 2 tubes was inspected 

2. Only the hot-leg expansion transition region of the tubes in steam generators A and D were inspected (i.e., from 3 inches above to 3 inches below the TTS 

3. The U-bend region of the row 1 and row 2 tubes was not inspected with a bobbin probe. The U-bend region of 50% of the row 1 and 2 tubes was inspected 

4. The U-bend region of the row 1 and row 2 tubes was not inspected with a bobbin probe. The U-bend region of 100% of the row 1 and 2 tubes was inspecte

Total 

Plug 

Outage

Completion 

Date

Cumul. 

EFPY

SG A SG B SG C SG D 

Total 

DePl
3-274

Table 3-26: Vogtle 2: Causes of Tube Plugging

1990 1992 1993 1995 1996 1998 1999 2001 2002 2004 2005 2007 2008 2010 2011 2013

Pre-Op RFO 1 RFO 2 RFO 3 RFO 4 RFO 5 RFO 6 RFO 7 RFO 8 RFO 9 RFO 10 RFO 11 RFO 12 RFO 13 RFO 14 RFO 15 RFO 16 

AVB 3 6 5 2 1 1 2 1 

Preheater TSP (D5) 

TSP 

Confirmed 

Not confirmed, 

periphery 

Not confirmed, not 

periphery 

From PSI, no 

progression 

Service-induced 

Preservice 15 

Other 

Probe lodged 

Data quality 

Dent/geometry 

Permeability 1 

Not inspected 

Top of tubesheet 9 

Freespan 

TSP 

Other/not reported 

ID 

OD 

TOTALS 15 0 0 0 3 6 0 5 0 2 11 0 0 1 2 1 2 

Notes: 1 2

Notes

1. Nine tubes were plugged for indications originally attributed to ODSCC. Analysis of pulled tubes revealed that the eddy current signals were a result of scale or deposits on the tubes at the top of the tubesheet.

2. One tube was plugged for circumferential ODSCC at the expansion transition.

Year

Wear

Loose Parts

Obstruction 

Restriction

Cause of Tube Plugging/Outage

Manufacturing 

Flaws

Inspection 

Issues

Other

SCC
3-275

Table 3-27: Vogtle 2: Tubes Plugged for Indications Other Than AVB Wear

STEAM GENERATOR A

Tube Location RFO # Characterization Stabilized

11-64 TSH 10 Scale or Deposits1 Y

STEAM GENERATOR B

Tube Location RFO # Characterization Stabilized

3-7 TSH 10 Permeability Variation Y

11-60 TSH 10 Scale or Deposits (Tube Pulled)1 N

12-59 TSH 10 Scale or Deposits (Tube Pulled)1 N

15-60 TSH-0.2 16 SCC—circumferential ODSCC Y

17-68 TSH 10 Scale or Deposits1 Y

STEAM GENERATOR C

Tube Location RFO # Characterization Stabilized

11-65 TSH 10 Scale or Deposits1 Y

14-56 TSH 10 Scale or Deposits1 Y

46-89 TSH 10 Scale or Deposits1 Y

STEAM GENERATOR D

Tube Location RFO # Characterization Stabilized

11-50 TSH 10 Scale or Deposits1 Y

14-67 TSH 10 Scale or Deposits1 Y

1. Initial characterization of these indications was ODSCC in the expansion transition region. Analysis of pulled tubes revealed that the 

signals were a result of scale or deposits on the tubes at the top of the tubesheet.
3-276

Table 3-28: Wolf Creek: Summary of Bobbin Inspections and Tube Pugging

Insp. Plug DePl Insp. Plug DePl Insp. Plug DePl Insp. Plug DePl

Pre-op 8 3 4 15 0 

RFO 1 10/27/1986 1.07 393 0 384 0 0 0 

RFO 2 0 0 

RFO 3 11/18/1988 2.43 2969 1 2972 1 2973 3 2975 17 22 0 

RFO 4 04/04/1990 3.56 3205 0 3169 2 2 0 

RFO 5 10/24/1991 4.78 1565 0 1227 2 2 2 2 

RFO 6 03/31/1993 5.81 5623 5 5 0 

RFO 7 10/11/1994 7.07 5617 9 5607 24 6 33 6 

RFO 8 03/05/1996 8.28 5617 12 5619 4 16 0 

RFO 9 11/06/1997 9.73 5608 5 5589 14 19 0 

RFO 10 04/24/1999 11.06 5605 1 5615 5 6 0 

RFO 11 10/20/2000 12.42 5603 3 5575 29 32 0 

RFO 12 04/08/2002 13.78 5604 6 5610 3 9 0 

RFO 13 10/31/2003 15.22 5600 3 5546 17 20 0 

RFO 14 04/22/2005 16.51 5598 7 5607 1 8 0 

RFO 15 10/22/2006 17.89 5597 6 5529 17 23 0 

RFO 16 05/07/2008 19.23 0 5591 18 5606 8 3 29 0 

RFO 17 11/20/2009 20.6 5591 7 5509 11 18 0 

RFO 18 06/22/2011 21.84 1406 0 2290 9 1406 3 1406 3 15 0 

RFO 19 04/13/2013 23.22 1406 5 1406 4 1406 2 1406 5 16 0 

Totals: 47 0 66 0 35 2 142 6 290 8

Plant Data Acronyms

Model: F Pre-op = prior to operation

T-hot (approximate): 618 °F Cumul. = cumulative

Tubes per steam generator: 5626 Insp. = number of tubes inspected

Number of steam generators: 4 Plug = number of tubes plugged

DePl = number of tubes deplugged

RFO = refueling outage

Notes

1. No tube inspections were performed during RFO 2.

2. The U-bend region of the row 1 and row 2 tubes was not inspected with a bobbin probe. The U-bend region of 50% of the row 1 and 2 tubes was inspected 

3. The U-bend region of the row 1 and row 2 tubes was not inspected with a bobbin probe.

4. The U-bend region of the tubes in rows 1 through 4 was not inspected with a bobbin probe.

5. Only the hot-leg tube ends were inspected in steam generators A and D.

6. The U-bend region of the row 1 and row 2 tubes was not inspected with a bobbin probe. The U-bend region of 25% of the row 1 and 2 tubes was inspected 

Total 

Plug Outage

Completion 

Date

Cumul. 

EFPY

SG A SG B SG C SG D 

Total 

DePl
3-277

Table 3-29: Wolf Creek: Causes of Tube Plugging

1986 1988 1990 1991 1993 1994 1996 1997 1999 2000 2002 2003 2005 2006 2008 2009 2011 

Pre-Op RFO 1 RFO 2 RFO 3 RFO 4 RFO 5 RFO 6 RFO 7 RFO 8 RFO 9 RFO 10 RFO 11 RFO 12 RFO 13 RFO 14 RFO 15 RFO 16 RFO 17 RFO 18 RFO 

AVB 19 2 2 5 25 16 19 6 30 8 19 4 21 20 16 15 

Preheater TSP (D5) 

TSP 

Confirmed 

Not confirmed, 

periphery 

Not confirmed, not 

periphery 

From PSI, no 

progression 

Service-induced 1 

Preservice 15 

Other 1 2 

Probe lodged 

Data quality 

Dent/geometry 2 

Permeability 

Not inspected 

Top of tubesheet 1 1 

Freespan 3 -2 4 

TSP 2 1 

Other/not reported 

ID 8 

OD 

TOTALS 15 0 0 22 2 0 5 27 16 19 6 32 9 20 8 23 29 18 15 

Notes: 1 2 3 4 5 6 

Notes

1. Deplugged two freespan indications originally plugged during RFO 3 (R28C56, R28C76)

2. Deplugged 6 previously plugged AVB wear indications. Plugged 31 other AVB wear indications for a net total of 25 tubes plugged for AVB wear.

3. One tube was plugged due to a circumferential anomaly (small dimple). This indication was not flaw-like.

4. Two tubes were plugged due to geometric anomalies (inner diameter ridge or scratch extending from within the tubesheet to a few inches above the tubesheet). Present since at least 1994 (1st rotating probe inspection).

5. Eight tubes were plugged due to PWSCC near the tube end. One tube was plugged since it was not expanded into the tubesheet on the hot-leg.

6. Two tubes were plugged due to a geometric anomaly at the top of the tubesheet.

7. Five tubes were plugged due to non-optimal tube processing. One tube was plugged due to circumferential ODSCC in a bulge on the hot-leg side of the steam generator.

Year

Wear

Loose Parts

Obstruction 

Restriction

Cause of Tube Plugging/Outage

Manufacturing 

Flaws

Inspection 

Issues

Other

SCC
3-278

Table 3-30: Wolf Creek: Tubes Plugged for Indications Other Than AVB Wear

STEAM GENERATOR A

Tube Location RFO # Characterization Stabilized

9-19 19 Nonoptimal tube processing

9-32 19 Nonoptimal tube processing

10-5 19 Nonoptimal tube processing

13-68 Tubesheet 15 Geometric Anomaly (scratch or ridge)

15-60 Tubesheet 15 Geometric Anomaly (scratch or ridge)

15-68 1H-0.81 7 55% throughwall indication

18-81 TTS 17 Geometric Anomaly

45-91 TSH-0.07 11 Volumetric

58-72 19 Obstruction (data quality)

STEAM GENERATOR B

Tube Location RFO # Characterization Stabilized

1-105 TSC+15.87

TSC+16.00

14 Wear from pressure pulse cleaning nozzle (28% and 49% throughwall)

1-106 TSC+15.95

TSC+15.72

14 Wear from pressure pulse cleaning nozzle (71% and 62% throughwall)

1-107 TSC+15.86

TSC+16.14

14 Wear from pressure pulse cleaning nozzle (40% and 57% throughwall)

1-108 TSC+15.63

TSC+16.01

14 Wear from pressure pulse cleaning nozzle (26% and 48% throughwall)

2-68 TEH+0.04 16 PWSCC (SCI)—near tube end

6-106 TEH+0.07 16 PWSCC (SCI)—near tube end

8-81 19 Nonoptimal tube processing

11-107 TEH+0.02

TEH+0.05

TEH+0.08

16 PWSCC (MCI)—near tube end

11-121 16 Tube not expanded in tubesheet on hot-leg side

17-89 19 SCC—circumferential PWSCC

49-68 TEH+0.08 16 PWSCC (SCI)—near tube end

55-71 TTS 12 Small “dimple” (no degradation)
3-279

Table 3-30: Wolf Creek: Tubes Plugged for Indications Other Than AVB Wear (cont’d)

STEAM GENERATOR C

Tube Location RFO # Characterization Stabilized

3-74 19 Nonoptimal tube processing

14-17 6H+9.26 3 36% throughwall

14-95 TEH+0.07

TEH+0.12

16 PWSCC (MCI)—near tube end

28-56 FBH+16.75 3 37% throughwall indication, deplugged in RFO 5

28-76 FBC+14.28 3 45% throughwall indication, deplugged in RFO 5

STEAM GENERATOR D

Tube Location RFO # Characterization Stabilized

1-75 TEH+0.08 16 PWSCC (SCI)—near tube end

1-80 TEH+0.01 16 PWSCC (SCI)—near tube end

7-88 4H+0.54 11 Volumetric

9-72 TEH+0.05 16 PWSCC (SCI)—near tube end

16-61 TTS 17 Geometric Anomaly

19-93 2C+0.08 7 Volumetric

40-41 13 Obstruction (Bolt shank)
3-280

Table 3-31: Indian Point 2: Summary of Bobbin Inspections and Tube Plugging

Insp. Plug DePl Insp. Plug DePl Insp. Plug DePl Insp. Plug DePl

Pre-op 0 0 0 2 2 0 

RFO 15 11/17/2002 1.72 3214 8 3214 1 3214 3 3212 4 16 0 

RFO 16 11/21/2004 3.56 0 0 

RFO 17 05/19/2006 4.94 1607 2 1607 2 1607 0 1607 3 7 0 

RFO 18 04/19/2008 6.76 0 0 

RFO 19 04/10/2010 8.62 2471 4 2473 2 2473 2 2467 1 9 0 

RFO 20 03/30/2012 10.38 0 0 

RFO 21 03/18/2014 12.24 1607 6 1607 0 1607 8 1607 0 14 0 

Totals: 20 0 5 0 13 0 10 0 48 0

Plant Data Acronyms

Model: 44F Pre-op = prior to operation

T-hot (approximate): 599 °F Cumul. = cumulative

Tubes per steam generator: 3214 Insp. = number of tubes inspected

Number of steam generators: 4 Plug = number of tubes plugged

DePl = number of tubes deplugged

RFO = refueling outage

Notes

1. The U-bend region of the row 1 and row 2 tubes was not inspected with a bobbin probe. The U-bend region of 100% of the row 1 and 2 tubes was inspecte

2. No steam generator tube inspections were performed.

3. The U-bend region of the row 1 and row 2 tubes was not inspected with a bobbin probe. The U-bend region of 50% of the row 1 and 2 tubes was inspected 

Total 

Plug 

Outage

Completion 

Date

Cumul. 

EFPY

SG A SG B SG C SG D 

Total 

DePl
3-281

Table 3-32: Indian Point 2 Causes of Tube Plugging

2002 2004 2006 2008 2010 2012 2014

Pre-Op RFO 15 RFO 16 RFO 17 RFO 18 RFO 19 RFO 20 RFO 21 

AVB 13 7 9 5 

Preheater TSP (D5) 

TSP 

Confirmed 

Not confirmed, 

periphery 5 

Not confirmed, not 

periphery 4 

From PSI, no 

progression 

Service-induced 

Preservice 2 

Other 3 

Probe lodged 

Data quality 

Dent/geometry 

Permeability 

Not inspected 

Top of tubesheet 

Freespan 

TSP 

Other/not reported 

ID 

OD 

TOTALS 2 16 0 7 0 9 0 14 0 

Notes: 1

Notes

1. Three deep buff marks that became volumetric indications as a result of heating during first cycle of operation.

Year

Wear

Loose Parts

Obstruction 

Restriction

Cause of Tube Plugging/Outage

Manufacturing 

Flaws

Inspection 

Issues

Other

SCC
3-282

Table 3-33: Indian Point 2: Tubes Plugged for Indications Other Than AVB Wear

STEAM GENERATOR A

Tube Location RFO # Characterization Stabilized

14-71 21 PLP Y

14-72 21 PLP Y

15-72 21 PLP Y

15-73 21 PLP Y

16-28 5H+5.63 15 Volumetric (18% throughwall)—deep buff mark

21-56 TSH+18.39 15 Volumetric (18% throughwall)—deep buff mark

STEAM GENERATOR B

Tube Location RFO # Characterization Stabilized

NONE

STEAM GENERATOR C

Tube Location RFO # Characterization Stabilized

27-33 5H+37.98 15 Volumetric (19% throughwall) – deep buff mark

32-24 21 PLP Y

33-24 21 PLP Y

33-25 21 PLP Y

34-25 21 PLP Y

34-26 21 PLP Y

STEAM GENERATOR D

Tube Location RFO # Characterization Stabilized

NONE
3-283

Table 3-34: Point Beach 1: Summary of Bobbin Inspections and Tube Plugging

Insp. Plug DePl Insp. Plug DePl

Pre-op 04/09/1984 3211 3 3214 1 4 0 4 0.06

RFO 12 04/13/1985 0.96 101 0 101 0 0 0 4 0.06

RFO 13 04/19/1986 122 0 146 0 0 0 4 0.06

RFO 14 1987 0 0 4 0.06

RFO 15 05/06/1988 129 0 112 2 2 0 6 0.09

RFO 16 04/11/1989 592 0 610 0 0 0 6 0.09

RFO 17 04/09/1990 0 0 6 0.09

RFO 18 04/18/1991 576 1 584 1 2 0 8 0.12

RFO 19 04/18/1992 591 0 592 0 0 0 8 0.12

RFO 20 04/17/1993 588 0 591 0 0 0 8 0.12

RFO 21 1994 0 0 8 0.12

RFO 22 03/25/1995 3210 0 3210 1 1 0 9 0.14

RFO 23 1996 0 0 9 0.14

RFO 24 03/31/1998 3210 0 3209 0 0 0 9 0.14

RFO 25 12/09/1999 0 0 9 0.14

Mid-Cycle 03/05/2000 0 0 9 0.14 1

RFO 26 04/24/2001 13.7 3210 0 3209 1 1 0 10 0.16

RFO 27 10/23/2003 0 0 10 0.16 2

RFO 28 04/30/2004 16.43 3210 0 3208 0 0 0 10 0.16 3

RFO 29 11/24/2005 17.7 1607 0 0 0 10 0.16

RFO 30 04/30/2007 19.05 1743 0 0 0 10 0.16

RFO 31 11/09/2008 20.4 3210 1 3208 0 1 0 11 0.17 4

RFO 32 04/04/2010 0 0 11 0.17 2

RFO 33 12/12/2011 23.2 3209 0 3208 2 2 0 13 0.20 5

RFO 34 04/16/2013 3209 0 3206 0 0 0 13 0.20 5

Totals: 5 0 8 0 13 0

Plant Data Acronyms

Model: 44F Pre-op = prior to operation

T-hot (approximate): Cumul. = cumulative

Tubes per steam generator: 3214 Insp. = number of tubes inspected

Number of steam generators: 2 Plug = number of tubes plugged

DePl = number of tubes deplugged

RFO = refueling outage

Notes

1. Plant was shut down to investigate an indication of a possible loose part.

2. No steam generator tube inspections were performed.

3. The U-bend region of all row 1 and 7 row 2 tubes was not inspected with a bobbin probe; however, they were inspected with a rotating prob

4. The U-bend region of the row 1 and row 2 tubes was not inspected with a bobbin probe. The U-bend region of 50% of the row 1

 and 2 tubes in SG A and 20% of the row 1 and row 2 tubes in SG B were inspected with a rotating probe.

5. The U-bend region of the row 1 and row 2 tubes was not inspected with a bobbin probe. 

 The U-bend region of 50% of the row 1 and 2 tubes was inspected with a rotating probe.

SG A SG B Percent 

Plugged Notes

Cumul. 

Plugged

Total 

DePl

Total 

Plug Outage

Completion 

Date

Cumul. 

EFPY
3-284

Table 3-35: Point Beach 1: Causes of Tube Plugging

1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1998 1999 2000 2001 2003 2004 2005 2007 2008 2010 2

Pre-Op RFO 12 RFO 13 RFO 14 RFO 15 RFO 16 RFO 17 RFO 18 RFO 19 RFO 20 RFO 21 RFO 22 RFO 23 RFO 24 RFO 25 Mid-Cycle RFO 26 RFO 27 RFO 28 RFO 29 RFO 30 RFO 31 RFO 32 RFO 3

AVB 1 1 1 

Preheater TSP (D5) 

TSP 1 

Confirmed 

Not confirmed, 

periphery 

Not confirmed, not 

periphery 

From PSI, no 

progression 

Service-induced 

Preservice 4 

Other 2 1 

Probe lodged 

Data quality 

Dent/geometry 

Permeability 

Not inspected 

Top of tubesheet 

Freespan 

TSP 

Other/not reported 

ID 

OD 

TOTALS 4 0 0 0 2 0 0 2 0 0 0 1 0 0 0 0 1 0 0 0 0 1 0 

Notes: 1 2 3 

Notes

1. Two tubes damaged during modification to the wrapper.

2. Mid-cycle outage due to an indication of a possible loose part.

3. One tube was plugged since it was not expanded for the full depth of the tubesheet.

4. Two tubes were plugged due to circumferential PWSCC near the tube end.

Loose Parts

Year

Wear

Cause of Tube Plugging/Outage

SCC

Obstruction 

Restriction

Manufacturing 

Flaws

Inspection 

Issues

Other
3-285

Table 3-36: Point Beach 1: Tubes Plugged for Indications Other Than AVB Wear

STEAM GENERATOR A

Tube Location RFO # Characterization Stabilized

21-63 5H-0.65 18 68% throughwall wear indication

38-69 Tubesheet 31 Tube not expanded for the full depth of the tubesheet

STEAM GENERATOR B

Tube Location RFO # Characterization Stabilized

1-1 TSC+18" 15 Damaged during tube lane blocking device removal

1-48 TEH+0.1 33 SCC—circumferential PWSCC

2-1 TSC+18" 15 Damaged during tube lane blocking device removal

4-41 TEH+0.1 33 SCC—circumferential PWSCC
3-286

Table 3-37: Robinson 2: Summary of Bobbin Inspections and Tube Plugging

Insp. Plug DePl Insp. Plug DePl Insp. Plug DePl

Pre-op 0 0 0 0 0 0 0.

RFO 10 02/01/1986 0.9 306 0 305 0 287 0 0 0 0 0.

RFO 11 05/01/1987 1.8 301 0 301 0 296 0 0 0 0 0.

RFO 12 12/05/1988 2.8 630 0 631 0 633 1 1 0 1 0.

Mid-Cycle 04/15/1989 0 0 1 0.

RFO 13 11/01/1990 3.8 654 0 655 0 653 1 1 0 2 0.

RFO 14 04/28/1992 4.8 661 1 659 0 667 0 1 0 3 0.

RFO 15 10/05/1993 5.9 1084 1 1187 0 1083 0 1 0 4 0.

Mid-Cycle 03/20/1994 6.1 484 2 2 0 6 0.

RFO 16 06/21/1995 7.0 3210 0 0 0 6 0.

RFO 17 09/27/1996 8.2 3212 1 1 0 7 0.

RFO 18 04/14/1998 9.5 2025 0 1607 0 0 0 7 0.

RFO 19 10/24/1999 10.9 1610 0 0 0 7 0.

RFO 20 04/27/2001 12.3 1619 1 1697 3 4 0 11 0.

RFO 21 10/29/2002 13.7 1871 4 1806 3 1709 1 8 0 19 0.

RFO 22 05/28/2004 15.1 1751 0 3210 5 1765 2 7 0 26 0.

RFO 23 10/25/2005 16.5 0 0 26 0.

RFO 24 05/13/2007 18.0 1911 0 1957 5 1917 1 6 0 32 0.

RFO 25 10/05/2008 19.2 0 0 32 0.

RFO 26 07/18/2010 20.5 3207 0 3200 7 3203 5 12 0 44 0.4

RFO 27 03/20/2012 21.8 0 0 44 0.4

RFO 28 11/07/2013 23.2 1607 2 1607 2 1607 0 4 0 48 0.

Mid-Cycle 04/07/2014 1607 0 1607 0 3198 1 1 0 49 0.

Totals: 9 0 23 0 17 0 49 0

Plant Data Acronyms

Model: 44F Pre-op = prior to operation

T-hot (approximate): 604 °F Cumul. = cumulative

Tubes per steam generator: 3214 Insp. = number of tubes inspected

Number of steam generators: 3 Plug = number of tubes plugged

DePl = number of tubes deplugged

RFO = refueling outage

Notes

1. Mid-cycle outage to investigate an indication of a possible loose part on the primary side of the steam generator. No tube inspections performed.

2. Mid-cycle outage to investigate an indication of a possible loose part on the secondary side of the steam generator.

3. No steam generator tube inspections were performed.

4. The U-bend region of the row 1 and 2 tubes was not inspected with a bobbin probe. The U-bend region of 50% of the row 1 and 2 tubes was inspected

 with a rotating probe.

5. The U-bend region of the row 1 and 2 tubes was not inspected with a bobbin probe. The U-bend region of 50% of the row 1 and 2 tubes in SG B and C

 was inspected with a rotating probe. The U-bend region of 100% of the row 1 and 2 tubes in SG A was inspected with a rotating probe.

6. The U-bend region of the row 1 and 2 tubes was not inspected with a bobbin probe.

 The U-bend region of 50% of the row 1 and 2 tubes was inspected with either a rotating probe or an array probe.

7. Mid-cycle outage due to primary-to-secondary leakage caused by a loose part in a SG.

Total 

DePl 

Percen

Plugge

Cumul. 

Plugged Outage

Completion 

Date

Cumul. 

EFPY

SG A SG B SG C Total 

Plug
3-287

Table 3-38: Robinson 2: Causes of Tube Plugging

1986 1987 1988 1989 1990 1992 1993 1994 1995 1996 1998 1999 2001 2002 2004 2005 2007 2008 2010 2012 2013 

Pre-Op RFO 10 RFO 11 RFO 12 Mid-Cycle RFO 13 RFO 14 RFO 15 Mid-CycleRFO 16 RFO 17 RFO 18 RFO 19 RFO 20 RFO 21 RFO 22 RFO 23 RFO 24 RFO 25 RFO 26 RFO 27 RFO 28 

AVB 1 

Preheater TSP (D5) 

TSP 

Confirmed 2 2 6 

Not confirmed, 

periphery 1 1 1 1 2 2 6 

Not confirmed, not 

periphery 1 2 3 5 

From PSI, no 

progression 1 1 

Service-induced 1 

Preservice 

Other 4 4 

Probe lodged 

Data quality 1 

Dent/geometry 

Permeability 

Not inspected 

Top of tubesheet 

Freespan 

TSP 

Other/not reported 

ID 

OD 

TOTALS 0 0 0 1 0 1 1 1 2 0 1 0 0 4 8 7 0 6 0 12 0 4 

Notes: 1 1 2 3 

Notes

1. Mid-cycle outage due to an indication of a possible loose part.

2. One tube plugged due to mechanical damage from the sludge lancing equipment. 3 tubes plugged due to anomalies attributed to manufacturing.

3. Four tubes were plugged since the bottom of the expansion transition was greater than 1-inch below the top of the tubesheet.

4. Mid-cycle outage due to primary-to-secondary leakage caused by a loose part in a SG.

SCC

Loose Parts

Obstruction 

Restriction

Manufacturing 

Flaws

Inspection 

Cause of Tube Plugging/Outage

Wear

Issues

Other

Year
3-288

Table 3-39: Robinson 2: Tubes Plugged for Indications Other Than AVB Wear

STEAM GENERATOR A

Tube Location RFO # Characterization Stabilized

1-29 6H 14 Restriction at 6H (since preservice inspection)

1-47 28 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

2-6 6H 15 Restriction at 6H (since preservice inspection)

4-39 3C-0.88” 21 PLP—37% wall thinning

20-35 28 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

37-50 TSH+0.04” 21 Manufacturing anomaly—41% wall thinning

37-51 TSH+0.04” 21 Manufacturing anomaly—37% wall thinning

37-73 Cold-leg 17 Possible loose part in periphery (38% throughwall indication)

38-50 TSH+0.07” 21 Manufacturing anomaly—41% wall thinning
3-289

Table 3-39: Robinson 2: Tubes Plugged for Indications Other Than AVB Wear (cont’d)

STEAM GENERATOR B

Tube Location RFO # Characterization Stabilized

1-27 TSC+16.33” 21 Wear from maintenance equipment—41% wall thinning

3-44 TSH+0.41 24 PLP—32% wall thinning Y

11-70 28 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

23-71 4H-0.03" 22 Adjacent to leaking tube (loose part not identified or removed)—55% 

wall thinning

Y

23-72 4H-0.34” 22 Leaking tube (loose part not identified nor removed) Y

24-33 TSH+0.19” 22 PLP—20% wall thinning Y

24-65 2H+0.36” 21 PLP—30% wall thinning

25-10 28 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

28-63 2H-0.58 26 CLP—64% wall thinning N

29-14 FBH+0.46” 24 PLP—31% wall thinning Y

29-15 FBH+0.43 24 PLP—36% wall thinning Y

30-14 FBH+0.44” 24 PLP—22% wall thinning Y 

33-17 FBH+0.72 24 PLP—20% wall thinning Y

34-18 FBH+0.60” 22 PLP—22% wall thinning Y

34-43 TSH+0.01” 21 PLP—20% wall thinning Y

35-30 FBC+0.47 26 CLP—40% wall thinning Y

36-30 FBC+0.45 26 CLP—40% wall thinning Y

37-30 26 CLP N

38-30 FBC+0.42 26 CLP—27% wall thinning Y

38-69 TSH 22 PLP—wear scar detected through visual exam only - <20% wall thinning N

39-30 FBC+0.43 26 CLP—27% wall thinning Y

40-30 FBC+0.52 26 CLP—60% wall thinning Y

43-55 20 Dent (since manufacture) resulting in poor data quality
3-290

Table 3-39: Robinson 2: Tubes Plugged for Indications Other Than AVB Wear (cont’d)

STEAM GENERATOR C

Tube Location RFO # Characterization Stabilized

1-90 TSH, TSC 1994 57% throughwall confirmed loose part indication

2-90 TSC+0.6" 13 44% throughwall possible loose part indication

2-91 TSC+0.05 24 PLP—38% wall thinning N

3-90 TSC 1994 33% throughwall confirmed loose part indication

7-92 TSH 12 76% throughwall gouge-like indication indicative of a debris related 

defect

8-15 4C-0.58 26 PLP—37% wall thinning (not periphery) Y

23-70 5C-0.86 26 PLP—33% wall thinning (not periphery) Y

27-71 4C-0.57 26 PLP—41% wall thinning (not periphery) N

31-15 TSH+0.66 2014 

Mid

CLP—100% wall thinning (primary-to-secondary leak)

32-26 TSH+0.28" 20 32% throughwall wear indication attributed to transient loose part

32-46 3H-0.56 26 PLP—51% wall thinning (not periphery) N

33-34 6H 20 Obstruction above 6H

39-34 2H-0.82” 22 PLP—17% wall thinning Y

39-35 2H-0.74” 22 PLP—30% wall thinning Y

44-56 FBH+0.45" 20 Flow distribution baffle wear indication attributed to transient loose part

45-41 6H-0.98” 21 PLP—50% wall thinning
3-291

Table 3-40: Salem 1: Summary of Bobbin Inspections and Tube Plugging

Insp. Plug DePl Insp. Plug DePl Insp. Plug DePl Insp. Plug DePl

Pre-op 0 3 9 1 13 0 

RFO 13 10/15/1999 1.348 5626 3 5623 0 5617 4 5625 3 10 0 

RFO 14 05/03/2001 2.715 5623 6 5623 12 5613 11 5622 6 35 0 

RFO 15 10/27/2002 3.989 5617 8 5611 11 5602 12 5616 2 33 0 

RFO 16 04/19/2004 5.304 5609 16 5600 3 5590 13 5614 5 37 0 

RFO 17 11/04/2005 6.567 0 0 

RFO 18 04/16/2007 7.937 5593 11 5597 16 5577 54 5609 15 96 0 

RFO 19 11/12/2008 0 0 

RFO 20 04/27/2010 5582 2 5581 6 5523 5 5594 1 14 0 

RFO 21 11/18/2011 0 0 

RFO 22 05/22/2013 5580 4 5575 3 5518 3 5593 3 13 0 

Totals: 50 0 54 0 111 0 36 0 251 0

Plant Data Acronyms

Model: F Pre-op = prior to operation

T-hot (approximate): Cumul. = cumulative

Tubes per steam generator: 5626 Insp. = number of tubes inspected

Number of steam generators: 4 Plug = number of tubes plugged

DePl = number of tubes deplugged

RFO = refueling outage

Notes

1. Bobbin probe inspections were not performed in the U-bend region for those row 1 and row 2 tubes that had their U-bend region inspected with a rotating 

2. No steam generator tube inspections were performed.

Total 

DePl

Total 

Plug 

Outage

Completion 

Date

Cumul. 

EFPY

SG A SG B SG C SG D 
3-292

Table 3-41: Salem 1: Causes of Tube Plugging

1999 2001 2002 2004 2005 2007 2008 2010 2011 2013

Pre-Op RFO 13 RFO 14 RFO 15 RFO 16 RFO 17 RFO 18 RFO 19 RFO 20 RFO 21 RFO 22 

AVB 8 29 33 28 95 7 8 

Preheater TSP (D5) 

TSP 

Confirmed 3 5 3 

Not confirmed, 

periphery 2 1 2 

Not confirmed, not 

periphery 

From PSI, no 

progression 

Service-induced 

Preservice 13 

Other 2 2 

Probe lodged 

Data quality 3 1 1 

Dent/geometry 

Permeability 1 3 1 

Not inspected 

Top of tubesheet 

Freespan 

TSP 

Other/not reported 

ID 

OD 

TOTALS 13 10 35 33 37 0 96 0 14 0 13 0 

Notes: 1 2 3 4

Notes

1. Two tubes were not fully expanded into the tubesheet.

2. The 2 possible loose parts indications were in the U-bend region of the tube bundle.

3. One tube that was plugged as a result of AVB wear also contained wear at the 7th tube support plate on the cold-leg side.

4. Two high row tubes were plugged due to non-optimal tube processing.

Cause of Tube Plugging/Outage

Manufacturing 

Flaws

Inspection 

Issues

Other

SCC

Year

Wear

Loose Parts

Obstruction 

Restriction
3-293

Table 3-42: Salem 1: Tubes Plugged for Indications Other Than AVB Wear

STEAM GENERATOR A

Tube Location RFO # Characterization Stabilized

1-3 Above 7C 14 Possible loose part indication aligned with one of tube support lands

8-115 TSC 16 CLP—<=8% wall thinning (part removed)

9-115 TSC 16 CLP—<=8% wall thinning (part removed)

9-116 TSC 16 CLP—<=8% wall thinning (part removed)

36-54 16 Permeability Variation

58-48 5H+6.69 to

5H+32.09"

14 Permeability

58-72 U-bend 16 Data Quality in U-bend

STEAM GENERATOR B

Tube Location RFO # Characterization Stabilized

1-43 7H+2.17" 14 Data Quality/Obstruction

3-3 TSC-0.03 22 PLP—31% wall thinning Y

5-31 18 Permeability Variation
3-294

Table 3-42: Salem 1: Tubes Plugged for Indications Other Than AVB Wear (cont’d)

STEAM GENERATOR C

Tube Location RFO # Characterization Stabilized

1-4 7H+5.81 14 Data quality—probe skipping/stalling

2-6 16 Permeability Variation

33-98 16 Preventative—Potential high residual stress

36-15 FBC-0.2 20 PLP Y

36-108 FBH+0.82

FBH+0.38

22 CLP—40% and 32% wall thinning N

36-109 FBH+0.59 22 CLP—50% wall thinning N

37-108 FBH+0.62 22 CLP—13% wall thinning N

38-96 16 Preventative—Potential high residual stress

46-64 Tubesheet 13 Tube not fully expanded into tubesheet

54-60 Tubesheet 13 Tube not fully expanded into tubesheet

55-39 16 Permeability Variation

55-82 7H 20 Data quality (permeability)

STEAM GENERATOR D

Tube Location RFO # Characterization Stabilized

1-79 7H+5.74" 14 Data Quality/Obstruction

2-23 Below 7C 14 Possible loose part indication aligned between 2 tube support lands

20-42 TSH 20 PLP Y

20-43 TSH 20 PLP Y

21-41 TSH 20 PLP Y

21-42 TSH 20 PLP Y

33-109 FBH+0.48 22 PLP—32% wall thinning

34-109 FBH+0.45 20 CLP—40% wall thinning
3-295

Table 3-43: Surry 1: Summary of Bobbin Inspections and Tube Plugging

Insp. Plug DePl Insp. Plug DePl Insp. Plug DePl

Pre-op 1 1 0 2 0 2 

RFO 1 03/01/1983 1.3 316 0 378 0 0 0 2 

RFO 2 11/01/1984 2.3 858 3 562 1 4 0 6 

RFO 3 06/01/1986 3.4 2869 0 1553 2 2874 2 4 0 10 

RFO 4 04/01/1988 4.7 788 0 788 0 0 0 10 

RFO 5 10/01/1990 6 152 0 881 0 1246 2 2 0 12 

RFO 6 03/01/1992 7.1 1170 2 1170 0 2 0 14 

RFO 7 02/01/1994 8.7 3339 4 4 0 18 

RFO 8 10/01/1995 10.1 3338 1 1 0 19 

RFO 9 03/01/1997 11.4 3336 5 5 0 24 

RFO 10 10/01/1998 12.7 3334 6 6 0 30 

RFO 11 04/01/2000 14.1 3337 8 8 0 38 

RFO 12 10/01/2001 15.5 3331 5 5 0 43 

RFO 13 04/01/2003 16.8 3328 7 20 4 11 0 54 

RFO 14 10/01/2004 18.2 0 0 54 

RFO 15 04/01/2006 19.5 3326 13 3325 3 16 0 70 

RFO 16 11/28/2007 20.9 3321 1 1 0 71 

RFO 17 05/10/2009 22.2 3313 9 132 0 3322 6 15 0 86 

RFO 18 12/01/2010 23.6 184 6 3320 4 138 10 20 0 106 

RFO 19 06/05/2012 25 3298 0 3306 0 0 0 106 

RFO 20 11/20/2013 26.4 3316 0 0 0 106 

Totals: 44 0 26 0 36 0 106 0

Plant Data Acronyms

Model: 51F Pre-op = prior to operation

T-hot (approximate): 605 °F Cumul. = cumulative

Tubes per steam generator: 3342 Insp. = number of tubes inspected

Number of steam generators: 3 Plug = number of tubes plugged

DePl = number of tubes deplugged

RFO = refueling outage

Notes

1. Inspections were from hot-leg tube end through uppermost tube support on cold-leg (i.e., no full length inspections).

2. The U-bend region of the row 1 tubes was not inspected with a bobbin probe. The U-bend region of 100% of the row 1 tubes was inspected 

 with a rotating probe.

3. Inspections in SG C were partial tube inspections and limited to tubes potentially damaged by sludge lancing equipment.

4. The U-bend region of the row 1 and 2 tubes was not inspected with a bobbin probe. The U-bend region of 100% of the row 1 and 2 tubes in SGs A 

 was inspected with a rotating probe.

5. The U-bend region of the row 1 and 2 tubes was not inspected with a bobbin probe. The U-bend region of 100% of the row 1 and 2 tubes in SG B

 was inspected with a rotating probe.

Outage

Completion 

Date

Cumul. 

EFPY

SG A SG B SG C Perc

Plugg

Cumul. 

Plugged

Total 

Plug 

Total 

DePl
3-296

Table 3-44: Surry 1: Causes of Tube Plugging

1983 1984 1986 1988 1990 1992 1994 1995 1997 1998 2000 2001 2003 2004 2006 2007 2009 2010 2012 

Pre-Op RFO 1 RFO 2 RFO 3 RFO 4 RFO 5 RFO 6 RFO 7 RFO 8 RFO 9 RFO 10 RFO 11 RFO 12 RFO 13 RFO 14 RFO 15 RFO 16 RFO 17 RFO 18 RFO 19 R

AVB 1 4 1 1 7 1 1 

Preheater TSP (D5) 

TSP 

Confirmed 5 

Not confirmed, 

periphery 3 2 1 2 

Not confirmed, not 

periphery 1 1 

From PSI, no 

progression 

Service-induced 1 3 3 

Preservice 2 

Other 1 2 3 8 17 

Probe lodged 

Data quality 

Dent/geometry 2 

Permeability 1 1 7 1 

Not inspected 

Top of tubesheet 1 

Freespan 1 1 1 1 

TSP 3 1 

Other/not reported 

ID 13 

OD 1 

TOTALS 2 0 4 4 0 2 2 4 1 5 6 8 5 11 0 16 1 15 20 0 

Notes: 1, 2 3 4 4,5 6 7 8

Notes

1. Assumed tube plugged for a restriction was service-induced.

2. A tube pulled for destructive examination was classified as a manufacturing flaw.

3. Two tubes pulled for destructive examination revealed manufacturing flaws.

4. One tube was plugged for a wear indication in U-bend attributed to interaction with the tip of the AVB - classified as a free span indication.

5. Three tubes were plugged as a result of mechanical damage from the sludge lancing equipment - classified as manufacturing flaws.

6. Eight tubes were plugged as a result of mechanical damage from the sludge lancing equipment - classified as manufacturing flaws.

7. Twelve tubes were plugged due to circumferential PWSCC at the tube ends. One tube was plugged for axial PWSCC at expansion transition.

8. One tube was plugged due to circumferential ODSCC at the expansion transition. Seventeen tubes were plugged since the bottom of the expansion transition was greater than 1-inch from the top of the tubesheet.

Inspection 

Issues

Other

SCC

Year

Wear

Loose Parts

Obstruction 

Restriction

Cause of Tube Plugging/Outage

Manufacturing 

Flaws
3-297

Table 3-45: Surry 1: Tubes Plugged for Indications Other Than AVB Wear

STEAM GENERATOR A

Tube Location RFO # Characterization Stabilized

1-9 TSC+16" 12 Mechanical damage because of sludge lancing equipment

1-28 TSC, TSH+16" 12 Mechanical damage because of sludge lancing equipment

1-35 TSC 9 Restriction

1-36 TSC 9 Restriction

1-37 TSC 9 Restriction

1-49 TEH+0.02

TEH+0.03

17 SCC—circumferential N

1-67 TSH+16" 12 Mechanical damage because of sludge lancing equipment

3-27 6H-25.99” to 

35.48”

15 Permeability Variation

4-82 3C+12.58” 15 Permeability Variation

5-88 TSH+0.16” 15 PLP—40% wall thinning (no part present)

6-61 TEH+0.04

TEH+0.05

17 SCC—circumferential N

6-71 2H+22.43” 15 Permeability Variation

9-69 TSH+0.02 17 SCC—axial PWSCC Y

10-24 2C-20.57” to 

23.15”

15 Permeability Variation

10-44 U-bend 

Freespan

12 Wear caused by tip of AVB

12-55 TEH+0.02 17 SCC—circumferential N

13-20 4H 6 31% throughwall indication associated with a dent

13-55 TEH+0.01 17 SCC—circumferential N

14-55 TEH+0.06

TEH+0.07

TEH+0.08

17 SCC—circumferential N

14-73 3C+15.49” to 

25.67”

15 Permeability Variation

14-85 9 Permeability

19-55 3C-1.34” to 

20.86”

15 Permeability Variation

19-62 TEH+0.34 17 SCC—circumferential N

23-49 TEH+0.02

TEH+0.03

17 SCC—circumferential N

27-84 BPH+0.51

BPH+0.71

17 PLP—40% wall thinning (periphery) N

32-51 4H-22.43”0 to 

-26.08”

15 Permeability Variation

34-40 18 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

N
3-298

Table 3-45: Surry 1: Tubes Plugged for Indications Other Than AVB Wear (cont’d)

STEAM GENERATOR A

Tube Location RFO # Characterization Stabilized

35-40 18 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

N

35-68 TSH+0.16” 15 CLP—65% wall thinning (part removed) Y

35-69 TSH+0.17” 15 CLP—49% wall thinning (part removed) Y

36-40 18 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

N

36-49 TSH-0.01” 15 CLP—41% wall thinning (part removed)

36-50 TSH+0.0” 15 CLP—43% wall thinning (part removed)

36-58 TSH 2 60% throughwall indication

36-68 TSH+0.13” 15 CLP—54% wall thinning (part removed)

37-20 7H 2 89% throughwall indication

37-40 18 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

N

39-37 18 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

N

39-60 5H 2 96% throughwall indication

43-40 18 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

N
3-299

Table 3-45: Surry 1: Tubes Plugged for Indications Other Than AVB Wear (cont’d)

STEAM GENERATOR B

Tube Location RFO # Characterization Stabilized

1-9 TSH+15.56

TSC+15.49

13 Mechanical damage because of sludge lancing equipment—39% and 

28% wall thinning

1-28 TSH+15.51

TSC+16.18

13 Mechanical damage because of sludge lancing equipment—31% and 

41% wall thinning

1-34 TSH 13 108 volt dent near expansion transition

1-58 TSH 10 Restriction

1-59 TSH 10 Restriction

1-60 TSH 10 Restriction

1-67 TSH+15.63

TSC+16.16

13 Mechanical damage because of sludge lancing equipment—20% and 

18% wall thinning

1-86 TSC+15.27 13 Mechanical damage because of sludge lancing equipment—36% wall 

thinning

4-41 18 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

N

4-51 18 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

N

11-14 2H to 4H 3 Multiple indications between 2H and 4H ranging from 33% to 53% 

throughwall

11-88 2C+42.64 16 Permeability variation N

16-50 3H+0.64 to 

3H+17.69

13 Permeability variation

21-76 1C+22.2 13 55 volt dent

32-14 FBH 10 22% throughwall possible loose part wear indication

32-16 FBH 10 21% throughwall possible loose part wear indication

33-16 FBH 10 26% throughwall possible loose part wear indication

33-43 2C 3 59% throughwall indication

37-22 2H-0.74 18 PLP—24% wall thinning (periphery) Y

38-21 2H-0.59 18 PLP—28% wall thinning (periphery) Y

46-46 3H 2 44% throughwall indication
3-300

Table 3-45: Surry 1: Tubes Plugged for Indications Other Than AVB Wear (cont’d)

STEAM GENERATOR C

Tube Location RFO # Characterization Stabilized

1-9 TSH+16.07

TSC+15.81

13 Mechanical damage because of sludge lancing equipment—16% and 

15% wall thinning

1-28 TSH+15.92

TSC+16.44

13 Mechanical damage because of sludge lancing equipment—30% and 

21% wall thinning

1-37 TEH+0.06 17 SCC—circumferential PWSCC N

1-44 TEH+0.01 17 SCC—circumferential PWSCC N

1-67 TSH+16.72

TSC+15.96

13 Mechanical damage because of sludge lancing equipment—26% and 

35% wall thinning

1-86 TSH+16.91 13 Mechanical damage because of sludge lancing equipment—34% wall 

thinning

2-7 3 Restriction

4-33 TEH+0.05

TEH+0.07

17 SCC—circumferential PWSCC N

10-26 1H-0.69 PLP—59% wall thinning (not periphery) N

10-53 Tubesheet 5 Tube pulled—no service-induced degradation

11-38 U-bend 

Freespan

11 Wear caused by tip of AVB

11-39 TEH+0.04 17 SCC—circumferential PWSCC N

12-35 18 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

N

15-62 3H-0.59” 15 PLP—27% wall thinning

18-42 TEH+0.03 17 SCC—circumferential PWSCC N

19-25 18 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

N

25-57 Tubesheet 5 Tube pulled—no service-induced degradation

26-10 18 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

N

30-21 TSH-0.03 18 SCC—circumferential ODSCC at expansion transition Y

35-42 18 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

N

38-62 1H-0.35” 15 PLP—32% wall thinning

39-42 18 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

N

39-43 18 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

N

40-70 7H 3 Tube pulled—no service-induced degradation

41-53 18 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

N

42-45 18 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

N

46-49 18 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

N
3-301

Table 3-46: Surry 2: Summary of Bobbin Inspections and Tube Plugging

Insp. Plug DePl Insp. Plug DePl Insp. Plug DePl

Pre-op 0 1 1 2 0 2 0.02

RFO 1 12/01/1981 1.1 0 0 0 0 2 0.02 1

RFO 2 06/01/1983 2.4 701 0 572 0 0 0 2 0.02 2

RFO 3 04/01/1985 3.6 535 0 534 0 0 0 2 0.02

Mid-Cycle 06/01/1986 4.5 23 1 1 0 3 0.03 3

RFO 4 10/01/1986 4.7 586 0 580 0 0 0 3 0.03

RFO 5 10/01/1988 5.9 786 0 781 0 0 0 3 0.03

RFO 6 03/01/1991 7.2 1180 0 1175 0 0 0 3 0.03

RFO 7 03/01/1993 8.7 3342 2 2 0 5 0.05

RFO 8 02/01/1995 10.2 3340 5 5 0 10 0.10

RFO 9 04/01/1996 11.2 3341 8 8 0 18 0.18

RFO 10 10/01/1997 12.5 3340 5 5 0 23 0.23

RFO 11 04/01/1999 13.9 3335 8 0 1 9 0 32 0.32

RFO 12 10/01/2000 15.2 3332 7 7 0 39 0.39

RFO 13 04/20/2002 16.5 3327 1 1 0 40 0.40 4

RFO 14 10/23/2003 17.9 3335 3 3 0 43 0.43 4

RFO 15 05/22/2005 19.3 3325 8 8 0 51 0.51 4, 

RFO 16 11/20/2006 20.7 3326 4 4 0 55 0.55 4

RFO 17 05/18/2008 22.1 3 3332 1 3317 5 9 0 64 0.64 4, 

RFO 18 11/30/2009 23.5 3319 7 7 16 30 0 94 0.94 7,

RFO 19 06/15/2011 24.8 3324 0 3296 0 0 0 94 0.94 7

RFO 20 12/02/2012 26.2 3312 0 0 0 94 0.94 7

RFO 21 05/20/2014 27.5 3324 1 3296 0 1 0 95 0.95 7

Totals: 30 0 19 0 46 0 95 0

Plant Data Acronyms

Model: 51F Pre-op = prior to operation

T-hot (approximate): 605 °F Cumul. = cumulative

Tubes per steam generator: 3342 Insp. = number of tubes inspected

Number of steam generators: 3 Plug = number of tubes plugged

DePl = number of tubes deplugged

RFO = refueling outage

Notes

1. Number of tubes inspected was not readily available. Inspections only performed in steam generators A and B.

2. Most inspections are from the hot-leg tube end through uppermost tube support on cold-leg (i.e., limited full-length inspections).

3. During a plant shutdown, a 21 gpd primary-to-secondary leak was investigated and 23 tubes were inspected.

4. The U-bend region of the row 1 tubes was not inspected with a bobbin probe. The U-bend region of 100% of the row 1 tubes was inspected with a rotating pro

5. The expansion transition region of six tubes in steam generator B was inspected with a rotating probe as a result of visually identifying potential tube damage.

6. The hot-leg tube end region in steam generator A was inspected with a rotating probe.

7. The U-bend region of the row 1 and 2 tubes was not inspected with a bobbin probe. The U-bend region of 100% of the row 1 and 2 tubes was inspected

 with a rotating probe.

8. Select rotating probe inspections were performed in steam generators B and C. The inspections focused within the tubesheet and at the top of the tubesheet.

Outage

Completion 

Date

Cumul. 

EFPY

SG A SG B SG C Percent 

Plugged

Cumul. 

Plugged

Total 

DePl

Total 

Plug Note
3-302

Table 3-47: Surry 2: Causes of Tube Plugging

1981 1983 1985 1986 1986 1988 1991 1993 1995 1996 1997 1999 2000 2002 2003 2005 2006 2008 2009 2011 2012 

Pre-Op RFO 1 RFO 2 RFO 3 Mid-CycleRFO 4 RFO 5 RFO 6 RFO 7 RFO 8 RFO 9 RFO 10 RFO 11 RFO 12 RFO 13 RFO 14 RFO 15 RFO 16 RFO 17 RFO 18 RFO 19 RFO 20 

AVB 2 3 3 7 1 

Preheater TSP (D5) 

TSP 

Confirmed 1 3 3 1 

Not confirmed, 

periphery 5 2 7 

Not confirmed, not 

periphery 3 12 

From PSI, no 

progression 

Service-induced 1 2 2 1 

Preservice 2 

Other 11 

Probe lodged 

Data quality 

Dent/geometry 

Permeability 

Not inspected 

Top of tubesheet 4 3 8 

Freespan 

TSP 

Other/not reported 1 

ID 6 

OD 

TOTALS 2 0 0 0 1 0 0 0 2 5 8 5 9 7 1 3 8 4 9 30 0 0 

Notes: 1 2 2 3 4 5

Notes

1. During a plant shutdown, a 21 gpd primary-to-secondary leak was investigated.

2, Top of tubesheet indications attributed to "pitlike" indications.

3. One tube was plugged due to damage to the hot-leg tube end during prior removal of a tube plug.

4. Six tubes plugged due to hot-leg tube end indications.

5. Eleven tubes were plugged since they were not expanded within the tubesheet region.

SCC

Inspection 

Wear

Issues

Other

Loose Parts

Obstruction 

Restriction

Manufacturing 

Cause of Tube Plugging/Outage

Flaws

Year
3-303

Table 3-48: Surry 2: Tubes Plugged for Indications Other Than AVB Wear

STEAM GENERATOR A

Tube Location RFO # Characterization Stabilized

1-36 8 Restriction

1-46 TEH 17 Tube end crack N

1-59 TSH 8 Restriction

2-31 TEH 17 Tube end crack N

4-36 TSC 8 Axially oriented anomaly—pitlike indication

4-43 TSC+2.44 11 Pitlike indication

4-45 TSC+2.3

TSC+3.2

11 Pitlike indication

6-38 TSC+3.8

TSC+4.2

11 Pitlike indication

6-39 TSC 8 Axially oriented anomaly—pitlike indication

7-36 TSC+4.7 11 Pitlike indication

7-39 TSC 8 Axially oriented anomaly—pitlike indication

7-49 TSC+4.27

TSC+5.47

11 Pitlike indication

7-50 TSC 8 Axially oriented anomaly—pitlike indication

7-57 TSC+3.06 11 Pitlike indication

9-51 TSC+3.19 11 Pitlike indication

12-29 TEH 17 Tube end crack N

34-26 TSC+0.13 18 PLP—40% wall thinning (not periphery) N

34-27 TSC+0.18 16 Possible loose part—72% wall thinning (peripheral tube)

35-27 TSC+0.18 16 Possible loose part—49% wall thinning (peripheral tube)

40-28 TSC+0.1 18 PLP—41% wall thinning (periphery) N

40-29 TSC+0.13 18 PLP—42% wall thinning (periphery) N

41-27 TEH+1.75 16 Hot-leg tube end damage because of plug removal in a prior outage

41-28 TSC 1986 Confirmed loose part—part removed

41-29 TSC+0.18 16 Confirmed loose part—70% wall thinning—part removed in 1986

45-47 BPH 18 PLP Y

45-48 BPH 18 PLP Y

46-47 BPH+0.67 18 PLP—50% wall thinning Y

46-48 BPH+0.66 18 PLP—33% wall thinning Y
3-304

Table 3-48: Surry 2: Tubes Plugged for Indications Other than AVB Wear (cont’d)

STEAM GENERATOR B

Tube Location RFO # Characterization Stabilized

1-34 10 Restriction

1-35 10 Restriction

9-89 18 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

11-88 3C+0.64 21 PLP—26% wall thinning

15-76 TEH 17 Tube end crack N

16-89 18 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

21-10 2C+0.55 14 Confirmed loose part - 28% wall thinning - part not removed Y

21-11 2C+0.76 18 PLP – 29% wall thinning (periphery) Y

22-10 2C+0.88 14 Confirmed loose part – 18% wall thinning - part not removed Y

22-11 2C+0.67 14 Confirmed loose part – 16% wall thinning - part not removed Y

22-82 TSH+0.14 18 PLP – 55% wall thinning (not periphery) N

32-65 18 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

35-41 18 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

36-27 TSC+0.17 18 PLP – 45% wall thinning (not periphery) N
3-305

Table 3-48: Surry 2: Tubes Plugged for Indications Other Than AVB Wear (cont’d)

STEAM GENERATOR C

Tube Location RFO # Characterization Stabilized

1-36 TEH 9 Restriction

1-51 TEH 17 Tube end crack N

1-59 TEC 9 Restriction

1-63 TEH 17 Tube end crack N

2-28 18 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

2-30 18 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

20-57 18 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

21-22 18 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

23-40 18 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

25-13 TSC+2.2 11 Pitlike indication

31-27 TSH 9 Single axial anomaly

31-28 TSH-0.1 15 CLP—98% wall thinning – part not removed Y

32-28 TSH-0.06 15 CLP—90% wall thinning – part not removed Y

33-37 BPH+0.24 17 PLP—16% wall thinning – part not removed Y

33-39 BPH 18 PLP Y

34-35 BPH+0.51 17 PLP—12% wall thinning – part not removed Y

34-36 BPH+0.56 17 PLP—18% wall thinning – part not removed Y

34-39 BPH+0.55 18 PLP—31% wall thinning (not periphery) Y

34-73 TSH 9 Single axial anomaly

35-17 TSH+1.35 15 CLP—42% wall thinning – part removed N

35-37 BPH+0.56 18 PLP—25% wall thinning (not periphery) Y

35-38 BPH 18 PLP Y

35-39 BPH+0.53 18 PLP—26% wall thinning (not periphery) Y

35-43 18 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

35-68 TSH 9 Multiple axial anomaly

35-69 TSH+0.09

TSH+0.13

18 PLP—26% and 44% wall thinning (not periphery) N

35-70 TSH+0.19 15 PLP—42% wall thinning N

35-71 TSH+0.26 18 PLP—41% wall thinning (not periphery) N

35-73 TSH+0.16 15 PLP—63% wall thinning N

35-75 18 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

36-37 BPH+0.55 18 PLP—22% wall thinning (not periphery) Y

36-70 TSH-0.03 15 PLP—59% wall thinning N

37-36 TSH+0.54 15 PLP—49% wall thinning N

38-54 TSH+0.18 18 PLP—40% wall thinning (not periphery) N

41-61 TSH+0.33 15 PLP—41% wall thinning N
3-306

Table 3-49: Turkey Point 3: Summary of Bobbin Inspections and Tube Plugging

Insp. Plug DePl Insp. Plug DePl Insp. Plug DePl

Pre-op 13 7 19 39 0 39 

RFO 8 10/01/1983 1.4 0 0 0 0 0 39 

RFO 9 06/01/1985 2.4 276 0 420 4 199 0 4 0 43 

RFO 10 06/13/1987 3.6 324 0 332 0 373 1 1 0 44 

RFO 11 03/13/1990 5.0 3203 2 3205 3 3194 6 11 0 55 

RFO 12 10/18/1992 6.2 3199 1 3200 1 3188 5 7 0 62 

RFO 13 04/25/1994 7.4 3198 1 3199 1 3183 2 4 0 66 

RFO 14 09/19/1995 8.7 3197 0 3198 2 3181 0 2 0 68 

RFO 15 03/19/1997 10.0 3197 3 3196 9 3181 2 14 0 82 

RFO 16 10/08/1998 11.4 3194 0 3187 1 3179 0 1 0 83 

RFO 17 03/15/2000 12.7 1609 25 1601 28 1627 16 69 0 152 

RFO 18 10/13/2001 14.2 3169 1 3158 11 3163 2 14 0 166 

RFO 19 03/13/2003 15.5 3168 1 3147 2 3161 0 3 0 169 

RFO 20 10/14/2004 17.0 3167 0 3145 0 3161 0 0 0 169 

RFO 21 04/09/2006 18.1 0 0 169 

RFO 22 10/09/2007 19.4 3167 0 3145 0 3161 1 1 0 170 

RFO 23 05/08/2009 0 0 170 

RFO 24 11/07/2010 22.2 3167 1 3145 5 3160 8 14 0 184 

RFO 25 08/20/2012 0 0 184 

RFO 26 04/24/2014 24.7 3166 0 3140 6 3152 0 6 0 190 

Totals: 48 0 80 0 62 0 190 0

Plant Data Acronyms

Model: 44F Pre-op = prior to operation

T-hot (approximate): Cumul. = cumulative

Tubes per steam generator: 3214 Insp. = number of tubes inspected

Number of steam generators: 3 Plug = number of tubes plugged

DePl = number of tubes deplugged

RFO = refueling outage

Notes

1. Number of tubes plugged inferred from other inspection results.

2. Extent of inspections not readily available. No tubes were plugged during this outage.

3. The U-bend region of the row 1 and 2 tubes was not inspected with a bobbin probe. The U-bend region of 50% of the row 1 and 2 tubes was 

 with a rotating probe.

4. No steam generator tube inspections were performed.

Total 

DePl Outage

Completion 

Date

Cumul. 

EFPY

SG A SG B SG C 

Cumul. 

Plugged

Total 

Plug 
3-307

Table 3-50: Turkey Point 3: Causes of Tube Plugging

1983 1985 1987 1990 1992 1994 1995 1997 1998 2000 2001 2003 2004 2006 2007 2009 2010 2012 

Pre-Op RFO 8 RFO 9 RFO 10 RFO 11 RFO 12 RFO 13 RFO 14 RFO 15 RFO 16 RFO 17 RFO 18 RFO 19 RFO 20 RFO 21 RFO 22 RFO 23 RFO 24 RFO 25 RFO 

AVB 7 3 3 1 1 1 5 1 1 1 

Preheater TSP (D5) 

TSP 12 2 

Confirmed 

Not confirmed, 

periphery 2 

Not confirmed, not 

periphery 2 

From PSI, no 

progression 1 1 

Service-induced 

Preservice 39 1 

Other 1 9 

Probe lodged 

Data quality 

Dent/geometry 

Permeability 

Not inspected 

Top of tubesheet 3 1 2 1 8 64 

Freespan 4 1 3 

TSP 1 2 

Other/not reported 

ID 

OD 

TOTALS 39 0 4 1 11 7 4 2 14 1 69 14 3 0 0 1 0 14 0 

Notes: 1 2 2, 3 4 5

Notes

1. Volumetric and circumferential indications were detected in 64 tubes. Many of these indications were reclassified after the outage as not service induced degradation.

2. One row 1 tube was plugged since a plus-point probe inspection could not be performed in the U-bend area (restriction attributed to ovalization as a result of bending during fabrication).

3. One row 21 tube was plugged as a result of a manufacturing indication in the U-bend region. The indication is volumetric in nature and has not exhibited any evidence of change since the preservice inspection.

4. Tube plugged as a result of an outside diameter initiated volumetric indication located approximately 6 inches below the top of the tubesheet on the hot-leg side, which was attributed to manufacturing/fabrication.

5. Nine tubes were plugged since the tubes were not expanded into the tubesheet region.

Year

Wear

Loose Parts

Obstruction 

Restriction

Cause of Tube Plugging/Outage

Manufacturing 

Flaws

Inspection 

Issues

Other

SCC
3-308

Table 3-51: Turkey Point 3: Tubes Plugged for Indications Other Than AVB Wear

STEAM GENERATOR A

Tube Location RFO # Characterization Stabilized

3-80 TSH-0.08 17 Circumferential indication (reclassified as no service-related 

degradation)

Y

9-32 4H 11 ≥40% throughwall indication

10-31 TSH-0.15 17 Circumferential indication (reclassified as no service-related 

degradation)

Y

13-5 TSH+3.8 15 No characterization provided

16-64 TSH-0.09 17 Circumferential indication (reclassified as no service-related 

degradation)

Y

17-15 TSH+0.05 17 Circumferential indication (reclassified as no service-related

degradation)

Y

17-33 TSH+0.15 17 Circumferential indication (reclassified as no service-related 

degradation)

Y

18-83 TSH+0.11 17 Volumetric indication (reclassified as a pit)

18-84 TSH+0.16 17 Volumetric indication (reclassified as a pit)

19-84 TSH+0.91

TSH+0.46

17 Volumetric indication (reclassified as a pit)

21-32 6H+2.3 12 44% throughwall indication

21-38 AV2+11.25 19 Volumetric manufacturing indication - present during preservice 

inspection

21-87 TSH+0.68 17 Volumetric indication (reclassified as no service-related degradation)

28-75 TSH+0.15 17 Volumetric indication (reclassified as a pit)

29-75 TSH+0.14 17 Volumetric

30-65 TSH+0.24 17 Volumetric indication (reclassified as no service-related degradation)

31-18 6H+1.1 15 Volumetric

31-77 TSH+0.1 17 Volumetric indication (reclassified as a pit)

32-15 1H-0.45 18 Wear

32-23 TSH-0.05 17 Circumferential indication (reclassified as no service-related 

degradation)

Y

32-47 TSH 24 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

32-63 TSH+0.05 17 Circumferential indication (reclassified as a volumetric indication) Y

32-64 TSH-0.01 17 Circumferential indication (reclassified as no service-related 

degradation)

Y

33-35 TSH-0.02 17 Circumferential indication (reclassified as a pit) Y

33-78 TSH+0.65 17 Volumetric indication (reclassified as no service-related degradation)

34-25 TSH-0.08 17 Circumferential indication (reclassified as no service-related 

degradation)

Y

35-65 TSH+0.98 17 Volumetric indication (reclassified as no service-related degradation)

36-69 TSH+0.21 17 Volumetric

38-66 TSH+0.23 17 Volumetric indication (reclassified as no service-related degradation)

39-67 TSH-0.05 17 Volumetric indication (reclassified as no service-related degradation)

44-36 TSH+0.7 15 Volumetric
3-309

Table 3-51: Turkey Point 3: Tubes Plugged for Indications Other Than AVB Wear 

(cont’d)

STEAM GENERATOR B

Tube Location RFO # Characterization Stabilized

1-3 18 Restriction in U-bend

1-14 TSH-0.28 17 Circumferential indication (reclassified as no service-related 

degradation)

Y

1-86 19 Restriction in U-bend

1-87 TSC 24 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

3-43 TSH+0.99 26 PLP – 31% wall thinning (periphery)

5-65 2H-0.84 26 TSP wear—25% wall thinning

6-45 2C 24 PLP—8% wall thinning N

7-45 2C 24 PLP—14% wall thinning N

7-92 TSH+0.57 17 Volumetric indication (reclassified as no service-related degradation)

8-8 1H+0.7 13 44% throughwall indication

15-17 TSH-0.06 17 Circumferential indication (reclassified as no service-related 

degradation)

Y

15-76 3H-0.7 18 Wear

18-80 2H-0.90 26 TSP wear—35% wall thinning

19-6 TSH 24 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

19-10 TSH+0.24 17 Volumetric indication (reclassified as a pit)

19-12 TSH+0.54 17 Volumetric indication (reclassified as a pit)

19-13 TSH+0.25 17 Volumetric indication (reclassified as a pit)

19-14 TSH+0.29 17 Volumetric indication (reclassified as a pit)

20-10 TSH+0.03 17 Volumetric indication (reclassified as a pit)

20-12 TSH+0.21 17 Volumetric indication (reclassified as a pit)

20-13 TSH+0.03 17 Volumetric indication (reclassified as a pit)

21-56 TSH+0.43 17 Volumetric indication (reclassified as no service-related degradation)

22-53 TSH+0.58 17 Volumetric indication (reclassified as no service-related degradation)

23-7 TSH+0.58 17 Volumetric indication (reclassified as no service-related degradation)

23-41 3C+0.5 15 Volumetric

23-71 2C-20.90 26 Permeability variation

24-8 TSH 24 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

25-32 4H+0.0 9 31% throughwall indication

25-34 TSH+0.2 17 Volumetric indication (reclassified as no service-related degradation)

26-71 TSH+0.12 17 Volumetric indication (reclassified as no service-related degradation)

26-77 2H-0.48 18 Wear

27-41 3C+0.59 18 Wear

27-42 3C+0.59 18 Wear
3-310

Table 3-51: Turkey Point 3: Tubes Plugged for Ind. Other Than AVB Wear (cont’d)

STEAM GENERATOR B

Tube Location RFO # Characterization Stabilized

28-41 3C+0.69

3C+0.61

18 Wear

30-17 2C+0.56 18 Wear

32-19 2H-0.61 18 Wear

32-66 2H-084 18 Wear

33-70 TSH-0.06 17 Circumferential indication (reclassified as no service-related 

degradation)

Y

34-57 TSH+0.1 17 Volumetric indication (reclassified as a pit)

37-20 TSH+0.4 15 Volumetric

37-46 TSH+0.04 17 Volumetric indication (reclassified as a pit)

38-39 TSH+0 17 Circumferential indication (reclassified as a volumetric) Y

38-45 TSH+0.16 17 Circumferential indication (reclassified as a pit) Y

38-46 TSH+0.59 17 Volumetric indication (reclassified as a pit)

38-69 2H+0.99 18 Wear

39-39 5H+0.8 15 Volumetric

39-59 TSH+0.19 17 Volumetric indication (reclassified as no service-related degradation)

39-64 FBH-0.33 26 TSP wear—26% wall thinning

40-39 5H 11 ≥40% throughwall indication

41-43 TSH+0.04 17 Volumetric indication (reclassified as no service-related degradation)

41-44 TSH+0.6 15 Volumetric

41-65 TSH+0.63 17 Volumetric indication (reclassified as no service-related degradation)

42-30 TSH+0.4 9 36% throughwall indication

42-37 TSH+0.7 14 44% throughwall indication

42-38 TSH+1.5 15 Volumetric

43-33 TSH+0.14 17 Volumetric indication (reclassified as a pit)

43-45 FBH-0.27 26 TSP wear—26% wall thinning

44-40 TSH+0.3

TSH+1.8

15 82% throughwall volumetric indication, pit

44-41 TSH+0.2

TSH+0.4

TSH+0.5

15 Volumetric

44-42 TSH+0.4 17 Volumetric indication (reclassified as a pit)

45-41 TSH+0.6 15 Adjacent to a loose part so tube was plugged.

45-42 TSH+1.3 15 Adjacent to a loose part so tube was plugged.

45-43 TSH+0.6

TSH+0.8

9 56% throughwall indication

45-44 TSH+3.6

TSH+3.8

9 39% throughwall indication. Tube was replugged in RFO13 since plug 

was leaking

45-47 TSH+0.64 17 Volumetric indication (reclassified as no service-related degradation)
3-311

Table 3-51: Turkey Point 3: Tubes Plugged for Indications Other Than AVB Wear 

(cont’d)

STEAM GENERATOR C

Tube Location RFO # Characterization Stabilized

1-20 TSH-0.12 17 Circumferential indication (reclassified as no service-related 

degradation)

Y

2-55 TSC+24.1 12 60% throughwall indication

2-70 2C+0.7 12 45% throughwall indication

3-46 TSH-0.08 17 Circumferential indication (reclassified as no service-related 

degradation)

Y

3-82 TSH 24 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

3-83 TSH 24 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

3-85 TSH 24 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

5-23 TSH 24 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

7-3 TSH+0.09 17 Volumetric indication (reclassified as no service-related degradation)

13-89 TSC 11 ≥40% throughwall indication

14-6 TSH 11 ≥40% throughwall indication

14-89 CL 10 48% throughwall indication in sludge pile

15-44 TSH+0.03 17 Circumferential indication (reclassified as no service-related 

degradation)

Y

19-85 2H-0.78 18 Wear

20-66 6C+2.4 12 41% throughwall indication

20-67 TSH-6.01 22 Volumetric indication (OD initiated) within tubesheet – attributed to 

manufacturing/fabrication

21-61 4H-0.76 24 TSP wear—37% wall thinning

22-7 TSH+0.55 17 Volumetric indication (reclassified as no service-related degradation)

23-7 TSH+0.59 17 Volumetric indication (reclassified as no service-related degradation)

29-77 3H-0.81 24 TSP wear—31% wall thinning

30-69 TSH-0.03 17 Circumferential indication (reclassified as no service-related 

degradation)

Y

31-24 TSH+0.16 17 Circumferential indication (reclassified as a volumetric indication) Y

32-64 2H-0.59 18 Wear

33-66 TSH+0.6 15 58% throughwall indication

34-40 TSH-0.08 17 Circumferential indication (reclassified as no service-related 

degradation)

Y

34-66 TSH+0.23 17 Volumetric indication (reclassified as no service-related degradation)

36-74 TSH-0.07 17 Circumferential indication (reclassified as no service-related 

degradation)

Y

39-49 TSH-0.01 17 Volumetric

40-49 TSH+0.06 17 Circumferential indication (reclassified as a volumetric indication) Y

41-43 TSH 24 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

45-49 TSH+2.89 17 Volumetric indication (reclassified as no service-related degradation)
3-312

Table 3-52: Turkey Point 4: Summary of Bobbin Inspections and Tube Plugging

Insp. Plug DePl Insp. Plug DePl Insp. Plug DePl

Pre-op 15 7 9 31 0 31 

RFO 9 05/15/1984 0.65 211 0 162 0 502 0 0 0 31 

RFO 10 03/16/1986 328 0 318 0 345 0 0 0 31 

RFO 11 11/15/1988 3199 1 3207 0 3205 0 1 0 32 

RFO 12 05/13/1991 3198 0 3207 1 3205 0 1 0 33 

RFO 13 04/28/1993 3198 0 3206 0 3205 0 0 0 33 

RFO 14 10/17/1994 3198 0 3206 0 3205 0 0 0 33 

RFO 15 03/01/1996 0 0 33 

RFO 16 09/22/1997 3198 0 3206 0 3205 0 0 0 33 

RFO 17 03/01/1999 0 0 33 

RFO 18 10/09/2000 1602 3 1604 5 1607 2 10 0 43 

RFO 19 04/07/2002 0 0 43 

RFO 20 10/20/2003 3195 4 3201 0 3203 0 4 0 47 

RFO 21 06/12/2005 16.46 0 0 47 

RFO 22 11/16/2006 17.7 3191 6 3201 0 3203 0 6 0 53 

RFO 23 05/09/2008 18.96 0 0 53 

RFO 24 11/13/2009 20.37 3185 4 3201 7 3203 0 11 0 64 

RFO 25 04/30/2011 21.61 0 0 64 

RFO 26 04/06/2013 23.05 3181 0 3194 1 3203 0 1 0 65 

Totals: 33 0 21 0 11 0 65 0

Plant Data Acronyms

Model: 44F Pre-op = prior to operation

T-hot (approximate): 610 °F Cumul. = cumulative

Tubes per steam generator: 3214 Insp. = number of tubes inspected

Number of steam generators: 3 Plug = number of tubes plugged

DePl = number of tubes deplugged

RFO = refueling outage

Notes

1. Number of tubes plugged was deduced based on information provided in various reports.

2. No steam generator tube inspections were performed.

3. The U-bend region of the row 1 and 2 tubes was not inspected with a bobbin probe. The U-bend region of 30% of the row 1 and 2 tubes was inspecte

 with a rotating probe.

4. The U-bend region of the row 1 and 2 tubes was not inspected with a bobbin probe. The U-bend region of 50% of the row 1 and 2 tubes was inspecte

 with a rotating probe.

5. The U-bend region of the row 1 and 2 tubes was not inspected with a bobbin probe. The U-bend region of 100% of the row 1 and 2 tubes was inspec

 with a rotating probe.

Outage

Completion 

Date

Cumul. 

EFPY

SG A SG B SG C P

P

Cumul. 

Plugged

Total 

Plug

Total 

DePl
3-313

Table 3-53: Turkey Point 4: Causes of Tube Plugging

1984 1986 1988 1991 1993 1994 1996 1997 1999 2000 2002 2003 2005 2006 2008 2009 2011 2

Pre-Op RFO 9 RFO 10 RFO 11 RFO 12 RFO 13 RFO 14 RFO 15 RFO 16 RFO 17 RFO 18 RFO 19 RFO 20 RFO 21 RFO 22 RFO 23 RFO 24 RFO 25 RFO 

AVB 1 1 

Preheater TSP (D5) 

TSP 1 2 

Confirmed 

Not confirmed, 

periphery 1 6 

Not confirmed, not 

periphery 

From PSI, no 

progression 

Service-induced 1 1 

Preservice 31 

Other 10 

Probe lodged 

Data quality 

Dent/geometry 

Permeability 1 

Not inspected 

Top of tubesheet 7 

Freespan 1 

TSP 

Other/not reported 

ID 

OD 

TOTALS 31 0 0 1 1 0 0 0 0 0 10 0 4 0 6 0 11 0 

Notes: 1 2 

Notes

1. One tube was plugged since it was damaged during loose part retrieval activities.

2. Nine tubes were plugged because they were not expanded into the tubesheet region. One tube was plugged since the bottom of the expansion transition was greater than 1-inch below the top of the tubesheet.

3. Wear at tube support plate associated with a possible loose part.

Cause of Tube Plugging/Outage

Manufacturing 

Flaws

Other

SCC

Obstruction 

Restriction

Inspection 

Issues

Year

Wear

Loose Parts
3-314

Table 3-54: Turkey Point 4: Tubes Plugged for Indications Other Than AVB Wear

STEAM GENERATOR A

Tube Location RFO # Characterization Stabilized

2-5 HL Tubesheet 11 Clamp stuck inside tube. Attempts to retrieve were unsuccessful.

3-1 FBH-0.38 20 Pit-shaped wear

5-4 TSC 24 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

12-25 18 Permeability signal in Expansion Transition Area

18-44 TSH 24 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

23-10 FBH+0.34 20 PLP wear

23-62 TSH 24 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

26-80 TSH+2.27 18 Pit

33-73 TSH+0.17 18 Volumetric indication

33-78 24 Wear and dent at AVB

35-68 TSC-0.05 22 PLP wear

35-69 TSC-0.01 22 PLP wear

35-70 TSC+0.01 22 PLP wear

35-71 TSC+0.00 22 PLP wear

35-72 TSC+0.03 22 PLP wear

36-74 TSC+0.04 22 PLP wear

40-28 FBH-0.22 20 Pit-shaped wear

45-45 TSC+12.15 20 Wear because of maintenance
3-315

Table 3-54: Turkey Point 4: Tubes Plugged for Indications Other Than AVB Wear 

(cont’d)

STEAM GENERATOR B

Tube Location RFO # Characterization Stabilized

2-90 FBH-0.46 18 Wear

5-66 TSH 24 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

8-81 TSH-2.0 12 Restriction

9-12 TSH 24 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

10-67 TSH 24 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

12-39 TSH 24 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

17-74 1H+0.70 26 PLP wear Y

20-80 TSH 18 Pit

21-80 TSH+0.05 18 Pit

23-12 TSC 24 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

24-19 TSH 24 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

29-62 TSH+0.12 18 Pit

31-37 TSH 24 Bottom of expansion transition greater than 2.54 cm (1 in.) below top of 

tubesheet

43-51 TSH-0.04 18 Pit

STEAM GENERATOR C

Tube Location RFO # Characterization Stabilized

3-91 TSH+0 18 Pit

4-1

4 SUMMARY

The following section summarizes the operating experience presented in Section 3. Summaries 

are provided for each of the three groupings of units (i.e., model D5, model F, and replacement 

models) and an overall summary. The overall summary includes discussions on forced outages 

and unplanned inspections, tubes removed for laboratory examination, corrosion of tubes, 

degradation in the steam generator channel head and of steam generator secondary-side

internals, tube wear, and observations about the results from the inspections. Although 

Section 3 only summarizes the operating experience from January 2002 through December 

2013, this section summarizes the operating experience since the steam generators were 

placed in service.

4.1 Model D5 Summary

There are a total of 73,120 thermally treated tubes in the four units with model D5 steam 

generators. Cumulatively, these four units have operated for 99 calendar years as of 

December 2013, and have commercially operated for an average of 25 calendar years as of 

December 2013. These four units have operated for an average of 21.7 effective full power 

years as of December 2013. Of the 73,120 tubes in these steam generators, only 1,068 tubes 

(1.5 percent) have been plugged. This information is summarized in Table 4-1.

Table 4-2 summarizes the number of tubes plugged in the model D5 steam generators as a

function of the degradation mechanism. The information in this table is graphically depicted in 

Figure 4-1. As can be seen from the figure, approximately 33 percent of the tubes were 

plugged because of wear at tube supports. This wear occurred predominantly at the antivibration bars (AVBs), although some occurred at tube support plates. With only 30 tubes being 

plugged for wear in the preheater region, it appears that the tube expansion at the preheater 

baffle plates (as discussed in Section 2.2) was successful in mitigating this phenomenon. 

In addition to tube wear, many (32 percent) of the tubes were plugged because of loose parts. 

This includes tubes that had wear attributed to loose parts and also includes tubes that had no 

wear, but were plugged since they were near a loose part that was not removed.

Figures 4-2a and 4-2b depict the number of tubes plugged at each unit as a function of year. 

Figure 4-3 depicts the number of tubes plugged at each unit as a function of refueling outage. 

These figures indicate, for the most part, that the four units are operating similarly. The data 

supporting Figures 4-2a and 4-2b are contained in Tables 4-3 and 4-4. The data supporting 

Figure 4-3 are contained in Table 4-5.

Figure 4-4 depicts the percentage of tubes plugged for a specific mechanism as a function of 

year. This figure was developed from the data provided in Tables 4-6, 4-7, and 4-8. In this 

figure, tubes plugged before commercial operation were treated as being plugged during the 

year the unit began commercial operation (in previous tables and figures in this report, tubes 

plugged before operation were treated as a distinct group independent of the actual year/outage 

in which they were plugged).

Tables 3-1, 3-4, 3-7, and 3-10 indicate that all units with D5 steam generators except for 

Comanche Peak 2 inspect 100 percent of the tubes with a bobbin coil probe in all four steam 

generators during each refueling outage. At Comanche Peak 2, a sampling approach is used 

and inspections are performed every other refueling outage.
4-2

4.2 Model F Summary

There are a total of 117,376 thermally treated tubes in the six units that originally installed model 

F steam generators in their units. However, with the replacement of the model F steam 

generators at Callaway in 2005, there are only 112,520 thermally treated tubes in the five units 

currently operating with originally installed model F steam generators. Cumulatively, the six 

units have operated for about 152 calendar years as of December 2013, and have commercially 

operated for an average of 25 calendar years as of December 2013. These numbers reflect the 

amount of time Callaway operated with their original model F steam generators. The five 

currently operating units with model F steam generators have commercially operated for an 

average of 26 calendar years as of December 2013 and have operated for an average of 22.1 

effective full power years as of December 2013. Of the 117,376 tubes in these steam 

generators, only 871 tubes (0.7 percent) have been plugged. This information is summarized in 

Table 4-9.

Table 4-10 summarizes the number of tubes plugged in the model F steam generators as a 

function of degradation mechanism. The information in this table is graphically depicted in 

Figure 4-5. As can be seen from the figure, about 56 percent of the tubes were plugged 

because of wear at tube supports. This wear occurred predominantly at the AVBs. Only 

11 tubes have been plugged for wear at the tube support plates. After wear at tube supports, 

cracking is the next dominant degradation mechanism in model F steam generators. Twelve 

percent of the tubes were plugged because of cracking.

The wear at the AVBs in model F steam generators is primarily observed in the tubes in row 20 

and higher on the periphery and row 30 and higher in the middle of the tube bundle. At least 

one licensee has reported that the AVB wear flaws in the middle of the tube bundle tend to be 

shallower than those on the periphery. In addition, several licensees reported that the average 

AVB wear rate generally decreases with time.

Figures 4-6a and 4-6b depict the number of tubes plugged at each unit as a function of year. 

Figure 4-7 depicts the number of tubes plugged at each unit as a function of refueling outage. 

These figures indicate, for the most part, that the six units are operating similarly. The data 

supporting Figures 4-6a and 4-6b are contained in Tables 4-11 and 4-12. The data supporting 

Figure 4-7 are contained in Table 4-13.

Figure 4-8 depicts the percentage of tubes plugged for a specific mechanism as a function of 

year. This figure was developed from the data provided in Tables 4-14, 4-15, and 4-16. In this 

figure, tubes plugged before commercial operation were treated as being plugged during the 

year the unit began commercial operation (in previous tables and figures in this report, tubes 

plugged before operation were treated as a distinct group independent of the actual year/outage 

in which they were plugged).

Tables 3-13, 3-16, 3-19, 3-22, 3-25, and 3-28 indicate that most units with model F steam 

generators typically inspect 100 percent of the tubes with a bobbin coil probe in two of the four 

steam generators each refueling outage. Recently, however, Wolf Creek has started to sample 

a subset of the tubes in each of the four steam generators every refueling outage.
4-3

4.3 Replacement Model Summary

There are a total of 90,766 tubes in the eight units with replacement steam generators that 

contain thermally treated Alloy 600 tubes. Cumulatively, these eight units have operated for 

approximately 217 calendar years as of December 2013, and have commercially operated for 

an average of 27 calendar years as of December 2013. These eight units have operated for an 

average of 22.0 effective full power years as of December 2013. Of the 90,766 tubes in these 

steam generators, only 795 tubes (0.9 percent) have been plugged. This information is 

summarized in Table 4-17.

Table 4-18 summarizes the number of tubes plugged in the replacement model steam 

generators as a function of degradation mechanism. The information in this table is graphically 

depicted in Figure 4-9. As can be seen from the figure, approximately 40 percent of the tubes 

were plugged because of wear at tube supports. This wear occurred predominantly at the 

AVBs. Only 18 tubes have been plugged for wear at the tube support plates. After wear at tube 

supports, the category with the next highest number of tubes being plugged is manufacturing.

Figures 4-10a and 4-10b depict the number of tubes plugged at each unit as a function of year. 

Figure 4-11 depicts the number of tubes plugged at each unit as a function of refueling outage. 

These figures indicate, for the most part, that the eight units are operating similarly with the 

possible exception of Salem 1, which has Model F steam generators, and Turkey Point 3. Both 

of these units have plugged significantly more tubes than the other units. The data supporting 

Figures 4-10a and 4-10b are contained in Tables 4-19 and 4-20. The data supporting 

Figure 4-11 are contained in Table 4-21.

Figure 4-12 depicts the percentage of tubes plugged for a specific mechanism as a function of 

year. This figure was developed from the data provided in Tables 4-22, 4-23, and 4-24. In this 

figure, tubes plugged before commercial operation were treated as being plugged during the 

year the unit began commercial operation (in previous tables and figures in this report, tubes 

plugged before operation were treated as a distinct group independent of the actual year/outage 

in which they were plugged).

Tables 3-31, 3-34, 3-37, 3-40, 3-43, 3-46, 3-49, and 3-52 indicate that units with replacement 

steam generators with thermally treated Alloy 600 tubes have a variety of strategies for 

inspecting their steam generators. Several units inspect a subset of steam generators each 

refueling outage (e.g., one of three steam generators is inspected one outage and the remaining 

two steam generators are inspected the next outage). This is referred to as “skip steam 

generator.” Others inspect all steam generators every other outage (i.e., no tube inspections 

are performed during one refueling outage, but all steam generators are inspected the next 

refueling outage). This schedule is referred to as “skip cycle.” Units that skip cycles or skip 

steam generators typically inspect 100 percent of the tubes in the steam generators inspected.

4.4 Overall Summary

4.4.1 Forced outages and unplanned inspections

As of December 2013, the steam generator operating experience of units with thermally treated 

Alloy 600 has been favorable. These units account for approximately 26 percent of the 

operating pressurized water reactors. A review of the operating experience from units with 

thermally treated Alloy 600 steam generator tubes identified only three unplanned outages 
4-4

because of primary-to-secondary leakage and five unplanned outages because of indications of 

loose parts (e.g., loose parts monitor alarms) as of December 2013. These eight outages are 

discussed below. (During the preparation of this report in the first half of 2014, one other

unplanned outage occurred because of primary-to-secondary leakage. This is briefly discussed 

below.) In addition to these outages, there have been instances where units have shut down 

because of water chemistry issues and there have been instances where inspections had to be 

performed during an outage when no inspections had been planned (e.g., in response to finding 

loose parts on the secondary side of a steam generator).

In three instances, units with thermally treated Alloy 600 tubes have been shut down because of

primary-to-secondary leakage as of December 2013. Byron 2 shut down in June 2002 because 

of a 284- to 303-liter-per-day (lpd) (75- to 80-gallon-per-day (gpd)) primary-to-secondary leak. 

The cause of the leak was wear attributed to two pieces of spiral wound sheathing. The wear 

occurred at tube support 2C in the preheater region of the steam generator. These objects 

damaged three tubes and the tubes were plugged. One tube had a 100 percent throughwall 

flaw (the leaking tube), another tube had a 37 percent throughwall indication, and the last tube 

had two indications measuring 11 percent and 13 percent throughwall.

Byron 2 also shut down in 1996 and entered a refueling outage early because of a 120-gpd 

primary-to-secondary leak. The cause of the leak was a foreign object attributed to 

thermal-cutting debris from a pipe whose diameter was somewhere between 30.5 and 45.7 cm 

(12 and 18 in.). The foreign object was on the secondary side of the steam generator. This 

object damaged four tubes and the tubes were plugged. One tube had a 100 percent

throughwall indication, one had a 56 percent throughwall indication, and the remaining two 

tubes were plugged because of nonquantifiable volumetric indications found by a rotating 

pancake coil probe.

Surry 2 shut down in June 1986 because of a leak in an expansion joint on the service water 

return line from a recirculation spray heat exchanger and to identify the source of a primary-tosecondary leak. Similar to Byron 2, the source of the Surry 2 leak was a tube affected by a 

foreign object. One steam generator tube was plugged because of this outage.

As this report was being prepared, Robinson 2 shut down in March 2014 because of a 144-lpd 

(38-gpd) primary-to-secondary leak. The cause of the leak was wear attributed to a foreign

object that was introduced into the feedwater system during maintenance performed in the 

previous refueling outage (about four months earlier). Only the tube that leaked was plugged 

during this outage.

Other units (e.g., Seabrook, Indian Point 2, Point Beach 1, Robinson 2) have experienced 

leakage (less than 19 lpd (5 gpd)), but the leak rate has been too small to necessitate a unit 

shutdown. The sources of such small amounts of leakage are usually never conclusively 

identified (although in the case of Robinson 2 during refueling outage (RFO) 22 in 2002, the 

source of the leak was identified as wear attributed to a loose part). In addition, this leakage 

may be observed for several cycles. Sometimes leakage is observed when there is a leaking 

fuel assembly (e.g., Robinson 2 before RFO 25 in 2008). Most units with thermally treated Alloy 

600 steam generator tubes operate with no detectable amounts of primary-to-secondary 

leakage.

In five instances, units with thermally treated Alloy 600 tubes have been shut down because of

indications of a loose part in the steam generators. Wolf Creek shut down in May 2002 because 
4-5

of a loose part on the primary side of the steam generator. The part was a control rod guide 

tube support pin nut and locking device.

In February 2000, Point Beach 1 was shut down to investigate indications of loose parts in the 

steam generator. A thorough inspection found no loose parts and the unit was restarted.

In May 1996, Vogtle 1 shut down in response to a possible loose part on the primary side of 

steam generator 4. Upon entering the hot-leg channel head, a support pin nut from a control 

rod guide tube assembly was found. The nut’s locking device was found wedged into the 

bottom of a tube and was subsequently removed. Another object, believed to be a fragment of 

the support pin nut, was found on the cold-leg side of the steam generator. The loose object 

impacted the lower tubesheet on the hot-leg side and numerous indications were noted. The 

hot legs of the other three steam generators did not exhibit any signs of damage. During a 

subsequent steam generator tube inspection, the shank of the broken support pin was found 

lodged in a tube. The shank was left in place and the tube was plugged. Damaged tube ends 

on the tubesheet were rerolled during this outage.

In February 1994, Robinson 2 was shut down for repairs to an emergency diesel generator. 

During this shutdown, the source of a loose parts monitor alarm was investigated. The 

investigation revealed two strips of metal resting on the tubesheet. Their composition was 

similar to that of welding electrodes believed to have been used to fabricate the replacement 

steam generator shell welds. The pieces of metal were removed and two tubes were plugged 

because of localized wear where the metal objects contacted the tubes. Two nearby tubes had 

been plugged in prior outages because of either outside-diameter wear or manufacturing marks. 

These indications may have been related to the loose part.

In April 1989, Robinson 2 was shut down because of audio signals indicating a loose part in the 

hot-leg channel head of steam generator C. When the steam generator manway was opened, a 

loose part fell out. The part was a split pin nut from a control rod guide tube support. 

Examination of the tubesheet, tube ends, tube-to-tubesheet welds, and divider plate welds did 

not reveal conditions that required immediate repair. However, this examination did reveal 

damage to the tubesheet and tube ends on the hot-leg side of steam generator C. This damage 

obliterated some of the tubesheet face markings used to identify tubes on the hot leg, 

complicating the insertion of inspection probes through the hot-leg tube end.

In addition to these forced outages, there have been other instances where tube inspections 

were performed when none had been planned during a scheduled outage (e.g., Robinson 2 in 

2004), and there have been instances where units were shut down because of secondary-side

water chemistry issues (e.g., Vogtle 1 and 2 in 2002, Comanche Peak 2 in 2011). 

4.4.2 Tubes removed for laboratory examination

To characterize eddy current indications found during steam generator tube in-service 

inspections, portions of a few tubes have been removed from steam generators with thermally 

treated Alloy 600 tubes. Based on information supplied to the NRC, tubes have been removed 

six times from units with thermally treated Alloy 600 steam generator tubes as of December 

2013: Vogtle 1, Vogtle 2, Seabrook, Byron 2, and Surry 1 (twice). The results of these 

examinations are discussed below.

In 2008, Vogtle 1 removed portions of two tubes to characterize outside-diameter initiated 

indications at the top of the tubesheet on the hot-leg side of the steam generator. One of the 
4-6

tubes had an axial indication and the other tube had a circumferential indication. The 

destructive examination of the pulled tubes confirmed the presence of outside-diameter initiated 

intergranular stress corrosion cracking within the expansion transition at the top of the 

tubesheet. Three axial cracks were found in one of the tubes. The cracks were 

circumferentially separated by about 55 degrees and were 100 percent throughwall. The 

maximum depth of these indications was estimated by eddy current to be approximately 

77 percent throughwall. Circumferential cracking was found around the entire circumference of 

the other tube. The maximum depth from the destructive examination was 80 percent

throughwall whereas the eddy current examination estimated the flaws to be 54 percent

throughwall. The percent degraded area was 21 percent from the destructive examination and 

was estimated to be 7.3 percent from the eddy current inspection. Both tubes were burst tested 

and both had burst pressures in excess of three times the normal operating differential 

pressure. The microstructure indicated relatively low amounts of intergranular carbides and 

high amounts of intragranular carbides indicating that the mill annealing temperature may have 

been too low to put carbon/carbides into solution. Carbon in solution is necessary for the 

thermal treatment process to precipitate the carbides at the grain boundaries (and thereby 

improve corrosion resistance). More information concerning the results of destructive and 

nondestructive examination of these pulled tubes can be found in the pulled tube report 

(ADAMS Accession No. ML100560265).

In 2004, Vogtle 2 removed portions of two tubes to characterize circumferential indications at 

the expansion transition, which were thought to be circumferentially oriented outside-diameter 

stress corrosion cracks. The laboratory examination indicated that both pulled tubes exhibited a 

ring of gray/brownish deposit at, and slightly above, the expansion transition region. The height 

of this deposit was about 12.7 mm (0.5 in.), and it was about 0.1 to 0.2 mm (4 to 8 mils) in 

thickness. A dark grayish deposit was observed extending about 2.54 cm (1 in.) to 3.8 cm 

(1.5 in.) above the collar deposit on both tubes. A relatively thin and uniform gray oxide was 

noted on all remaining tube surfaces above the top of the tubesheet region. Although laboratory 

eddy current and ultrasonic testing were able to detect signals that indicate deposits, none of 

the field signals indicative of crack-like indications were present in the laboratory obtained data. 

Destructive (metallographic) examination of the top of the tubesheet region of one tube showed 

no evidence of degradation. Although the tube had copper and lead in the oxide deposit, 

corrosion had not started. Metallographic examination was not performed on the portion of the 

second tube. The root cause of the field flaw-like signals was not identified; however, the 

licensee concluded that the false positive indications could be the result of the nonhomogeneous scale or deposits on the tubes at the top of the tubesheet on the hot-leg side of 

the steam generators.

In 2002, Seabrook removed portions of two tubes to investigate the nature of axial-crack-like 

indications, which were observed at the hot- and cold-leg tube support plates. All of the 

indications were on the portion of the tube within the thickness of the tube support plate and 

opposite the broached tube hole lands. The destructive examination confirmed the presence of 

cracks in these tubes, representing the first confirmed instance of cracking in thermally treated 

Alloy 600 tubes. The root cause evaluation, including the destructive examination of these two 

pulled tubes, confirmed that the indications were axially oriented outside-diameter stress 

corrosion cracking, and also identified unusually high levels of residual stress in the straight leg 

sections of both the hot and cold legs. Nonoptimal tube processing during steam generator 

manufacturing was strongly suspected to be the primary cause of the high residual stresses and 

the principal factor increasing the susceptibility of the affected tubes to stress corrosion 

cracking. The precise processing steps responsible for the adverse stress state could not be 

conclusively determined from a review of the tube processing records. More information 
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concerning the results of destructive and non-destructive examination of these pulled tubes can 

be found in the pulled tube report (ADAMS Accession No. ML023240524).

In 1998, Byron 2 removed portions of three tubes with circumferential indications at the hot-leg 

expansion transition region for destructive examination. Twenty-nine tubes with circumferential 

indications were identified, stabilized, and plugged during this outage. According to the 

preliminary tube pull results, the circumferential indications were not service-induced cracking or 

corrosion but shallow grooves that may have been introduced during initial steam generator 

fabrication or the first few cycles of operation. Burst testing of the indications showed that the 

indications did not affect the structural integrity of the tubes. Final results from these 

examinations were not readily available.

In 1990, portions of two tubes were removed from Surry 1 to examine axial and circumferential 

anomalies at the top of the tubesheet and were subsequently plugged. The examination found 

no operationally induced degradation of the tube wall on either of these tubes. Field 

nondestructive examination results suggested the presence of circumferentially oriented 

degradation. Upon further review of the nondestructive examination results for one of the pulled 

tubes, the licensee concluded that the poorly defined rotating pancake coil signal was similar to 

that of a ding or mechanical deformation. For the other pulled tube, a 70-degree groove, 

mechanical in nature, was found on the outside diameter of the tube and attributed to the 

interaction of the tube with the edge of the tubesheet during the expansion process. Although 

the hydraulic expansion process used was designed to position the transition slightly below the 

top of the tubesheet, the licensee concluded that this tube was overexpanded above the top of 

the tubesheet. In summary, destructive examination of the pulled tube segments detected no 

corrosion. The nondestructive examination indications were attributed to probe liftoff in the 

expansion transition and to the tube installation process.

Portions of one tube were removed from steam generator C at Surry 1 in 1986 to examine an 

eddy current indication near the uppermost (seventh) tube support plate. The indication was 

thought to be caused by conductive deposits on the outside surface of the tubes. The tube pull 

confirmed the absence of degradation where eddy current testing had suggested degradation.

Although tube wear (from support structures and loose parts) is the dominant degradation 

mechanism, no tubes have been pulled from units with thermally treated Alloy 600 to 

characterize these indications.

4.4.3 Corrosion of tubes

Steam generator tubes have experienced degradation because of corrosion mechanisms. This 

degradation was widespread in steam generators with mill-annealed Alloy 600 tubes. In units 

with thermally treated Alloy 600 tubes, the number of instances of tube degradation because of

corrosion has been limited. Two types of corrosion mechanisms have been observed: pitting 

and cracking.

Only four units with thermally treated Alloy 600 steam generator tubes have potentially 

experienced tube degradation because of pitting: Surry 1 and 2, and Turkey Point 3 and 4. 

These units were the first to use thermally treated Alloy 600 tubes in their steam generators. 

At Surry 2 in the mid-1990s, a limited number of pitlike indications were detected above the 

tubesheet on the cold-leg side of the steam generator. A rotating pancake coil terrain plot 

display was used as the primary basis for classifying the signals as pitlike indications. 

The indications were nearly round and were in the cold leg above the tubesheet expansion 
4-8

transition, where pitting might be expected given the chemistry conditions. Some of these tubes 

with pitlike indications were initially left in service. The pitting is believed to have initiated before 

the chemical cleaning that was performed in 1994. New pits are unlikely to initiate in future 

cycles because the copper-rich sludge, the major contributor to pitting, is being removed, and 

improvements were made to the chemistry control program. All 12 tubes with pitlike indications 

at Surry 2 were plugged because of the uncertainty in nondestructive sizing estimates.

The number of tubes in which pits have been observed is small (fewer than 30 tubes), and all 

but one of the tubes with pits have been removed from service. The one pit indication currently

being reported in an active tube is at Surry 1. No tubes, or portions thereof, have been removed 

to characterize this degradation mechanism. This degradation mechanism appears to have 

been arrested because of improvements in water chemistry because no units are reporting the 

initiation of new pitting indications and the existing pit indication is not progressing.

Cracking has been observed in units with thermally treated Alloy 600 tubes. Cracking has 

resulted in plugging approximately 7 percent of the tubes in steam generators with thermally 

treated Alloy 600 as of December 2013. In 2002, the first confirmed instance of cracking in 

thermally treated Alloy 600 tubes was reported. There was at least one report of cracking 

before 2002, but it was subsequently concluded that this indication was not a crack. This 

indication was reported at Braidwood 2 in 1996 when one axial indication was detected in a tube 

with a small-bend-radius (a row 1 tube). At the time, this indication was attributed to primary 

water stress corrosion cracking. In addition, axial and circumferential indications were reported 

at Callaway at the expansion transition in 1996, and an undefined indication was reported in the 

U-bend of a row 2 tube in 1992; however, these indications have typically not been considered 

cracks.

Cracking has primarily occurred on the hot-leg side of the steam generator. The only cracks 

detected on the cold-leg side of the steam generator were at the tube ends or were at the tube 

support elevations in tubes with nonoptimal tube processing as determined from the eddy 

current data (i.e., stress relieved tubes with an offset in the eddy current data or non-stress 

relieved tubes without an offset in the eddy current data (or more precisely where the offset is 

two standard deviations below the mean of the response for that row of tubes)).

Cracking has occurred at various locations along the tube length including near the tube end, 

within the tubesheet (but only at bulges and overexpansions), at the expansion transition, 

slightly above the expansion transition in the sludge pile, in the freespan, at tube support 

elevations in tubes with nonoptimal tube processing, at a dented tube support plate elevation, 

and in the U-bend.

Cracking that initiates from the inside surface of the tube has been observed as has cracking 

that initiates from the outside surface of the tube. Cracking that initiates from the inside-surface 

of the tube, typically referred to as primary water stress corrosion cracking, has been observed 

near the tube end and possibly extending into the tube-to-tubesheet weld, within

bulges/overexpansions inside the tubesheet region, at the expansion transition, and in the 

U-bend region of a row 1 tube. A bulge or overexpansion is created when the tube is expanded 

into a tubesheet bore hole that is not perfectly round. Cracking that initiates from the 

outside-surface of the tube, typically referred to as outside-diameter stress corrosion cracking 

has been observed at the expansion transition, in the sludge pile, in the freespan, at non-dented 

tube support plate elevations, and at dented tube support plate elevations.
4-9

A summary of all cracks reported is provided in Table 4-25. As can be seen from Table 4-25, 

most of the crack-like indications are in the portion of the tube confined within the tubesheet. 

Of the crack-like indications in the tubesheet region, most are near the tube-end and are a 

mixture of axial and circumferentially oriented cracking. Indications reported near the tube end 

may be in the tube-to-tubesheet weld or in the tack roll expansion area. Currently used eddy 

current inspection techniques cannot reliably differentiate whether these indications are in the 

weld or in the tack roll region.

Given that cracks in the portion of the tube within the tubesheet cannot burst and are generally 

regarded as having low safety significance, the NRC has received proposals to limit the extent 

of inspection in the tubesheet region to the uppermost portion of the tube within the tubesheet. 

These proposals for units with thermally treated Alloy 600 steam generator tubes are referred to 

as H* (H-star) amendments. The H* distance is that distance below the top of the tubesheet 

over which sufficient frictional force, with acceptable safety margins, can be developed between 

each tube and the tubesheet to overcome the tube “end cap” pressure loads associated with 

normal operating and design-basis-accident conditions. This frictional force prevents significant 

slippage or pullout of the tube from the tubesheet (i.e., tube axial displacement), assuming the 

tube is fully severed at the H* distance below the top of the tubesheet. The H* distance varies 

from unit-to-unit. H* permits tubes with flaws that occur beneath the inspected region of the 

tube to remain in service. 

As discussed in Section 1.3.3, the NRC has permanently approved the H* alternate repair 

criterion for all units with thermally treated Alloy 600 steam generator tubes except for Point 

Beach 1. In addition, before the permanent approval, the NRC had approved similar 

amendments that were applicable for a limited amount of time for most of the units with 

thermally treated Alloy 600 steam generator tubes. Because this repair criterion no longer 

requires the tube ends to be inspected, any cracks that may occur near the tube end would not 

be detected (including cracks in the tube-to-tubesheet weld, the tack expansion region, and the 

region where a plug had been installed and then subsequently removed (i.e., a deplugged 

tube)). However, licensees still could inspect this region and could report these indications (and 

if they are reported they were included in Table 4-25). Because of these H* amendments, the 

extent to which this region has been inspected varies from unit-to-unit and has changed with 

time; therefore, the true extent of cracking near the tube end and when it initiated is difficult to 

determine. Table 4-26 provides a summary of only the crack indications detected near the tube 

end. Most of these tubes have been allowed to remain in service with the H* amendments.

Tables 4-27 and 4-28 provide a summary of all the cracks detected except for those cracks 

detected at the tube end sorted by plant name and by location, respectively. As can be seen 

from these tables, the number of tubes affected by cracking at these locations is small. All of 

these tubes have been plugged. All of the cracks reported at the tube support plate elevations 

have been in tubes with nonoptimal tube processing except for one tube in which the crack was 

associated with a dent at the tube support plate elevation.

One crack has been detected in the U-bend region. This crack was near a manufacturing 

indication referred to as a Blairsville bump (because the bump was most likely introduced when 

the tube was bent into its final “U-shape” at a facility in Blairsville, PA). This bump is at the start 

of the bent region of the tube (i.e., the start of the U-bend region or the tangent point – refer to 

Figure 1-4). Although the crack was near the manufacturing indication, it is not known whether 

this condition is necessary to lead to the initiation of a crack in this region of the tubing. 

Nonetheless, some units have identified tubes with this manufacturing artifact (Blairsville bump) 

and have highlighted these tubes as a different population for inspections.
4-10

The number of tubes with corrosion-related cracking is small in comparison to the approximately 

275,000 thermally treated Alloy 600 tubes in service. Although only a small number of tubes 

have been identified with crack-like indications, these findings indicate that the tubes are 

potentially susceptible to cracking at a variety of locations.

No corrosion has been reported in any Alloy 690 tubes as of December 2014.

4.4.4 Degradation in steam generator channel head

Because of operating experience, increased emphasis has been placed on inspecting the 

interior portion of the steam generator channel head. As a result of these inspections some 

degradation has been observed at units with thermally treated Alloy 600 steam generator tubes. 

Specifically, degradation was observed at Surry 2 in 2006 and at Wolf Creek in 2013. NRC 

Information Notice (IN) 2013-20, “Steam Generator Channel Head and Tubesheet Degradation,” 

summarizes this operating experience.

As discussed in this IN, Surry 2 identified a yellow stain at one tube end and on a portion of the 

channel head near this tube location. This tube was inadvertently plugged in 1986 and when

the plug was removed by drilling in 1991, the tube appeared to have been drilled off-center 

longitudinally from the tube end for a distance of approximately 44 mm (1.75 in.). This resulted 

in perforating the tube wall over a circumferential distance of about 23 mm (0.9 in.). As a result, 

this damaged tube end was in service from 1991 until 2006 when the yellow stain was noticed. 

The yellow stain was attributed to the corrosion of the tubesheet material. Although the damage 

to the tube end was substantial, the as-found condition did not compromise tube integrity given 

that the tube damage was near the primary face of the tubesheet.

Given the damage to the tube near the tube-end, a special plug was used on the hot-leg side of 

the tube. The plug’s structural joint was above the damaged region. Two other joints, including 

one below the damaged region, were made. The lowest joint was expected to form a tortuous 

leakage path and allow little or no primary coolant to contact the tubesheet material. However, 

to the extent that the lower joint does not isolate the carbon steel, it was assumed that corrosion 

of the tubesheet material could occur. The rate of carbon steel corrosion during operation with 

very low oxygen in the primary coolant is much lower than that during shutdown when the 

material could be exposed to air. The licensee performed an assessment assuming corrosion 

would occur and concluded that the corrosion would not affect the structural integrity of the 

tubesheet. This tube was plugged at both ends during the 2006 outage. The licensee plans to 

visually inspect this region during future inspections of the tubes in the affected steam 

generator.

The Surry 2 licensee also characterized and evaluated the channel head degradation. 

Ultrasonic examination of the tubesheet-to-channel-head transition region confirmed that no 

degradation extended into the base material. The licensee performed an evaluation of potential 

carbon steel corrosion rates and concluded that the condition was acceptable for continued 

service without repair for the remaining licensed life of the unit. During RFO 20 in 2012, visual 

inspections of this region indicated there was no change in the indication/degradation.

During RFO 16 in 2006 at Surry 2, the hot-leg primary manway flange face also was examined 

visually. This inspection revealed a localized region of corrosion between the gasket seating 
4-11

surface and the bolt circle. During RFO 20 in 2012, this area was re-examined and there was 

no advancement of the degradation. The degradation was attributed to gasket leakage at some 

point before 2006.

As discussed in the IN, Wolf Creek also identified degradation in the channel head region. 

Specifically, Wolf Creek identified a rust-colored spot about 152 mm (6 in.) below the primary 

face of the tubesheet along the weld connecting the divider plate to the channel head during 

RFO 19 in 2013. The divider-plate-to-channel-head weld is made with weld material of the Alloy 

600 type. The cladding on the channel head is primarily stainless steel; however, the cladding 

near the rust-colored spot may be either stainless steel or Alloy 182 (an Alloy 600 type material) 

depending on the actual fabrication process. Visual inspections revealed a flaw in the 

divider-plate-to-channel-head fillet weld, which was attributed to a fabrication defect. An 

ultrasonic test indicated the flaw in the channel head’s base material was about 2.5 mm (0.1 in.) 

deep and about 51 mm (2 in.) long. The width of the flaw could not be determined because the 

ultrasonic testing equipment could not be placed at the appropriate location on the outside 

surface of the channel head because of access limitations.

The flaw at the edge of the divider-plate-to-channel-head weld was evaluated in accordance 

with Subparagraph IWB-3510.1 and Table IWB-3510-1 of Section XI of the American Society of 

Mechanical Engineers Boiler and Pressure Vessel Code. The flaw in the base material was 

treated as a planar flaw. The evaluation considered flaw growth in the future. The licensee 

concluded that it was acceptable to operate the steam generator through the operating cycle. 

During the cycle, a detailed fracture mechanics analysis of the flaw to determine the long-term 

corrective action required was planned.

Based on the corrosion properties of the stainless steel cladding and Alloy 600 weld material, 

and because the primary chemistry is usually maintained in a condition that scavenges oxygen, 

the licensee concluded that the flaw in the divider-plate-to-channel-head weld was only able to 

grow when there were oxidizing conditions in the primary coolant (i.e., for a short period before 

each shutdown because of peroxide addition during the shutdown process) and when the steam 

generator was open for inspection. Based on this estimated exposure period and boric acid 

corrosion rates in literature, the licensee predicted that the flaw in the base material would be 

about 2.5 mm (0.1 in.) deep, assuming that the base material corrosion started at the beginning 

of plant operation. This matches the actual extent of degradation observed in the channel head 

base material, as determined from the ultrasonic examination. Using a flaw growth rate of about

0.1 mm (0.005 in.) per operating cycle, the licensee concluded the flaw in the channel head 

base material would be about 2.7 mm (0.105 in.) deep at the next refueling outage.

Visual inspections of steam generator channel heads were reviewed and the rust spot was not 

visible during the 2011 inspections, but was visible during all prior outages in which visual 

inspections of this region were performed (i.e., in 2009, 2006, 2000, and 1994). The 1994 video 

is the earliest video recording of this area and is a black-and-white recording.

Because structural interferences prevent a zero-degree ultrasonic examination of the dividerplate-to-channel-head weld flaw, it could not be confirmed that there is no delamination between 

the stainless steel cladding and the channel head’s base material in the area directly under the 

flaw. It was confirmed, however, that there are no delaminations between the cladding and the 

channel head in those areas around the divider-plate-to-channel-head weld flaw, where there is 

access for a zero-degree ultrasonic examination.
4-12

The licensee has no direct evidence that the flaw at the rust spot’s location was not caused by 

stress corrosion cracking or fatigue. However, the licensee has indirect evidence to support the 

conclusion that the flaw was not caused by stress corrosion cracking or fatigue. The licensee’s 

evidence includes the fact that stress corrosion cracking is highly unlikely in stainless steel or 

carbon steel on the primary side of a steam generator, and the existence of the rust stain is 

evidence that the carbon steel channel head is corroding. The rust spot is around a black spot 

that the licensee has stated appears to be either a weld crater pit or weld porosity. The rust 

spot appears to be about 21.8 mm (0.86 in.) long and 6.4 mm (0.25 in.) wide. Also, an industry

fatigue stress analysis, which the licensee has cited, showed fatigue stresses in this location of 

the steam generator are very low. The licensee said other paths of stress corrosion cracking in

the weld could exist, but that there was no evidence of these other paths. The licensee 

concluded that the black spot is a fabrication defect in the weld material and that a breach 

through the cladding was probably created because of the high tensile stresses from the weld 

geometry.

The licensee plans to re-inspect this area during the next refueling outage to monitor/confirm the 

flaw’s growth rate.

4.4.5 Degradation of steam generator secondary-side internals

Degradation has been observed on internal components on the secondary side of steam 

generators with thermally treated Alloy 600 tubes. The term “secondary-side internals” does not 

include the steam generator tubes nor does it include the shell. It does include, in part, the 

wrapper (shroud), the feedring, the tube supports, and the moisture separation equipment.

The degradation observed in the secondary-side internals is grouped by model. Although 

grouped by model, it may be possible for degradation observed in one model to also be 

observed in the other models. More detailed information concerning the nature of the 

degradation detected can be found in Section 3.

Model D5 steam generators include a preheater region, which is sometimes referred to as a 

waterbox. In some of the steam generators at Braidwood 2, Byron 2, and Catawba 2, there was 

a cutout made in the waterbox cap plate during fabrication. No such cutout regions exist in the 

Comanche Peak 2 steam generators. Minor erosion of the waterbox cap plate holes was 

reported at Braidwood 2 during RFO 11 in 2005, RFO 12 in 2006, and RFO 13 in 2008. Similar 

erosion of the cap plate holes was observed at Byron 2 during RFO 14 in 2008. In addition, 

erosion of the weld associated with the cutout region was observed at Byron 2 during RFO 11 

in 2004. In addition to this degradation, some of the fit-up bars (also called backing bars) used 

during steam generator fabrication had become loose parts (i.e., they were no longer at the 

locations where they had been installed). This was observed at Braidwood 2 during RFO 10 

in 2003, at Byron 2 during RFO 11 in 2004, and at Catawba 2 during RFO 13 in 2004.

Erosion has also been observed in the moisture separation equipment in model D5 steam 

generators. Erosion of the primary moisture separator tangential nozzles, downcomer barrels, 

and swirl vanes has been reported at Braidwood 2 from RFO 11 (2005) through RFO 15 (2011). 

Similarly Byron 2 has reported erosion of the moisture separator tangential nozzles, downcomer 

barrels, swirl vanes, spacer tabs, and orifice rings during RFO 12 in 2005, RFO 13 in 2007, and 

RFO 15 in 2010.

Degradation of secondary-side internals has also been reported in model F steam generators. 

Erosion of the feedring and J-tubes was reported at Millstone 3 during RFO 7 in 2001. This 
4-13

degradation was repaired in various steam generators during RFO 9 in 2004, RFO 10 in 2005, 

and RFO 11 in 2007. Flow-accelerated corrosion of the reducers and “T’s” in the feedring was 

reported at Millstone 3 during RFO 12 in 2008. Mild flow-assisted corrosion of the feedring was 

observed at Vogtle 1 during RFO 15 in 2009. Base material loss in the feedwater ring-to-nozzle 

joints was observed at Vogtle 2 during RFO 15 in 2011. Erosion of two J-tubes was observed at 

Wolf Creek during RFO 16 in 2008 and RFO 17 in 2009. Minor degradation of the J-nozzle to 

feedring interface was observed at Wolf Creek during RFO 18 in 2011. Minor degradation of 

the J-tubes was observed at Wolf Creek during RFO 19 in 2013.

Minor roughness, pitting, or erosion of the primary moisture separators in the area where 

overspray from the J-nozzles occurs was reported at Millstone 3 during RFO 10 in 2005 and 

RFO 13 in 2010. Mild erosion or corrosion of the swirl vanes was observed at Vogtle 1 during 

RFO 15 in 2009.

Secondary-side internals degradation has also been reported in the units with replacement 

steam generators with thermally treated Alloy 600 tubing. Flow impingement patterns were 

observed on the feedring, some primary moisture separator riser barrels, and under and around 

some J-tubes at Point Beach 1 during RFO 30 in 2007 and RFO 31 in 2008. Melt through at the 

J-tube to feedring weld, a fabrication related issue, was reported at Point Beach 1 during RFO 

30 in 2007. Impingement erosion of several primary moisture separator riser barrels because of

overspray from the J-tubes was reported at Salem 1 during RFO 22 in 2013. Flow-assisted 

corrosion of the feedring was reported at Surry 1 during RFO 16 in 2007. The feedrings at 

Surry 1 were replaced during RFO 18 in 2010. The feedrings at Surry 2 were replaced during 

RFO 19 in 2011. A hole, which was at the location where overspray from the J-tube occurs, 

was reported in one of the primary separator riser barrels at Surry 2 during RFO 19 in 2011. 

This location was repaired by welding an Inconel patch plate over the hole.

Bowing of one of the perforated plates of the secondary moisture separator was observed at 

Point Beach 1 during RFO 29 in 2005 and RFO 30 in 2007. A pin-hole was observed in the 

Pagoda (a structure that holds the moisture separators in place) at Robinson 2 during RFO 24 

in 2007 and RFO 26 in 2010.

4.4.6 Tube wear

The dominant degradation mechanism in units with thermally treated Alloy 600 steam generator 

tubes is wear. Wear has occurred as a result of interaction between the tubes and the support 

plates, AVBs, loose parts, and maintenance equipment. Wear at the AVBs is the most 

prevalent.

Table 4-29 summarizes the number of indications and number of tubes with wear indications at 

the AVBs as of the last inspection outage reported in Section 3. In some cases, data from the 

last two outages was used to obtain an estimate of the number of tubes and indications of wear 

at the AVBs given that some units do not inspect all steam generators during an outage and 

some units may not inspect all tubes in any given outage. In Table 4-29, the number of tubes 

plugged attributed to wear at the AVBs is also reported. Other tubes could have been plugged 

that contained wear indications at the AVBs, but they would not be included in this table unless 

the main reason for plugging the tube was an indication of wear at the AVBs (e.g., a tube 

plugged for a wear indication attributed to a loose part or cracking that also had an AVB wear 

indication would not be included in this table). This is also the case for other tables showing the 

cause of tube plugging (i.e., a singular cause is identified for plugging a tube). In addition, in 

interpreting Table 4-29, it should be recognized that units may have different reporting/recording 
4-14

criteria for wear indications and units may have different practices when determining when to 

plug a tube (other than those explicitly required by the unit’s technical specification 

plugging/repair criteria).

4.4.7 Selected findings

In addition to the information discussed in Sections 4.4.1 through 4.4.6, some observations from 

the review of the inspections performed at units with thermally treated Alloy 600 steam 

generator tubes are highlighted below.

At least one unit monitors tubes surrounding plugged tubes that were not stabilized. These 

inspections are intended to provide an early indication of whether the plugged, non-stabilized 

tube has severed.

The size of the cracks at the expansion transition, which were removed from the Vogtle 1 steam 

generators, was significantly underestimated during the in-service inspection.

At least one unit has identified tubes with manufacturing indications in the U-bend (e.g., 

Blairsville bump) and treats these tubes as a separate inspection population.

Most, if not all, units have identified low-row (stress-relieved) tubes that may have potentially 

elevated residual stresses as determined by the presence of an eddy current offset. In addition, 

most, if not all, units have identified high row (non-stress relieved) tubes whose offsets are 

significantly less than what would be expected for that row of tubes based on a statistical 

analysis of the offset (commonly referred to as “minus 2 sigma” tubes).

H* may only be applied to tubes whose bottom of the expansion transition is no more than 

2.54 cm (1 in.) below the top of the tubesheet. As a result, units implementing H* plugged all 

tubes where the bottom of the expansion transition was greater than 2.54 cm (1 in.) from the top 

of the tubesheet.

At Millstone 3 in 2013, an increase was seen in the amount of wear at the tube support plate 

elevations. The licensee suspected that changing local flow conditions could be causing this 

increase.

At Byron 2 in 2011, denting was observed at the bottom edge of tube support plate 3C.

At Vogtle 1 in 2008, several tubes were damaged in the process of removing portions of a tube 

for laboratory examination.

At Surry 1 in 2006, a tube was in-situ pressure tested. During the test, the pressure was held 

for 5 minutes before terminating the test. During the 5-minute hold, the leakage continued to 

increase. Although the licensee concluded that the tube satisfied the structural integrity 

performance criteria, NRC staff questioned whether the test adequately demonstrated that the 

tube had adequate integrity because the leak rate was not stable at the time the test was 

concluded.

At Millstone 3 in February 2001, 29 single volumetric indications at the top of the tubesheet and 

flow distribution baffle were identified. These indications were attributed to wear because of

loose parts and to fabrication-related defects.
4-15

At Turkey Point 3 in 2001, 12 tubes were plugged because of indications of mechanical wear at 

the broached tube support plates. Plugging of tubes for wear at tube support plates is fairly rare 

in units with thermally treated Alloy 600 tubes.

In the spring of 2000, Turkey Point 3 staff identified 41 volumetric pitlike indications, 15 

inside-diameter initiated circumferential indications, and 8 outside-diameter initiated 

circumferential indications. Most of these indications were in the hot-leg hydraulic-expansion 

transition region at the top of the tubesheet. The volumetric and circumferential indications 

were detected with rotating probes. This was the first time rotating probes were used 

extensively at Turkey Point 3. As a result of these findings, the licensee began, during the 

outage, a review of historical data and industry experience to assess the root causes of the tube 

degradation. Because of the lack of prior rotating probe inspection data for Turkey Point 3 and 

the limited number of defects identified by the industry in thermally treated Alloy 600 tubes, the 

results, at the time of the inspection, were inconclusive for the circumferential and volumetric 

indications. Based on subsequent investigation, the licensee concluded that of the 64 

volumetric and circumferential indications originally identified, only 26 tubes contain volumetric 

or pitlike indications (possibly because of manufacturing and installation artifacts), while the 

remaining 38 tubes contain no degradation (13 had circumferential geometric anomalies, 23 had 

dings or dents, and 2 had manufacturing buff marks).

In an outage at Turkey Point 4 in the fall of 2000, the licensee detected seven tubes with 

possible corrosion degradation and plugged these tubes because a qualified depth-sizing 

technique was not available. Based on the eddy current and ultrasonic examination results of 

this inspection, the licensee reanalyzed the spring 2000 Unit 3 data (discussed above). The 

licensee’s judgment is that the indications at Unit 3 were false positives and caused by 

manufacturing anomalies or deposits at the top of tubesheet or by the inspection techniques 

associated with the rotating probe. These results are discussed in NRC IN 2001-016, “Recent 

Foreign and Domestic Experience with Degradation of Steam Generator Tubes and Internals.”

At Surry 1, starting in 2000 denting of tubes at the sixth and seventh tube supports was 

detected. These dents corresponded to the quatrefoil lands. The dents are concentrated in the 

periphery of the tube bundle near the wedge regions and are at (or near) the edges of the 

support plate. Denting at the sixth and seventh tube supports was also reported at Surry 2 in 

2002.

At Callaway in 1996, axial, circumferential, and volumetric indications were detected at the

hot-leg expansion transition. Additional indications were detected near the top of the tubesheet 

(i.e., the expansion transition region) in subsequent outages.

At Millstone 3 in August 1993, a tube was deplugged to replace the plug with a more 

corrosion-resistant material. This tube had been plugged in 1989 because of a 43 percent

throughwall wear indication at the fifth anti-vibration bar. During the 4 years the tube was 

plugged, the defect had apparently grown from 43 percent to 100 percent throughwall. To 

prevent the tube from severing at the defect and contacting adjacent tubes, a stabilizer was 

inserted before the tube was replugged.

At Callaway in 1992, one undefined indication was detected in a row 2 tube. The indication, just 

above the seventh cold-leg support plate, was not identified with the bobbin coil. The licensee 

concluded that this indication was an anomaly since no degradation mechanism had been 

identified in this region. In addition, a senior eddy current analyst judged this indication to be a 

distorted signal caused by its location in the U-bend transition.
4-16

4.4.8 Summary and observations

As depicted in Figure 4-13, there were 281,262 thermally treated Alloy 600 tubes placed in 

service at 18 units between 1980 and 2013. Cumulatively, these 18 units have operated for 

approximately 468 calendar years as of December 2013 and have commercially operated for an 

average of 26 calendar years as of December 2013. Of these 281,262 tubes, only 2,734 tubes 

(1.0 percent) have been plugged. The number and percentage of tubes plugged at the 18 units 

with thermally treated tubes are summarized in Table 4-30. Figure 4-14 depicts the total 

number and percentage of tubes plugged in units with thermally treated Alloy 600 tubes as a 

function of model/grouping (i.e., model D5, model F, replacement models).

Only 17 units currently have thermally treated Alloy 690 steam generator tubes. This reflects 

the replacement of the Callaway steam generators in 2005. The Callaway steam generators 

had both mill annealed and thermally treated Alloy 600 tubes. Most of the tubes were mill 

annealed and degradation observed in these tubes resulted in their replacement. For the 

currently operating units with thermally treated Alloy 600 steam generator tubes, they have 

operated for approximately 374 effective full power years as of December 2013 and have 

operated for an average of 22.0 effective full power years as of December 2013.

Tables 4-31 and 4-32 summarize the causes of tube plugging for Model D5, Model F, and 

replacement steam generators. In addition, these tables summarize the causes of tube 

plugging for all steam generators with thermally treated Alloy 600 tubes. The information in 

these tables is graphically depicted in Figure 4-15. As can be seen from the tables and figure, 

the dominant degradation mode of thermally treated Alloy 600 tubes is wear at tube supports. 

Of the approximately 2,700 tubes plugged, about 42 percent of the tubes were plugged because 

of wear at the tube supports. Tube wear occurs because of contact between the tube and a 

support structure (e.g., an anti-vibration bar). The rate of tube wear from support structures is 

generally predictable and is readily managed. The wear in thermally treated tubes has occurred 

predominantly at the AVBs although some has occurred at tube support plates. The percentage 

of tubes plugged for wear at tube supports is greater for the Model F steam generators than for 

the Model D5 or replacement model steam generators. 

Wear can also occur because of loose parts; however, this type of wear is tracked under the 

“loose parts” category. This category includes not only tubes plugged for wear attributed to 

loose parts, but also for tubes that had no wear associated with a loose part but because the 

tube was near a loose part that was not removed from the steam generator. Loose parts can be 

introduced during steam generator fabrication, during maintenance activities, or because of

corrosion degradation of other components in the primary or secondary side of the steam 

generator (e.g., a split pin nut). Wear from loose parts is usually unexpected and can only be 

detected by inspection, loose parts monitoring systems, or primary-to-secondary leakage. 

Loose parts accounted for a significant percentage of tube plugging, accounting for 

approximately 20 percent of the tubes plugged.

Several tubes have been plugged because of restrictions. The nature and causes of many of 

these restrictions have not been provided.

Units with steam generators with thermally treated Alloy 600 tubes have a variety of strategies 

for inspecting their steam generators. Several units inspect a subset of steam generators each 
4-17

refueling outage. Others inspect all steam generators every other outage (i.e., no tube 

inspections are performed during one refueling outage but all steam generators are inspected 

the next refueling outage). Yet others inspect all steam generators every outage.

Based on a review of inspection summary reports, tube inspections in units with thermally 

treated Alloy 600 have become more comprehensive since the early 1980s. The inspections 

today focus on ensuring tube integrity for the interval between inspections. There have been no 

reported instances in which a thermally treated Alloy 600 tube did not have adequate integrity.

Figure 4-16 depicts the number of tubes plugged for each type of thermally treated Alloy 600 

steam generator (e.g., Model D5) as a function of year. Similarly, Figure 4-17 provides the 

percentage of tubes plugged for each type of thermally treated Alloy 600 steam generator 

(e.g., Model D5) as a function of year. The percentage of tubes plugged each year has no 

discernible trend. The data used to compile these figures is summarized in Table 4-33.

Figure 4-18 depicts the fraction of tubes plugged for a specific mechanism as a function of year. 

This figure was developed from the data provided in Tables 4-34, 4-35, and 4-36. In this figure, 

tubes plugged before commercial operation were treated as being plugged during the year the 

unit began commercial operation (in previous tables and figures in this report, tubes plugged 

before operation were treated as a distinct group independent of the actual year/outage in which 

they were plugged).

Far fewer tubes have been plugged in the steam generators with second-generation tube 

materials (i.e., thermally treated alloy 600) than in earlier steam generators with comparable 

operating times. Improvements in the design and operation of the second-generation steam 

generators appear to have increased the corrosion resistance of the tubes, as evidenced by the 

general lack of any significant amounts of corrosion degradation. The enhanced corrosion 

resistance is largely because of the thermal treatment process that has superseded the mill 

annealing process used in earlier steam generator designs.

The relatively good operating experience for units with thermally treated Alloy 600 steam 

generator tubes can be attributed to several factors in addition to the heat treatment the tubes 

received: hydraulic expansion of the tubes into the tubesheet, the quatrefoil design of the tube 

support plates, and the stainless steel material used to fabricate the plates. The residual stress 

levels at the expansion transition in tubes hydraulically expanded into the tubesheet are lower 

than observed in units whose tubes were expanded mechanically or explosively. Because

crack growth rate and time to crack initiation depend, in part, on the stress level, lower stresses 

may result in lower crack growth rates and/or longer times before crack initiation.

Although the operating experience with thermally treated Alloy 600 tubes has been favorable to 

date, there is a continued need to monitor the tubes to detect the onset of tube degradation and 

to assure the structural and leakage integrity of the tubes during the intervals between 

inspections.
4-18

Table 4-1: Model D5: Total Number and Percentage of Tubes Plugged (12/2013)

Unit

Number of Tubes 

Plugged1 Percent Plugged Operating Time2

Braidwood 2 270 1.48 25

Byron 2 408 2.23 26

Catawba 2 309 1.69 27

Comanche Peak 2 81 0.44 20

TOTALS: 1068 1.46

1

As of 12/31/2013

2

Operating Time = calendar years of operation as of 12/31/2013
4-19

Table 4-2: Model D5: Number of Tubes Plugged as a Function of Mechanism (Detailed) (1

Tubes 

Plugged

Percentage 

of Plugs

Tubes 

Plugged

Percentage 

of Plugs

AVB 320 30.0%

Preheater TSP (D5) 30 2.8%

TSP 3 0.3%

Confirmed 200 18.7%

Not Confirmed, 

Periphery 88 8.2%

Not Confirmed, Not 

Periphery 56 5.2%

From PSI - no 

progression 1 0.1%

Service Induced 2 0.2%

Preservice 50 4.7%

Other 65 6.1%

Probe Lodged 2 0.2%

Data Quality 19 1.8%

Dent/Geometry 5 0.5%

Permeability 7 0.7%

Not Inspected 3 0.3%

Top of Tubesheet 18 1.7%

Freespan 79 7.4%

TSP 42 3.9%

Other/Not Reported 11 1.0%

ID 51 4.8%

OD 16 1.5%

TOTALS 1068 100.0% 1068 100.0%

Total Tubes: 73120

Fraction Plugged 1.46%

Inspection 

Cause of Tube Plugging

Wear

Issues

Other

SCC

Loose Parts

Obstruction 

Restriction

3.4%

14.0%

6.3% 67

150

36

115

3

353

344

33.1%

32.2%

0.3%

10.8% Manufacturing 

Flaws
4-20

Table 4-3: Model D5: Cumulative Plugging per Year

Year Braidwood 2 Byron 2 Catawba 2 Comanche Peak 2

Pre-Op 6 11 14 20

1986

1987 14

1988 21

1989 22 29

1990 8 43 48

1991 18 60

1992 72

1993 34 108 103

1994 40 134 20

1995 137 157

1996 75 167 20

1997 103 167 28

1998 205 176

1999 109 219 33

2000 120 183 37

2001 223 183

2002 122 240 48

2003 180 216 52

2004 332 264

2005 186 349 65

2006 200 278 65

2007 366 286

2008 223 379 78

2009 229 296 78

2010 380 297

2011 259 408 81

2012 270 302 81

2013 408 309

 
4-21

Year Braidwood 2 Byron 2 Catawba 2 Comanche Peak 2

Model D5 

Totals

Pre-Op 6 11 14 20 

1986 

1987 0 

1988 7 

1989 11 8 

1990 2 21 19 

1991 10 12 

1992 29 

1993 16 36 43 

1994 6 31 0 

1995 29 23 

1996 35 30 0 

1997 28 10 8 

1998 38 9 

1999 6 14 5 

2000 11 7 4 

2001 4 0 

2002 2 17 11 

2003 58 33 4 

2004 92 48 

2005 6 17 13 

2006 14 14 0 

2007 17 8 

2008 23 13 13 

2009 6 10 0 

2010 1 1 

2011 30 28 3 

2012 11 5 0 

2013 0 7 

Totals: 270 408 309 81 

Note: Values adjusted to account for deplugging of tubes.

 Table 4-4: Model D5: Plugging per Year
4-22

Table 4-5: Model D5: Cumulative Plugging per RFO (12/2013)

Outage Braidwood 2 Byron 2 Catawba 2

Comanche 

Peak 2

Pre-Op 6 11 14 20

RFO 1 8 22 21 20

RFO 2 19 43 29 20

RFO 3 34 72 48 28

RFO 4 40 108 60 33

RFO 5 75 137 103 37

RFO 6 103 167 134 48

RFO 7 109 205 157 52

RFO 8 120 219 167 65

RFO 9 122 223 176 65

RFO 10 180 240 183 78

RFO 11 186 332 183 78

RFO 12 200 349 216 81

RFO 13 223 366 264 81

RFO 14 229 379 278

RFO 15 259 380 286

RFO 16 270 408 296

RFO 17 408 297

RFO 18 302

RFO 19 309

 
4-23

Table 4-6: Model D5: Number of Tubes Plugged as a Function of Mechanism per Year (De

1980-1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 

AVB 2 35 17 25 51 7 22 48 19 2 15 15 4 15 1 10 10 3 7 1 0 

Preheater TSP (D5) 1 1 2 6 0 6 2 0 3 0 0 

TSP 2 0 0 0 0 0 0 0 0 1 

Confirmed 2 4 1 6 3 3 1 16 42 109 0 9 0 3 0 0 

Not Confirmed, 

Periphery 1 1 1 7 1 5 2 3 6 5 9 0 13 5 4 0 

Not Confirmed, 

Not Periphery 1 2 5 0 7 3 2 0 1 1 1 

From PSI - no 

progression 0 0 0 1 0 0 0 0 0 

Service Induced 1 1 0 0 0 0 0 0 0 0 0 

Preservice 14 11 6 -1 20 0 0 0 0 0 0 0 0 0 

Other 15 29 0 4 0 7 4 1 1 1 0 

Probe Lodged 2 0 0 0 0 0 0 0 0 0 

Data Quality 1 1 0 17 0 0 0 0 0 0 0 

Dent/Geometry 1 1 2 0 0 0 0 1 0 0 0 0 

Permeability 2 1 1 0 2 1 0 0 0 0 0 0 

Not Inspected 1 2 0 0 0 0 0 0 0 0 0 

Top of Tubesheet 2 3 4 2 1 3 2 1 0 0 0 0 0 0 0 0 0 

Freespan 3 4 1 1 3 30 20 10 5 1 1 0 0 0 0 0 0 0 0 0 

TSP 2 3 3 5 1 8 6 5 4 4 1 0 0 0 0 0 0 0 0 0 

Not Reported 1 2 2 5 0 0 1 0 0 0 0 0 0 

ID 0 0 16 0 0 0 29 6 0 

OD 0 3 0 0 0 8 0 3 0 

TOTALS 0 14 11 13 19 42 22 29 115 37 52 65 46 47 25 22 4 30 95 140 36 28 25 49 16 2 

Stress Corrosion 

Cracking (SCC)

Loose Parts

Obstruction 

Restriction

Manufacturing 

Flaws

Inspection 

Cause of Tube Plugging/Outage

Issues

Year

Wear

Other
4-24

Table 4-7: Model D5: Number of Tubes Plugged as a Function of Mechanism per Year (Su

Year 1980-1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 

Cause 

Wear 0 0 0 0 2 35 17 25 51 7 22 48 19 5 16 15 0 6 21 1 16 12 3 10 1 

Loose Parts 0 0 0 2 5 1 0 0 1 0 8 6 3 4 6 2 3 24 48 121 12 11 13 9 5 

Restrictions 0 0 0 0 0 0 0 0 0 0 0 0 1 0 1 0 0 0 0 0 1 0 0 0 0 

Manufacturing 0 14 11 6 0 0 -1 0 20 0 0 0 15 29 0 0 0 0 4 0 7 4 1 1 1 

Inspection Issues 0 0 0 0 2 0 0 0 0 0 0 1 4 3 0 5 0 0 19 1 0 1 0 0 0 

Other 0 0 0 5 10 6 6 4 43 30 22 10 4 6 2 0 1 0 0 1 0 0 0 0 0 

SCC 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 3 16 0 0 8 29 9 

0 14 11 13 19 42 22 29 115 37 52 65 46 47 25 22 4 30 95 140 36 28 25 49 16 
4-25

Table 4-8: Model D5: Percentage of Tubes Plugged as a Function of Mechanism per Y

Year 1980-1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 

Cause 

Wear 0.0% 0.0% 0.0% 10.5% 83.3% 77.3% 86.2% 44.3% 18.9% 42.3% 73.8% 41.3% 10.6% 64.0% 68.2% 0.0% 20.0% 22.1% 0.7% 44.4% 42.9% 12.0% 20.4% 6.3% 5

Loose Parts 0.0% 0.0% 15.4% 26.3% 2.4% 0.0% 0.0% 0.9% 0.0% 15.4% 9.2% 6.5% 8.5% 24.0% 9.1% 75.0% 80.0% 50.5% 86.4% 33.3% 39.3% 52.0% 18.4% 31.3% 5

Restrictions 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 2.2% 0.0% 4.0% 0.0% 0.0% 0.0% 0.0% 0.0% 2.8% 0.0% 0.0% 0.0% 0.0% 

Manufacturing 100.0% 100.0% 46.2% 0.0% 0.0% -4.5% 0.0% 17.4% 0.0% 0.0% 0.0% 32.6% 61.7% 0.0% 0.0% 0.0% 0.0% 4.2% 0.0% 19.4% 14.3% 4.0% 2.0% 6.3% 

Inspection Issues 0.0% 0.0% 0.0% 10.5% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 1.5% 8.7% 6.4% 0.0% 22.7% 0.0% 0.0% 20.0% 0.7% 0.0% 3.6% 0.0% 0.0% 0.0% 

Other 0.0% 0.0% 38.5% 52.6% 14.3% 27.3% 13.8% 37.4% 81.1% 42.3% 15.4% 8.7% 12.8% 8.0% 0.0% 25.0% 0.0% 0.0% 0.7% 0.0% 0.0% 0.0% 0.0% 0.0% 

SCC 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 3.2% 11.4% 0.0% 0.0% 32.0% 59.2% 56.3% 

0.00 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 10
4-26

Table 4-9: Model F: Total Number and Percentage of Tubes Plugged (12/2013)

Unit

Number of Tubes 

Plugged1 Percent Plugged Operating Time2

Callaway3 21 0.43 21

Millstone 3 187 0.83 28

Seabrook 1 182 0.81 23

Vogtle 1 151 0.67 27

Vogtle 2 48 0.21 25

Wolf Creek 1 282 1.25 28

TOTALS: 871 0.74

1

As of 12/31/2013

2

Operating Time = calendar years of operation as of 12/31/2013

3

Thermally Treated Tubes Only
4-27

Table 4-10: Model F: Number of Tubes Plugged as a Function of Mechanism (Detailed) 

(12/2013) 

Tubes 

Plugged

Percentage 

of Plugs

Tubes 

Plugged

Percentage 

of Plugs

AVB 480 55.1%

Preheater TSP (D5) 0 0.0%

TSP 11 1.3%

Confirmed 18 2.1%

Not Confirmed, 

Periphery 46 5.3%

Not Confirmed, Not 

Periphery 9 1.0%

From PSI - no 

progression 2 0.2%

Service Induced 5 0.6%

Preservice 63 7.2%

Other 21 2.4%

Probe Lodged 1 0.1%

Data Quality 1 0.1%

Dent/Geometry 39 4.5%

Permeability 2 0.2%

Not Inspected 0 0.0%

Top of Tubesheet 29 3.3%

Freespan 17 2.0%

TSP 20 2.3%

Other/Not Reported 0 0.0%

ID 35 4.0%

OD 72 8.3%

TOTALS 871 100.0% 871 100.0%

Total Tubes: 117376

Fraction Plugged 0.74%

Inspection 

Issues

Other

SCC

Cause of Tube Plugging

Wear

Loose Parts

Obstruction 

Restriction

4.9%

7.6%

107 12.3%

66

43

84

7

73

491 56.4%

8.4%

0.8%

9.6% Manufacturing 

Flaws
4-28

Table 4-11: Model F: Cumulative Plugging per Year

Year Callaway Millstone 3 Seabrook Vogtle 1 Vogtle 2 Wolf Cre

Pre-Op 4 10 13 6 15 

1986 4 

1987 5 12

1988 7 

1989 6 16

1990 6 11 15 

1991 21 23 11 

1992 7 23 15

1993 7 28 15 15 

1994 24 27 

1995 11 39 36 18

1996 16 41 31 24 

1997 49 46 

1998 16 24

1999 16 55 74 46 29 

2000 90 48 

2001 17 106 29

2002 19 117 125 50 31 

2003 140 53 

2004 21 127 42

2005 21 129 140 55 42 

2006 161 74 

2007 133 42

2008 159 161 121 43 

2009 173 146 

2010 166 45

2011 177 173 148 46 

2012 182 151

2013 187 48 

 
4-29

Table 4-12: Model F: Plugging per Year

Year Callaway Millstone 3 Seabrook Vogtle 1 Vogtle 2 Wolf Creek

Mode

Tota

Pre-Op 4 10 13 6 15 15 

1986 0 0 

1987 1 2 

1988 1 22 

1989 1 4 

1990 0 4 0 2 

1991 5 10 0 0 

1992 1 0 0 

1993 0 7 4 0 5 

1994 1 12 27 

1995 4 11 12 3 

1996 5 2 4 6 16 

1997 13 15 19 

1998 0 0 

1999 0 14 25 0 5 6 

2000 16 2 32 

2001 1 51 0 

2002 2 11 35 2 2 9 

2003 15 3 20 

2004 2 10 11 

2005 0 2 0 2 0 8 

2006 21 19 23 

2007 4 0 

2008 26 0 47 1 29 

2009 12 25 18 

2010 7 2 

2011 11 0 2 1 15 

2012 9 3 

2013 10 2 16 

Totals: 21 187 182 151 48 282 

 
4-30

Table 4-13: Model F: Cumulative Plugging per RFO (12/2013)

Outage Callaway Millstone 3 Seabrook Vogtle 1 Vogtle 2 W

Pre-Op 4 10 13 6 15 

RFO 1 4 12 23 7 15 

RFO 2 5 16 23 11 15 

RFO 3 6 21 24 11 15 

RFO 4 6 28 36 15 18 

RFO 5 7 39 49 27 24 

RFO 6 7 55 74 31 24 

RFO 7 11 106 90 46 29 

RFO 8 16 117 125 46 29 

RFO 9 16 127 140 48 31 

RFO 10 16 129 140 50 42 

RFO 11 17 133 161 53 42 

RFO 12 19 159 161 55 42 

RFO 13 21 166 173 74 43 

RFO 14 21 177 173 121 45 

RFO 15 187 182 146 46 

RFO 16 148 48 

RFO 17 151 

RFO 18 

RFO 19 

 
4-31

Table 4-14: Model F: Number of Tubes Plugged as a Function of Mechanism per Year (De

1980-1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 20

AVB 2 19 3 6 11 16 38 26 28 38 49 44 15 28 29 2 6 24 2 24 29 

Preheater TSP (D5) 0 0 0 0 0 0 0 0 

TSP 2 0 0 0 0 0 0 0 

Confirmed 4 5 1 0 2 0 0 2 2 0 

Not Confirmed, 

Periphery 2 1 1 6 11 1 5 0 16 0 0 0 

Not Confirmed, 

Not Periphery 2 2 1 0 0 0 0 2 0 0 0 

From PSI - no 

progression 0 0 0 0 0 0 0 0 

Service Induced 2 1 1 0 0 0 0 0 1 

Preservice 4 15 10 6 15 13 0 0 0 0 0 0 0 0 

Other 0 3 2 0 1 0 1 2 

Probe Lodged 0 0 0 0 0 0 0 0 

Data Quality 0 0 0 0 0 0 0 0 

Dent/Geometry 2 1 0 0 2 0 34 0 

Permeability 0 0 1 0 0 0 0 1 

Not Inspected 0 0 0 0 0 0 0 0 

Top of Tubesheet 3 2 14 1 0 9 0 0 0 0 0 

Freespan 4 1 0 1 2 2 3 0 0 0 4 0 0 0 0 

TSP 1 1 2 1 13 0 0 2 0 0 0 0 0 

Not Reported 0 0 0 0 0 0 0 0 

ID 0 0 0 2 0 0 31 1 

OD 15 3 0 0 18 0 11 21 

TOTALS 0 4 15 10 9 23 20 19 15 1 16 40 30 33 47 0 50 50 52 61 38 23 12 63 4 103 55 

Cause of Tube Plugging/Outage

Year

Wear

Other

SCC

Loose Parts

Obstruction 

Restriction

Manufacturing 

Flaws

Inspection 

Issues
4-32

Table 4-15: Model F: Number of Tubes Plugged as a Function of Mechanism per Yea

Year 1980-1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 

Cause 

Wear 0 0 0 0 2 19 3 6 11 0 16 38 26 28 38 0 49 44 15 30 29 2 6 24 2 24 29 

Loose Parts 0 0 0 0 0 0 0 0 4 0 0 0 2 0 7 0 1 3 7 12 1 7 0 18 2 2 0 

Restrictions 0 0 0 0 0 0 0 0 0 0 0 0 0 0 2 0 0 0 0 1 1 0 0 0 0 0 1 

Manufacturing 0 4 15 10 6 0 15 13 0 0 0 0 0 0 0 0 0 0 0 0 3 2 0 1 0 1 2 

Inspection Issues 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 2 1 1 0 2 0 34 1 

Other 0 0 0 0 1 4 2 0 0 1 0 2 2 5 0 0 0 3 30 1 0 11 4 0 0 0 0 

SCC 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 15 3 0 2 18 0 42 22 

0 4 15 10 9 23 20 19 15 1 16 40 30 33 47 0 50 50 52 61 38 23 12 63 4 103 55 
4-33

Table 4-16: Model F: Percentage of Tubes Plugged as a Function of Mechanism per Ye

Year 1980-1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 

Cause 

Wear 0.0% 0.0% 0.0% 22.2% 82.6% 15.0% 31.6% 73.3% 0.0% 100.0% 95.0% 86.7% 84.8% 80.9% 98.0% 88.0% 28.8% 49.2% 76.3% 8.7% 50.0% 38.1% 50.0% 23.3% 52.7% 

Loose Parts 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 26.7% 0.0% 0.0% 0.0% 6.7% 0.0% 14.9% 2.0% 6.0% 13.5% 19.7% 2.6% 30.4% 0.0% 28.6% 50.0% 1.9% 0.0% 

Restrictions 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 4.3% 0.0% 0.0% 0.0% 1.6% 2.6% 0.0% 0.0% 0.0% 0.0% 0.0% 1.8% 

Manufacturing 100.0% 100.0% 100.0% 66.7% 0.0% 75.0% 68.4% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 7.9% 8.7% 0.0% 1.6% 0.0% 1.0% 3.6% 

Inspection Issues 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 3.3% 2.6% 4.3% 0.0% 3.2% 0.0% 33.0% 1.8% 

Other 0.0% 0.0% 0.0% 11.1% 17.4% 10.0% 0.0% 0.0% 100.0% 0.0% 5.0% 6.7% 15.2% 0.0% 0.0% 6.0% 57.7% 1.6% 0.0% 47.8% 33.3% 0.0% 0.0% 0.0% 0.0% 

SCC 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 24.6% 7.9% 0.0% 16.7% 28.6% 0.0% 40.8% 40.0% 

100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 
4-34

Table 4-17: Replacement Models: Total Number and Percentage of Tubes Plugged 

(12/2013)

Unit

Number of Tubes 

Plugged1 Percent Plugged Operating Time2

Indian Point 2 34 0.26 13

Point Beach 1 13 0.20 30

Robinson 2 48 0.50 29

Salem 1 251 1.12 17

Surry 1 106 1.06 33

Surry 2 94 0.94 33

Turkey Point 3 184 1.91 32

Turkey Point 4 65 0.67 31

TOTALS: 795 0.88

1

As of 12/31/2013

2

Operating Time = calendar years of operation as of 12/31/2013
4-35

Table 4-18: Replacement Models: Number of Tubes Plugged as a Function of Mechanism (Detai

Tubes 

Plugged

Percentage 

of Plugs

Tubes 

Plugged

Percentage 

of Plugs

AVB 299 37.6%

Preheater TSP (D5) 0 0.0%

TSP 18 2.3%

Confirmed 34 4.3%

Not Confirmed, 

Periphery 50 6.3%

Not Confirmed, Not 

Periphery 31 3.9%

From PSI - no 

progression 4 0.5%

Service Induced 16 2.0%

Preservice 94 11.8%

Other 80 10.1%

Probe Lodged 0 0.0%

Data Quality 6 0.8%

Dent/Geometry 2 0.3%

Permeability 16 2.0%

Not Inspected 0 0.0%

Top of Tubesheet 102 12.8%

Freespan 13 1.6%

TSP 7 0.9%

Other/Not Reported 1 0.1%

ID 21 2.6%

OD 1 0.1%

TOTALS 795 100.0% 795 100.0%

Total Tubes: 90766

Fraction Plugged 0.88%

174

20

317

115

39.9%

14.5%

Obstruction 

Restriction

Manufacturing 

Flaws

Cause of Tube Plugging

Wear

21.9%

Other

SCC

15.5%

2.8% 22

123

24 Inspection 

Issues 3.0%

Loose Parts

2.5%
4-36

Table 4-19: Replacement Models: Cumulative Plugging per Year

Outage Indian Point 2 Point Beach 1 Robinson 2 Salem 1 Surry 1 Surry 2 Turkey Poin

Pre-Op 2 4 0 13 2 2 

1980

1981 2

1982

1983 2 2 

1984 4 6 

1985 4 2 

1986 4 0 10 6 

1987 4 0 

1988 6 1 10 3 

1989 6 1

1990 6 2 12 

1991 8 3 

1992 8 3 14 

1993 8 4 5 

1994 8 6 18 

1995 9 6 19 10 

1996 9 7 18 

1997 24 23 

1998 9 7 30 

1999 9 7 23 32 

2000 9 38 39 1

2001 10 11 58 43 1

2002 18 19 91 40 

2003 10 54 43 1

2004 18 10 26 128 54 1

2005 10 26 128 51 

2006 25 70 55 1

2007 10 32 224 71 1

2008 25 11 32 224 64 

2009 86 94 1

2010 34 11 44 238 106 1

2011 13 238 94 

2012 34 44 106 94 1

2013 13 48 251 106 

 
4-37

Table 4-20: Replacement Models: Plugging per Year

Year Indian Point 2 Point Beach 1 Robinson 2 Salem 1 Surry 1 Surry 2 Turkey Point 3 Turkey Po

Pre-Op 2 4 0 13 2 2 39 

1980 

1981 0 

1982 

1983 0 0 0 

1984 0 4 

1985 0 0 4 

1986 0 0 4 1 

1987 0 0 1 

1988 2 1 0 0 

1989 0 0 

1990 0 1 2 11 

1991 2 0 

1992 0 1 2 7 

1993 0 1 2 

1994 0 2 4 4 

1995 1 0 1 5 2 

1996 0 1 8 

1997 5 5 14 

1998 0 0 6 1 

1999 0 0 10 9 

2000 0 8 7 69 

2001 1 4 35 5 14 

2002 16 8 33 1 

2003 0 11 3 3 

2004 0 0 7 37 0 0 

2005 0 0 0 8 

2006 7 16 4 0 

2007 0 6 96 1 1 

2008 0 1 0 0 9 

2009 15 30 0 

2010 9 0 12 14 20 14 

2011 2 0 0 

2012 0 0 0 0 0 

2013 0 4 13 0 

Totals: 34 13 48 251 106 94 184 

 
4-38

Table 4-21: Replacement Models: Cumulative Plugging Per RFO (12/2013)

Outage Indian Point 2 Point Beach 1 Robinson 2 Salem 1 Surry 1 Surry 2 Turkey Po

Pre-Op 2 4 0 13 2 2 

RFO 1 18 4 0 23 2 2 

RFO 2 18 4 0 58 6 2 

RFO 3 25 4 1 91 10 2 

RFO 4 25 6 2 128 10 3 

RFO 5 34 6 3 128 12 3 

RFO 6 34 6 4 224 14 3 

RFO 7 8 6 224 18 5 

RFO 8 8 7 238 19 10 

RFO 9 8 7 238 24 18 

RFO 10 8 7 251 30 23 

RFO 11 9 11 38 32 

RFO 12 9 19 43 39 

RFO 13 9 26 54 40 

RFO 14 9 26 54 43 

RFO 15 10 32 70 51 

RFO 16 10 32 71 55 

RFO 17 10 44 86 64 

RFO 18 10 44 106 94 

RFO 19 10 48 106 94

RFO 20 11 106 94

RFO 21 11

RFO 22 13

RFO 23 13
4-39

Table 4-22: Replacement Models: Number of Tubes Plugged as a Function of Mechanism per Ye

1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 

AVB 7 1 4 2 7 3 3 5 1 8 20 32 47 1 28 0 8 95 0 1 

Preheater TSP (D5) 0 0 0 0 0 0 0 0 

TSP 1 1 12 0 2 0 0 0 0 0 0 

Confirmed 1 2 0 3 5 3 6 0 0 0 

Not Confirmed, 

Periphery 1 1 1 2 3 3 2 1 2 5 10 6 0 8 

Not Confirmed, 

Not Periphery 1 2 0 3 0 1 0 3 13 

From PSI - no 

progression 1 1 1 0 1 0 0 0 0 0 0 

Service Induced 1 1 1 1 2 5 3 1 1 0 0 0 0 0 0 0 0 

Preservice 2 2 39 31 4 13 2 0 1 0 0 0 0 0 0 

Other 1 2 2 2 3 7 8 2 0 0 1 1 21 

Probe Lodged 0 0 0 0 0 0 0 0 

Data Quality 4 0 0 1 0 0 0 0 0 

Dent/Geometry 0 2 0 0 0 0 0 0 

Permeability 1 1 1 0 1 3 0 7 2 0 0 

Not Inspected 0 0 0 0 0 0 0 0 

Top of Tubesheet 1 3 1 2 5 3 8 8 71 0 0 0 0 0 0 0 0 

Freespan 1 5 1 3 1 1 0 1 0 0 0 0 0 0 

TSP 3 1 1 2 0 0 0 0 0 0 0 0 

Not Reported 0 0 0 0 1 0 0 0 

ID 0 0 0 0 0 0 6 13 

OD 0 0 0 0 0 0 0 0 

TOTALS 2 2 39 31 8 4 5 1 4 0 14 3 10 3 10 9 9 37 7 19 96 59 58 21 44 8 33 104 10 56 

SCC

Loose Parts

Obstruction 

Restriction

Manufacturing 

Flaws

Inspection 

Cause of Tube Plugging/Outage

Wear

Issues

Other

Year
4-40

Table 4-23: Replacement Models: Number of Tubes Plugged as a Function of Mechanism per Ye

Year 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 200

Cause 

Wear 0 0 0 0 0 0 0 0 0 0 7 2 4 2 7 3 3 5 1 8 21 44 47 3 28 0 8 95 0 

Loose Parts 0 0 0 0 0 0 1 0 1 0 1 0 0 0 2 0 1 2 3 0 0 4 4 4 10 8 17 6 3 2

Restrictions 0 0 0 0 0 0 1 0 1 0 0 1 1 1 0 1 2 5 3 1 0 2 0 1 0 0 0 0 0 

Manufacturing 2 2 39 31 4 0 1 0 2 0 2 0 0 0 0 0 0 13 0 2 2 3 7 9 2 0 0 1 1 2

Inspection Issues 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1 0 0 1 5 0 3 4 0 7 2 0 

Other 0 0 0 0 4 4 2 1 0 0 4 0 5 0 1 5 3 11 0 8 72 1 0 1 0 0 1 0 0 

SCC 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 6 

2 2 39 31 8 4 5 1 4 0 14 3 10 3 10 9 9 37 7 19 96 59 58 21 44 8 33 104 10 5
4-41

Table 4-24: Replacement Models: Percentage of Tubes Plugged as a Function of Mechanism per Y

Year 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 200

Cause 

Wear 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 50.0% 66.7% 40.0% 66.7% 70.0% 33.3% 33.3% 13.5% 14.3% 42.1% 21.9% 74.6% 81.0% 14.3% 63.6% 0.0% 24.2% 91.3% 0.0% 1.8

Loose Parts 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 20.0% 0.0% 25.0% 7.1% 0.0% 0.0% 0.0% 20.0% 0.0% 11.1% 5.4% 42.9% 0.0% 0.0% 6.8% 6.9% 19.0% 22.7% 100.0% 51.5% 5.8% 30.0% 37.5

Restrictions 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 20.0% 0.0% 25.0% 0.0% 33.3% 10.0% 33.3% 0.0% 11.1% 22.2% 13.5% 42.9% 5.3% 0.0% 3.4% 0.0% 4.8% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0

Manufacturing 100.0% 100.0% 100.0% 100.0% 50.0% 0.0% 20.0% 0.0% 50.0% 14.3% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 35.1% 0.0% 10.5% 2.1% 5.1% 12.1% 42.9% 4.5% 0.0% 0.0% 1.0% 10.0% 37.5

Inspection Issues 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 2.7% 0.0% 0.0% 1.0% 8.5% 0.0% 14.3% 9.1% 0.0% 21.2% 1.9% 0.0% 0.0

Other 0.0% 0.0% 0.0% 0.0% 50.0% 100.0% 40.0% 100.0% 0.0% 28.6% 0.0% 50.0% 0.0% 10.0% 55.6% 33.3% 29.7% 0.0% 42.1% 75.0% 1.7% 0.0% 4.8% 0.0% 0.0% 3.0% 0.0% 0.0% 0.0

SCC 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 60.0% 23.2

100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0
4-42

Table 4-25: Cracking in Thermally Treated Alloy 600 Tubes (12/2013)

Unit RFO Year EFPY

T-Hot 

(degrees 

F) ID or OD

Axial or 

Circumferential HL/CL

Number of 

Tubes Location Notes

Braidwood 2 10 2003 12.78 611 OD Axial HL 3 TSP

Nonoptimal tube processing, high 

row

Braidwood 2 13 2008 17.05 611 ID Axial HL Tube End

Braidwood 2 13 2008 17.05 611 ID Circumferential HL Tube End

Braidwood 2 13 2008 17.05 611 ID Mixed Mode HL Tube End

Braidwood 2 15 2011 19.86 611 OD Axial HL 1 TSP

Nonoptimal tube processing, low row, 

3 indications

Braidwood 2 16 2012 21.27 611 OD Axial HL TSP

Braidwood 2 16 2012 21.27 611 OD Axial HL Freespan

Byron 2 14 2008 18.58 611 ID Axial HL 65 Tube End

Catawba 2 13 2004 14.68 615 ID Axial HL Tube End

Catawba 2 13 2004 14.68 615 ID Circumferential HL Tube End

Catawba 2 13 2004 14.68 615 ID Circumferential HL 1 Tubesheet Overexpansion, 3 indications

Catawba 2 14 2006 16.06 615 ID Axial HL Tube End

Catawba 2 14 2006 16.06 615 ID Circumferential HL Tube End

Catawba 2 15 2007 17.43 615 ID Axial HL Tube End

Catawba 2 15 2007 17.43 615 ID Circumferential HL Tube End

Catawba 2 15 2007 17.43 615 ID Mixed Mode HL Tube End

Catawba 2 15 2007 17.43 615 ID Circumferential CL 10 Tube End

Subsequently reclassifed as 

permeability variations

Catawba 2 15 2007 17.43 615 OD Axial HL 8 Expansion Transition Sludge Pile

Catawba 2 16 2009 18.73 615 ID Axial HL Tube End

Catawba 2 16 2009 18.73 615 ID Circumferential HL Tube End

Catawba 2 16 2009 18.73 615 OD Axial HL 3 TSP

Nonoptimal tube processing, 8 

indications

Catawba 2 17 2010 20.13 615 ID Axial HL Tube End

Catawba 2 17 2010 20.13 615 ID Circumferential HL Tube End

Catawba 2 18 2012 21.50 615 ID Axial HL Tube End

Catawba 2 18 2012 21.50 615 ID Circumferential HL Tube End

Catawba 2 19 2013 22.89 615 ID Axial HL Tube End

Catawba 2 19 2013 22.89 615 ID Circumferential HL Tube End

Comanche Peak 2 10 2008 13.04 618 ID Axial HL 9 Tube End

Comanche Peak 2 10 2008 13.04 618 ID Circumferential HL 4 Tube End

Millstone 3 12 2008 16.60 622 ID Axial HL 94 Tube End

Millstone 3 12 2008 16.60 622 ID Circumferential HL 48 Tube End

Millstone 3 12 2008 16.60 622 ID Mixed Mode HL 4 Tube End

Millstone 3 12 2008 16.60 622 ID Circumferential CL 1 Tube End

Point Beach 1 33 2011 23.20 ID Circumferential HL 2 Tube End

Robinson 28 2013 23.20 604 ID Circumferential HL 2 Tube End

Seabrook 8 2002 9.71 618 OD Axial HL

Seabrook 8 2002 9.71 618 OD Axial CL

Seabrook 9 2003 11.00 618 OD Axial HL 3 TSP Nonoptimal tube processing

Seabrook 13 2009 16.53 621 OD Axial HL 1 Expansion Transition

Starts at bottom of expansion 

transition and goes into tubesheet

Seabrook 15 2012 18.95 621 OD Axial HL 1 Dented TSP Dented TSP, 11.4 volt dent

Seabrook 15 2012 18.95 621 OD Axial HL 1 Freespan 3 indications

Surry 1 17 2009 22.20 605 ID Axial HL 1 Expansion Transition

Extends above and below top of 

tubesheet

Surry 1 17 2009 22.20 605 ID Axial HL 19 Tube End

Surry 1 17 2009 22.20 605 ID Circumferential HL 66 Tube End

Surry 1 18 2010 23.60 605 OD Circumferential HL 1 Expansion Transition

Surry 2 17 2008 22.10 605 ID Axial HL 16 Tube End 18 indications

Surry 2 17 2008 22.10 605 ID Circumferential HL 101 Tube End 102 indications

Turkey Point 3 26 2014 24.70 ID Axial HL 1 Tube End

Turkey Point 4 26 2013 23.05 610 ID Axial HL 11 Tube End

Vogtle 1 12 2005 15.68 618 ID Circumferential HL 2 Tubesheet Bulge

Vogtle 1 13 2006 17.08 618 OD Axial HL 1 Expansion Transition

Vogtle 1 13 2006 17.08 618 OD Circumferential HL 17 Expansion Transition

Vogtle 1 14 2008 18.40 618 OD Axial HL 1 Expansion Transition

Vogtle 1 14 2008 18.40 618 OD Circumferential HL 10 Expansion Transition

Vogtle 1 14 2008 18.40 618 ID Axial HL 21 Tube End

Vogtle 1 14 2008 18.40 618 ID Circumferential HL 6 Tube End

Vogtle 1 15 2009 19.80 618 ID Axial HL 1 U-bend Row 1

Vogtle 1 15 2009 19.80 618 OD Circumferential HL 20 Expansion Transition

Vogtle 1 16 2011 21.20 618 OD Axial HL 1 Expansion Transition

Vogtle 1 18 2014 24.00 618 OD Circumferential HL 8 Expansion Transition

Vogtle 1 18 2014 24.00 618 ID Circumferential HL 1 Tubesheet Bulge

Vogtle 2 10 2004 13.49 618 OD Circumferential HL 9 Expansion Transition False indications based on tube pulls

Vogtle 2 16 2013 21.30 618 OD Circumferential HL 1 Expansion Transition

Wolf Creek 16 2008 19.23 618 ID Axial HL 33 Tube End

Wolf Creek 16 2008 19.23 618 ID Circumferential HL 36 Tube End

Wolf Creek 19 2013 23.22 618 ID Circumferential HL 1 Tubesheet Bulge

Acronyms:

CL = cold-leg

EFPY = effective full power years

HL = hot-leg

ID = inside diameter

OD = outside diameter

TSP = tube support plate

288 285 axial indications, 46 

circumferential indications

1 Nonoptimal tube processing, high 

row

15 TSP Nonoptimal tube processing, 42 

indications, 36 HL, 6CL
4-43

Table 4-26: Tube End Cracking in Thermally Treated Alloy 600 Tubes (12/2013)

Unit RFO Year EFPY

T- Hot 

(degrees F) ID or OD

Axial or 

Circumferential HL/CL

Number 

of Tubes Location Notes

Braidwood 2 13 2008 17.05 611 ID Axial HL Tube End

Braidwood 2 13 2008 17.05 611 ID Circumferential HL Tube End

Braidwood 2 13 2008 17.05 611 ID Mixed Mode HL Tube End

Byron 2 14 2008 18.58 611 ID Axial HL 65 Tube End

Catawba 2 13 2004 14.68 615 ID Axial HL Tube End

Catawba 2 13 2004 14.68 615 ID Circumferential HL Tube End

Catawba 2 14 2006 16.06 615 ID Axial HL Tube End

Catawba 2 14 2006 16.06 615 ID Circumferential HL Tube End

Catawba 2 15 2007 17.43 615 ID Axial HL Tube End

Catawba 2 15 2007 17.43 615 ID Circumferential HL Tube End

Catawba 2 15 2007 17.43 615 ID Mixed Mode HL Tube End

Catawba 2 15 2007 17.43 615 ID Circumferential CL 10 Tube End

Subsequently reclassifed as 

permeability variations

Catawba 2 16 2009 18.73 615 ID Axial HL Tube End

Catawba 2 16 2009 18.73 615 ID Circumferential HL Tube End

Catawba 2 17 2010 20.13 615 ID Axial HL Tube End

Catawba 2 17 2010 20.13 615 ID Circumferential HL Tube End

Catawba 2 18 2012 21.50 615 ID Axial HL Tube End

Catawba 2 18 2012 21.50 615 ID Circumferential HL Tube End

Catawba 2 19 2013 22.89 615 ID Axial HL Tube End

Catawba 2 19 2013 22.89 615 ID Circumferential HL Tube End

Comanche Peak 2 10 2008 13.04 618 ID Axial HL 9 Tube End

Comanche Peak 2 10 2008 13.04 618 ID Circumferential HL 4 Tube End

Millstone 3 12 2008 16.60 622 ID Axial HL 94 Tube End

Millstone 3 12 2008 16.60 622 ID Circumferential HL 48 Tube End

Millstone 3 12 2008 16.60 622 ID Mixed Mode HL 4 Tube End

Millstone 3 12 2008 16.60 622 ID Circumferential CL 1 Tube End

Point Beach 1 33 2011 23.20 ID Circumferential HL 2 Tube End

Robinson 28 2013 23.20 604 ID Circumferential HL 2 Tube End

Surry 1 17 2009 22.20 605 ID Axial HL 19 Tube End

Surry 1 17 2009 22.20 605 ID Circumferential HL 66 Tube End

Surry 2 17 2008 22.10 605 ID Axial HL 16 Tube End 18 indications

Surry 2 17 2008 22.10 605 ID Circumferential HL 101 Tube End 102 indications

Turkey Point 3 26 2014 24.70 ID Axial HL 1 Tube End

Turkey Point 4 26 2013 23.05 610 ID Axial HL 11 Tube End

Vogtle 1 14 2008 18.40 618 ID Axial HL 21 Tube End

Vogtle 1 14 2008 18.40 618 ID Circumferential HL 6 Tube End

Wolf Creek 16 2008 19.23 618 ID Axial HL 33 Tube End

Wolf Creek 16 2008 19.23 618 ID Circumferential HL 36 Tube End

Acronyms:

CL = cold-leg

EFPY = effective full power years

HL = hot-leg

ID = inside diameter

OD = outside diameter

TSP = tube support plate

288 285 axial indications, 46 

circumferential indications
4-44

Table 4-27: Non Tube-End Cracking in Thermally Treated Alloy 600 Tubes

(Sorted by Plant) (12/2013)

Unit RFO Year EFPY

T-Hot 

(degrees F) ID or OD

Axial or 

Circumferential HL/CL

Number 

of Tubes Location Notes

Braidwood 2 10 2003 12.78 611 OD Axial HL 3 TSP Nonoptimal tube processing, high row

Braidwood 2 15 2011 19.86 611 OD Axial HL 1 TSP

Nonoptimal tube processing, low row, 3 

indications

Braidwood 2 16 2012 21.27 611 OD Axial HL TSP

Braidwood 2 16 2012 21.27 611 OD Axial HL Freespan

Catawba 2 13 2004 14.68 615 ID Circumferential HL 1 Tubesheet Overexpansion, 3 indications

Catawba 2 15 2007 17.43 615 OD Axial HL 8 Expansion Transition Sludge Pile

Catawba 2 16 2009 18.73 615 OD Axial HL 3 TSP Nonoptimal tube processing, 8 indications

Seabrook 8 2002 9.71 618 OD Axial HL

Seabrook 8 2002 9.71 618 OD Axial CL

Seabrook 9 2003 11.00 618 OD Axial HL 3 TSP Nonoptimal tube processing

Seabrook 13 2009 16.53 621 OD Axial HL 1 Expansion Transition

Starts at bottom of expansion transition and 

goes into tubesheet

Seabrook 15 2012 18.95 621 OD Axial HL 1 Dented TSP Dented TSP, 11.4 volt dent

Seabrook 15 2012 18.95 621 OD Axial HL 1 Freespan 3 indications

Surry 1 17 2009 22.20 605 ID Axial HL 1 Expansion Transition Extends above and below top of tubesheet

Surry 1 18 2010 23.60 605 OD Circumferential HL 1 Expansion Transition

Vogtle 1 12 2005 15.68 618 ID Circumferential HL 2 Tubesheet Bulge

Vogtle 1 13 2006 17.08 618 OD Axial HL 1 Expansion Transition

Vogtle 1 13 2006 17.08 618 OD Circumferential HL 17 Expansion Transition

Vogtle 1 14 2008 18.40 618 OD Axial HL 1 Expansion Transition

Vogtle 1 14 2008 18.40 618 OD Circumferential HL 10 Expansion Transition

Vogtle 1 15 2009 19.80 618 ID Axial HL 1 U-bend Row 1

Vogtle 1 15 2009 19.80 618 OD Circumferential HL 20 Expansion Transition

Vogtle 1 16 2011 21.20 618 OD Axial HL 1 Expansion Transition

Vogtle 1 18 2014 24.00 618 OD Circumferential HL 8 Expansion Transition

Vogtle 1 18 2014 24.00 618 ID Circumferential HL 1 Tubesheet Bulge

Vogtle 2 10 2004 13.49 618 OD Circumferential HL 9 Expansion Transition False indications based on tube pulls

Vogtle 2 16 2013 21.30 618 OD Circumferential HL 1 Expansion Transition

Wolf Creek 19 2013 23.22 618 ID Circumferential HL 1 Tubesheet Bulge

Acronyms:

CL = cold-leg

EFPY = effective full power years

HL = hot-leg

ID = inside diameter

OD = outside diameter

TSP = tube support plate

Nonoptimal tube processing, 42 indications, 

36 HL, 6CL

1 Nonoptimal tube processing, high row

15 TSP
4-45

Table 4-28: Non Tube-End Cracking in Thermally Treated Alloy 600 Tubes

(Sorted by Location) (12/2013)

Unit RFO Year EFPY

T-Hot 

(degrees F) ID or OD

Axial or 

Circumferential HL/CL

Number 

of Tubes Location Notes

Seabrook 15 2012 18.95 621 OD Axial HL 1 Dented TSP Dented TSP, 11.4 volt dent

Catawba 2 15 2007 17.43 615 OD Axial HL 8 Expansion Transition Sludge Pile

Seabrook 13 2009 16.53 621 OD Axial HL 1 Expansion Transition

Starts at bottom of expansion transition and 

goes into tubesheet

Surry 1 17 2009 22.20 605 ID Axial HL 1 Expansion Transition Extends above and below top of tubesheet

Surry 1 18 2010 23.60 605 OD Circumferential HL 1 Expansion Transition

Vogtle 1 13 2006 17.08 618 OD Axial HL 1 Expansion Transition

Vogtle 1 13 2006 17.08 618 OD Circumferential HL 17 Expansion Transition

Vogtle 1 14 2008 18.40 618 OD Axial HL 1 Expansion Transition

Vogtle 1 14 2008 18.40 618 OD Circumferential HL 10 Expansion Transition

Vogtle 1 15 2009 19.80 618 OD Circumferential HL 20 Expansion Transition

Vogtle 1 16 2011 21.20 618 OD Axial HL 1 Expansion Transition

Vogtle 1 18 2014 24.00 618 OD Circumferential HL 8 Expansion Transition

Vogtle 2 10 2004 13.49 618 OD Circumferential HL 9 Expansion Transition False indications based on tube pulls

Vogtle 2 16 2013 21.30 618 OD Circumferential HL 1 Expansion Transition

Seabrook 15 2012 18.95 621 OD Axial HL 1 Freespan 3 indications

Braidwood 2 10 2003 12.78 611 OD Axial HL 3 TSP Nonoptimal tube processing, high row

Braidwood 2 15 2011 19.86 611 OD Axial HL 1 TSP

Nonoptimal tube processing, low row, 3 

indications

Braidwood 2 16 2012 21.27 611 OD Axial HL TSP

Braidwood 2 16 2012 21.27 611 OD Axial HL Freespan

Catawba 2 16 2009 18.73 615 OD Axial HL 3 TSP Nonoptimal tube processing, 8 indications

Seabrook 8 2002 9.71 618 OD Axial HL

Seabrook 8 2002 9.71 618 OD Axial CL

Seabrook 9 2003 11.00 618 OD Axial HL 3 TSP Nonoptimal tube processing

Catawba 2 13 2004 14.68 615 ID Circumferential HL 1 Tubesheet Overexpansion, 3 indications

Vogtle 1 12 2005 15.68 618 ID Circumferential HL 2 Tubesheet Bulge

Vogtle 1 18 2014 24.00 618 ID Circumferential HL 1 Tubesheet Bulge

Wolf Creek 19 2013 23.22 618 ID Circumferential HL 1 Tubesheet Bulge

Vogtle 1 15 2009 19.80 618 ID Axial HL 1 U-bend Row 1

Acronyms:

CL = cold-leg

EFPY = effective full power years

HL = hot-leg

ID = inside diameter

OD = outside diameter

TSP = tube support plate

1 Nonoptimal tube processing, high row

15 TSP Nonoptimal tube processing, 42 indications, 

36 HL, 6CL
4-46

Table 4-29: Wear at the AVBs (12/2013)

Unit

SG 

Operation 

Date Model

"Last" 

RFO

Plugged for 

AVB Wear 

(Total)

Number of 

Tubes with 

AVB Wear

Number of 

AVB Wear 

Indications

Braidwood 2 10/17/1988 D5 16 133 530 969

Byron 2 08/21/1987 D5 16 138 751 1023

Callaway 12/19/1984 F

Catawba 2 08/19/1986 D5 19 29 214 338

Comanche Peak 21 08/03/1993 D5 12 20 177 286

Indian Point 21 12/01/2000 44F 19 29 103 207

Millstone 3 04/23/1986 F 14/15 75 323 639

Point Beach 1 03/01/1984 44F 34 3 108 176

Robinson 21 10/01/1984 44F 28 1 11 15

Salem 1 07/01/1997 F 22 208 737 1472

Seabrook 08/19/1990 F 15 102 592 1279

Surry 1 07/01/1981 51F 19/20 16 62 79

Surry 2 09/01/1980 51F 19/20 16 68 95

Turkey Point 3 04/01/1982 44F 24 24 116 165

Turkey Point 4 05/01/1983 44F 26 2 50 62

Vogtle 1 06/01/1987 F 16/17 45 371 703

Vogtle 2 05/20/1989 F 15/16 22 262 465

Wolf Creek1 09/03/1985 F 19 236 1388 3241

Notes/Acronyms:

1

100% of the tubes were not inspected, but all prior indications were inspected during the outage.

AVB = anti-vibration bar

RFO = refueling outage

SG = steam generator
4-47

Table 4-30: All Models: Total Number and Percentage of Tubes Plugged (12/2013)

Braidwood 2 270 1.48 25.2

Byron 2 408 2.23 26.4

Catawba 2 309 1.69 27.4

Comanche Peak 2 81 0.44 20.4

Indian Point 2 34 0.26 13.1

Millstone 3 187 0.83 27.7

Point Beach 1 13 0.20 29.9

Robinson 2 48 0.50 29.3

Salem 1 251 1.12 16.5

Seabrook 1 182 0.81 23.4

Surry 1 106 1.06 32.5

Surry 2 94 0.94 33.4

Turkey Point 3 184 1.91 31.8

Turkey Point 4 65 0.67 30.7

Vogtle 1 151 0.67 26.6

Vogtle 2 48 0.21 24.6

Wolf Creek 1 282 1.25 28.3

Callaway3 21 0.43 20.9

TOTALS: 2734 0.97 1

As of 12/31/2013

2

Operating Time = calendar years of operation as of 12/31/2013

3

Only the first 10 rows of the Callaway steam generators have thermally treated tubes;

 the remaining are mill-annealed Alloy 600. Steam generators were replaced in 2005.

 New steam generators have Alloy 690 tubes.

Unit

Number of Tubes 

Plugged1 Percent Plugged Operating Time2
4-48

Table 4-31: All Models: Number of Tubes Plugged as a Function of Mechanism (Detailed) (

Tubes 

Plugged

Percentage 

of Plugs

Tubes 

Plugged

Percentage 

of Plugs

Tubes 

Plugged

Percentage 

of Plugs

Tu

Plug

AVB 320 30.0% 480 55.1% 299 37.6% 

Preheater TSP (D5) 30 2.8% 0 0.0% 0 0.0% 

TSP 3 0.3% 11 1.3% 18 2.3% 

Confirmed 200 18.7% 18 2.1% 34 4.3% 

Not Confirmed, 

Periphery 88 8.2% 46 5.3% 50 6.3% 

Not Confirmed, Not 

Periphery 56 5.2% 9 1.0% 31 3.9% 

From PSI - no 

progression 1 0.1% 2 0.2% 4 0.5% 

Service Induced 2 0.2% 5 0.6% 16 2.0% 

Preservice 50 4.7% 63 7.2% 94 11.8% 

Other 65 6.1% 21 2.4% 80 10.1% 

Probe Lodged 2 0.2% 1 0.1% 0 0.0% 

Data Quality 19 1.8% 1 0.1% 6 0.8% 

Dent/Geometry 5 0.5% 39 4.5% 2 0.3% 

Permeability 7 0.7% 2 0.2% 16 2.0% 

Not Inspected 3 0.3% 0 0.0% 0 0.0% 

Top of Tubesheet 18 1.7% 29 3.3% 102 12.8% 

Freespan 79 7.4% 17 2.0% 13 1.6% 

TSP 42 3.9% 20 2.3% 7 0.9% 

Other/Not Reported 11 1.0% 0 0.0% 1 0.1% 

ID 51 4.8% 35 4.0% 21 2.6% 

OD 16 1.5% 72 8.3% 1 0.1% 

TOTALS 1068 100.0% 871 100.0% 795 100.0% 

Total Tubes: 73120 117376 90766 28

Percentage Plugged: 1.46% 0.74% 0.88% 0

Average Age (years): 24.9 26.1 27.1 

Age does not include Callaway

Cause of Tube Plugging

Other

SCC

Obstruction 

Restriction

Replacement Models Model F Model D5

Manufacturing 

Flaws

Inspection 

Issues

Loose Parts

Wear
4-49

Table 4-32: All Models: Number of Tubes Plugged as a Function of Mechanism (Summary) 

Tubes 

Plugged

Percentage 

of Plugs

Tubes 

Plugged

Percentage 

of Plugs

Tubes 

Plugged

Percentage 

of Plugs

Tube

Plugg

AVB

Preheater TSP (D5)

TSP

Confirmed

Not Confirmed, 

Periphery

Not Confirmed, Not 

Periphery

From PSI - no 

progression

Service Induced

Preservice

Other

Probe Lodged

Data Quality

Dent/Geometry

Permeability

Not Inspected

Top of Tubesheet

Freespan

TSP

Other/Not Reported

ID

OD

TOTALS 1068 100.0% 871 100.0% 795 100.0% 2

Total Tubes: 73120 117376 90766 281

Percentage Plugged: 1.46% 0.74% 0.88% 0.9

Average Age (years): 24.9 26.1 27.1 2

Age does not include Callaway

Cause of Tube Plugging

Model D5 Model F Replacement Models

Wear

Loose Parts

491 56.4%

8.4%

0.8%

9.6%

SCC

Obstruction 

Restriction

Manufacturing 

Flaws

Inspection 

Issues

Other

67

33.1%

32.2%

0.3%

10.8%

3.4%

14.0%

6.3%

353

344

3

115

36

150

107

73

7

84

43

66

30

373

103

339

12.3%

174

24

123

22

15.5%

2.8%

39.9%

14.5%

2.5%

317

115

20

196

21.9%

3.0%

116

532

4.9%

7.6%
4-50

Table 4-33: All Models: Plugging per Year

Year Model D5 Model F

Replacement 

Models All Models

Tubes in TT 

SGs

Pre-Op 51 63 93 207 281262

1980 0 0 10026

1981 0 0 20052

1982 0 0 29694

1983 0 0 39336

1984 4 4 60262

1985 4 4 82766

1986 0 0 5 5 123550

1987 0 3 1 4 164334

1988 7 23 4 34 182614

1989 19 5 0 24 205118

1990 42 6 14 62 227622

1991 22 15 3 40 227622

1992 29 1 10 40 227622

1993 95 16 3 114 245902

1994 37 40 10 87 245902

1995 52 30 9 91 245902

1996 65 33 9 107 245902

1997 46 47 24 117 268406

1998 47 0 7 54 268406

1999 25 50 19 94 268406

2000 22 50 94 166 281262

2001 4 52 59 115 281262

2002 30 61 58 149 281262

2003 95 38 21 154 281262

2004 140 23 44 207 281262

2005 36 12 8 56 276406

2006 28 63 33 124 276406

2007 25 4 104 133 276406

2008 49 103 10 162 276406

2009 16 55 56 127 276406

2010 2 9 69 80 276406

2011 61 29 2 92 276406

2012 16 12 0 28 276406

2013 7 28 18 53 276406

Totals: 1068 871 795 2734

 
4-51

Table 4-33b: Plugging per Year

Year Model D5

Tubes in TT 

SGs Model F

Tubes in TT 

SGs

Replacement 

Models

Tubes in TT 

SGs All Models

Tubes in TT 

SGs Model D5 Model F

Pre-Op 51 73120 63 117376 93 90766 207 281262 0.07% 0.05

1980 0 10026 0 10026 0.00% 0.00

1981 0 20052 0 20052 0.00% 0.00

1982 0 29694 0 29694 0.00% 0.00

1983 0 39336 0 39336 0.00% 0.00

1984 4856 4 55406 4 60262 0.00% 0.00

1985 27360 4 55406 4 82766 0.00% 0.00

1986 0 18280 0 49864 5 55406 5 123550 0.00% 0.00

1987 0 36560 3 72368 1 55406 4 164334 0.00% 0.00

1988 7 54840 23 72368 4 55406 34 182614 0.01% 0.03

1989 19 54840 5 94872 0 55406 24 205118 0.03% 0.01

1990 42 54840 6 117376 14 55406 62 227622 0.08% 0.01

1991 22 54840 15 117376 3 55406 40 227622 0.04% 0.01

1992 29 54840 1 117376 10 55406 40 227622 0.05% 0.00

1993 95 73120 16 117376 3 55406 114 245902 0.13% 0.01

1994 37 73120 40 117376 10 55406 87 245902 0.05% 0.03

1995 52 73120 30 117376 9 55406 91 245902 0.07% 0.03

1996 65 73120 33 117376 9 55406 107 245902 0.09% 0.03

1997 46 73120 47 117376 24 77910 117 268406 0.06% 0.04

1998 47 73120 0 117376 7 77910 54 268406 0.06% 0.00

1999 25 73120 50 117376 19 77910 94 268406 0.03% 0.04

2000 22 73120 50 117376 94 90766 166 281262 0.03% 0.04

2001 4 73120 52 117376 59 90766 115 281262 0.01% 0.04

2002 30 73120 61 117376 58 90766 149 281262 0.04% 0.05

2003 95 73120 38 117376 21 90766 154 281262 0.13% 0.03

2004 140 73120 23 117376 44 90766 207 281262 0.19% 0.02

2005 36 73120 12 112520 8 90766 56 276406 0.05% 0.01

2006 28 73120 63 112520 33 90766 124 276406 0.04% 0.06

2007 25 73120 4 112520 104 90766 133 276406 0.03% 0.00

2008 49 73120 103 112520 10 90766 162 276406 0.07% 0.09

2009 16 73120 55 112520 56 90766 127 276406 0.02% 0.05

2010 2 73120 9 112520 69 90766 80 276406 0.00% 0.01

2011 61 73120 29 112520 2 90766 92 276406 0.08% 0.03

2012 16 73120 12 112520 0 90766 28 276406 0.02% 0.01

2013 7 73120 28 112520 18 90766 53 276406 0.01% 0.02

Totals: 1068 871 795 2734

Note: Table 4-33b tracks the number and percentage of tubes removed from service each year, after steam generator operation commenced. The percent plugging per year does not include tubes removed fro
4-52

Table 4-34: All Models: Number of Tubes Plugged as a Function of Mechanism per Year (D

1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 

AVB 0 0 2 19 5 48 29 29 69 52 51 79 62 3 72 79 47 79 45 31 16 42 100 31 31 

Preheater TSP (D5) 0 0 0 0 0 0 0 0 0 0 0 0 0 1 1 0 0 2 6 0 6 2 0 3 0 

TSP 0 0 0 0 0 0 1 0 0 0 0 0 0 2 0 1 12 2 2 0 0 0 0 0 0 

Confirmed 0 1 0 2 4 0 4 0 0 2 1 6 8 3 0 0 1 17 45 116 3 15 2 5 0 

Not Confirmed, 

Periphery 0 0 0 1 1 2 0 0 1 0 9 1 2 4 6 1 11 16 8 12 14 26 19 5 12 

Not Confirmed, 

Not Periphery 0 0 0 0 0 0 0 0 0 0 0 0 2 0 1 4 2 7 0 10 3 5 0 4 14 

From PSI - no 

progression 0 0 0 0 0 0 0 1 1 0 0 0 0 0 0 0 1 0 1 0 1 0 0 0 0 

Service Induced 0 1 0 1 0 0 1 0 0 0 1 2 8 3 2 0 1 1 1 0 0 0 0 0 1 

Preservice 2 2 39 31 8 15 24 17 6 15 13 -1 0 20 0 0 0 13 0 0 2 0 0 1 0 0 0 0 0 0 

Other 0 1 0 2 0 2 0 0 0 0 0 0 15 29 2 0 3 7 15 4 7 5 2 3 24 

Probe Lodged 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 2 0 0 0 0 0 0 0 0 0 

Data Quality 0 0 0 0 1 0 0 0 0 0 0 0 1 0 0 0 4 0 17 1 0 0 0 0 0 

Dent/Geometry 0 0 0 0 1 0 0 0 0 0 0 1 0 2 0 0 0 2 3 0 0 3 0 34 0 

Permeability 0 0 0 0 0 0 0 0 0 0 0 0 3 1 0 2 1 0 3 5 0 7 2 0 1 

Not Inspected 0 0 0 0 0 0 0 0 0 0 0 0 1 0 0 2 0 0 0 0 0 0 0 0 0 

Top of Tubesheet 1 3 0 1 0 2 2 0 0 3 4 7 7 11 2 9 73 14 1 0 9 0 0 0 0 0 

Freespan 0 1 0 7 5 1 1 9 30 21 12 7 4 0 0 1 5 0 1 0 4 0 0 0 0 

TSP 3 1 1 1 2 4 5 5 1 8 8 5 4 0 4 1 1 13 0 0 2 0 0 0 0 0 

Not Reported 0 0 0 0 1 2 0 0 2 0 5 0 0 0 0 0 0 0 0 1 0 1 0 0 0 

ID 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 16 2 0 0 66 20 

OD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 15 6 0 0 18 8 11 24 

TOTALS 2 2 39 31 12 19 29 21 40 39 75 40 40 134 87 91 107 130 54 94 168 115 149 154 207 56 124 133 162 127 

Cause of Tube Plugging/Outage

Year

Wear

Other

SCC

Loose Parts

Obstruction 

Restriction

Manufacturing 

Flaws

Inspection 

Issues
4-53

Table 4-35: All Models: Number of Tubes Plugged as a Function of Mechanism per Year (Su

Year 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 200

Cause 

Wear 0 0 0 0 0 0 0 2 19 5 48 30 29 69 52 51 79 62 6 73 80 59 83 53 31 22 44 100 34 3

Loose Parts 0 0 0 0 0 0 1 0 3 5 2 4 0 1 2 10 7 12 7 7 5 14 40 53 138 20 46 21 14 2

Restrictions 0 0 0 0 0 0 1 0 1 0 0 1 1 1 0 1 2 8 3 2 0 2 1 2 0 1 0 0 0 

Manufacturing 2 2 39 31 8 15 25 17 8 15 15 -1 0 20 0 0 0 28 29 2 2 3 7 16 4 7 5 2 3 2

Inspection Issues 0 0 0 0 0 0 0 0 0 2 0 0 0 0 0 0 1 5 3 0 6 5 2 23 6 0 10 2 34 

Other 0 0 0 0 4 4 2 2 9 12 10 6 10 43 33 29 18 15 6 10 75 32 1 1 12 4 1 0 0 

SCC 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 15 6 16 2 18 8 77 4

2 2 39 31 12 19 29 21 40 39 75 40 40 134 87 91 107 130 54 94 168 115 149 154 207 56 124 133 162 12
4-54

Table 4-36: All Models: Percentage of Tubes Plugged as a Function of Mechanism per Year (S

Year 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 200

Cause 

Wear 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 9.5% 47.5% 12.8% 64.0% 75.0% 72.5% 51.5% 59.8% 56.0% 73.8% 47.7% 11.1% 77.7% 47.6% 51.3% 55.7% 34.4% 15.0% 39.3% 35.5% 75.2% 21.0% 24.4

Loose Parts 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 3.4% 0.0% 7.5% 12.8% 2.7% 10.0% 0.0% 0.7% 2.3% 11.0% 6.5% 9.2% 13.0% 7.4% 3.0% 12.2% 26.8% 34.4% 66.7% 35.7% 37.1% 15.8% 8.6% 20.5

Restrictions 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 3.4% 0.0% 2.5% 0.0% 0.0% 2.5% 2.5% 0.7% 0.0% 1.1% 1.9% 6.2% 5.6% 2.1% 0.0% 1.7% 0.7% 1.3% 0.0% 1.8% 0.0% 0.0% 0.0% 0.8

Manufacturing 100.0% 100.0% 100.0% 100.0% 66.7% 78.9% 86.2% 81.0% 20.0% 38.5% 20.0% -2.5% 0.0% 14.9% 0.0% 0.0% 0.0% 21.5% 53.7% 2.1% 1.2% 2.6% 4.7% 10.4% 1.9% 12.5% 4.0% 1.5% 1.9% 18.9

Inspection Issues 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 5.1% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.9% 3.8% 5.6% 0.0% 3.6% 4.3% 1.3% 14.9% 2.9% 0.0% 8.1% 1.5% 21.0% 0.8

Other 0.0% 0.0% 0.0% 0.0% 33.3% 21.1% 6.9% 9.5% 22.5% 30.8% 13.3% 15.0% 25.0% 32.1% 37.9% 31.9% 16.8% 11.5% 11.1% 10.6% 44.6% 27.8% 0.7% 0.6% 5.8% 7.1% 0.8% 0.0% 0.0% 0.0

SCC 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 10.1% 3.9% 7.7% 3.6% 14.5% 6.0% 47.5% 34.6

100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0
4-55

Figure 4-1: Model D5: Causes of Tube Plugging (12/2013)
4-56

Figure 4-2a: Model D5: Cumulative Plugging per Year (12/2013)
4-57

Figure 4-2b: Model D5: Plugging per Year (12/2013)
4-5

8

Figure 4-3: Model D5: Cumulative Plugging per Refueling Outage (12/2013)
4-59

Figure 4-4: Model D5: Causes of Tube Plugging per Year (12/2013)
4-60

Figure 4-5: Model F: Causes of Tube Plugging (12/2013)
4-61

Figure 4-6a: Model F: Cumulative Plugging per Year (12/2013)
4-62

Figure 4-6b: Model F: Plugging per Year (12/2013)
4-63

Figure 4-7: Model F: Cumulative Plugging per Refueling Outage (12/2013)
4-64

Figure 4-8: Model F: Causes of Tube Plugging per Year (12/2013)
4-65

Figure 4-9: Replacement Models: Causes of Tube Plugging (12/2013)
4-66

Figure 4-10a: Replacement Models: Cumulative Plugging per Year (12/2013)
4-67

Figure 4-10b: Replacement Models: Plugging per Year (12/2013)
4-68

Figure 4-11: Replacement Models: Cumulative Plugging per Refueling Outage (12/201
4-69

Figure 4-12: Replacement Models: Causes of Tube Plugging per Year (12/2013)
4-70

Figure 4-13: Number of Thermally Treated Alloy 600 Tubes in Service per Year (12/201
4-71

Figure 4-14: All Models: Tubes Plugged Per Grouping/Model (12/2013)
4-72

Figure 4-15: All Models: Causes of Tube Plugging (12/2013)
4-73

Figure 4-16: All Models: Number of Tubes Plugged per Year (12/2013)
4-74

Figure 4-17: All Models: Percentage of Tubes Plugged per Year (12/2013)
4-75

Figure 4-18: All Models: Causes of Tube Plugging per Year (12/2013)

A-1

APPENDIX A: BIBLIOGRAPHY

General

Code of Federal Regulations

Title 10, “Energy,” Part 50, “Domestic Licensing of Production and Utilization Facilities.”

Title 10, “Energy,” Part 100, “Reactor Site Criteria.”

Electric Power Research Institute

Electric Power Research Institute, “PWR [Pressurized-Water Reactor] Primary-to-Secondary 

Leak Guidelines, Revision 3,” December 2004 (ADAMS Accession No. ML050840534).

U.S. Nuclear Regulatory Commission

Generic Letter 2004-01, “Requirements for Steam Generator Tube Inspections,” 

August 30, 2004 (ADAMS Accession No. ML042370766).

Generic Letter 2006-01, “Steam Generator Tube Integrity and Associated Technical 

Specifications,” January 20, 2006 (ADAMS Accession No. ML060200385).

Information Notice (IN) 2001-016, “Recent Foreign and Domestic Experience with Degradation 

of Steam Generator Tubes and Internals,” October 31, 2001 (ADAMS Accession 

No. ML013030601).

IN 2002-02, “Recent Experience with Plugged Steam Generator Tubes,” January 8, 2002 

(ADAMS Accession No. ML013480327).

IN 2002-02, Supplement 1, “Recent Experience with Plugged Steam Generator Tubes,” 

July 17, 2002 (ADAMS Accession No. ML021980191).

IN 2002-21, “Axial Outside-Diameter Cracking Affecting Thermally Treated Alloy 600 Steam 

Generator Tubing,” June 25, 2002 (ADAMS Accession No. ML021770094).

IN 2002-21, Supplement 1, “Axial Outside-Diameter Cracking Affecting Thermally Treated 

Alloy 600 Steam Generator Tubing,” April 1, 2003 (ADAMS Accession No. ML030900517).

IN 2003-13, “Steam Generator Tube Degradation at Diablo Canyon,” August 28, 2003 (ADAMS 

Accession No. ML032410215).

IN 2004-10, “Loose Parts in Steam Generators,” May 4, 2004 (ADAMS Accession 

No. ML041170480).

IN 2004-16, “Tube Leakage Due to a Fabrication Flaw in a Replacement Steam Generator,” 

August 3, 2004 (ADAMS Accession No. ML041460357).

IN 2004-17, “Loose Part Detection and Computerized Eddy Current Data Analysis in Steam 

Generators,” August 25, 2004 (ADAMS Accession No. ML042180094).
A-2

IN 2005-09, “Indications in Thermally Treated Alloy 600 Steam Generator Tubes and 

Tube-To-Tubesheet Welds,” April 7, 2005 (ADAMS Accession No. ML050530400).

IN 2005-29, “Steam Generator Tube and Support Configuration,” October 27, 2005 (ADAMS 

Accession No. ML052280011).

IN 2007-37, “Buildup of Deposits in Steam Generators,” November 23, 2007 (ADAMS 

Accession No. ML072910750).

IN 2008-07, “Cracking Indications in Thermally Treated Alloy 600 Steam Generator Tubes,” 

April 24, 2008 (ADAMS Accession No. ML080040353).

IN 2010-05, “Management of Steam Generator Loose Parts and Automated Eddy Current Data 

Analysis,” February 3, 2010 (ADAMS Accession No. ML093640691).

IN 2010-07, “Welding Defects in Replacement Steam Generators,” April 5, 2010 (ADAMS 

Accession No. ML100070106).

IN 2010-21, “Crack-Like Indication in the U-Bend Region of a Thermally Treated Alloy 600 

Steam Generator Tube,” October 6, 2010 (ADAMS Accession No. ML102210244).

IN 2012-07, “Tube-to-Tube Contact Resulting in Wear in Once-Through Steam Generators,” 

July 17, 2012 (ADAMS Accession No. ML120740578).

IN 2013-11, “Crack-Like Indications at Dents/Dings and in the Freespan Region of Thermally 

Treated Alloy 600 Steam Generator Tubes,” July 3, 2013 (ADAMS Accession 

No. ML13127A236).

IN 2013-20, “Steam Generator Channel Head and Tubesheet Degradation,” October 3, 2013 

(ADAMS Accession No. ML13204A143).

NUREG-0966, “Safety Evaluation Report Related to the D2/D3 Steam Generator Design 

Modification,” March 1983.

NUREG-1014, “Safety Evaluation Report Related to the D4/D5/E Steam Generator Design 

Modification,” October 1983.

NUREG-1604, “Circumferential Cracking of Steam Generator Tubes,” April 1997.

NUREG-1771, “U.S. Operating Experience with Thermally Treated Alloy 600 Steam Generator 

Tubes,” April 2003 (ADAMS Accession No. ML031140094).

NUREG-1841, “U.S. Operating Experience with Thermally Treated Alloy 690 Steam Generator 

Tubes,” August 2007 (ADAMS Accession No. ML072330588).

NUREG/CR-6365, “Steam Generator Tube Failures,” April 1996.

Regulatory Guide 1.121, “Bases for Plugging Degraded PWR Steam Generator Tubes,”

August 1976 (ADAMS Accession No. ML003739366).
A-3

Regulatory Issue Summary (RIS) 2007-20, “Implementation of Primary-to-Secondary Leakage 

Performance Criteria,” August 23, 2007 (ADAMS Accession No. ML070570297).

RIS 2009-04, “Steam Generator Tube Inspection Requirements,” April 3, 2009 (ADAMS 

Accession No. ML083470557).

Other

“New Requirements for Ensuring Steam Generator Tube Integrity in Pressurized Water 

Reactors in the United States,” Emmett Murphy, Senior Materials Engineer, U.S. Nuclear 

Regulatory Commission, 2007 (ADAMS Accession No. ML071300355).

“Transmittal of TSTF-449 Revision 4, ‘Steam Generator Tube Integrity,’” April 14, 2005 (ADAMS 

Accession No. ML051090200).

“Transmittal of TSTF-510, Revision 0, ‘Revision to Steam Generator Program Inspection 

Frequencies and Tube Sample Selection,’” March 26, 2009 (ADAMS Accession 

No. ML090890367).
A-4

Braidwood 2

Letter from J.D. von Suskil, Exelon Generation Co., LLC, to the NRC, dated May 10, 2002, 

“Ninth Refuel Outage, Steam Generator Inservice Inspection Report.” ADAMS Accession 

No. ML021480394

Letter from J.D. von Suskil, Exelon Generation Co., LLC, to the NRC, dated August 12, 2002, 

“Braidwood Station, Unit 2 Inservice Inspection Summary Report.” ADAMS Accession 

No. ML022280412

Letter from J.D. von Suskil, Exelon Generation Co., LLC, to the NRC, dated April 9, 2003, 

“Braidwood Station, Unit 2 Ninth Refueling Outage Steam Generator Tube Inspection Report.” 

ADAMS Accession No. ML031110379

Letter from M.J. Pacilio, Exelon Generation Co., LLC, to the NRC, dated July 29, 2003, 

“Braidwood Station, Unit 2 Ninth Refueling Outage Steam Generator Tube Inspection Report, 

Additional Information Pertaining to Steam Generator Secondary Side Inspections.” ADAMS 

Accession No. ML032200254

Letter from M.J. Pacilio, Exelon Generation Co., LLC, to the NRC, dated November 24, 2003, 

“Tenth Refuel Outage, Steam Generator In-Service Inspection Report.” ADAMS Accession 

No. ML033360656

Letter from M.L. Chawla, NRC, to J.L. Skolds, Exelon Generation Co., LLC dated 

January 15, 2004, “Summary of Conference Call with Exelon Nuclear Regarding the 

2003 Steam Generator Inspections at Braidwood Unit 2 (TAC No. MC1367).” ADAMS 

Accession No. ML033580377

Letter from T.P. Joyce, Exelon Generation Co., LLC, to the NRC dated February 12, 2004, 

“Braidwood Station, Unit 2 Tenth Refueling Outage Steam Generator Inservice Inspection 

Summary Report.” ADAMS Accession No. ML040540452

Letter from K.R. Jury, Exelon Generation Co., LLC, to the NRC dated October 29, 2004, 

“Response to NRC Generic Letter 2004-01, ‘Requirements for Steam Generator Tube 

Inspections.’” ADAMS Accession No. ML043060328

Letter from G.F. Dick, NRC, to C.M. Crane, Exelon Generation Co., LLC, dated April 25, 2005, 

“Braidwood Station, Units 1 and 2—Issuance of Exigent Amendments Re: Revision of Scope of 

Steam Generator Inspections for Unit 2 Refueling Outage 11 (TAC Nos. MC6686 and 

MC6687).” ADAMS Accession No. ML051170149

Letter from K.J. Polson, Exelon Generation Co., LLC, to the NRC dated May 10, 2005, 

“April 2005, Eleventh Refuel Outage, Steam Generator Inservice Inspection Report.” ADAMS 

Accession No. ML051370406

Letter from K.J. Polson, Exelon Generation Co., LLC, to the NRC dated July 27, 2005, 

“Braidwood Station, Unit 2, Eleventh Refueling Outage Steam Generator Inservice Inspection 

Summary Report.” ADAMS Accession No. ML052140465
A-5

Letter from J.B. Hopkins, NRC, to C.M. Crane, Exelon Generation Co., LLC, dated 

September 16, 2005, “Braidwood Station, Unit 2—Summary of Conference Call Regarding 

2005 Steam Generator Tube Inspections.” ADAMS Accession No. ML052550318

Letter from K.J. Polson, Exelon Generation Co., LLC, to the NRC, dated February 13, 2006, 

“Response to Request for Additional Information Regarding the Braidwood Station Unit 2 

Spring 2005 Steam Generator Inspection.” ADAMS Accession No. ML060670367

Letter from R.F. Kuntz, NRC, to C.M. Crane, Exelon Generation Co., LLC, dated 

October 24, 2006, “Braidwood Station, Unit No. 2—Issuance of Amendments Re: Steam 

Generator Inspection Criteria (TAC No. MC8969).” ADAMS Accession No. ML062780507

Letter from T. Coutu, Exelon Generation Co., LLC, to the NRC, dated November 9, 2006, 

“October 2006, Twelfth Refueling Outage, Steam Generator In-Service Inspection Report.” 

ADAMS Accession No. ML063130425

Letter from T. Coutu, Exelon Generation Co., LLC, to the NRC, dated January 29, 2007, 

“Braidwood Station, Unit 2, Twelfth Refueling Outage Steam Generator Inservice Inspection 

Summary Report.” ADAMS Accession No. ML070290637

Letter from R.F. Kuntz, NRC, to C.M. Crane, Exelon Generation Co., LLC, dated 

March 30, 2007, “Byron Station, Unit Nos. 1 and 2, and Braidwood Station, Unit Nos. 1 and 2—

Issuance of Amendments Re: Steam Generator Tube Surveillance Program (TAC 

Nos. MC8966, MC8967, MC8968, and MC8969).” ADAMS Accession Nos. ML070810354 and 

ML071210555

Letter from T. Coutu, Exelon Generation Co., LLC, to the NRC, dated August 17, 2007, 

“Response to Request for Additional Information Regarding the Braidwood Station, Unit 2 

Fall 2006 Steam Generator Inspection.” ADAMS Accession No. ML072290564

Letter from M.J. David, NRC, to C.G. Pardee, Exelon Generation Co., LLC, dated 

April 18, 2008, “Braidwood Station, Units 1 and 2—Issuance of Amendments Re: Revision to 

Technical Specifications for the Steam Generator Program (TAC Nos. MD8158 and MD8159).” 

ADAMS Accession No. ML080920889

Letter from M.J. David, NRC, to C.G. Pardee, Exelon Generation Co., LLC, dated July 16, 2008, 

“Braidwood Station, Unit 2—Summary of Conference Call Regarding Spring 2008 Steam 

Generator Tube Inspections (TAC No. MD8409).” ADAMS Accession No. ML081640265

Letter from B. Hanson, Exelon Generation Co., LLC, to the NRC, dated November 11, 2008, 

“Braidwood Station, Unit 2 Thirteenth Refueling Outage Steam Generator Tube Inspection 

Report.” ADAMS Accession No. ML083220444

Letter from P.R. Simpson, Exelon Generation Co., LLC, to the NRC, dated May 15, 2009, 

“Response to Request for Additional Information Regarding the Braidwood Station, Unit 2,

Spring 2008 Refueling Outage Steam Generator Tube Inspections.” ADAMS Accession 

No. ML091380475
A-6

Letter from M.J. David, NRC, to C.G. Pardee, Exelon Nuclear, dated October 16, 2009, 

“Braidwood Station, Units 1 and 2, and Byron Station, Unit Nos. 1 and 2—Issuance of 

Amendments Re: Revision to Technical Specifications for the Steam Generator Program (TAC 

Nos. ME1613, ME1614, ME1615, and ME1616).” ADAMS Accession No. ML092520512

Letter from A. Shahkarami, Exelon Generation Co., LLC, to the NRC, dated January 27, 2010, 

“Braidwood Station, Unit 2 Steam Generator Tube Inspection Report for Refueling Outage 14.” 

ADAMS Accession No. ML100350212

Letter from M.J. David, NRC, to M.J. Pacilio, Exelon Generation Co., LLC, dated 

September 17, 2010, “Braidwood Station, Unit 2—Review of the 2009 Steam Generator Tube 

Inservice Inspection Report (TAC No. ME3372).” ADAMS Accession No. ML102530544

Letter from N.J. DiFrancesco, NRC, to M.J. Pacilio, Exelon Nuclear, dated April 13, 2011, 

“Braidwood Station, Units 1 and 2, and Byron Station, Unit Nos. 1 and 2—Issuance of 

Amendments Re: Changes to Technical Specification Sections 5.5.9, ‘Steam Generator (SG) 

Program’ and 5.6.9 ‘Steam Generator (SG) Tube Inspection Report.’ (TAC Nos. ME5198, 

ME5199, ME5200, and ME5201).” ADAMS Accession No. ML110840580

Letter from D.J. Enright, Exelon Generation Co., LLC, to the NRC, dated August 10, 2011, 

“Braidwood Station, Unit 2 Steam Generator Tube Inspection Report for Refueling Outage 15.” 

ADAMS Accession No. ML11227A037

Letter from N.J. DiFrancesco, NRC, to M.J. Pacilio, Exelon Nuclear, dated September 22, 2011, 

“Braidwood Station, Unit 2—Summary of Conference Call Regarding 2011 Steam Generator 

Tube Inspections (TAC No. ME6106).” ADAMS Accession No. ML112590225

Letter from B.L. Mozafari, NRC, to M.J. Pacilio, Exelon Nuclear, dated April 12, 2012, 

“Braidwood Station, Unit 2—Review of the 2011 Steam Generator Tube Inservice Inspections at 

Braidwood Station Unit 2 (TAC No. ME7112).” ADAMS Accession No. ML120930296

Letter from M. Mahoney, NRC, to M.J. Pacilio, Exelon Generation Co., LLC, dated 

October 5, 2012, “Braidwood Station, Units 1 and 2, and Byron Station, Unit Nos. 1 and 2—

Issuance of Amendments Re: Revise Technical Specifications 5.5.9 and 5.6.9 for Permanent 

Alternate Repair Criteria (TAC Nos. ME8296, ME8297, ME8298, and ME8299).” ADAMS 

Accession No. ML12262A360

Letter from D. Enright, Exelon Generation Co., LLC, to the NRC, dated February 5, 2013, 

“Braidwood Station, Unit 2 Steam Generator Tube Inspection Report for Refueling Outage 16.” 

ADAMS Accession No. ML13039A042

Letter from J.S. Wiebe, NRC, to M.J. Pacilio, Exelon Generation Co., LLC, dated 

March 21, 2013, “Braidwood Station, Units 1 and 2, and Byron Station, Unit Nos. 1 and 2—

Issuance of Amendments Re: Application to Revise Technical Specifications to Adopt 

TSTF-510, ‘Revision to Steam Generator Program Inspection Frequencies and Tube Sample 

Selection’ (TAC Nos. ME8243, ME8244, ME8245, and ME8246).” ADAMS Accession 

No. ML13009A172
A-7

Letter from D.M. Gullott, Exelon Generation Co., LLC, to the NRC, dated August 6, 2013, 

“Response to Request for Additional Information Regarding the Steam Generator Tube 

Inspection Report for Braidwood Station, Unit 2, Refueling Outage 16.” ADAMS Accession 

No. ML13219A320

Letter from J.S. Wiebe, NRC, to M.J. Pacilio, Exelon Generation Co., LLC, dated 

January 7, 2014, “Braidwood Station, Unit 2—Review of the 2012 Steam Generator Tube 

Inservice Inspections (TAC No. MF0659).” ADAMS Accession No. ML13326A965

Letter from M.E. Kanavos, Exelon Generation Co., LLC, to the NRC, dated November 14, 2014, 

“Braidwood Station, Unit 2 Steam Generator Tube Inspection Report for Refueling Outage 17.” 

ADAMS Accession No. ML14318A211
A-8

Byron 2

“Preliminary Notification of Event or Unusual Occurrence—PNO-III-02-029,” dated 

June 25, 2002. ADAMS Accession No. ML021760784

Letter from R.P. Lopriore, Exelon Generation Co., LLC, to the NRC, dated October 8, 2002, 

“Steam Generator Tube Repairs Resulting from Byron Station, Unit 2, Cycle 10 Refueling 

Outage.” ADAMS Accession No. ML022900008

Letter from M.L. Chawla, NRC, to J.L. Skolds, Exelon Generation Co., LLC, dated 

November 8, 2002, “Byron Station, Unit 2—Summary of Conference Calls with Exelon 

Generation Co. Regarding Its 2002 Steam Generator Tube Inspection Results (TAC 

Nos. MB6310 and MB4017).” ADAMS Accession No. ML022950043

Letter from R.P. Lopriore, Exelon Generation Co., LLC, to the NRC, dated December 10, 2002, 

“Byron Station Unit 2 Steam Generator Inservice Inspection Summary Report.” ADAMS 

Accession No. ML023520084

Letter from S.E. Kuczynski, Exelon Generation Co., LLC, to the NRC, dated April 17, 2004,

“Steam Generator Tube Repairs Resulting from Byron Station, Unit-2, Cycle 11 Refueling 

Outage.” ADAMS Accession No. ML041170314

Letter from S.E. Kuczynski, Exelon Generation Co., LLC, to the NRC, dated June 23, 2004, 

“Byron Station Unit 2 Steam Generator Inservice Inspection Summary Report.” ADAMS 

Accession No. ML041830404

Letter from G.F. Dick, Jr., NRC, to C.M. Crane, Exelon Generation Co., LLC, dated 

August 12, 2004, “Summary of Conference Call with Exelon Generation Co., LLC Regarding the 

Results of the Spring 2004 Steam Generator Inspections at Byron Station, Unit 2 (TAC 

No. MC2597).” ADAMS Accession No. ML042260202

Letter from K.R. Jury, Exelon Generation Co., LLC, to the NRC, dated October 29, 2004, 

“Response to NRC Generic Letter 2004-01, ‘Requirements for Steam Generator Tube 

Inspections.’” ADAMS Accession No. ML043060328

Letter from S.E. Kuczynski, Exelon Generation Co., LLC, to the NRC, dated 

November 10, 2004, “Response to Request for Additional Information Regarding the Byron 

Station, Unit 2 Spring 2004 Steam Generator Inspection.” ADAMS Accession No. ML043210495

Letter from J.B. Hopkins, NRC, to C.M. Crane, Exelon Generation Co., LLC, dated 

September 19, 2005, “Byron Station, Unit 2—Issuance of Amendment (TAC No. MC7219).” 

ADAMS Accession No. ML052230019

Letter from S.E. Kuczynski, Exelon Generation Co., LLC, to the NRC, dated October 17, 2005, 

“Steam Generator Tube Repairs Resulting from Byron Station, Unit-2, Cycle 12 Refueling

Outage.” ADAMS Accession No. ML052920168

Letter from S.E. Kuczynski, Exelon Generation Co., LLC, to the NRC, dated January 3, 2006, 

“Byron Station Unit 2 Steam Generator Inservice Inspection Summary Report.” ADAMS 

Accession No. ML060050335
A-9

Letter from M.L. Chawla, NRC, to C.M. Crane, Exelon Generation Co., LLC, dated 

March 22, 2006, “Byron Station, Unit 2—Summary of Conference Telephone Call Regarding 

Steam Generator Inspections from the Fall 2005 Outage (TAC No. MC8527).” ADAMS 

Accession No. ML060610209

Letter from D.M. Hoots, Exelon Generation Co., LLC, to the NRC, dated September 8, 2006, 

“Response to Request for Additional Information Regarding the Byron Station, Unit 2 Fall 2005 

Steam Generator Inspection.” ADAMS Accession No. ML062560349

Letter from D.M. Hoots, Exelon Generation Co., LLC, to the NRC, dated January 16, 2007, 

“Response to Request for Additional Information Regarding the Byron Station, Unit 2 Fall 2005 

Steam Generator Inspection.” ADAMS Accession No. ML070170225

Letter from R.F. Kuntz, NRC, to C.M. Crane, Exelon Generation Co., LLC, dated 

March 30, 2007, “Byron Station, Unit Nos. 1 and 2, and Braidwood Station, Unit Nos. 1 and 2—

Issuance of Amendments Re: Steam Generator Tube Surveillance Program (TAC 

Nos. MC8966, MC8967, MC8968, and MC8969).” ADAMS Accession Nos. ML070810354 and 

ML071210555

Letter from D.M. Hoots, Exelon Generation Co., LLC, to the NRC, dated July 31, 2007, “Byron 

Station Unit 2 90-Day Inservice Inspection Report for Interval 3, Period 1, Outage 1 (B2R13).” 

ADAMS Accession No. ML072120471

Letter from D.M. Hoots, Exelon Generation Co., LLC, to the NRC, dated July 31, 2007, “Byron 

Station Unit 2 Steam Generator Inservice Inspection Summary Report for Refueling Outage 13.” 

ADAMS Accession No. ML072120520

Letter from P.R. Simpson, Exelon Generation Co., LLC, to the NRC, dated February 20, 2008, 

“Response to Request for Additional Information—Steam Generator Inspection Summary 

Report.” ADAMS Accession No. ML080510729

Letter from M.J. David, NRC, to C.G. Pardee, Exelon Generation Co., LLC, dated 

April 14, 2008, “Byron Station, Unit 2—Review of Spring 2007 Steam Generator Tube Inservice 

Inspection Reports (TAC No. MD6203).” ADAMS Accession No. ML080990790

Letter from M.J. David, NRC, to C.G. Pardee, Exelon Generation Co., LLC, dated 

October 1, 2008, “Byron Station, Unit Nos. 1 and 2—Issuance of Amendments Re: Revision to 

Technical Specifications for the Steam Generator Program (TAC Nos. MD9018 and MD9019).” 

ADAMS Accession No. ML082340799

Letter from M.J. David, NRC, to C.G. Pardee, Exelon Generation Co., LLC, dated 

November 20, 2008, “Byron Station, Unit No. 2—Summary of Conference Call Regarding 

Fall 2008 Steam Generator Tube Inspections (TAC No. MD9590).” ADAMS Accession 

No. ML083180783

Letter from D.M. Hoots, Exelon Generation Co., LLC, to the NRC, dated January 20, 2009, 

“Byron Station Unit 2 Steam Generator Inservice Inspection Summary Report for Refueling 

Outage 14.” ADAMS Accession No. ML090330274
A-10

Letter from M.J. David, NRC, to C.G. Pardee, Exelon Generation Co., LLC, dated 

October 5, 2009, “Byron Station, Unit No. 2—Review of Fall 2008 Steam Generator Tube 

Inservice Inspection Report (TAC No. ME0802).” ADAMS Accession No. ML092720611

Letter from M.J. David, NRC, to C.G. Pardee, Exelon Nuclear, dated October 16, 2009, 

“Braidwood Station, Units 1 and 2, and Byron Station, Unit Nos. 1 and 2—Issuance of 

Amendments Re: Revision to Technical Specifications for the Steam Generator Program (TAC 

Nos. ME1613, ME1614, ME1615, and ME1616).” ADAMS Accession No. ML092520512

Letter from D.J. Enright, Exelon Generation Co., LLC, to the NRC, dated July 23, 2010, “Byron 

Station Unit 2 Steam Generator Inservice Inspection Summary Report for Refueling Outage 15.” 

ADAMS Accession No. ML102100454

Letter from N.J. DiFrancesco, NRC, to M.J. Pacilio, Exelon Nuclear, dated April 13, 2011, 

“Braidwood Station, Units 1 and 2 and Byron Station, Unit Nos. 1 and 2—Issuance of 

Amendments Re: Changes to Technical Specification Sections 5.5.9, ‘Steam Generator (SG) 

Program’ and 5.6.9 ‘Steam Generator (SG) Tube Inspection Report.’ (TAC Nos. ME5198, 

ME5199, ME5200, and ME5201).” ADAMS Accession No. ML110840580

Letter from N.J. DiFrancesco, NRC, to M.J. Pacilio, Exelon Nuclear, dated November 7, 2011, 

“Byron Station, Unit No. 2—Summary of Conference Call Regarding 2011 Steam Generator 

Tube Inspections (TAC No. ME7191).” ADAMS Accession No. ML113010322

Letter from T.J. Tulon, Exelon Generation Co., LLC, to the NRC, dated January 4, 2012, “Byron 

Station Unit 2 Steam Generator Inservice Inspection Summary Report for Refueling Outage 16.” 

ADAMS Accession No. ML12019A194

Letter from M. Mahoney, NRC, to M.J. Pacilio, Exelon Generation Co., LLC, dated 

October 5, 2012, “Braidwood Station, Units 1 and 2, and Byron Station, Unit Nos. 1 and 2—

Issuance of Amendments Re: Revise Technical Specifications 5.5.9 and 5.6.9 for Permanent 

Alternate Repair Criteria (TAC Nos. ME8296, ME8297, ME8298, and ME8299).” ADAMS 

Accession No. ML12262A360

Letter from J.S. Wiebe, NRC, to M.J. Pacilio, Exelon Generation Co., LLC, dated 

March 21, 2013, “Braidwood Station, Units 1 and 2, and Byron Station, Unit Nos. 1 and 2—

Issuance of Amendments Re: Application to Revise Technical Specifications to Adopt 

TSTF-510, ‘Revision to Steam Generator Program Inspection Frequencies and Tube Sample 

Selection’ (TAC Nos. ME8243, ME8244, ME8245, and ME8246).” ADAMS Accession 

No. ML13009A172

Letter from J.S. Wiebe, NRC, to M.J. Pacilio, Exelon Generation Co., LLC, dated April 1, 2013, 

“Byron Nuclear Power Station, Unit 2—Review of Refueling Outage 16 Steam Generator Tube 

Inservice Inspections (TAC No. ME9447).” ADAMS Accession No. ML13087A420
A-11

Catawba 2

Letter from C.P. Patel, NRC, to G.R. Peterson, Duke Energy Corp., dated June 18, 2002. 

“Catawba Nuclear Station, Unit 2 RE: “Summary of Conference Call with Duke Energy 

Regarding 2001 Steam Generator Tube Inspection Results at Catawba Unit 2 (TAC 

No. MB3037).” ADAMS Accession No. ML021780129

Letter from G.R. Peterson, Duke Energy Corporation, to the NRC, dated April 7, 2003, 

“Catawba Nuclear Station, Unit 2, Docket No. 50-414, Steam Generator Tube Inspection 

Report, 2 End of Core (EOC) 12.” ADAMS Accession No. ML031060081

Letter from K.S. Canady, Duke Energy Corp., to the NRC, dated June 18, 2003, “Duke Energy 

Corp., Catawba Nuclear Station (CNS), Unit 2, Docket Number 50-414, Inservice Inspection 

Report and Steam Generator Outage Summary Report for End of Cycle 12 Refueling Outage.” 

ADAMS Accession No. ML031760596

Letter from D.M. Jamil, Duke Energy Corp., to the NRC, dated February 10, 2004, “Duke 

Energy Corp., Catawba Nuclear Station, Unit 2, Docket Number 50-414, Steam Generator 

Outage Summary Report for End of Cycle 12 Refueling Outage, Reply to Request for Additional 

Information (TAC No.MC0957).” ADAMS Accession No. ML040500713

Letter from D.M. Jamil, Duke Energy Corp., to the NRC, dated April 7, 2004, “Duke Energy 

Corp., Catawba Nuclear Station, Unit 2, Docket Number 50-414, Steam Generator Outage 

Summary Report for End of Cycle 12 Refueling Outage, Reply to Request for Additional 

Information (TAC No. MC0957).” ADAMS Accession No. ML041110904

Letter from D.M. Jamil, Duke Energy Corp., to the NRC, dated October 21, 2004, “Catawba 

Nuclear Station, Unit 2, Docket Number 50-414, Steam Generator Tube Plugging Report, 2 End 

of Core (EOC) 13.” ADAMS Accession No. ML043070616

Letter from W.R. McCollum, Jr., Duke Energy Corp., to the NRC, dated October 28, 2004, 

“Duke Energy Corp. Oconee Nuclear Station, Units 1, 2, & 3, Docket Nos. 50-269, 50-270, 

50-287, McGuire Nuclear Station, Units 1 & 2, Docket Nos. 50-369 and 50-370, Catawba 

Nuclear Station, Units 1 & 2, Docket Nos. 50-413, 50-414, Response to NRC Generic 

Letter 2004-01, Requirements for Steam Generator Tube Inspections.” ADAMS Accession 

No. ML043090390

Letter from S.E. Peters, NRC, to D.M. Jamil, Duke Energy Corp., dated November 11, 2004, 

“Catawba Nuclear Station, Unit 2 Re: Summary of Conference Call Regarding the 2004 Steam 

Generator Tube Inspections (TAC No. MC4503).” ADAMS Accession No. ML043130438

Letter from D.M. Jamil, Duke Energy Corp., to the NRC, dated January 17, 2005, “Duke Energy 

Corp., Catawba Nuclear Station, Unit 2, Docket Number 50-414, Steam Generator Outage 

Summary Report for End of Cycle 13 Refueling Outage.” ADAMS Accession No. ML050240371

Letter from J.F. Stang, NRC, to D. Jamil, Duke Energy Corp., dated March 31, 2006. “Catawba 

Nuclear Station, Unit 2, Issuance of Amendments Regarding the Steam Generator Program 

(TAC No. MC9430).” ADAMS Accession No. ML060760011 and ML060760111
A-12

Letter from D.M. Jamil, Duke Energy Corp., to the NRC dated July 18, 2006, “Duke Power Co.,

LLC d/b/a Duke Energy Carolinas, LLC (Duke), Catawba Nuclear Station, Unit 2, Docket 

Number 50-414, Steam Generator Outage Summary Inservice Inspection Report for End of 

Cycle 14 Refueling Outage.” ADAMS Accession No. ML062060296

Letter from D.M. Jamil, Duke Energy Corp., to the NRC dated August 31, 2006, “Duke Power 

Co. LLC d/b/a Duke Energy Carolinas, LLC (Duke), Catawba Nuclear Station, Unit 2, Docket 

Number 50-414, Steam Generator Outage Summary 180-Day Report for End of Cycle 14 

Refueling Outage.” ADAMS Accession No. ML062550112

Letter from J.R. Morris, Duke Energy Corp., to the NRC dated May 31, 2007, “Duke Power Co.,

LLC d/b/a Duke Energy Carolinas, LLC (Duke), Catawba Nuclear Station, Unit 2, Docket 

Number 50-414, Reply to Request for Additional Information Concerning Steam Generator 

Outage Summary Reports for End of Cycle 14 and for End of Cycle 13 Refueling Outages 

(TAC No.MD3419).” ADAMS Accession No. ML071630231

Letter from J.F. Stang, NRC to J.R. Morris, Duke Power Co., LLC, dated October 31, 2007, 

“Catawba Nuclear Station, Unit 2, Issuance of Amendment Regarding Technical Specification 

5.5.9 ‘Steam Generator Tube Surveillance Program’ (TAC No. MD5554).” ADAMS Accession 

No. ML072820013

Letter from J.R. Morris, Duke Energy Corp., to the NRC dated February 11, 2008, “Duke Power 

Co. LLC d/b/a Duke Energy Carolinas, LLC, Catawba Nuclear Station, Unit 2, Docket 

Number 50-414, Inservice Inspection Report and Steam Generator In-service Inspection 

Summary Report for End of Cycle 15 Refueling Outage.” ADAMS Accession No. ML080500179

Letter from J.R. Morris, Duke Energy Corp., to the NRC dated March 26, 2008, “Duke Power 

Co., LLC, d/b/a Duke Energy Carolinas, LLC (Duke), Catawba Nuclear Station, Unit 2, Docket 

Number 50-414, Steam Generator Outage Summary 180-Day Report for End of Cycle 15 

Refueling Outage.” ADAMS Accession No. ML080930312

Letter from J.R. Morris, Duke Energy Corp., to the NRC dated December 18, 2008, “Duke 

Energy Carolinas, LLC (Duke), Catawba Nuclear Station, Unit 2, Docket Number 50-414, Reply 

to Request for Additional Information Concerning Steam Generator Tube Inspection Reports for 

End of Cycle 15 Refueling Outage (TAC No. MD8402).” ADAMS Accession No. ML083660086

Letter from J. Stang, NRC, to J.R. Morris, Duke Energy Carolinas, LLC, dated April 13, 2009, 

“Catawba Nuclear Station, Unit 2, Issuance of Amendment Regarding Interim Alternate Repair 

Criterion for Steam Generator Tube Repair (TAC No. ME0236).” ADAMS Accession 

No. ML091030088

Letter from J.R. Morris, Duke Energy Corp., to the NRC dated May 28, 2009, “Duke Energy 

Carolinas, LLC (Duke), Catawba Nuclear Station, Unit 2, Docket Number 50-414, Reply to 

Request for Additional Information Concerning Steam Generator Tube Inspection Reports for 

End of Cycle 15 Refueling Outage (TAC No. MD8402).” ADAMS Accession No. ML091550027

Letter from J.R. Morris, Duke Energy Carolinas, LLC, to the NRC dated July 14, 2009, “Duke 

Energy Carolinas, LLC, Catawba Nuclear Station, Unit 2, Docket Number 50-414, Inservice 

Inspection Report and Steam Generator In-service Inspection Summary Report for End of 

Cycle 16 Refueling Outage.” ADAMS Accession No. ML092010498
A-13

Letter from J.R. Morris, Duke Energy Corp., to the NRC dated May 20, 2010, “Duke Energy 

Carolinas, LLC (Duke Energy), Catawba Nuclear Station, Unit 2, Docket Number 50-414, 

Steam Generator In-service Inspection Summary Report for End of Cycle 16 Refueling Outage, 

Response to NRC Requests for Additional Information (RAIs).” ADAMS Accession 

No. ML101470067

Letter from J. Thompson, NRC, to J.R. Morris, Duke Energy Carolinas, LLC, dated 

July 14, 2010, “Catawba Nuclear Station, Unit 2 (Catawba 2)—Summary of Telephone 

Conference Call Regarding the 2009 Steam Generator (SG) Tube Inspections (TAC 

Nos. ME0910 and ME0911).” ADAMS Accession No. ML101900062

Letter from J. Thompson, NRC, to J.R. Morris, Duke Energy Carolinas, LLC, dated July 21, 

2010, “Catawba Nuclear Station, Unit 2 (Catawba 2)—Summary of Telephone Conference Call 

Regarding the Fall 2007 Steam Generator (SG) Tube Inspections.” ADAMS Accession No. 

ML102010007

Letter from J. Thompson, NRC, to J.R. Morris, Duke Energy Carolinas, LLC, dated 

September 27, 2010, “Catawba Nuclear Station, Unit 2, Issuance of Amendment Regarding the 

Steam Generator Program (TAC No. ME4108).” ADAMS Accession No. ML102640537

Letter from J.R. Morris, Duke Energy Corp., to the NRC dated January 19, 2011, “Duke Energy 

Carolinas, LLC, Catawba Nuclear Station, Unit 2, Docket Number 50-414, Inservice Inspection 

Report and Steam Generator In-service Inspection Summary Report for End of Cycle 17 

Refueling Outage.” ADAMS Accession No. ML110200322

Letter from J.R. Morris, Duke Energy Corp., to the NRC dated April 5, 2011, “Duke Energy 

Carolinas, LLC, Catawba Nuclear Station, Unit 2, Docket Number 50-414, Steam Generator 

(SG) Tube Inspection Report for End of Cycle 17 Refueling Outage Pursuant to Technical 

Specification (TS) 5.6.8.” ADAMS Accession No. ML110980601

Letter from J.R. Morris, Duke Energy Corp., to the NRC dated June 27, 2011, “Duke Energy 

Carolinas, LLC (Duke Energy), Catawba Nuclear Station, Unit 2, Docket Number 50-414, 

Steam Generator In-service Inspection Summary Report for End of Cycle 17 Refueling Outage, 

Response to NRC Requests for Additional Information (RAIs), TAC No. ME5834.” ADAMS 

Accession No. ML11180A269

Letter from J. Thompson, NRC, to J.R. Morris, Duke Energy Carolinas, LLC, dated 

March 12, 2012, “Catawba Nuclear Station, Units 1 and 2, Issuance of Amendments Regarding 

Technical Specifications Amendments for Permanent Alternate Repair Criteria for Steam 

Generator Tubes (TAC Nos. ME6670 and ME6671).” ADAMS Accession No. ML12054A692

Letter from R.M. Glover, Duke Energy Carolinas, LLC, to the NRC dated July 10, 2012, “Duke 

Energy Carolinas, LLC, Catawba Nuclear Station, Unit 2, Docket Number 50-414, Inservice 

Inspection Report and Steam Generator Inservice Inspection Summary Report for End of 

Cycle 18 Refueling Outage.” ADAMS Accession No. ML12195A346

Letter from J. Thompson, NRC, to K. Henderson, Duke Energy Carolinas, LLC, dated 

April 2, 2013, “Catawba Nuclear Station, Unit 2 (Catawba)—Review of the 2012 Steam 

Generator (SG) Tube Inspections During Refueling Outage 18 End-of-Cycle (EOC 18) (TAC 

No. ME9122).” ADAMS Accession No. ML13084A218
A-14

Letter from K. Henderson, Duke Energy, to the NRC dated January 13, 2014, “Duke Energy 

Carolinas, LLC (Duke Energy), Catawba Nuclear Station, Unit 2, Docket Number 50-414, 

Inservice Inspection Report and Steam Generator Inservice Inspection Summary Report for End 

of Cycle 19 Refueling Outage.” ADAMS Accession No. ML14016A147

Letter from R.J. Pascarelli, NRC, to K. Henderson, Duke Energy Carolinas, LLC, dated 

August 27, 2014, “Catawba Nuclear Station, Unit 2—Review of the Steam Generator Tube 

Inservice Inspection Report for the Fall 2013 Refueling Outage (TAC No. MF3355).” ADAMS 

Accession No. ML14237A008
A-15

Comanche Peak 2

Letter from C.L. Terry, TXU Energy, to the NRC dated April 18, 2002, “Comanche Peak Steam 

Electric Station (CPSES) – Unit 2, Docket No. 50-446, Unit 2, Sixth Refueling Outage (2RF06), 

Steam Generator Inservice Inspection Tube Plugging, Special Report No. 2-SR-02-001-00.” 

ADAMS Accession No. ML021210473

Letter from C.L. Terry, TXU Energy, to the NRC dated June 5, 2002, “Comanche Peak Steam 

Electric Station (CPSES) – Unit 2, Docket No. 50-446, Unit 2 Sixth Refueling Outage (2RF06), 

Steam Generator Twelve Month Report, Special Report No. 2-SR-02-002-00.” ADAMS 

Accession No. ML021640618

Letter from C.L. Terry, TXU Energy, to the NRC dated July 17, 2002, “Comanche Peak Steam 

Electric Station (CPSES)—Unit 2, Docket Nos. 50-446, Submittal of Unit 2 Sixth Refueling 

Outage (2RF06), Inservice Inspection (ISI) Summary Report (1986 Edition of ASME Code, 

Section XI, No Addenda; Unit 2 Interval Dates: August 3, 1993—August 3, 2003, First Interval).” 

ADAMS Accession No. ML022060178

Letter from M.R. Blevins, TXU Energy, to the NRC dated November 6, 2003, “Comanche Peak 

Steam Electric Station (CPSES)—Unit 2, Docket No. 50-446, Unit 2, Seventh Refueling Outage 

(2RF07), Steam Generator Inservice Inspection Tube Plugging, Special Report 

No. 2-SR-03-001-00.” ADAMS Accession No. ML033180430

Letter from M.R. Blevins, TXU Energy, to the NRC dated January 22, 2004, “Comanche Peak 

Steam Electric Station (CPSES), Unit 2 Docket No. 50-446, Submittal of Unit 2 Seventh 

Refueling Outage (2RF07), Inservice Inspection (ISI) Summary Report (Unit 2: 1986 Edition of 

ASME Code, Section XI, No Addenda; Interval Start Date – August 3, 1993, First Interval).” 

ADAMS Accession No. ML040290102

Letter from M.R. Blevins, TXU Power, to the NRC dated June 30, 2004, “Comanche Peak 

Steam Electric Station (CPSES), Docket No. 50-446, Unit 2 Seventh Refueling Outage (2RF07), 

Steam Generator Twelve Month Report.” ADAMS Accession No. ML041890306

Letter from M.R. Blevins, TXU Power, to the NRC dated October 14, 2004, “Comanche Peak 

Steam Electric Station (CPSES), Unit 2—Docket No. 50-446, Response to NRC Request for 

Additional Information, Re: 2RF06 and 2RF07 Steam Generator Reports.” ADAMS Accession 

No. ML042930638

Letter from M.R. Blevins, TXU Power, to the NRC dated October 14, 2004, “Comanche Peak 

Steam Electric Station (CPSES), Units 1 and 2—Docket Nos. 50-445 and 50-446, Response to 

NRC Generic Letter 2004-01; ‘Requirements For Steam Generator Tube Inspections.’ (TAC 

No MC4811).” ADAMS Accession No. ML042940371

Letter from M.R. Blevins, TXU Power, to the NRC dated April 28, 2005, “Comanche Peak 

Steam Electric Station (CPSES), Unit 2, Docket No. 50-446, Technical Specification 15-Day 

Report for Steam Generator Tube Plugging.” ADAMS Accession No. ML051250408
A-16

Letter from M.R. Blevins, TXU Power, to the NRC dated October 3, 2005, “Comanche Peak 

Steam Electric Station (CPSES), Docket No. 50-446, Submittal of Revised Unit 2 Eighth 

Refueling Outage (2RF08) Inservice Inspection (ISI) Summary Report (Unit 2: 1998 Edition of 

ASME Code Section XI, 1999 and 2000 Addenda, Interval Start Date—August 3, 2004, Second

Interval).” ADAMS Accession No. ML052850272

Letter from M.R. Blevins, TXU Power, to the NRC dated February 14, 2006, “Comanche Peak 

Steam Electric Station (CPSES), Docket No. 50-446, Unit 2 Eighth Refueling Outage (2RF08), 

Steam Generator Twelve Month Report.” ADAMS Accession No. ML060540491

Letter from M.C. Thadani, NRC, to M.R. Blevins, TXU Power dated September 12, 2006, 

“Comanche Peak Steam Electric Station (CPSES), Units 1 and 2—Issuance of Amendments 

Re: Steam Generator Tube Surveillance Program (TAC Nos. MC9498 and MC9499).” ADAMS 

Accession No. ML062340117

Letter from M.R. Blevins, TXU Power, to the NRC dated November 1, 2006, “Comanche Peak 

Steam Electric Station (CPSES), Unit 2, Docket No. 50-446, Response to Request for Additional 

Information, 2RF08 Steam Generator Tube Inservice Inspection Report—(TAC No. MC6952).” 

ADAMS Accession No. ML063110573

Letter from M.R. Blevins, TXU Power, to the NRC dated January 24, 2007, “Comanche Peak 

Steam Electric Station (CPSES), Docket No. 50-446, Submittal of Unit 2 Ninth Refueling Outage 

(2RF09) Inservice Inspection (ISI) Summary Report (Unit 2: 1998 Edition of ASME Code 

Section XI, through 2000 Addenda, Interval Start Date – August 3, 2004, Second Interval).” 

ADAMS Accession No. ML070310371

Letter from B.K. Singal, NRC to M.R. Blevins, Luminant Generation Co., LLC, dated 

June 20, 2008, “Comanche Peak Steam Electric Station, Unit 2—Summary of Conference Call 

Regarding the Spring 2008 Steam Generator Tube Inspections (TAC No. MD8067).” ADAMS 

Accession No. ML081710055

Letter from M.R. Blevins, Luminant Power, to the NRC dated July 10, 2008, “Comanche Peak 

Nuclear Power Plant (CPNPP), Docket No. 50-446, Submittal of Unit 2 Tenth Refueling Outage 

(2RF10) Inservice Inspection (ISI) Summary Report (Unit 2: 1998 Edition of ASME Code 

Section XI, through 2000 Addenda, Interval Start Date – August 3, 2004, Second Interval).” 

ADAMS Accession No. ML082000122

Letter from M.R. Blevins, Luminant Power, to the NRC dated September 18, 2008, “Comanche 

Peak Steam Electric Station (CPSES), Unit 2 Tenth Refueling Outage (2RF10) Steam 

Generator 180 Day Report.” ADAMS Accession No. ML082690600

Letter from R. Flores, Luminant Power, to the NRC dated April 9, 2009, “Comanche Peak 

Steam Electric Station (CPSES), Unit 2, Docket No. 50-446, Response to Request for Additional 

Information, 2RF10 Steam Generator Tube Inservice Inspection Report—TAC No. ME0123.” 

ADAMS Accession No. ML091070586

Letter from B.K. Singal, NRC, to R. Flores, Luminant Generation Co., LLC, dated 

October 9, 2009, “Comanche Peak Steam Electric Station, Units 1 and 2—Issuance of 

Amendments to Modify Technical Specifications to Establish Alternate Repair Criteria and 

Include Reporting Requirements Specific to Alternate Repair Criteria for Steam Generator 

Program (TAC Nos. ME1446 and ME1447).” ADAMS Accession No. ML092740076
A-17

Letter from B.K. Singal, NRC, to R. Flores, Luminant Generation Co., LLC, dated April 6, 2011, 

“Comanche Peak Nuclear Power Plant, Units 1 and 2—Issuance of Amendments to Modify 

Technical Specifications to Establish Alternate Repair Criteria for Steam Generator Program 

(TAC Nos. ME5110 and ME5111).” ADAMS Accession No. ML110770322

Letter from B.K. Singal, NRC, to R. Flores, Luminant Generation Co., LLC, dated May 23, 2011, 

“Comanche Peak Nuclear Power Plant, Unit 2—Summary of Conference Call Regarding the 

Spring 2011 Steam Generator Tube Inspections (TAC No. ME5826).” ADAMS Accession 

No. ML111400148

Letter from F.W. Madden, Luminant Generation Co., LLC, to the NRC dated July 14, 2011, 

“Comanche Peak Nuclear Power Plant (CPNPP) Docket No. 50-446, Licensee Event Report 

446/11-002-00, Unit 2 Manual Trip Due to High Steam Generator Sodium Concentration.” 

ADAMS Accession No. ML11203A077

Letter from F.W. Madden, Luminant Generation Co., LLC, to the NRC dated October 12, 2011, 

“Comanche Peak Nuclear Power Plant, Docket No. 50-446, Unit 2 Twelfth Refueling Outage 

(2RF12) Steam Generator 180 Day Report.” ADAMS Accession No. ML11306A012

Letter from R.B. Mays, Luminant Generation Co., LLC, to the NRC dated April 10, 2012, 

“Comanche Peak Nuclear Power Plant Unit 2, Docket No. 50-446, Response to Request for 

Additional Information, 2RF12 Steam Generator Tube Inservice Inspection Report—TAC 

No. ME7345.” ADAMS Accession No. ML12109A051

Letter from B.K. Singal, NRC, to R. Flores, Luminant Generation Co., LLC, dated 

October 18, 2012, “Comanche Peak Nuclear Power Plant, Units 1 and 2—Issuance of 

Amendments Re: License Amendment Request for Changes to Technical Specifications 5.5.9 

and 5.6.9 Regarding Alternate Steam Generator Repair Criteria (TAC Nos. ME8374 and 

ME8375).” ADAMS Accession No. ML12263A036

Letter from B.K. Singal, NRC, to R. Flores, Luminant Generation Co., LLC, dated 

February 27, 2014, “Comanche Peak Nuclear Power Plant, Units 1 and 2—Issuance of 

Amendments Re: Adoption of TSTF-510, ‘Revision to Steam Generator Program Inspection 

Frequencies and Tube Sample Selection’ (TAC Nos. MF2651 and MF2652).” ADAMS 

Accession No. ML14042A223

Letter from F.W. Madden, Luminant Generation Co., LLC, to the NRC dated October 21, 2014, 

“Comanche Peak Nuclear Power Plant, Docket No. 50-446, Unit 2 Fourteenth Refueling Outage 

(2RF14) Steam Generator 180 Day Report.” ADAMS Accession No. ML14302A067
A-18

Callaway

Letter from W.A. Witt, Union Electric, to the NRC dated November 19, 2002, “Docket 

Number 50-483, Callaway Plant Unit 1, Union Electric Co., Facility Operating License NPF-30, 

Licensee Event Report 2002-011-00; Inservice Inspection Results for ‘A’ Steam Generator 

Classified as C-3.” ADAMS Accession No. ML023310226

Letter from W.A. Witt, Union Electric, to the NRC dated November 19, 2002, “Docket 

Number 50-483, Callaway Plant Unit 1, Union Electric Co., Facility Operating License NPF-30, 

Special Report 2002-03, C-3 Classified Inservice Inspection Results for Steam Generator Tube 

Inspections.” ADAMS Accession No. ML023310230

Letter from W.A. Witt, Union Electric, to the NRC dated November 21, 2002, “Docket 

Number 50-483, Callaway Plant Unit 1, Union Electric Co., Facility Operating License NPF-30, 

Special Report 2002-04, Inservice Inspection Results for Steam Generator Tube Inspections—

Number of Tubes Plugged or Repaired.” ADAMS Accession No. ML023360363

Letter from J.N. Donohew, NRC, to G.L. Randolph, Union Electric Co. dated March 5, 2003, 

“Callaway Plant—Summary of Conference Call with Union Electric Co. Regarding the 

2002 Steam Generator Inspections (TAC No. MB6643).” ADAMS Accession No. ML030640628

Letter from W.A. Witt, Union Electric, to the NRC dated March 17, 2003, “Docket 

Number 50-483, Callaway Plant Unit 1, Union Electric Co., Facility Operating License NPF-30, 

Results of the Thirteenth Steam Generator Tube In-Service Inspection.” ADAMS Accession 

No. ML030850274

Letter from K.D. Young, Union Electric, to the NRC dated August 22, 2003, “Docket 

Number 50-483, Callaway Plant Unit 1, Union Electric Co., Facility Operating License NPF-30, 

Request for Additional Information on November 2002 Steam Generator Tube Inspection.” 

ADAMS Accession No. ML032510091

Letter from W.A. Witt, Union Electric, to the NRC dated May 25, 2004, “Docket Number 50-483, 

Callaway Plant Unit 1, Union Electric Co., Facility Operating License NPF-30, Licensee Event 

Report 2004-006-00, ‘A’ Steam Generator Tube Inspection Results Classified as C-3.” ADAMS 

Accession No. ML041560005

Letter from W.A. Witt, Union Electric, to the NRC dated June 24, 2004, “Docket Number 50-483, 

Callaway Plant Unit 1, Union Electric Co., Facility Operating License NPF-30, Special Report, 

Inservice Inspection Results for Steam Generator Tube Inspections—Number of Tubes Plugged 

or Repaired.” ADAMS Accession No. ML041830237

Letter from K.D. Young, Union Electric, to the NRC dated July 9, 2004, “Docket Number 50-483, 

Callaway Plant Unit 1, Union Electric Co., Facility Operating License NPF-30, Inservice 

Inspection (ISI) Summary Reports for Interval 2 Period 2.” ADAMS Accession 

No. ML042150072

Letter from W.A. Witt, Union Electric, to the NRC dated September 30, 2004, “Docket 

Number 50-483, Callaway Plant Unit 1, Union Electric Co., Facility Operating License NPF-30, 

Steam Generator Condition Monitoring Report.” ADAMS Accession No. ML042820060
A-19

Letter from K.D. Young, Union Electric, to the NRC dated October 27, 2004, “Docket 

Number 50-483, Callaway Plant Unit 1, Union Electric Co., Facility Operating License NPF-30, 

Response to NRC Generic Letter 2004-01: Requirements For Steam Generator Tube 

Inspections.” ADAMS Accession No. ML043140239

Letter from C.R. Younie, Union Electric, to the NRC dated June 2, 2005, “Docket 

Number 50-483, Callaway Plant Unit 1, Union Electric Co., Facility Operating License NPF-30, 

Results of the Fourteenth Steam Generator Tube Inservice Inspection.” ADAMS Accession 

No. ML051580381

Letter from J.N. Donohew, NRC, to C.D. Naslund, Union Electric Co. dated 

September 29, 2005, “Callaway Plant, Unit 1—Issuance of Amendment Regarding the Steam 

Generator Replacement Project (TAC No. MC4437).” ADAMS Accession No. ML052570086
A-20

Millstone 3

Letter from J.A. Price, Dominion Nuclear Connecticut, Inc., to the NRC dated October 7, 2002, 

“Millstone Power Station, Unit No. 3, Steam Generator Tube Plugging.” ADAMS Accession 

No. ML022910045

Letter from V. Nerses, NRC, to J.A. Price, Dominion Nuclear Connecticut, Inc., dated 

November 8, 2002, “Millstone Power Station, Unit No. 3—Summary of Conference Calls with 

Dominion Nuclear Connecticut, Inc., Regarding the 2002 Steam Generator Inspection Results at 

Millstone Power Station, Unit No. 3 (TAC No. MB6183).” ADAMS Accession No. ML023110528

Letter from J.A. Price, Dominion Nuclear Connecticut, Inc., to the NRC dated August 25, 2003, 

“Millstone Power Station, Unit No. 3, Steam Generator Tube Inservice Inspection Report.” 

ADAMS Accession No. ML032471591

Letter from L.N. Hartz, Dominion Nuclear Connecticut, Inc., to the NRC dated April 5, 2004, 

“Dominion Nuclear Connecticut, Inc., (DNC), Millstone Power Station Unit 3, Response to 

Request for Additional Information (RAI) Regarding Steam Generator Tube Inspection Summary 

For Fall 2002 Outage.” ADAMS Accession No. ML040970336

Letter from L.N. Hartz, Dominion Nuclear Connecticut, Inc., to the NRC dated May 3, 2004, 

“Dominion Nuclear Connecticut, Inc., Millstone Power Station Unit 3, Steam Generator Tube 

Plugging Report.” ADAMS Accession No. ML041260535

Letter from W.R. Matthews, Dominion Nuclear Connecticut, Inc., to the NRC dated 

October 29, 2004, “Virginia Electric and Power Co. (Dominion), Dominion Nuclear Connecticut, 

Inc. (DNC), North Anna Power Station Units 1 and 2, Surry Power Station Units 1 and 2, 

Millstone Power Station Units 2 and 3, Sixty Day Response to NRC Generic Letter 2004-01, 

Requirements for Steam Generator Tube Inspections.” ADAMS Accession No. ML043060099

Letter from J.A. Price, Dominion Nuclear Connecticut, Inc., to the NRC dated April 7, 2005, 

“Dominion Nuclear Connecticut, Inc., Millstone Power Station Unit 3, Special Report, Steam 

Generator Tube Inservice Inspection,” ADAMS Accession No. ML051040333

Letter from J.A. Price, Dominion Nuclear Connecticut, Inc., to the NRC dated October 26, 2005, 

“Dominion Nuclear Connecticut, Inc., Millstone Power Station Unit 3, Steam Generator Tube 

Plugging Report.” ADAMS Accession No. ML053070547

Letter from J.A. Price, Dominion Nuclear Connecticut, Inc., to the NRC dated 

December 14, 2005, “Dominion Nuclear Connecticut, Inc., Millstone Power Station Unit 3, 

Supplement to Steam Generator Tube Inservice Inspection Report.” ADAMS Accession 

No. ML053570271

Letter from V. Nerses, NRC, to D.A. Christian, Dominion Nuclear Connecticut, Inc. dated 

July 19, 2006, “Review of Steam Generator Tube Inservice Inspection Report for the 2004 

Refueling Outage at Millstone Power Station, Unit No. 3 (TAC No. MC6714).” ADAMS 

Accession No. ML061930135

Letter from J.A. Price, Dominion Nuclear Connecticut, Inc., to the NRC dated October 2, 2006, 

“Dominion Nuclear Connecticut, Inc., Millstone Power Station Unit 3, Special Report, Steam 

Generator Tube Inservice Inspection.” ADAMS Accession No. ML062860044
A-21

Letter from J.A. Price, Dominion Nuclear Connecticut, Inc., to the NRC dated May 8, 2007, 

“Dominion Nuclear Connecticut, Inc., Millstone Power Station Unit 3, Steam Generator Tube 

Plugging Report.” ADAMS Accession No. ML071350249

Letter from J. D. Hughey, NRC, to D.A. Christian, Dominion Nuclear Connecticut, Inc. dated 

May 31, 2007, “Millstone Power Station, Unit Nos. 2 and 3—Issuance of Amendments 

Regarding Steam Generator Tube Integrity (TAC Nos. MD2570 and MD2571).” ADAMS 

Accession No. ML071380257

Letter from J.A. Price, Dominion Nuclear Connecticut, Inc., to the NRC dated 

December 18, 2007, “Dominion Nuclear Connecticut, Inc., Millstone Power Station Unit 3, 

Response to Request for Additional Information, 2005 Steam Generator Tube Inspections.” 

ADAMS Accession No. ML073620218

Letter from J.A. Price, Dominion Nuclear Connecticut, Inc., to the NRC dated April 11, 2008, 

“Dominion Nuclear Connecticut, Inc., Millstone Power Station Unit 3, 2007 Steam Generator 

Tube Inspection Report.” ADAMS Accession No. ML081140138

Letter from J.A. Price, Dominion Nuclear Connecticut, Inc., to the NRC dated 

September 17, 2008, “Dominion Nuclear Connecticut, Inc., Millstone Power Station Unit 3, 

Response to Request for Additional Information Regarding the 2007 Steam Generator Tube 

Inspections.” ADAMS Accession No. ML082680092

Letter from C.J. Sanders, NRC, to D.A. Christian, Dominion Nuclear Connecticut, Inc., dated 

September 30, 2008, “Millstone Power Station, Unit No. 3—Issuance of Amendment Regarding 

Changes to Technical Specification (TS) Section 6.8.4.g, ‘Steam Generator Program’ and 

Section 6.9.1.7, ‘Steam Generator Tube Inspection Report’ (TAC No. MD8736).” ADAMS 

Accession No. ML082321292 and ML082810147

Letter from C.J. Sanders, NRC, to D.A. Christian, Dominion Nuclear Connecticut, Inc. dated 

December 12, 2008, “Millstone Power Station, Unit No. 3—Summary of Conference Call with 

Dominion Nuclear Connecticut, Inc., to Discuss 2008 Steam Generator Tube Inspections (TAC 

No. MD9954).” ADAMS Accession No. ML083370136

Letter from A.J. Jordan, Dominion Nuclear Connecticut, Inc., to the NRC dated March 13, 2009, 

“Dominion Nuclear Connecticut, Inc., Millstone Power Station Unit 3, End of Cycle 12 Steam 

Generator Tube Inspection Report.” ADAMS Accession No. ML090850344

Letter from A.J. Jordan, Dominion Nuclear Connecticut, Inc., to the NRC dated 

November 23, 2009, “Dominion Nuclear Connecticut, Inc., Millstone Power Station Unit 3, 

Response to Request for Additional Information Regarding 2008 Steam Generator Tube 

Inspections.” ADAMS Accession No. ML093350528

Letter from C.J. Sanders, NRC, to D.A. Heacock, Dominion Nuclear Connecticut, Inc. dated 

May 3, 2010, “Millstone Power Station, Unit No. 3—Issuance of Amendment Re: Changes to the 

Steam Generator Inspection Scope and Repair Requirements (TAC No. ME2978).” ADAMS 

Accession No. ML100770358
A-22

Letter from A.J. Jordan, Dominion Nuclear Connecticut, Inc., to the NRC dated 

October 28, 2010, “Dominion Nuclear Connecticut, Inc., Millstone Power Station Unit 3, End of 

Cycle 13 Steam Generator Tube Inspection Report.” ADAMS Accession No. ML103130038

Letter from A.J. Jordan, Dominion Nuclear Connecticut, Inc., to the NRC dated May 24, 2011, 

“Dominion Nuclear Connecticut, Inc., Millstone Power Station Unit 3, Response to Request for 

Additional Information Regarding the Steam Generator Tube Inservice Inspection Report for the 

End of Cycle 13.” ADAMS Accession No. ML11159A025

Letter from C.J. Sanders, NRC, to D.A. Heacock, Dominion Nuclear Connecticut, Inc., dated 

October 7, 2011, “Millstone Power Station, Unit No. 3—Issuance of Amendment Re: Steam 

Generator Tube Inspection Alternate Repair Criteria (TAC No. ME5389).” ADAMS Accession 

No. ML112580517

Letter from S.E. Scace, Dominion Nuclear Connecticut, Inc., to the NRC dated April 6, 2012, 

“Dominion Nuclear Connecticut, Inc., Millstone Power Station Unit 3, End of Cycle 14 Steam 

Generator Tube Inspection Report.” ADAMS Accession No. ML12109A044

Letter from S.E. Scace, Dominion Nuclear Connecticut, Inc., to the NRC dated October 1, 2012, 

“Dominion Nuclear Connecticut, Inc., Millstone Power Station Unit 3, Response to Request for 

Additional Information Regarding the End of Cycle 14 Steam Generator Tube Inspection Report 

(TAC No. ME8422).” ADAMS Accession No. ML12292A192

Letter from J. Kim, NRC, to D.A. Heacock, Dominion Nuclear Connecticut, Inc., dated 

December 6, 2012, “Millstone Power Station Unit No. 3—Issuance of Amendment Re: Revise 

Technical Specification 6.8.4.g, ‘Steam Generator (SG) Program,’ and Technical 

Specifications 6.9.1.7, ‘Steam Generator Tube Inspection Report,’ for a Permanent Alternate 

Repair Criteria (TAC No. ME8455).” ADAMS Accession No. ML12299A498

Letter from J. Kim, NRC, to D.A. Heacock, Dominion Nuclear Connecticut, Inc., dated 

January 11, 2013, “Millstone Power Station, Unit No. 3—Issuance of Amendment Re: Adopt 

TSTF-510, ‘Revision to Steam Generator Program Inspection Frequencies and Tube Sample 

Selection’ (TAC No. ME9189).” ADAMS Accession No. ML12333A255

Letter from S.E. Scace, Dominion Nuclear Connecticut, Inc., to the NRC dated October 2, 2013, 

“Dominion Nuclear Connecticut, Inc., Millstone Power Station Unit 3, End of Cycle 15 Steam 

Generator Tube Inspection Report.” ADAMS Accession No. ML13284A065

Letter from S.E. Scace, Dominion Nuclear Connecticut, Inc., to the NRC dated 

February 26, 2014, “Dominion Nuclear Connecticut, Inc., Millstone Power Station Unit 3, 

Response to Request for Additional Information Regarding End of Cycle 15 Steam Generator 

Tube Inspection Report.” ADAMS Accession No. ML14069A173
A-23

Seabrook

Letter from J.M. Peschel, North Atlantic Energy Service Corp., to the NRC dated June 3, 2002, 

“Seabrook Station, Steam Generator Tubes Plugged During Eighth Inservice Inspection.” 

ADAMS Accession No. ML021640036

Letter from R.D. Starkey, NRC, to T.C. Feigenbaum, North Atlantic Energy Service Corp. dated 

July 2, 2002, “Summary of Conference Calls with North Atlantic Energy Service Corp.

Regarding the 2002 Steam Generator Inspection Results at Seabrook Station, Unit No. 1 

(Seabrook) (TAC No. MB5299).” ADAMS Accession No. ML021800003

Letter from R.D. Starkey, NRC, to T.C. Feigenbaum, North Atlantic Energy Service Corp. dated 

September 20, 2002, “Summary of Conference Call with North Atlantic Energy Service Corp.

Regarding the 2002 Steam Generator Inspection Results at Seabrook Station, Unit No. 1 (TAC 

No. MB5299).” ADAMS Accession No. ML022590328

Letter from J.M. Vargas, North Atlantic Energy Service Corp., to the NRC dated 

October 31, 2002, “Seabrook Station, Unit No. 1, Response to Request for Information—Steam 

Generator Tubes.” ADAMS Accession No. ML023100348

Letter from G.F. St. Pierre, FPL Energy Seabrook Station, to the NRC dated November 8, 2002, 

“Seabrook Station, Response to Request for Information—Steam Generator Tube.” ADAMS 

Accession No. ML023240524

Letter from R.D. Starkey, NRC, to M.E. Warner, North Atlantic Energy Service Corp. dated 

November 26, 2002, “Summary of October 9, 2002, Conference Call with North Atlantic Energy 

Service Corp. Regarding the Seabrook Station Steam Generator Tube Laboratory Examination 

Results (TAC No. MB5299).” ADAMS Accession No. ML023300041

Letter from R.D. Starkey, NRC, to File dated November 26, 2002, “Summary of 

November 14, 2002, Meeting with FPL Energy Seabrook, LLC, (FPLE Seabrook) to Discuss the 

Root Cause Evaluation for Axial Outside Diameter Indications on Steam Generator Tubes at 

Seabrook Station, Unit No. 1.” ADAMS Accession No. ML023300457

Letter from J.M. Peschel, FPL Energy Seabrook, LLC, to the NRC dated December 2, 2002, 

“Seabrook Station, Response to Request for Corrected Information—Steam Generator Tube.” 

ADAMS Accession No. ML023470223

Letter from J.M. Peschel, FPL Energy Seabrook, LLC, to the NRC dated April 24, 2003, 

“Seabrook Station, Steam Generator Inservice Inspection.” ADAMS Accession 

No. ML031220028

Letter from V. Nerses, NRC, to M.E. Warner, FPL Energy Seabrook, LLC, dated July 23, 2003, 

“Summary of Pre-Outage Conference Call with FPL Energy Seabrook, LLC Regarding the 

Inspection Scope For the Upcoming Steam Generator Inspections at the Seabrook Station, Unit 

No. 1 (TAC No. MB8928).” ADAMS Accession No. ML031970605

Letter from J.M. Peschel, FPL Energy Seabrook, LLC, to the NRC dated November 3, 2003, 

“Seabrook Station, Steam Generator Tubes Plugged During Ninth Inservice Inspection.” 

ADAMS Accession No. ML033180464
A-24

Letter from V. Nerses, NRC, to M.E. Warner, FPL Energy Seabrook, LLC, dated 

December 29, 2003, “Seabrook Station, Unit No. 1—Summary of Conference Call with 

FPL Energy Seabrook, LLC, Regarding the 2003 Steam Generator Inspections (TAC 

No. MC0721).” ADAMS Accession No. ML033490139

Letter from V. Nerses, NRC, to M.E. Warner, FPL Energy Seabrook, LLC, dated 

February 18, 2004, “Review of Steam Generator Tube Inservice Inspection Report for the 

2002 Refueling Outage at Seabrook Station, Unit No. 1 (TAC No. MB8928).” ADAMS Accession 

No. ML040360108

Letter from M.E. Warner, FPL Energy Seabrook, LLC, to the NRC dated October 12, 2004, 

“Seabrook Station, Steam Generator Inservice Inspection.” ADAMS Accession 

No. ML042940501

Letter from J.A. Stall, FPL Energy Seabrook, LLC, to the NRC dated October 29, 2004, “Florida 

Power and Light Co., St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389, Turkey Point 

Units 3 and 4, Docket Nos. 50-250 and 50 251, FPL Energy Seabrook, LLC, Seabrook Station, 

Docket No. 50-443, NRC Generic Letter 2004-01, Requirements for Steam Generator Tube

Inspections.” ADAMS Accession No. ML043070353

Letter from G.F. St. Pierre, FPL Energy Seabrook, LLC, to the NRC dated August 4, 2005, 

“Seabrook Station, Facility Operating License NPF-86, Response to Request for Additional 

Information Regarding Seabrook Station, Unit No. 1, Steam Generator Tube Inspection 

Summary for the Fall 2003 Outage.” ADAMS Accession No. ML052280221

Letter from G.E. Miller, NRC, to G.F. St. Pierre, FPL Energy Seabrook, LLC, dated 

September 29, 2006, “Seabrook Station, Unit No. 1—Issuance of Amendment Re: Limited 

Inspection of the Steam Generator Tube Portion within the Tubesheet (TAC No. MC8554).” 

ADAMS Accession No. ML062630457

Letter from G.F. St. Pierre, FPL Energy Seabrook, LLC, to the NRC dated October 26, 2006, 

“Seabrook Station, Steam Generator Tubes Plugged During Refueling Outage 11 Inservice 

Inspection.” ADAMS Accession No. ML063040324

Letter from G.E. Miller, NRC, to G.F. St. Pierre, FPL Energy Seabrook, LLC, dated 

March 28, 2007, “Seabrook Station, Unit No. 1—Issuance of Amendment Re: Technical 

Specification Task Force (TSTF)-449, ‘Steam Generator Tube Integrity,’ (TAC No. MD0696).” 

ADAMS Accession Nos. ML070510645 and ML071420135

Letter from G.F. St. Pierre, FPL Energy Seabrook, LLC, to the NRC dated May 23, 2007, 

“Seabrook Station, Steam Generator Inservice Inspection.” ADAMS Accession 

No. ML071510197

Letter from G.E. Miller, NRC, to G.F. St. Pierre, FPL Energy Seabrook, LLC, dated 

March 7, 2008, “Seabrook Station, Unit No. 1—Summary of Conference Call and Request for 

Additional Information Regarding the Fall 2006 Steam Generator Inspections (TAC 

No. MD2791).” ADAMS Accession No. ML073532041
A-25

Letter from G.F. St. Pierre, FPL Energy Seabrook, LLC, to the NRC dated June 18, 2008, 

“Seabrook Station, Response to Request for Additional Information Related to Steam Generator 

Inspections Performed During the Eleventh Refueling Outage.” ADAMS Accession 

No. ML081750527

Letter from G.F. St. Pierre, FPL Energy Seabrook, LLC, to the NRC dated August 8, 2008, 

“Seabrook Station, Response to Clarifying Questions Related to Steam Generator Inspections 

Performed During the Eleventh Refueling Outage.” ADAMS Accession No. ML082260306

Letter from D. Egan, NRC, to G.F. St. Pierre, NextEra Energy Seabrook, LLC, dated 

October 13, 2009, “Seabrook Station, Unit No. 1—Issuance of Amendment Re: Changes to the 

Steam Generator Inspection Scope and Repair Requirements (TAC No. ME1386).” ADAMS 

Accession No. ML092460184

Letter from M. O’Keefe, NextEra Energy Seabrook, LLC, to the NRC dated April 7, 2010, 

“Seabrook Station, Steam Generator Tube Inspection Report.” ADAMS Accession 

No. ML101030109

Letter from P. Freeman, NextEra Energy Seabrook, LLC, to the NRC dated November 3, 2010, 

“Seabrook Station, Response to Request for Additional Information Regarding Seabrook Station 

2009 Steam Generator Tube Inspection Report.” ADAMS Accession No. ML103130033

Letter from G.E. Miller, NRC, to P. Freeman, NextEra Energy Seabrook, LLC, dated 

July 28, 2011, “Summary of Steam Generator Tube Mid-Inspection Conference Call for 

Spring 2011—Seabrook Station, Unit No. 1 (TAC No. ME5715).” ADAMS Accession 

No. ML112010532

Letter from M. O’Keefe, NextEra Energy Seabrook, LLC, to the NRC dated 

September 19, 2011, “Seabrook Station, Steam Generator Tube Inspection Report.” 

ADAMS Accession No. ML11266A008

Letter from P. Freeman, NextEra Energy Seabrook, LLC, to the NRC dated March 6, 2012, 

“Seabrook Station, Response to Request for Additional Information, 2011 Steam Generator 

Tube Inspections.” ADAMS Accession No. ML12072A065

Letter from J.G. Lamb, NRC, to K. Walsh, NextEra Energy Seabrook, LLC, dated 

September 10, 2012, “Seabrook Station, Unit No. 1—Issuance of Amendment Re: Permanent 

Application of Steam Generator Tube Alternate Repair Criteria, H* (TAC No. ME8513).” ADAMS 

Accession No. ML12178A537

Letter from M. O’Keefe, NextEra Energy Seabrook, LLC, to the NRC dated December 31, 2012, 

“Seabrook Station, Steam Generator Tube Inspection Report.” ADAMS Accession 

No. ML13008A160

Letter from M.H. Ossing, NextEra Energy Seabrook, LLC, to the NRC dated 

September 13, 2013, “Seabrook Station, Response to Request for Additional Information 

Regarding the 2012 Steam Generator Tube Inspection Report.” ADAMS Accession 

No. ML13261A149
A-26

Letter from J.G. Lamb, NRC, to K. Walsh, NextEra Energy Seabrook, LLC, dated 

October 25, 2013, “Seabrook Station, Unit No. 1—Issuance of Amendment Regarding License 

Amendment Request 13-02, Application to Revise Technical Specifications to Adopt TSTF-510, 

‘Revision to Steam Generator Program Inspection Frequencies and Tube Sample Selection,’ 

Using the Consolidated Line Item Improvement Process (TAC No. MF1372).” ADAMS 

Accession No. ML13107A016

Letter from M. Ossing, NextEra Energy Seabrook, LLC, to the NRC dated October 14, 2014, 

“Seabrook Station, Steam Generator Tube Inspection Report.” ADAMS Accession 

No. ML14297A090
A-27

Vogtle 1

Letter from J.B. Beasley Jr., Southern Nuclear Operating Co., Inc., to the NRC dated 

April 5, 2002, “Vogtle Electric Generating Plant, Technical Specification Report 1-2002-1, 

Number of Steam Generator Tubes Plugged During 1R10.”

Letter from J.B. Beasley Jr., Southern Nuclear Operating Co., Inc., to the NRC dated 

July 1, 2002, “Vogtle Electric Generating Plant, Inservice Inspection Summary Report.” ADAMS 

Accession No. ML021920516

Letter from J.T. Gasser, Southern Nuclear Operating Co., Inc., to the NRC dated 

February 12, 2003, “Vogtle Electric Generating Plant, Response to Request for Additional 

Information, Steam Generator Tube Inspections.” ADAMS Accession No. ML030510260

Letter from B.R. Bonser, NRC, to J.T. Gasser Jr., Southern Nuclear Operating Co., Inc., dated 

April 24, 2003, “Vogtle Electric Generating Plant—NRC Integrated Inspection Report 

50-424/03-02 and 50-425/03-02.” ADAMS Accession No. ML031150065

Letter from J.T. Gaser, Southern Nuclear Operating Co., Inc., to the NRC dated 

October 27, 2003, “Vogtle Electric Generating Plant, Technical Specification Report 1-2003-1, 

Number of Steam Generator Tubes Plugged During 1R11.” ADAMS Accession 

No. ML033030404

Letter from J.T. Gasser, Southern Nuclear Operating Co., Inc., to the NRC dated 

January 16, 2004, “Vogtle Electric Generating Plant, Inservice Inspection Summary Report.” 

ADAMS Accession No. ML040220620

Letter from J.T. Gasser, Southern Nuclear Operating Co., Inc., to the NRC dated 

August 26, 2004, “Vogtle Electric Generating Plant, Response to NRC Questions Regarding the 

2002 Unit 2 (2R9) and 2003 Unit 1 (1R11) Steam Generator Tube Inspection Reports.” ADAMS 

Accession No. ML042430424

Letter from L.M Stinson, Southern Nuclear Operating Co., Inc., to the NRC dated 

October 25, 2004, “Joseph M. Farley Nuclear Plant, Vogtle Electric Generating Plant, Response 

to NRC Generic Letter 2004-01, ‘Requirements for Steam Generator Tube Inspections.’” 

ADAMS Accession No. ML043010265

Letter from L.M Stinson, Southern Nuclear Operating Co., Inc., to the NRC dated 

January 7, 2005, “Joseph M. Farley Nuclear Plant, Vogtle Electric Generating Plant, 

Supplemental Response to NRC Generic Letter 2004-01, ‘Requirements for Steam Generator 

Tube Inspections.’” ADAMS Accession No. ML050110224

Letter from D.E. Grissette, Southern Nuclear Operating Co., Inc., to the NRC dated 

February 24, 2005, “Vogtle Electric Generating Plant, Revised Response to Generic Letter 

97-06, ‘Degradation of Steam Generator Internals.’” ADAMS Accession No. ML050590124

Letter from D.E. Grissette, Southern Nuclear Operating Co., Inc., to the NRC dated 

April 12, 2005, “Vogtle Electric Generating Plant, Technical Specification Report 1-2005-1, 

Number of Steam Generator Tubes Plugged During 1R12.” ADAMS Accession 

No. ML051040239
A-28

Letter from C. Gratton, NRC, to D.E. Grissette, Southern Nuclear Operating Co., Inc., dated 

June 3, 2005, “Vogtle Electric Generating Station (Vogtle), Unit 1—Summary of Conference Call 

Regarding the 2005 Spring Outage Steam Generator Tube Inspections.” ADAMS Accession 

No. ML051400035

Letter from D.E. Grissette, Southern Nuclear Operating Co., Inc., to the NRC dated 

July 1, 2005, “Vogtle Electric Generating Plant, Inservice Inspection Summary Report.” ADAMS 

Accession No. ML052060257

Letter from C. Gratton, NRC, to D.E. Grissette, Southern Nuclear Operating Co., Inc., dated 

March 7, 2006, “Vogtle Electric Generating Plant, Unit 1 (Vogtle 1)—Summary of the Staff’s 

Review of the Steam Generator Tube Inservice Inspection Reports for the End-of-Cycle 

12 Refueling Outage in Spring 2005 (TAC No. MC8105).” ADAMS Accession No. ML060320582

Letter from C. Gratton, NRC, to D.E. Grissette, Southern Nuclear Operating Co., Inc., dated 

August 28, 2006, “Vogtle Electric Generating Plant, Units 1 and 2, Issuance of Amendments 

Regarding Steam Generator Tube Integrity (TAC Nos. MD1075 and MD1076).” ADAMS 

Accession No. ML062360577

Letter from C. Gratton, NRC, to D.E. Grissette, Southern Nuclear Operating Co., Inc., dated 

September 12, 2006, “Vogtle Electric Generating Plant, Units 1 and 2, Issuance of Amendments 

Regarding the Steam Generator Tube Surveillance Program (TAC Nos. MD2642 and 

MD2643).” ADAMS Accession No. ML062260302

Letter from R.E. Martin, NRC, to D.E. Grissette, Southern Nuclear Operating Co., Inc., dated 

December 19, 2006, “Vogtle Electric Generating Plant, Unit 1 (Vogtle)—Summary of 

Conference Call Regarding the 2006 Fall Outage Steam Generator Tube Inspections (TAC 

No. MD3371).” ADAMS Accession No. ML063390165

Letter from B.J. George, Southern Nuclear Operating Co., Inc., to the NRC dated April 18, 2007, 

“Vogtle Electric Generating Plant Unit 1, 1R13 Steam Generator Tube Inspection Report.” 

ADAMS Accession No. ML072480031

Letter from D.H. Jones, Southern Nuclear Operating Co., Inc., to the NRC dated 

January 31, 2008, “Vogtle Electric Generating Plant, Unit 1, Response to NRC Request for 

Additional Information Regarding the 2006 Unit 1 (1R13) Steam Generator Tube Inspections.” 

ADAMS Accession No. ML080320298

Letter from S.P. Lingam, NRC, to T.E. Tynan, Southern Nuclear Operating Co., Inc., dated 

April 9, 2008, “Vogtle Electric Generating Plant, Units 1 and 2, Issuance of Amendments 

Regarding Changes to Technical Specification (TS) Sections TS 5.5.9, ‘Steam Generator (SG) 

Program’ and TS 5.6.10, ‘Steam Generator Tube Inspection Report’ (TAC Nos. MD7450 and 

MD7451).” ADAMS Accession No. ML080950232

Letter from R.A. Jervey, NRC, to D.E. Grissette, Southern Nuclear Operating Co., Inc., dated 

May 28, 2008, “Vogtle Electric Generating Plant, Unit 1—Summary of Conference Calls 

Regarding the Spring 2008 Steam Generator Tube Inspections During Refueling Outage 14.” 

ADAMS Accession No. ML081430126
A-29

Letter from M.J. Ajluni, Southern Nuclear Operating Co., Inc., to the NRC dated 

October 17, 2008, “Vogtle Electric Generating Plant – Unit 1, Fourteenth Maintenance/Refueling 

Outage, Steam Generator Tube Inspection Report.” ADAMS Accession No. ML082911083

Letter from D.N. Wright, NRC, to M.J. Ajluni, Southern Nuclear Operating Co., Inc. dated 

June 18, 2009, “Vogtle Electric Generating Plant, Unit 1—Review of the 2008 Refueling Outage 

Steam Generator Tube Inservice Inspection Report (TAC No. ME0213).” ADAMS Accession 

No. ML091660259

Letter from D.N. Wright, NRC, to M.J. Ajluni, Southern Nuclear Operating Co., Inc. dated 

September 24, 2009, “Vogtle Electric Generating Plant, Units 1 and 2, Issuance of Amendments 

Regarding Technical Specification (TS) Section 5.5.9, ‘Steam Generator Program,’ and 

TS 5.6.10, ‘Steam Generator Tube Inspection Report,’ for Interim Alternate Repair Criteria (TAC 

Nos. ME1339 and ME1340).” ADAMS Accession No. ML092170782

Letter from D.N. Wright, NRC, to M.J. Ajluni, Southern Nuclear Operating Co., Inc., dated 

November 5, 2009, “Vogtle Electric Generating Plant, Unit 1—Summary of Conference Call 

Regarding the Fall 2009 Steam Generator Inspections (TAC No. ME2166).” ADAMS Accession 

No. ML093070375

Letter from M.J. Ajluni, Southern Nuclear Operating Co., Inc., to the NRC dated 

February 1, 2010, “Vogtle Electric Generating Plant – Unit 1, Supplement to 1R14 Steam 

Generator Inspection Report—Tube Pull Examination Results.” ADAMS Accession 

No. ML100560265

Letter from M.J. Ajluni, Southern Nuclear Operating Co., Inc., to the NRC dated April 13, 2010, 

“Vogtle Electric Generating Plant – Unit 1, Fifteenth Maintenance/Refueling Outage, Steam 

Generator Tube Inspection Report.” ADAMS Accession No. ML101040084

Letter from M.J. Ajluni, Southern Nuclear Operating Co., Inc., to the NRC dated August 6, 2010, 

“Vogtle Electric Generating Plant-Unit 1, Response to Request for Additional Information 

Related to Fifteenth Maintenance/Refueling Outage Steam Generator Tube Inspection Report.” 

ADAMS Accession No. ML102210415

Letter from R.E. Martin, NRC, to M.J. Ajluni, Southern Nuclear Operating Co., Inc., dated 

September 16, 2010, “Vogtle Electric Generating Plant, Unit 1—Review of Steam Generator 

Tube Inspections Performed During Fall 2009 Outage and Destructive Examination of 2008 

Pulled Tubes (TAC No. ME3825).” ADAMS Accession No. ML102520106

Letter from P.G. Boyle, NRC, to M.J. Ajluni, Southern Nuclear Operating Co., Inc., dated 

March 14, 2011, “Vogtle Electric Generating Plant, Units 1 and 2, Issuance of Amendments 

Regarding Steam Generator Tube Inspection Alternate Inspection Criteria (TAC Nos. ME5067 

and ME5068).” ADAMS Accession No. ML110660264

Letter from M.J. Ajluni, Southern Nuclear Operating Co., Inc., to the NRC dated June 30, 2011, 

“Vogtle Electric Generating Plant-Unit 1, 1R16 Inservice Inspection Report Summary.” ADAMS 

Accession No. ML111820361

Letter from M.J. Ajluni, Southern Nuclear Operating Co., Inc., to the NRC dated 

September 21, 2011, “Vogtle Electric Generating Plant – Unit 1, Sixteenth 
A-30

Maintenance/Refueling Outage, Steam Generator Tube Inspection Report.” ADAMS Accession 

No. ML112650199

Letter from M.J. Ajluni, Southern Nuclear Operating Co., Inc., to the NRC dated July 30, 2012, 

“Vogtle Electric Generating Plant – Unit 1, Response to Request for Additional Information 

Regarding the 2011 Steam Generator Tube Inspection Summary.” ADAMS Accession 

No. ML12212A335

Letter from R.E. Martin, NRC, to M.J. Ajluni, Southern Nuclear Operating Co., Inc. dated 

September 10, 2012, “Vogtle Electric Generating Plant, Units 1 and 2, Issuance of Amendments 

Regarding Revision to Technical Specifications 5.5.9, ‘Steam Generator (SG) Program,’ and 

5.6.10, ‘Steam Generator Tube Inspection Report,’ (TAC Nos. ME8313 and ME8314).” ADAMS 

Accession No. ML12216A056

Letter from M.J. Ajluni, Southern Nuclear Operating Co., Inc., to the NRC dated 

January 16, 2013, “Vogtle Electric Generating Plant – Unit 1, 1R17 Inservice Inspection Report 

Summary.” ADAMS Accession No. ML13017A377

Letter from C.R. Pierce, Southern Nuclear Operating Co., Inc., to the NRC dated April 2, 2013, 

“Vogtle Electric Generating Plant – Unit 1, Seventeenth Maintenance/Refueling Outage, Steam 

Generator Tube Inspection Report.” ADAMS Accession No. ML13093A178

Letter from R.E. Martin, NRC, to C.R. Pierce, Southern Nuclear Operating Co., Inc., dated 

September 26, 2013, “Vogtle Electric Generating Plant, Units 1 and 2, Farley Nuclear Plant, 

Units 1 and 2, Issuance of Amendments Regarding Steam Generator Tube Inspection Program 

(TAC Nos. MF0564, MF0565, MF0562, and MF0563).” ADAMS Accession No. ML13218B274

Letter from R.E. Martin, NRC, to C.R. Pierce, Southern Nuclear Operating Co., Inc. dated 

December 18, 2013, “Vogtle Electric Generating Plant, Unit 1—Regarding the 2012 Steam 

Generator Tube Inspections (TAC No. MF2343).” ADAMS Accession No. ML13346A152

Letter from C.R. Pierce, Southern Nuclear Operating Co., Inc., to the NRC dated 

October 3, 2014, “Vogtle Electric Generating Plant – Unit 1, Eighteenth Maintenance/Refueling 

Outage, Steam Generator Tube Inspection Report.” ADAMS Accession No. ML14276A430
A-31

Vogtle 2

Letter from J.T. Gasser, Southern Nuclear Operating Co., Inc., to the NRC dated 

October 31, 2002, “Vogtle Electric Generating Plant, Technical Specification Report 2-2002-1, 

Number of Steam Generator Tubes Plugged During 2R9.” ADAMS Accession 

No. ML023110389

Letter from J.T. Gasser, Southern Nuclear Operating Co., Inc., to the NRC dated 

February 4, 2003, “Vogtle Electric Generating Plant, Inservice Inspection Summary Report.” 

ADAMS Accession No. ML030410264

Letter from B.R. Bonser, NRC, to J.T. Gasser Jr., Southern Nuclear Operating Co., Inc., dated 

April 24, 2003, “Vogtle Electric Generating Plant—NRC Integrated Inspection Report 

50-424/03-02 and 50-425/03-02.” ADAMS Accession No. ML031150065

Morning Report—Region II, dated May 3, 2004, “Steam Generator Tubes Degraded.” ADAMS 

Accession No. ML041240281

Morning Report—Region II, dated May 10, 2004, “Steam Generator Tubes Degraded—Update.” 

ADAMS Accession No. ML041310366

Letter from L.M. Stinson, Southern Nuclear Operating Co., Inc., to the NRC dated 

May 20, 2004, “Vogtle Electric Generating Plant, Technical Specification Report 2-2004-1, 

Number of Steam Generator Tubes Plugged During 2R10.” ADAMS Accession 

No. ML041450232

Letter from C. Gratton, NRC, to J.T. Gasser, Southern Nuclear Operating Co., Inc., dated 

June 10, 2004, “Vogtle Electric Generating Plant, Unit 2—Summary of Conference Call with 

Southern Nuclear Operating Co. Regarding the 2004 Steam Generator Tube Inspection Results 

(TAC Nos. MC3046 and MC3047).” ADAMS Accession No. ML041660086

Letter from J.T. Gasser, Southern Nuclear Operating Co., Inc., to the NRC dated 

August 13, 2004, “Vogtle Electric Generating Plant, Inservice Inspection Summary Report.” 

ADAMS Accession No. ML042330493

Morning Report—Region II, dated August 19, 2004, “Steam Generator Tubes Degraded—

Updated.” ADAMS Accession No. ML042320667

Letter from J.T. Gasser, Southern Nuclear Operating Co., Inc., to the NRC dated 

August 26, 2004, “Vogtle Electric Generating Plant, Response to NRC Questions Regarding the 

2002 Unit 2 (2R9) and the 2003 Unit 1 (1R11) Steam Generator Tube Inspection Reports.” 

ADAMS Accession No. ML042430424

Letter from L.M. Stinson, Southern Nuclear Operating Co., Inc., to the NRC dated 

October 25, 2004, “Joseph M. Farley Nuclear Plant, Vogtle Electric Generating Plant, Response 

to NRC Generic Letter 2004-01, ‘Requirements for Steam Generator Tube Inspections.’” 

ADAMS Accession No. ML043010265

Letter from D.E. Grissette, Southern Nuclear Operating Co., Inc., to the NRC dated 

December 21, 2004, “Vogtle Electric Generating Plant, 2R10 Steam Generator Tube Pull Test 

Results.” ADAMS Accession No. ML050060198
A-32

Letter from L.M. Stinson, Southern Nuclear Operating Co., Inc., to the NRC dated 

January 7, 2005, “Joseph M. Farley Nuclear Plant, Vogtle Electric Generating Plant, 

Supplemental Response to NRC Generic Letter 2004-01, ‘Requirements for Steam Generator 

Tube Inspections.’” ADAMS Accession No. ML050110224

Letter from D.E. Grissette, Southern Nuclear Operating Co., Inc., to the NRC dated 

February 24, 2005, “Vogtle Electric Generating Plant, Revised Response to Generic Letter 

97-06, ‘Degradation of Steam Generator Internals.’” ADAMS Accession No. ML050590124

Letter from C. Gratton, NRC, to D.E. Grissette, Southern Nuclear Operating Co., Inc., dated 

June 2, 2005, “Vogtle Electric Generating Station, Unit 2—Review of Steam Generator Tube 

Activities for the Spring 2004 (2R10) Outage (TAC Nos. MC4377, MC3046, and MC3047).” 

ADAMS Accession No. ML051430048

Letter from C. Gratton, NRC, to D.E. Grissette, Southern Nuclear Operating Co., Inc., dated 

September 21, 2005, “Vogtle Electric Generating Plant, Units 1 and 2 Re: Issuance of 

Amendments Regarding the Steam Generator Tube Surveillance Program (TAC Nos. MC8078 

and MC8079).” ADAMS Accession No. ML052630014

Letter from D.E. Grissette, Southern Nuclear Operating Co., Inc., to the NRC dated 

October 20, 2005, “Vogtle Electric Generating Plant, Technical Specification Report 2-2005-1, 

Number of Steam Generator Tubes Plugged During 2R11.” ADAMS Accession 

No. ML052940077

Letter from D.E. Grissette, Southern Nuclear Operating Co., Inc., to the NRC dated 

January 11, 2006, “Vogtle Electric Generating Plant, Inservice Inspection Summary Report.” 

ADAMS Accession No. ML060180170

Letter from D.E. Grissette, Southern Nuclear Operating Co., Inc., to the NRC dated 

August 16, 2006, “Vogtle Electric Generating Plant, Response to NRC Request for Additional 

Information Regarding the 2005 Unit 2 (2R11) Steam Generator Tube Inspection Report.” 

ADAMS Accession No. ML062290288

Letter from C. Gratton, NRC, to D.E. Grissette, Southern Nuclear Operating Co., Inc., dated 

August 28, 2006, “Vogtle Electric Generating Plant, Units 1 and 2, Issuance of Amendments

Regarding Steam Generator Tube Integrity (TAC Nos. MD1075 and MD1076).” ADAMS 

Accession No. ML062360577

Letter from C. Gratton, NRC, to D.E. Grissette, Southern Nuclear Operating Co., Inc., dated 

September 12, 2006, “Vogtle Electric Generating Plant, Units 1 and 2, Issuance of Amendments 

Regarding the Steam Generator Tube Surveillance Program (TAC Nos. MD2642 and 

MD2643).” ADAMS Accession No. ML062260302

Letter from B.J. George, Southern Nuclear Operating Co., Inc., to the NRC dated 

October 12, 2007, “Vogtle Electric Generating Plant Unit 2, Twelfth Maintenance/Refueling 

Outage, Steam Generator Tube Inspection Report.” ADAMS Accession No. ML072880102

Letter from D.H. Jones, Southern Nuclear Operating Co., Inc., to the NRC dated 

February 25, 2008, “Vogtle Electric Generating Plant, Response to NRC Request for Additional 
A-33

Information Regarding the 2007 Unit 2 (2R12) Steam Generator Tube Inspections.” ADAMS 

Accession No. ML080570195

Letter from R.E. Martin, NRC, to T.E. Tynan, Southern Nuclear Operating Co., Inc., dated 

September 16, 2008, “Vogtle Electric Generating Plant, Units 1 and 2, Issuance of Amendments 

Regarding Steam Generator Tube Inspection Program (TAC Nos. MD9148 and MD9149).” 

ADAMS Accession No. ML082530038

Letter from M.J. Ajluni, Southern Nuclear Operating Co., Inc., to the NRC dated April 9, 2009, 

“Vogtle Electric Generating Plant – Unit 2, Thirteenth Maintenance/Refueling Outage, Steam 

Generator Tube Inspection Report.” ADAMS Accession No. ML090990606

Letter from D.N. Wright, NRC, to M.J. Ajluni, Southern Nuclear Operating Co., Inc., dated 

September 24, 2009, “Vogtle Electric Generating Plant, Units 1 and 2, Issuance of Amendments 

Regarding Technical Specification (TS) Section 5.5.9, ‘Steam Generator Program,’ and 

TS 5.6.10, ‘Steam Generator Tube Inspection Report,’ for Interim Alternate Repair Criteria (TAC 

Nos. ME1339 and ME1340).” ADAMS Accession No. ML092170782

Letter from M.J. Ajluni, Southern Nuclear Operating Co., Inc., to the NRC dated 

September 28, 2010, “Vogtle Electric Generating Plant – Unit 2, Fourteenth 

Maintenance/Refueling Outage, Steam Generator Tube Inspection Report.” ADAMS Accession 

No. ML102710369

Letter from P.G. Boyle, NRC, to M.J. Ajluni, Southern Nuclear Operating Co., Inc., dated 

March 14, 2011, “Vogtle Electric Generating Plant, Units 1 and 2, Issuance of Amendments 

Regarding Steam Generator Tube Inspection Alternate Inspection Criteria (TAC Nos. ME5067 

and ME5068).” ADAMS Accession No. ML110660264

Letter from P.G. Boyle, NRC, to M.J. Ajluni, Southern Nuclear Operating Co., Inc., dated 

April 26, 2011, “Vogtle Electric Generating Plant, Unit 2 (Vogtle 2)—Review of the 

2010 Refueling Outage Steam Generator Tube Inservice Inspection Report (TAC 

No. ME4842).” ADAMS Accession No. ML11101A083

Letter from M.J. Ajluni, Southern Nuclear Operating Co., Inc., to the NRC dated 

January 10, 2012, “Vogtle Electric Generating Plant – Unit 2, 2R15 Inservice Inspection Report 

Summary.” ADAMS Accession No. ML120110136

Letter from M.J. Ajluni, Southern Nuclear Operating Co., Inc., to the NRC dated March 30, 2012, 

“Vogtle Electric Generating Plant – Unit 2, Fifteenth Maintenance/Refueling Outage, Steam 

Generator Tube Inspection Report.” ADAMS Accession No. ML12093A048

Letter from M.J. Ajluni, Southern Nuclear Operating Co., Inc., to the NRC dated 

August 29, 2012, “Vogtle Electric Generating Plant – Unit 2, Response to Request for Additional 

Information Regarding the 2011 Steam Generator Tube Inspections.” ADAMS Accession 

No. ML12243A249

Letter from R.E. Martin, NRC, to M.J. Ajluni, Southern Nuclear Operating Co., Inc., dated 

September 10, 2012, “Vogtle Electric Generating Plant, Units 1 and 2, Issuance of Amendments 

Regarding Revision to Technical Specifications 5.5.9, ‘Steam Generator (SG) Program,’ and 

5.6.10, ‘Steam Generator Tube Inspection Report,’ (TAC Nos. ME8313 and ME8314).” ADAMS 

Accession No. ML12216A056
A-34

Letter from R.E. Martin, NRC, to M.J. Ajluni, Southern Nuclear Operating Co., Inc., dated 

April 25, 2013, “Vogtle Electric Generating Plant, Unit 2—Conference Calls Summary Regarding 

the Spring 2013 Steam Generator Tube Inspections (TAC No. MF0736).” ADAMS Accession 

No. ML13112A225

Letter from C.R. Pierce, Southern Nuclear Operating Co., Inc., to the NRC dated July 2, 2013, 

“Vogtle Electric Generating Plant – Unit 2, 2R16 Inservice Inspection Report Summary.” 

ADAMS Accession No. ML13184A269

Letter from C.R. Pierce, Southern Nuclear Operating Co., Inc., to the NRC dated 

September 26, 2013, “Vogtle Electric Generating Plant – Unit 2, Sixteenth 

Maintenance/Refueling Outage, Steam Generator Tube Inspection Report.” ADAMS Accession 

No. ML14170A021

Letter from R.E. Martin, NRC, to C.R. Pierce, Southern Nuclear Operating Co., Inc. dated 

September 26, 2013, “Vogtle Electric Generating Plant, Units 1 and 2, Farley Nuclear Plant, 

Units 1 and 2, Issuance of Amendments Regarding Steam Generator Tube Inspection Program 

(TAC Nos. MF0564, MF0565, MF0562, and MF0563).” ADAMS Accession No. ML13218B274

Letter from C.R. Pierce, Southern Nuclear Operating Co., Inc., to the NRC dated 

January 12, 2015, “Vogtle Electric Generating Plant, Unit 2, Response to ‘Request for Additional 

Information on Spring 2013 Steam Generator Tube Inspections (TAC No. MF4288).’” ADAMS 

Accession No. ML15013A023

Letter from C.R. Pierce, Southern Nuclear Operating Co., Inc., to the NRC dated 

February 23, 2015, “Vogtle Electric Generating Plant – Unit 2, Clarification of Response to 

‘Request for Additional Information on Spring 2013 Steam Generator Tube Inspections (TAC 

No. MF4288).’” ADAMS Accession No. ML15054A536
A-35

Wolf Creek

Letter from R.A. Muench, Wolf Creek Nuclear Operating Corp., to the NRC dated April 21, 2002, 

“Docket No. 50-482: Steam Generator Tube Plugging Report.” ADAMS Accession 

No. ML021220567

Preliminary Notification of Event or Unusual Occurrence – PNO-IV-02-023 dated May 16, 2002, 

“Unplanned Shutdown Due to Loose Part in Steam Generator D.” ADAMS Accession 

No. ML021360620

Memorandum from J.N. Donohew, NRC to Docket File dated August 27, 2002, “Response to 

Request for Information on Loose Parts Found in the Steam Generator at Wolf Creek 

Generating Station.” ADAMS Accession No. ML022340708

Letter from G.B. Fader, Wolf Creek Nuclear Operating Corp., to the NRC dated 

December 11, 2002, “Docket No. 50-482: Results of the Eleventh Steam Generator Tube 

Inservice Inspection.” ADAMS Accession No. ML030020006

Letter from K.L. Scherich, Wolf Creek Nuclear Operating Corp., to the NRC dated July 23, 2003, 

“Docket No. 50-482: Response to Follow-up Questions Concerning the Results of the Eleventh 

Steam Generator Tube Inservice Inspection.” ADAMS Accession No. ML032130386

Letter from B.T. McKinney, Wolf Creek Nuclear Operating Corp., to the NRC dated 

November 10, 2003, “Docket No. 50-482: Steam Generator Tube Plugging Report.” ADAMS 

Accession No. ML033240355

Letter from R.A. Muench, Wolf Creek Nuclear Operating Corp., to the NRC dated 

October 27, 2004, “Docket No. 50-482: Response to NRC Generic Letter 2004-01.” ADAMS 

Accession No. ML043070595

Letter from R.A. Muench, Wolf Creek Nuclear Operating Corp., to the NRC dated 

October 27, 2004, “Docket No. 50-482: Results of the Twelfth Steam Generator Tube Inservice 

Inspection.” ADAMS Accession No. ML043080306

Letter from J.N. Donohew, NRC, to R.A. Muench, Wolf Creek Nuclear Operating Corp. dated 

April 28, 2005, “Wolf Creek Generating Station—Issuance of Exigent Amendment Re: Steam 

Generator (SG) Tube Surveillance Program (TAC No. MC6757).” ADAMS Accession 

No. ML051230044

Letter from T.J. Garrett, Wolf Creek Nuclear Operating Corp., to the NRC dated May 4, 2005, 

“Docket No. 50-482: Steam Generator Tube Plugging Report.” ADAMS Accession 

No. ML051370402

Letter from T.J. Garrett, Wolf Creek Nuclear Operating Corp., to the NRC dated July 14, 2005, 

“Docket No. 50-482: Wolf Creek Nuclear Operating Corp.’s (WCNOC’s) Response to Request 

for Additional Information Regarding the Steam Generator Tube Inspection Summary Reports 

for the Fall 2003 Outage (TAC No. MC5022).” ADAMS Accession No. ML052080042

Letter from T.J. Garrett, Wolf Creek Nuclear Operating Corp., to the NRC dated April 14, 2006, 

“Docket No. 50-482: Results of the Thirteenth Steam Generator Tube Inservice Inspection.” 

ADAMS Accession. No. ML061100519
A-36

Letter from J.N. Donohew, NRC, to R.A. Muench, Wolf Creek Nuclear Operating Corp. dated 

May 8, 2006, “Wolf Creek Generating Station—Issuance of Amendment Regarding Steam 

Generator Tube Integrity Using the Consolidated Line Item Improvement Process (TAC 

Nos. MC8842 and MD0122).” ADAMS Accession No. ML061280189

Letter from J.N. Donohew, NRC, to R.A. Muench, Wolf Creek Nuclear Operating Corp. dated 

October 10, 2006, “Wolf Creek Generating Station—Issuance of Amendment Re: Steam 

Generator Tube Inspections within the Tubesheet (TAC No. MD2467).” ADAMS Accession 

No. ML062580016

Letter from T.J. Garrett, Wolf Creek Nuclear Operating Corp., to the NRC dated 

November 7, 2006, “Docket No. 50-482: Response to Request for Additional Information 

Concerning the Results of the Thirteenth Steam Generator Tube Inservice Inspection.” ADAMS 

Accession No. ML063190301

Letter from K.J. Moles, Wolf Creek Nuclear Operating Corp., to the NRC dated 

January 31, 2007, “Docket No. 50-482: Inservice Inspection Program Third Interval, First Period, 

Refueling Outage 15 Owner’s Activity Report.” ADAMS Accession No. ML070430458

Letter from T.J. Garrett, Wolf Creek Nuclear Operating Corp., to the NRC dated 

March 19, 2007, “Docket No. 50-482: Results of the Fourteenth Steam Generator Tube 

Inservice Inspection.” ADAMS Accession No. ML070860222

Letter from T.J. Garrett, Wolf Creek Nuclear Operating Corp., to the NRC dated 

February 28, 2008, “Docket No. 50-482: Response to Request for Additional Information 

Concerning the Results of the Fourteenth Steam Generator Tube Inservice Inspection (TAC 

No. MD5946).” ADAMS Accession No. ML080660359

Letter from J.N. Donohew, NRC, to R.A. Muench, Wolf Creek Nuclear Operating Corp. dated 

April 4, 2008, “Wolf Creek Generating Station—Issuance of Amendment Re: Revision to 

Technical Specification 5.5.9 on the Steam Generator Program (TAC No. MD8054).” ADAMS 

Accession No. ML080840003

Letter from B.K. Singal, NRC, to R.A. Muench, Wolf Creek Nuclear Operating Corp. dated 

May 8, 2008, “Wolf Creek Generating Station—Summary of Conference Call Regarding the 

Spring 2008 Steam Generator Tube inspections During Refueling Outage 16 (TAC 

No. MD8099).” ADAMS Accession No. ML081280305

Letter from T.J. Garrett, Wolf Creek Nuclear Operating Corp., to the NRC dated 

October 27, 2008, “Docket No. 50-482: Results of the Fifteenth Steam Generator Tube 

Inservice Inspection.” ADAMS Accession No. ML083090879

Letter from T.J. Garrett, Wolf Creek Nuclear Operating Corp., to the NRC dated 

January 29, 2009, “Docket No. 50-482: Response to Request for Additional Information 

Concerning the Results of the Fifteenth Steam Generator Tube Inservice Inspection.” ADAMS 

Accession No. ML090430507

Letter from B.K. Singal, NRC, to R.A. Muench, Wolf Creek Nuclear Operating Corp. dated 

October 19, 2009, “Wolf Creek Generating Station—Issuance of Amendment Re: Revision to 

Technical Specification (TS) 5.5.9, ‘Steam Generator (SG) Program,’ and TS 5.6.10, ‘Steam 
A-37

Generator Tube Inspection Report’ for Alternate Repair Criteria (TAC No. ME1393).” ADAMS 

Accession No. ML092750606

Letter from T.J. Garrett, Wolf Creek Nuclear Operating Corp., to the NRC dated 

October 25, 2009, “Docket No. 50-482: Notification of Deviation from EPRI Pressurized Water 

Reactor Secondary Water Chemistry Guidelines.” ADAMS Accession No. ML093080013

Letter from T.J. Garrett, Wolf Creek Nuclear Operating Corp., to the NRC dated April 8, 2010, 

“Docket No. 50-482: Results of the Sixteenth Steam Generator Tube Inservice Inspection.” 

ADAMS Accession No. ML101100676

Letter from T.J. Garrett, Wolf Creek Nuclear Operating Corp., to the NRC dated July 15, 2010, 

“Docket No. 50-482: Response to Request for Additional Information Regarding the Sixteenth 

Steam Generator Tube Inservice Inspection.” ADAMS Accession No. ML102080031

Letter from J.R. Hall, NRC, to M.W. Sunseri, Wolf Creek Nuclear Operating Corp. dated 

April 6, 2011, “Wolf Creek Generating Station—Issuance of Amendment Re: Changes to 

Technical Specification (TS) 5.5.9, ‘Steam Generator (SG) Program,’ and TS 5.6.10, ‘Steam 

Generator Tube Inspection Report,’ (TAC No. ME5121).” ADAMS Accession No. ML110840590

Letter from R.P. Clemens, Wolf Creek Nuclear Operating Corp., to the NRC dated 

October 19, 2011, “Docket No. 50-482: Results of the Seventeenth Steam Generator Tube 

Inservice Inspection.” ADAMS Accession No. ML11298A261

Letter from T.A. Beltz, NRC, to M.W. Sunseri, Wolf Creek Nuclear Operating Corp. dated 

August 3, 2012, “Wolf Creek Generating Station—Review of the 2011 Steam Generator Tube 

Inspections During Refueling Outage 18 (TAC No. ME7755).” ADAMS Accession 

No. ML12137A280

Letter from C.F. Lyon, NRC, to M.W. Sunseri, Wolf Creek Nuclear Operating Corp. dated 

November 19, 2012, “Wolf Creek Generating Station—Issuance of Amendment Re: Adoption of 

TSTF-510, Revision 2, ‘Revision to Steam Generator Program Inspection Frequencies and 

Tube Sample Selection,’ Using the Consolidated Line Item Improvement Process (TAC 

No. ME8569).” ADAMS Accession No. ML12289A896

Letter from C.F. Lyon, NRC, to M.W. Sunseri, Wolf Creek Nuclear Operating Corp. dated 

December 11, 2012, “Wolf Creek Generating Station—Issuance of Amendment Re: Steam 

Generator Tube Permanent Alternate Repair Criteria (TAC No. ME8350).” ADAMS Accession 

No. ML12300A309

Letter from C.F. Lyon, NRC, to M.W. Sunseri, Wolf Creek Nuclear Operating Corp. dated 

April 1, 2013, “Wolf Creek Generating Station—Summary of Steam Generator Conference Calls 

For Refueling Outage 19 (TAC No. MF0736).” ADAMS Accession No. ML13077A073

Letter from J.P. Broschak, Wolf Creek Nuclear Operating Corp., to the NRC dated 

September 30, 2013, “Docket No. 50-482: Results of the Eighteenth Steam Generator Tube 

Inservice Inspection.” ADAMS Accession No. ML13277A558

Letter from J.P. Broschak, Wolf Creek Nuclear Operating Corp., to the NRC dated 

February 6, 2014, “Docket No. 50-482: Response to Request for Additional Information 

Regarding the 2013 Steam Generator Inspections.” ADAMS Accession No. ML14049A286
A-38

Indian Point 2

Letter from F. Dacimo, Entergy Nuclear Operations, Inc., to the NRC dated August 21, 2002, 

“Proposed Steam Generator Examination Program – 2002 Refueling Outage (2R15).” ADAMS 

Accession No. ML022390099

Letter from F. Dacimo, Entergy Nuclear Operations, Inc., to the NRC dated December 19, 2002, 

“Steam Generator Inservice Examination Program Results, 2002 Refueling Outage (2R15).” 

ADAMS Accession No. ML023580031

Letter from M.R. Kansler, Entergy Nuclear Operations, Inc., to the NRC dated October 21, 2003, 

“Indian Point Nuclear Generating Unit No. 2, Docket No. 50-247, Proposed Change to Technical 

Specifications: One-Time Change to the Indian Point 2 Steam Generator Tube Inspection 

Requirements.” ADAMS Accession No. ML032960328

Letter from M.R. Kansler, Entergy Nuclear Operations, Inc., to the NRC dated March 31, 2004, 

“Indian Point Nuclear Generating Unit No. 2, Docket No. 50-247, Response to NRC Request for 

Additional Information Re: ‘Proposed Change to Technical Specifications: One-Time Change to 

the Indian Point 2 Steam Generator Tube Inspection Requirements (TAC No. MC1260).’” 

ADAMS Accession No. ML040930142

Letter from P.D. Milano, NRC, to M.R. Kansler, Entergy Nuclear Operations, Inc., dated 

June 23, 2004, “Indian Point Nuclear Generating Unit No. 2—Amendment Re: One-Time 

Change to Steam Generator Tube Inspection Interval (TAC No. MC1260).” ADAMS Accession 

No. ML041750603

Letter from M.R. Kansler, Entergy Nuclear Operations, Inc., to the NRC dated October 27, 2004, 

“Indian Point Nuclear Generating Unit No. 2, Docket No. 50-247, Indian Point Nuclear 

Generating Unit No. 3, Docket No. 50-286, 60-Day Response to Generic Letter 2004-01, 

‘Requirements for Steam Generator Tube Inspections.’” ADAMS Accession No. ML043070599

Letter from P.W. Conroy, Entergy Nuclear Operations, Inc., to the NRC dated 

February 13, 2006, “Proposed Steam Generator Examination Program – 2006 Refueling 

Outage (2R17).” ADAMS Accession No. ML060530378

Letter from P.W. Conroy, Entergy Nuclear Operations, Inc., to the NRC dated March 29, 2006, 

“Reply to Request for Additional Information Regarding Indian Point 2 Steam Generator 

Examination Program for 2R17 (TAC No. MD0213).” ADAMS Accession No. ML061000616

“Condition Monitoring and Operational Assessment of Indian Point 2 Steam Generator Tubing 

for Cycles 18 and 19,” dated May 9, 2006. ADAMS Accession No. ML081200225

Letter from F. Dacimo, Entergy Nuclear Operations, Inc., to the NRC dated June 14, 2006, 

“Steam Generator Examination Program Results, 2006 Refueling Outage (2R17).” ADAMS 

Accession No. ML061780303

Letter from F.R. Dacimo, Entergy Nuclear Operations, Inc., to the NRC dated 

November 15, 2006, “Reply to Request for Additional Information Regarding Steam Generator 

Examination Results for 2006 Refueling Outage (TAC No. MD2783).” ADAMS Accession 

No. ML063240144
A-39

Letter from J.P. Boska, NRC, to M.R. Kansler, Entergy Nuclear Operations, Inc., dated 

February 13, 2007, “Indian Point Nuclear Generating Unit Nos. 2 and 3—Issuance of 

Amendments Re: Steam Generator Tube Integrity Technical Specification Based on Technical 

Specification Task Force (TSTF) Document TSTF-449, ‘Steam Generator Tube Integrity’ (TAC 

Nos. MD0083, MD0084, MD2178, and MD2179).” ADAMS Accession No. ML063450333

Letter from F.R. Dacimo, Entergy Nuclear Operations, Inc., to the NRC dated January 4, 2008, 

“Reply to Request for Additional Information Regarding License Renewal Application—(Steam 

Generator Tube Integrity and Chemistry).” ADAMS Accession No. ML080160123

Letter from R. Walpole, Entergy Nuclear Operations, Inc., to the NRC dated October 20, 2008, 

“Technical Specification 5.6.7—Steam Generator Tube Inspection Report—Spring 2008 

Refueling Outage.” ADAMS Accession No. ML083030054

Letter from R. Walpole, Entergy Nuclear Operations, Inc., to the NRC dated August 24, 2010, 

“Technical Specification 5.6.7—IP2 Steam Generator Tube Inspection Report—Spring 2010 

Refueling Outage; Indian Point Unit No. 2; Docket No. 50-247; License No. DPR-26.” ADAMS 

Accession No. ML102440036

Letter from R. Walpole, Entergy Nuclear Operations, Inc., to the NRC dated February 16, 2011, 

“Response to Request for Additional Information on IP2 Steam Generator Inspection Report; 

Indian Point Unit Number 2; Docket No. 50-247; License No. DPR-26.” ADAMS Accession 

No. ML110550188

Letter from R. Walpole, Entergy Nuclear Operations, Inc., to the NRC dated April 3, 2012, 

“Technical Specification 5.6.7—IP2 Steam Generator Tube Inspection Report—Spring 2012 

Refueling Outage; Indian Point Unit No. 2; Docket No. 50-247; License No. DPR-26.” ADAMS 

Accession Nos. ML12103A168 and ML12108A050

Letter from D.V. Pickett, NRC, to Entergy Nuclear Operations, Inc. dated September 5, 2014, 

“Indian Point Nuclear Generating Unit No. 2—Issuance of Amendment Re: H* Alternate Repair 

Criteria for Steam Generator Tube Inspection and Repair (TAC No. MF3369).” ADAMS 

Accession No. ML14198A161

Letter from J.A. Ventosa, Entergy Nuclear Operations, Inc., to the NRC dated 

September 8, 2014, “Steam Generator Examination Program Results 2014 Refueling Outage 

(2R21); Indian Point Unit No. 2; Docket No. 50-247; License No. DPR-26.” ADAMS Accession 

No. ML14262A059

Letter from D.V. Pickett, NRC, to Entergy Nuclear Operations, Inc. dated September 30, 2014, 

“Indian Point Nuclear Generating Unit No. 2—Correction Letter to Amendment No. 277 Re: H* 

Alternate Repair Criteria for Steam Generator Tube Inspection and Repair (TAC No. MF3369).” 

ADAMS Accession No. ML14252A679
A-40

Point Beach 1

Letter from G.D. Van Middlesworth, Nuclear Management Co., LLC, to the NRC dated 

June 10, 2004, “Summary of Spring 2004 Unit 1 (U1R28) Steam Generator Examinations.” 

ADAMS Accession No. ML041740744 

Letter from D.L. Koehl, Nuclear Management Co., LLC, to the NRC dated October 29, 2004, 

“60-Day Response to Generic Letter 2004-01, ‘Requirements for Steam Generator Tube 

Inspections.’” ADAMS Accession No. ML043100523

Letter from D.L. Koehl, Nuclear Management Co., LLC, to the NRC dated January 6, 2005, 

“Response to Request for Additional Information Regarding the Point Beach Nuclear Plant 

License Renewal Application (TAC Nos. MC2099 and MC2100).” ADAMS Accession 

No. ML050180203

Letter from D.L. Koehl, Nuclear Management Co., LLC, to the NRC dated March 4, 2005, 

“Supplement to Spring 2004 Unit 1 (U1R28) Steam Generator Examination Report.” ADAMS 

Accession No. ML050830168

Letter from D.L. Koehl, Nuclear Management Co., LLC, to the NRC dated February 21, 2006, 

“Fall 2005 Unit 1 (U1R29) Steam Generator Tube Inspection Report.” ADAMS Accession 

No. ML060600189

Letter from D.L. Koehl, Nuclear Management Co., LLC, to the NRC dated July 14, 2006, 

“Response to Request for Additional Information, Fall 2005 Unit 1 (U1R29) Steam Generator 

Tube Inspection Report.” ADAMS Accession No. ML061980407

Letter from C.F. Lyon, NRC, to D.L. Koehl, Nuclear Management Co., LLC dated 

August 22, 2006, “Point Beach Nuclear Plant, Units 1 and 2—Issuance of Amendments Re: 

Steam Generator Tube Integrity (TAC Nos. MD0194 and MD0195).” ADAMS Accession 

No. ML062050312

Letter from C.F. Lyon, NRC, to D.L. Koehl, Nuclear Management Co., LLC dated 

September 18, 2006, “Point Beach Nuclear Plant, Units 1 and 2—Correction to Amendments 

Re: Steam Generator Tube Integrity (TAC Nos. MD0194 and MD0195).” ADAMS Accession 

No. ML062440008

Letter from P.D. Milano, NRC, to D.L. Koehl, Nuclear Management Co., LLC dated 

April 4, 2007, “Point Beach Nuclear Plant, Unit 1—Issuance of Amendment Re: Steam 

Generator Tube Repair in the Tubesheet (TAC No. MD2583).” ADAMS Accession 

No. ML070800705

Letter from J.H. McCarthy, FPL Energy Point Beach, LLC, to the NRC dated October 25, 2007, 

“Spring 2007 Unit 1 (U1R30), Steam Generator Tube Inspection Report.” ADAMS Accession 

No. ML072990108

Letter from J.H. McCarthy, FPL Energy Point Beach, LLC, to the NRC dated March 14, 2008, 

“Response to Request for Additional Information, Spring 2007 Unit 1 (U1R30), Steam Generator 

Tube Inspection Report.” ADAMS Accession No. ML080770187
A-41

Letter from J. Cushing, NRC, to L. Myer, FPL Energy Point Beach, LLC. dated October 7, 2008, 

“Point Beach Nuclear Plant, Unit 1—Issuance of Amendment Re: Technical Specification 5.5.8 

and 5.6.8 (TAC No. MD8800).” ADAMS Accession No. ML082540876

Memorandum from J. Cushing, NRC, to File dated November 20, 2008, “Point Beach Nuclear 

Plant, Unit 1—Teleconference Summary Regarding the 2008 Steam Generator Tube Inspection 

Results (TAC No. MD9468).” ADAMS Accession No. ML083230820

Letter from J. Costedio, NextEra Energy Point Beach, LLC, to the NRC dated May 7, 2009, 

“Fall 2008 Unit 1 (U1R31), Steam Generator Tube Inspection Report.” ADAMS Accession 

No. ML091280187

Letter from J. Costedio, NextEra Energy Point Beach, LLC, to the NRC dated October 16, 2009, 

“Response to Request for Additional Information, Fall 2008 Unit 1 (U1R31), Steam Generator 

Tube Inspection Report.” ADAMS Accession No. ML092890472

Letter from T. Beltz, NRC, to NextEra Energy Point Beach, LLC, dated December 7, 2011, 

“Point Beach Nuclear Plant, Unit 1—Summary of Conference Call Regarding Steam Generator 

Tube Inspections During Fall 2011 Refueling Outage (TAC No. ME7140).” ADAMS Accession 

No. ML113270240

Letter from J. Costedio, NextEra Energy Point Beach, LLC, to the NRC dated May 29, 2012, 

“Fall 2011 Unit 1 (U133), Steam Generator Tube Inspection Report.” ADAMS Accession 

No. ML12150A287

Letter from J. Costedio, NextEra Energy Point Beach, LLC, to the NRC dated 

September 25, 2012, “Response to Request for Additional Information, Fall 2011 Unit 1 

(U1R33), Steam Generator Tube Inspection Report.” ADAMS Accession No. ML12270A037

Letter from M. Millen, NextEra Energy Point Beach, LLC, to the NRC dated January 31, 2013, 

“Fall 2011 Unit 1 Refueling Outage (U1R33), Steam Generator Tube Inspection Report.” 

ADAMS Accession No. ML13031A353

Letter from M. Millen, NextEra Energy Point Beach, LLC, to the NRC dated 

September 24, 2013, “Spring 2013 Unit 1 (U1R34), Steam Generator Tube Inspection Report.” 

ADAMS Accession No. ML13268A108

Letter from M. Millen, NextEra Energy Point Beach, LLC, to the NRC dated March 3, 2014, 

“Response to Request for Additional Information, Spring 2013 Unit 1 (U1R34), Steam Generator 

Tube Inspection Report.” ADAMS Accession No. ML14062A047
A-42

Robinson 2

Letter from C.T. Baucom, Carolina Power—Light Co., to the NRC dated November 11, 2002, 

“H.B. Robinson Steam Electric Plant, Unit No. 2, Docket No. 50-261/License No. DPR-23; 

Steam Generator Tube Plugging During Refueling Outage 21.” ADAMS Accession 

No. ML023170211

Letter from C.T. Baucom, Carolina Power & Light Co., to the NRC dated November 14, 2002, 

“H.B. Robinson Steam Electric Plant, Unit No. 2, Docket No. 50-261/License No. DPR-23; 

Monthly Operating Report.” ADAMS Accession No. ML023220203

Letter from C.T. Baucom, Carolina Power & Light Co., to the NRC dated February 11, 2003, 

“H.B. Robinson Steam Electric Plant, Unit No. 2, Docket No. 50-261/License No. DPR-23; 

Submittal of 90 Day Inservice Inspection Summary Report.” ADAMS Accession 

No. ML030440106

Letter from C.T. Baucom, Carolina Power & Light Co., to the NRC dated July 16, 2003, “H.B. 

Robinson Steam Electric Plant, Unit No. 2, Docket No. 50-261/License No. DPR-23; Response 

to NRC Request for Additional Information on the Steam Generator Inservice Inspection 

Results.” ADAMS Accession No. ML032020119

Letter from C.T. Baucom, Carolina Power & Light Co., to the NRC dated May 18, 2004, “H.B. 

Robinson Steam Electric Plant, Unit No. 2, Docket No. 50-261/License No. DPR-23; Steam 

Generator Tube Plugging Report for Refueling Outage 22.” ADAMS Accession 

No. ML041460268

Letter from C.T. Baucom, Carolina Power & Light Co., to the NRC dated June 15, 2004, 

“H.B. Robinson Steam Electric Plant, Unit No. 2, Docket No. 50-261/License No. DPR-23; 

Monthly Operating Report.” ADAMS Accession No. ML041680442

Letter from C.T. Baucom, Carolina Power & Light Co., to the NRC dated August 26, 2004, “H.B. 

Robinson Steam Electric Plant, Unit No. 2, Docket No. 50-261/License No. DPR-23; Submittal 

of 90 Day Inservice Inspection Summary Report.” ADAMS Accession No. ML042430598

Letter from J.F. Lucas, Carolina Power & Light Co., to the NRC dated October 28, 2004, 

“H.B. Robinson Steam Electric Plant, Unit No. 2, Docket No. 50-261/License No. DPR-23; 

Response to NRC Generic Letter 2004-01, ‘Requirements for Steam Generator Tube 

Inspections.’” ADAMS Accession No. ML043070395

Letter from C.P. Patel, NRC, to J.W. Moyer, Carolina Power & Light Co. dated 

December 20, 2004, “Summary of Conference Call with Carolina Power & Light Co. on the H.B. 

Robinson Unit No. 2 Spring 2004 Steam Generator Inspections (TAC No. MC3038).” ADAMS 

Accession No. ML043640546

Letter from C.T. Baucom, Carolina Power & Light Co., to the NRC dated May 25, 2005, “H.B. 

Robinson Steam Electric Plant, Unit No. 2, Docket No. 50-261/License No. DPR-23; Response 

to NRC Request for Additional Information on the Steam Generator Inservice Inspection Results 

(TAC No. MC4588).” ADAMS Accession No. ML051470117

Letter from C.T. Baucom, Carolina Power & Light Co., to the NRC dated January 16, 2006, 

“H.B. Robinson Steam Electric Plant, Unit No. 2, Docket No. 50-261/License No. DPR-23; 
A-43

Submittal of 90 Day Inservice Inspection Summary Report.” ADAMS Accession 

No. ML060240260

Letter from C.P. Patel, NRC to T.D. Walt, Carolina Power & Light Co. dated March 12, 2007, 

“H.B. Robinson Steam Electric Plant, Unit No. 2—Issuance of an Amendment—Steam 

Generator Tube Integrity (TAC No. MD2136).” ADAMS Accession No. ML070510368

Letter from C.P. Patel, NRC to T.D. Walt, Carolina Power & Light Co. dated April 9, 2007, 

“H.B. Robinson Steam Electric Plant, Unit No. 2—Issuance of an Amendment on Steam 

Generator Tube Repair in the Tubesheet (TAC No. MD4046).” ADAMS Accession 

No. ML071060259

Letter from C.T. Baucom, Carolina Power & Light Co., to the NRC dated August 2, 2007, 

“H.B. Robinson Steam Electric Plant, Unit No. 2, Docket No. 50-261/License No. DPR-23; 

Submittal of 90 Day Inservice Inspection Summary Report.” ADAMS Accession 

No. ML072250364

Letter From C. Castell, Carolina Power & Light Co., to the NRC dated November 1, 2007, 

“H.B. Robinson Steam Electric Plant, Unit No. 2, Docket No. 50-261/License No. DPR-23; 

Steam Generator Tube Inspection Report.” ADAMS Accession No. ML073110281

Letter From C. Castell, Carolina Power & Light Co., to the NRC dated April 30, 2008, 

“H.B. Robinson Steam Electric Plant, Unit No. 2, Docket No. 50-261/License No. DPR-23; 

Response to NRC Request for Additional Information on the Steam Generator Inservice 

Inspection Results.” ADAMS Accession No. ML081270049

Letter From C. Castell, Carolina Power & Light Co., to the NRC dated June 24, 2008, 

“H.B. Robinson Steam Electric Plant, Unit No. 2, Docket No. 50-261/License No DPR-23; 

Response to NRC Request for Additional Information on the Steam Generator Inservice 

Inspection Results.” ADAMS Accession No. ML081790164

Letter from M. Vaaler, NRC, to T.D. Walt, Carolina Power & Light Co. dated July 10, 2008, 

“H.B. Robinson Steam Electric Plant, Unit No. 2—Review of the Spring 2007 Refueling Outage

24 Steam Generator Tube Inspection Report (TAC No. MD7311).” ADAMS Accession 

No. ML081900019

Letter from C.A. Castell, Carolina Power & Light Co., to the NRC dated February 11, 2009, 

“H.B. Robinson Steam Electric Plant, Unit No. 2, Docket No. 50-261/License No. DPR-23; 

Submittal of 90 Day Inservice Inspection Summary Report.” ADAMS Accession 

No. ML090500831

Letter from C.A. Castell, Carolina Power & Light Co., to the NRC dated September 22, 2010, 

“H.B. Robinson Steam Electric Plant, Unit No. 2, Docket No. 50-261/License No. DPR-23; 

Submittal of 90 Day Inservice Inspection Summary Report.” ADAMS Accession 

No. ML102730790

Letter from C. Castell, Carolina Power & Light Co., to the NRC dated January 13, 2011, 

“H.B. Robinson Steam Electric Plant, Unit No. 2, Docket No. 50-261/License No. DPR-23; 

Steam Generator Tube Inspection Report.” ADAMS Accession No. ML110190222
A-44

Letter from R. J. Rogalski, Carolina Power & Light Co., to the NRC dated October 26, 2011, 

“H.B. Robinson Steam Electric Plant, Unit No. 2, Docket No 50-261/Renewed License 

No. DPR-23; Response to NRC Request for Additional Information Regarding H.B. Robinson 

Steam Generator Tube Report Dated January 13, 2011.” ADAMS Accession No. ML11305A077

Letter from W.R. Hightower, Carolina Power & Light Co., to the NRC dated June 15, 2012, “H.B. 

Robinson Steam Electric Plant, Unit No. 2, Docket No. 50-261/Renewed License No. DPR-23; 

Submittal of 90 Day Inservice Inspection Summary Report.” ADAMS Accession 

No. ML12184A040

Letter from S.P. Lingam, NRC, to W.G. Gideon, Duke Energy Progress, Inc. dated 

December 13, 2013, “H.B. Robinson Steam Electric Plant Unit 2—Summary of Conference Call 

Regarding the Fall 2013 Steam Generator Tube Inservice Inspections (TAC No. MF2941).” 

ADAMS Accession No. ML13333B555

Letter from W.R. Gideon, Duke Energy Progress, Inc., to the NRC dated January 30, 2014, 

“H.B. Robinson Steam Electric Plant, Unit No. 2, Docket No. 50-261/Renewed License 

No. DPR-23; Submittal of Ninety Day Inservice Inspection Summary Report.” ADAMS 

Accession No. ML14037A230

Preliminary Notification—PNO-II-14-004 dated March 10, 2014. ADAMS Accession 

No. ML14069A350

Preliminary Notification—PNO-II-14-004 dated April 7, 2014. ADAMS Accession 

No. ML14098A323

Letter from S.W. Peavyhouse, Duke Energy Progress, Inc., to the NRC dated April 29, 2014, 

“H.B. Robinson Steam Electric Plant, Unit No. 2, Docket No. 50-261/Renewed License 

No. DPR-23; Refueling Outage 28 Steam Generator Tube Inspection Report.” ADAMS 

Accession No. ML14127A066

Letter from S.W. Peavyhouse, Duke Energy Progress, Inc., to the NRC dated 

September 29, 2014, “H.B. Robinson Steam Electric Plant, Unit No. 2, Docket 

No. 50-261/Renewed License No. DPR-23; Forced Outage R229F3 Steam Generator Tube 

Inspection Report.” ADAMS Accession No. ML14282A020

Letter from M. Barillas, NRC, to Site Vice President, Duke Energy Progress, Inc. dated 

October 27, 2014, “H.B. Robinson Steam Electric Plant, Unit No. 2—Summary of Conference 

Call Regarding Steam Generator Inspections During a Forced Outage in Spring 2014 (TAC 

No. MF5001).” ADAMS Accession No. ML14293A672

Letter from S.W. Peavyhouse, Duke Energy Progress, Inc., to the NRC dated 

November 13, 2014, “H.B. Robinson Steam Electric Plant, Unit No. 2, Docket 

No. 50-261/Renewed License No. DPR-23; Response to NRC Request for Additional 

Information Related to Refueling Outage 28 Steam Generator Tube Inspection Report.” ADAMS 

Accession No. ML14364A080
A-45

Salem 1

Letter from D.F. Garchow, PSEG Nuclear LLC, to the NRC dated November 5, 2002, “Steam 

Generator Tube Plugging Report; Technical Specification 4.4.5.5.a; Salem Generating Station 

Unit No. 1; Facility Operating License DPR-70; Docket No. 50-272.” ADAMS Accession 

No. ML023180283

Letter from G. Salamon, PSEG Nuclear LLC, to the NRC dated February 27, 2003, “Technical 

Specification 6.9.1.5 Annual Reports; Salem and Hope Creek Generating Stations; Docket 

Nos. 50-272, 50-311, and 50-354.” ADAMS Accession No. ML030630790

Letter from D.F. Garchow, PSEG Nuclear LLC, to the NRC dated January 7, 2004, “Response 

to NRC Request for Additional Information (RAI); Re: Steam Generator Tube Inspections 

Annual Report; (TAC Nos. MB8098 and MB8099); Salem Unit Nos. 1 and 2; Facility Operating 

License Nos. DPR-70 and DPR 75; Docket Nos. 50-272 and 50-311.” ADAMS Accession 

No. ML040140289

Letter from S.R. Mannon, PSEG Nuclear LLC, to the NRC dated May 3, 2004, “Steam 

Generator Tube Plugging Report; Technical Specification 4.4.5.5.a; Salem Generating Station 

Unit No. 1; Facility Operating License DPR-70; Docket No. 50-272.” ADAMS Accession 

No. ML041320507

Letter from M.H. Brothers, PSEG Nuclear LLC, to the NRC dated October 29, 2004, “Response 

to Generic Letter 2004-01, ‘Requirements for Steam Generator Tube Inspections’; Salem 

Generating Station Unit 1 and Unit 2; Docket Nos. 50-272 and 50-311; Facility Operating 

License Nos. DPR-70 and DPR-75.” ADAMS Accession No. ML043140237

Letter from C.L. Perino, PSEG Nuclear LLC, to the NRC dated February 25, 2005, “Technical 

Specification 6.9.1.5 Annual Reports; Salem and Hope Creek Generating Stations; Docket 

Nos. 50-272, 50-311, and 50-354.” ADAMS Accession No. ML050670560

Letter from S.N. Bailey, NRC, to W. Levis, PSEG Nuclear LLC dated October 14, 2005, “Salem 

Nuclear Generating Station, Unit No. 1—Issuance of Amendments Re: Steam Generator Tube 

Inservice Inspection Program (TAC No. MC6213).” ADAMS Accession No. ML052900201

Letter from R.B. Ennis, NRC, to W. Levis, PSEG Nuclear LLC dated March 27, 2007, “Salem 

Nuclear Generating Station, Unit No. 1, Issuance of Amendment Re: Steam Generator Alternate 

Repair Criteria (TAC No. MD4034).” ADAMS Accession No. ML070790081

Letter from R.C. Braun, PSEG Nuclear LLC, to the NRC dated October 10, 2007, “Steam 

Generator Tube Inspection Report—Eighteenth Refueling Outage (1R18).” ADAMS Accession 

No. ML072970094

Letter from C.T. Neely, PSEG Nuclear LLC, to the NRC dated April 30, 2008, “RAI Response, 

Steam Generator Tube Inspection Report—Eighteenth Refueling Outage (1R18).” ADAMS 

Accession No. ML081290513

Letter from R.B. Ennis, NRC, to T. Joyce, PSEG Nuclear LLC dated March 29, 2010, “Salem 

Nuclear Generating Station, Unit No. 1, Issuance of Amendment Re: Steam Generator 

Inspection Scope and Repair Requirements (TAC No. ME2374).” ADAMS Accession 

No. ML100570452
A-46

Letter from R.B. Ennis, NRC, to T. Joyce, PSEG Nuclear LLC dated August 31, 2010, 

“Summary of Conference Call Regarding the Spring 2010 Steam Generator Tube Inspections at 

Salem Nuclear Generating Station, Unit No. 1 (TAC No. ME3459).” ADAMS Accession 

No. ML102290044

Letter from C.J. Fricker, PSEG Nuclear LLC, to the NRC dated October 21, 2010, “Steam 

Generator Tube Inspection Report—Twentieth Refueling Outage (1R20).” ADAMS Accession 

No. ML102980089

Letter from C.J. Fricker, PSEG Nuclear LLC, to the NRC dated February 10, 2011, “Response 

to Salem Nuclear Generating Station, Unit No. 1, Draft Request for Additional Information (TAC 

No. ME4923).” ADAMS Accession No. ML110550192

Letter from J.D. Hughey, NRC, to T. Joyce, PSEG Nuclear LLC dated March 28, 2013, “Salem 

Nuclear Generating Station, Unit No. 1—Issuance of Amendment Re: Revision to Technical 

Specification 6.8.4.i, ‘Steam Generator Program,’ and Technical Specification 6.9.1.10, ‘Steam 

Generator Tube Inspection Report,’ for a Permanent Alternate Repair Criteria (TAC 

No. ME8578).” ADAMS Accession No. ML13072A105

Letter from J. Perry, PSEG Nuclear LLC, to the NRC dated November 4, 2013, “Steam 

Generator Tube Inspection Report—Twenty Second Refueling Outage (1R22).” ADAMS 

Accession No. ML13310A885

Letter from J. Perry, PSEG Nuclear LLC, to the NRC dated April 24, 2014, “RAI [Request for

Additional Information] Response to the Steam Generator Tube Inspection Report—Twenty 

Second Refueling Outage (1R22).” ADAMS Accession No. ML14115A016
A-47

Surry 1 and 2

Letter from S.P. Sarver, Virginia Electric and Power Co., to the NRC dated April 3, 2002, 

“Virginia Electric and Power Co.; Surry Power Station Unit 2; Steam Generator Tube Inspection 

Report.” ADAMS Accession No. ML020990363

Letter from G.E. Edison, NRC, to D.A. Christian, Virginia Electric and Power Co. dated 

May 24, 2002, “Surry Power Station Unit 2—Summary of Conference Call Regarding Steam 

Generator Inspection (TAC No. MB4773).” ADAMS Accession No. ML021440045

Letter from C.L. Funderburk, Virginia Electric and Power Co., to the NRC dated 

February 26, 2003, “Virginia Electric and Power Co. (Dominion); Surry Power Station Units 1 

and 2; Annual Steam Generator Inservice Inspection Summary Report.” ADAMS Accession 

No. ML030690393

Letter from C.L. Funderburk, Virginia Electric and Power Co., to the NRC dated May 14, 2003, 

“Virginia Electric and Power Co.; Surry Power Station Unit 1; Steam Generator Tube Inspection 

Report.” ADAMS Accession No. ML031410078

Letter from C. Gratton, NRC, to D.A. Christian, Virginia Electric and Power Co. dated 

June 17, 2003, “Surry Unit 1—Summary of Conference Call with Virginia Electric and Power Co.

Regarding the 2003 Steam Generator Tube Inspection Results (TAC No. MB8131).” ADAMS 

Accession No. ML031750893

Letter from C. Gratton, NRC, to D.A. Christian, Virginia Electric and Power Co. dated 

October 24, 2003, “Surry Unit 1—Revised Summary of Conference Call with Virginia Electric 

and Power Co. Regarding the 2003 Steam Generator Tube Inspection Results for Surry Power 

Station, Unit 1 (TAC No. MB8131).” ADAMS Accession No. ML033010026

Letter from C.L. Funderburk, Virginia Electric and Power Co., to the NRC dated 

February 23, 2004, “Virginia Electric and Power Co. (Dominion); Surry Power Station Units 1 

and 2; Annual Steam Generator Inservice Inspection Summary Report.” ADAMS Accession 

No. ML040630162

Letter from W.R. Matthews, Virginia Electric and Power Co., to the NRC dated 

October 29, 2004, “Virginia Electric and Power Co. (Dominion); Dominion Nuclear Connecticut, 

Inc. (DNC); North Anna Power Station Units 1 and 2; Surry Power Station Units 1 and 2; 

Millstone Power Station Units 2 and 3; Sixty Day Response to NRC Generic Letter 2004-01; 

Requirements for Steam Generator Tube Inspections.” ADAMS Accession No. ML043060099

Letter from L.N. Hartz, Virginia Electric and Power Co., to the NRC dated November 1, 2004, 

“Virginia Electric and Power Co.; Surry Power Station Units 1 and 2; 2003 Annual Steam 

Generator Inservice Inspection Summary Report; Response to Request For Additional 

Information.” ADAMS Accession No. ML043070192

Letter from C.L. Funderburk, Virginia Electric and Power Co., to the NRC dated 

February 21, 2005, “Virginia Electric and Power Co. (Dominion); Surry Power Station Units 1 

and 2; Annual Steam Generator Inservice Inspection Summary Report.” ADAMS Accession 

No. ML050530052
A-48

Letter from C.L. Funderburk, Virginia Electric and Power Co., to the NRC dated May 31, 2005, 

“Virginia Electric and Power Co. (Dominion); Surry Power Station Unit 2; Steam Generator Tube 

Inspection Report.” ADAMS Accession No. ML051600111

Letter from C.L. Funderburk, Virginia Electric and Power Co., to the NRC dated 

February 28, 2006, “Virginia Electric and Power Co. (Dominion); Surry Power Station Units 1 

and 2; Annual Steam Generator Inservice Inspection Summary Report.” ADAMS Accession 

No. ML060600281

Letter from C.L. Funderburk, Virginia Electric and Power Co., to the NRC dated June 1, 2006, 

“Virginia Electric and Power Co. (Dominion); Surry Power Station Unit 1; Steam Generator Tube 

Inspection Report.” ADAMS Accession No. ML061520302

Letter from G.T. Bischof, Virginia Electric and Power Co., to the NRC dated August 2, 2006, 

“Virginia Electric and Power Co.; Surry Power Station Unit No. 2; Response to Request for 

Additional Information; Steam Generator Tube Inservice Inspection Reports for the 2005 

Refueling Outage.” ADAMS Accession No. ML062140360

Letter from C.L. Funderburk, Virginia Electric and Power Co., to the NRC dated 

November 30, 2006, “Virginia Electric and Power Co.; Surry Power Station Unit 2; Steam 

Generator Tube Plugging Report.” ADAMS Accession No. ML063340555

Letter from S.P. Lingam, NRC, to D.A. Christian, Virginia Electric and Power Co. dated 

December 4, 2006, “Surry Power Station, Unit No. 1—Summary of Conference Call Regarding 

the Spring 2006 Steam Generator Tube Inspection Activities (TAC No. MD2420).” ADAMS 

Accession No. ML063380371

Letter from C.L. Funderburk, Virginia Electric and Power Co., to the NRC dated March 1, 2007, 

“Virginia Electric and Power Co. (Dominion); Surry Power Station Units 1 and 2; 2006 Annual 

Steam Generator Inservice Inspection Summary Report.” ADAMS Accession No. ML070650263

Letter from S.P. Lingam, NRC, to D.A. Christian, Virginia Electric and Power Co. dated 

March 29, 2007, “Surry Power Station, Unit Nos. 1 and 2, Issuance of Amendments Regarding 

Steam Generator Tube Integrity (TAC Nos. MD2097 and MD2098).” ADAMS Accession 

No. ML070880618

Letter from G.T. Bischof, Virginia Electric and Power Co., to the NRC dated August 10, 2007, 

“Virginia Electric and Power Co.; Surry Power Station Units 1 and 2; Response to Request for 

Additional Information; 2006 Steam Generator Inservice Inspection Reports.” ADAMS 

Accession No. ML072280196

Letter from S.P. Lingam, NRC, to D.A. Christian, Virginia Electric and Power Co. dated 

December 11, 2007, “Surry Nuclear Power Station, Unit 1, 2007 Steam Generator Tube 

Inspections (TAC No. MD7236).” ADAMS Accession No. ML073380143

Letter from S.P. Lingam, NRC, to D.A. Christian, Virginia Electric and Power Co. dated 

May 16, 2008, “Surry Power Station, Unit No. 2—Issuance of Exigent Amendment RE: Interim 

Alternate Repair Criteria for Steam Generator Tube Repair (TAC No. MD8504).” ADAMS 

Accession No. ML081340106
A-49

Letter from D.E. Jernigan, Virginia Electric and Power Co., to the NRC dated May 21, 2008, 

“Virginia Electric and Power Co.; Surry Power Station Unit 1; Steam Generator Tube Inservice 

Inspection Report for the 2007 Refueling Outage.” ADAMS Accession No. ML081560216

Letter from S.P. Lingam, NRC, to D.A. Christian, Virginia Electric and Power Co. dated 

June 10, 2008, “Surry Power Station, Unit No. 2, Spring 2008 Refueling Outage Steam 

Generator Tube Inspections (TAC No. MD8615).” ADAMS Accession No. ML081490152

Letter from G.T. Bischof, Virginia Electric and Power Co., to the NRC dated October 9, 2008, 

“Virginia Electric and Power Co.; Surry Power Station Unit 1; Response to Request for 

Additional Information; 2007 Steam Generator Inservice Inspection Report.” ADAMS Accession 

No. ML082970192

Letter from G.T. Bischof, Virginia Electric and Power Co., to the NRC dated 

November 14, 2008, “Virginia Electric and Power Co.; Surry Power Station Unit 2; Steam 

Generator Tube Inservice Inspection Report for the 2008 Refueling Outage.” ADAMS Accession 

No. ML090060111

Letter from D.N. Wright, NRC, to D.A. Christian, Virginia Electric and Power Co. dated 

April 8, 2009, “Surry Power Station, Unit No. 1, Issuance of Amendment Regarding Proposed 

License Amendment Request—Interim Alternate Repair Criteria for Steam Generator Tube 

Repair (TAC No. MD9976).” ADAMS Accession No. ML090860735

Letter from D. Wright, NRC, to D.A. Christian, Virginia Electric and Power Co. dated 

April 16, 2009, “Surry Power Station, Unit No. 1 Correction Letter for License Amendment 

No. 263 Regarding Interim Alternate Repair Criteria for Steam Generator Tube Repair (TAC 

No. MD9976).” ADAMS Accession No. ML091040065

Letter from J. Stang, NRC, to D.A. Christian, Virginia Electric and Power Co. dated May 7, 2009, 

“Surry Power Station, Unit No. 1 Issuance of Amendment Regarding Modified Interim Alternate 

Repair Criteria for B Steam Generator Tube Repair (TAC No. ME1191).” ADAMS Accession 

No. ML091260386

Letter from G.T. Bischof, Virginia Electric and Power Co., to the NRC dated July 13, 2009, 

“Virginia Electric and Power Co.; Surry Power Station Unit 2; Response to Request for 

Additional Information; 2008 Steam Generator Inservice Inspection Report.” ADAMS Accession 

No. ML092020251

Letter from K. Cotton, NRC, to D.A. Heacock, Virginia Electric and Power Co. dated September 

16, 2009, “Surry Power Station, Unit No. 1—Summary of Conference Calls Regarding the 

Spring 2009 Steam Generator Inspections (TAC No. ME0981).” ADAMS Accession 

No. ML091950409

Letter from B.L. Stanley, Virginia Electric and Power Co., to the NRC dated November 4, 2009,

“Virginia Electric and Power Co.; Surry Power Station Unit 1; Steam Generator Tube Inservice 

Inspection Report for the 2009 Refueling Outage.” ADAMS Accession No. ML093200207

Letter from K. Cotton, NRC, to D.A. Heacock, Virginia Electric and Power Co. dated 

November 5, 2009, “Surry Power Station, Unit Nos. 1 and 2, Issuance of Amendments 

Regarding License Amendment Request for Alternate Repair Criteria for Steam Generator 
A-50

Tubesheet Expansion Region (TAC Nos. ME1783 and ME1784).” ADAMS Accession 

No. ML092960484

Letter from G.T. Bischof, Virginia Electric and Power Co., to the NRC dated May 24, 2010, 

“Virginia Electric and Power Co.; Surry Power Station Unit 2; Steam Generator Tube Inservice 

Inspection Report for the 2009 Refueling Outage.” ADAMS Accession No. ML101530533

Letter from B.L. Stanley, Virginia Electric and Power Co., to the NRC dated June 7, 2010, 

“Virginia Electric and Power Co.; Surry Power Station Unit 1; Response to Request for 

Additional Information; 2009 Steam Generator Inservice Inspection Report.” ADAMS Accession 

No. ML101660088

Letter from G.T. Bischof, Virginia Electric and Power Co., to the NRC dated April 25, 2011, 

“Virginia Electric and Power Co. (Dominion); Surry Power Station Unit 2; Response to Request 

for Additional Information; Unit 2 2009 Steam Generator Tube Inspection Report.” ADAMS 

Accession No. ML11124A009

Letter from K. Cotton, NRC, to D.A. Heacock, Virginia Electric and Power Co. dated 

May 20, 2011, “Surry Power Station, Unit No. 2, Issuance of Amendment Regarding Technical 

Specification Change to Sections 6.4Q, ‘Steam Generator (SG) Program’ and 6.6.A.3 ‘Steam 

Generator Tube Inspection Report’ (H*) (TAC No. ME5368).” ADAMS Accession 

No. ML11090A000 (and ML111810163)

Letter from G.T. Bischof, Virginia Electric and Power Co., to the NRC dated May 24, 2011, 

“Virginia Electric and Power Co.; Surry Power Station Unit 1; Steam Generator Tube Inservice 

Inspection Report for the 2010 Refueling Outage.” ADAMS Accession No. ML11154A101

Letter from K. Cotton, NRC, to D.A. Heacock, Virginia Electric and Power Co. dated 

June 30, 2011, “Surry Power Station, Unit No. 2—2009 Refueling Outage Steam Generator 

Tube Inspections Summary for End of Cycle 22 (TAC No. ME5689).” ADAMS Accession 

No. ML11144A252

Letter from K. Cotton, NRC, to D.A. Heacock, Virginia Electric and Power Co. dated 

July 5, 2011, “Surry Power Station, Unit No. 2—Summary of Conference Call Regarding the 

Spring 2011 Steam Generator Tube Inspections (TAC No. ME6146).” ADAMS Accession 

No. ML11173A154

Letter from G.T. Bischof, Virginia Electric and Power Co., to the NRC dated October 5, 2011, 

“Virginia Electric and Power Co.; Surry Power Station Unit 2; Steam Generator Tube Inservice 

Inspection Report for the 2011 Refueling Outage.” ADAMS Accession No. ML11291A058

Letter from B.L. Stanley, Virginia Electric and Power Co., to the NRC dated December 15, 2011, 

“Virginia Electric and Power Co.; Surry Power Station Unit 1; Response to Request for 

Additional Information; 2010 Steam Generator Inservice Inspection Report.” ADAMS Accession 

No. ML12003A242

Letter from K. Cotton, NRC, to D.A. Heacock, Virginia Electric and Power Co. dated 

April 17, 2012, “Surry Power Station, Unit Nos. 1 and 2, Issuance of Amendments Regarding 

Virginia Electric and Power Co. License Amendment Request for Permanent Alternate Repair 

Criteria for Steam Generator Tube Inspection and Repair (TAC Nos. ME6803 and ME6804).” 

ADAMS Accession Nos. ML120730304 and ML12109A270
A-51

Letter from N.L. Lane, Virginia Electric and Power Co., to the NRC dated June 22, 2012, 

“Virginia Electric and Power Co.; Surry Power Station Unit 2; Response to Request for 

Additional Information; 2011 Steam Generator Inservice Inspection Report.” ADAMS Accession 

No. ML12187A165

Letter from N.L. Lane, Virginia Electric and Power Co., to the NRC dated October 30, 2012, 

“Virginia Electric and Power Co.; Surry Power Station Unit 1; Steam Generator Tube Inservice 

Inspection Report for the Spring 2012 Refueling Outage.” ADAMS Accession 

No. ML12321A047

Letter from K. Cotton, NRC, to D.A. Heacock, Virginia Electric and Power Co. dated 

January 28, 2013, “Surry Power Station, Unit No. 1 and 2 Issuance of Amendments to Adopt 

Technical Specification Task Force (TSTF) 510, Revision 2, Revision to Steam Generator 

Program Inspection Frequencies and Tube Sample Selection (TAC Nos. ME9199 and 

ME9200).” ADAMS Accession No. ML13018A086

Letter from K. Cotton, NRC, to D.A. Heacock, Virginia Electric and Power Co. dated 

February 7, 2013, “Surry Power Station, Unit 1—Correction Letter to License Amendment 

No. 278 Regarding Adoption of Technical Specification Task Force (TSTF 510, Revision 2, 

Steam Generator Program Inspection Frequencies and Tube Sample Selection (TAC 

No. ME9199).” ADAMS Accession No. ML13032A206

Letter from D.C. Lawrence, Virginia Electric and Power Co., to the NRC dated April 1, 2013, 

“Virginia Electric and Power Co.; Surry Power Station Unit 1; Response to Request for 

Additional Information; 2012 Steam Generator Inservice Inspection Report.” ADAMS Accession 

No. ML13105A134

Letter from K. Cotton, NRC, to D.A. Heacock, Virginia Electric and Power Co. dated 

April 23, 2013, “Surry Power Station, Unit Nos. 1 and 2, Correction Letter Regarding License 

Amendment Nos. 278 and 278 to Adopt Technical Specification Task Force (TSTF)-510, 

Revision 2, Revision to Steam Generator Program Inspection Frequencies and Tube Sample 

Selection.” ADAMS Accession No. ML13099A106

Letter from N.L. Lane, Virginia Electric and Power Co., to the NRC dated May 10, 2013, 

“Virginia Electric and Power Co.; Surry Power Station Unit 2; Steam Generator Tube Inservice 

Inspection Report for the Fall 2012 Refueling Outage.” ADAMS Accession No. ML13149A229

Letter from K. Cotton, NRC, to D.A. Heacock, Virginia Electric and Power Co. dated 

August 16, 2013, “Surry Power Station—Review of the Steam Generator Tube Inservice 

Inspection Report for the Surry Power Station, Unit 1, Refueling Outage in 2012 (TAC 

No. MF0062).” ADAMS Accession No. ML13212A363

Letter from N.L. Lane, Virginia Electric and Power Co., to the NRC dated January 23, 2014, 

“Virginia Electric and Power Co.; Surry Power Station Unit 2; Response to Request for Clarifying 

Information Regarding Steam Generator Tube Inservice Inspection Report for the Fall 2012 

Refueling Outage.” ADAMS Accession No. ML14028A256

Letter from N.L. Lane, Virginia Electric and Power Co., to the NRC dated May 6, 2014, “Virginia 

Electric and Power Co.; Surry Power Station Unit 1; Steam Generator Tube Inservice Inspection 

Report for the Fall 2013 Refueling Outage.” ADAMS Accession No. ML14135A365
A-52

Letter from N.L. Lane, Virginia Electric and Power Co., to the NRC dated October 16, 2014, 

“Virginia Electric and Power Co.; Surry Power Station Unit 2; Steam Generator Tube Inservice 

Inspection Report for the Spring 2014 Refueling Outage.” ADAMS Accession 

No. ML14294A449

Letter from N.L. Lane, Virginia Electric and Power Co., to the NRC dated November 19, 2014, 

“Virginia Electric and Power Co.; Surry Power Station Unit 1; Response to Request for 

Additional Information; 2013 Steam Generator Inservice Inspection Report.” ADAMS Accession 

No. ML14335A606
A-53

Turkey Point 3

Letter from W. Jefferson, Jr., Florida Power and Light Co., to the NRC dated March 24, 2003, 

“Turkey Point Unit 3; Docket No. 50-250; Steam Generator Tube Plugging 15-Day Report.” 

ADAMS Accession No. ML041310225

Letter from T.O. Jones, Florida Power and Light Co., to the NRC dated June 26, 2003, “Turkey 

Point Unit 3; Docket No. 50-250; Inservice Inspection Report.” ADAMS Accession 

No. ML031820625

Letter from T.O. Jones, Florida Power and Light Co., to the NRC dated July 30, 2003, “Turkey 

Point Unit 3; Docket No. 50-250; Revision to End of Cycle 18; Steam Generator Tube Plugging 

Report.” ADAMS Accession No. ML032580517

Letter from T.O. Jones, Florida Power and Light Co., to the NRC dated May 3, 2004, “Turkey 

Point Units 3 and 4; Docket Nos. 50-250 and 50-251; 10 CFR 50.59 Report.” ADAMS Accession 

No. ML041330113

Letter from T.O. Jones, Florida Power and Light Co., to the NRC dated October 18, 2004, 

“Turkey Point Unit 3; Docket No. 50-250; Steam Generator Tube Plugging 15-Day Special 

Report.” ADAMS Accession No. ML060040111

Letter from J.A. Stall, Florida Power and Light Co., to the NRC dated October 29, 2004, “Florida 

Power and Light Co.; St. Lucie Units 1 and 2; Docket Nos. 50-335 and 50-389; Turkey Point 

Units 3 and 4; Docket Nos. 50-250 and 50-251; FPL Energy Seabrook, LLC; Seabrook Station; 

Docket No. 50-443; NRC Generic Letter 2004-01; Requirements for Steam Generator Tube 

Inspections.” ADAMS Accession No. ML043070353

Letter from T.O. Jones, Florida Power and Light Co., to the NRC dated November 5, 2004, 

“Turkey Point Units 3 and 4; Docket Nos. 50-250 and 50-251; Request for Additional 

Information—Steam Generator Tube Inspection Summary Reports.” ADAMS Accession 

No. ML043220407

Letter from T.O. Jones, Florida Power and Light Co., to the NRC dated February 28, 2005, 

“Turkey Point Unit 3; Docket No. 50-250; Inservice Inspection Report.” ADAMS Accession 

Nos. ML050670045 and ML050670057

Letter from T.O. Jones, Florida Power and Light Co., to the NRC dated June 17, 2005, “Turkey 

Point Unit 3; Docket No. 50-250; Steam Generator Tube Plugging; Inservice Inspection 12-

Month Special Report.” ADAMS Accession No. ML051810242

Letter from J.A. Stall, Florida Power and Light Co., to the NRC dated February 17, 2006, 

“Florida Power and Light Co.; St. Lucie Units 1 and 2; Docket Nos. 50-335 and 50-389; Turkey 

Point Units 3 and 4; Docket Nos. 50-250 and 50-251; FPL Energy Seabrook, LLC; Seabrook 

Station; Docket No. 50-443; Subject: 30-Day Response to NRC Generic Letter 2006-01, “Steam 

Generator Tube Integrity And Associated Technical Specifications,” January 20, 2006 

(ML060200385).” ADAMS Accession No. ML060530640
A-54

Letter from T.O. Jones, Florida Power and Light Co., to the NRC dated February 27, 2006, 

“Turkey Point Unit 3; Docket No. 50-250; Response to Request for Additional Information; 

Regarding Steam Generator Tube Plugging; Inservice Inspection Report (TAC No. MC8112).” 

ADAMS Accession No. ML060760370

Letter from T.O. Jones, Florida Power and Light Co., to the NRC dated June 28, 2006, “Turkey 

Point Unit 3; Docket No. 50-250; Inservice Inspection Report.” ADAMS Accession 

No. ML061860276

Letter from B.T. Moroney, NRC, to J.A. Stall, Florida Power and Light Co. dated 

November 1, 2006, “Turkey Point Plant, Units 3 and 4—Issuance of Amendments Regarding 

Steam Generator Alternate Repair Criteria (TAC Nos. MD1380 and MD1381).” ADAMS 

Accession No. ML062990193

Letter from B.L. Mozafari, NRC, to J.A. Stall, Florida Power and Light Co. dated April 27, 2007, 

“Turkey Point Plant, Units 3 and 4—Issuance of Amendments Regarding Steam Generator 

Tube Surveillance Program (TAC Nos. MD1389 and MD1390).” ADAMS Accession No. 

ML071080444

Letter from W. Jefferson, Jr., Florida Power and Light Co., to the NRC dated January 10, 2008, 

“Turkey Point Unit 3; Docket No. 50-250; Inservice Inspection Report.” ADAMS Accession 

No. ML080220439

Letter from W. Jefferson, Jr., Florida Power and Light Co., to the NRC dated April 3, 2008, 

“Turkey Point Unit 3; Docket No. 50-250; Steam Generator Tube Inspection Report.” ADAMS 

Accession No. ML081050248

Letter from W. Jefferson, Jr., Florida Power and Light Co., to the NRC dated January 30, 2009, 

“Turkey Point Unit 3; Docket No 50-250; Response to Request for Additional Information 

Regarding the 2007 Steam Generator Tube Inspection (TAC No. MD9234).” ADAMS Accession 

No. ML090570046

Letter from J.C. Paige, NRC, to M. Nazar, Florida Power and Light Co. dated October 30, 2009, 

“Turkey Point Units 3 and 4—Issuance of Amendments Regarding H*: Alternate Repair Criteria 

for Steam Generator Tubesheet Expansion Region (TAC Nos. ME1754 and ME1755).” ADAMS 

Accession No. ML092990489

Letter from J.C. Paige, NRC, to M. Nazar, Florida Power and Light Co. dated January 19, 2011, 

“Turkey Point Unit 3—Summary of October 12, 2010, Conference Call Regarding the Fall 2010, 

Steam Generator Inspections (TAC No. ME4556).” ADAMS Accession No. ML110030005

Letter from M. Kiley, Florida Power and Light Co., to the NRC dated April 19, 2011, “Turkey 

Point Unit 3; Docket No. 50-250; Steam Generator Tube Inspection Report.” ADAMS Accession 

No. ML11119A006

Letter from M. Kiley, Florida Power and Light Co., to the NRC dated May 6, 2011, “Turkey Point 

Unit 3; Docket No 50-250; Reportable Event: 2011-001-00; Date of Event: March 6, 2011; 

Manual Reactor Trip Due to Secondary Sodium Concentrations Exceeding Chemistry Limits.” 

ADAMS Accession No. ML11130A097
A-55

Letter from M. Kiley, Florida Power and Light Co., to the NRC dated November 23, 2011, 

“Turkey Point Unit 3; Docket No. 50-250; Response to Request for Additional Information 

Regarding the 2010 Steam Generator Tube Inspection.” ADAMS Accession No. ML11340A074

Letter from F.E. Saba, NRC, to M. Nazar, Florida Power and Light Co. dated November 5, 2012, 

“Turkey Point Nuclear Generating Station Unit Nos. 3 and 4—Issuance of Amendments 

Regarding Permanent Alternate Repair Criteria for Steam Generator Tubes (TAC Nos. ME8515 

and ME8516).” ADAMS Accession No. ML12292A342

Letter from F.E. Saba, NRC, to M. Nazar, Florida Power and Light Co. dated November 6, 2012, 

“Turkey Point Nuclear Generating Station Unit Nos. 3 and 4—Issuance of Amendments 

Regarding Adoption of TSTF-510, ‘Revision to Steam Generator Program Inspection 

Frequencies and Tube Sample Selection’ (TAC Nos. ME9106 and ME9107).” ADAMS 

Accession No. ML12297A240

Letter from M. Kiley, Florida Power and Light Co., to the NRC dated October 6, 2014, “Turkey 

Point Unit 3; Docket No. 50-250; Steam Generator Tube Inspection Report.” ADAMS Accession 

No. ML14302A079
A-56

Turkey Point 4

Letter from J.P. McElwain, Florida Power and Light Co., to the NRC dated June 25, 2002, 

“Turkey Point Unit 4; Docket No. 50-251; Inservice Inspection Report.” ADAMS Accession 

No. ML021900291

Letter from T.O. Jones, Florida Power and Light Co., to the NRC dated October 30, 2003, 

“Turkey Point Unit 4; Docket No. 50-251; Steam Generator Tube Plugging 15-Day Report.” 

ADAMS Accession No. ML15205A315

Letter from T.O. Jones, Florida Power and Light Co., to the NRC dated January 30, 2004, 

“Turkey Point Unit 4; Docket No. 50-251; Inservice Inspection Report.” ADAMS Accession 

No. ML040340484

Letter from T.O. Jones, Florida Power and Light Co., to the NRC dated May 3, 2004, “Turkey 

Point Units 3 and 4; Docket Nos. 50-250 and 50-251; 10 CFR 50.59 Report.” ADAMS Accession 

No. ML041330113

Letter from T.O. Jones, Florida Power and Light Co., to the NRC dated October 12, 2004, 

“Turkey Point Unit 4; Docket No. 50-251; Steam Generator Tube Plugging; Inservice Inspection 

12-Month Special Report.” ADAMS Accession No. ML042940297

Letter from J.A. Stall, Florida Power and Light Co., to the NRC dated October 29, 2004, “Florida 

Power and Light Co.; St. Lucie Units 1 and 2; Docket Nos. 50-335 and 50-389; Turkey Point 

Units 3 and 4; Docket Nos. 50-250 and 50-251; FPL Energy Seabrook, LLC; Seabrook Station; 

Docket No. 50-443; NRC Generic Letter 2004-01; Requirements for Steam Generator Tube 

Inspections.” ADAMS Accession No. ML043070353

Letter from T.O. Jones, Florida Power and Light Co., to the NRC dated November 5, 2004, 

“Turkey Point Units 3 and 4; Docket Nos. 50-250 and 50-251; Request for Additional 

Information—Steam Generator Tube Inspection Summary Reports.” ADAMS Accession 

No. ML043220407

Letter from T.O. Jones, Florida Power and Light Co., to the NRC dated September 8, 2005, 

“Turkey Point Unit 4; Docket No. 50-251; 2005 Inservice Inspection Report.” ADAMS Accession 

No. ML052630030

Letter from B.T. Moroney, NRC, to J.A. Stall, Florida Power and Light Co. dated 

November 1, 2006, “Turkey Point Plant, Units 3 and 4—Issuance of Amendments Regarding 

Steam Generator Alternate Repair Criteria (TAC Nos. MD1380 and MD1381).” ADAMS 

Accession No. ML062990193

Letter from M.E. Ernstes, NRC, to J.A. Stall, Florida Power and Light Co. dated 

January 26, 2007, “Turkey Point Nuclear Plant—Integrated Inspection Report 

05000250/2006005 and 05000251/2006005 and Exercise of Enforcement Discretion.” ADAMS 

Accession No. ML070260489

Letter from W. Jefferson, Jr., Florida Power and Light Co., to the NRC dated March 8, 2007, 

“Turkey Point Unit 4; Docket No. 50-251; Inservice Inspection Report.” ADAMS Accession 

No. ML070710304
A-57

Letter from B.L. Mozafari, NRC, to J.A. Stall, Florida Power and Light Co. dated April 27, 2007, 

“Turkey Point Plant, Units 3 and 4—Issuance of Amendments Regarding Steam Generator 

Tube Surveillance Program (TAC Nos. MD1389 and MD1390).” ADAMS Accession 

No. ML071080444

Letter from W. Jefferson, Jr., Florida Power and Light Co., to the NRC dated March 12, 2008, 

“Turkey Point Unit 4; Docket No. 50-251; Response to Request for Additional Information 

Regarding the 2006 Steam Generator Tube Inspections (TAC No. MD6875).” ADAMS 

Accession No. ML080810192

Letter from J.C. Paige, NRC, to M. Nazar, Florida Power and Light Co. dated October 30, 2009, 

“Turkey Point Units 3 and 4—Issuance of Amendments Regarding H*: Alternate Repair Criteria 

for Steam Generator Tubesheet Expansion Region (TAC Nos. ME1754 and ME1755).” ADAMS 

Accession No. ML092990489

Conference Call Summary dated January 27, 2010, “Summary of November 10, 2009, 

Conference Call with Florida Power & Light, on the Fall 2009 Steam Generator Inspections 

(TAC No. ME2536).” ADAMS Accession No. ML100251277

Letter from M. Kiley, Florida Power and Light Co., to the NRC dated April 21, 2010, “Turkey 

Point Unit 4; Docket No. 50-251; Steam Generator Tube Inspection Report.” ADAMS Accession 

No. ML101250532

Letter from F.E. Saba, NRC, to M. Nazar, Florida Power and Light Co. dated November 5, 2012, 

“Turkey Point Nuclear Generating Station Unit Nos. 3 and 4—Issuance of Amendments 

Regarding Permanent Alternate Repair Criteria for Steam Generator Tubes (TAC Nos. ME8515

and ME8516).” ADAMS Accession No. ML12292A342

Letter from F.E. Saba, NRC, to M. Nazar, Florida Power and Light Co. dated November 6, 2012, 

“Turkey Point Nuclear Generating Station Unit Nos. 3 and 4—Issuance of Amendments 

Regarding Adoption of TSTF-510, ‘Revision to Steam Generator Program Inspection 

Frequencies and Tube Sample Selection’ (TAC Nos. ME9106 and ME9107).” ADAMS 

Accession No. ML12297A240

Letter from M. Kiley, Florida Power and Light Co., to the NRC dated September 19, 2013, 

“Turkey Point Unit 4; Docket No. 50-251; Steam Generator Tube Inspection Report.” ADAMS 

Accession No. ML13277A358

Letter from M. Kiley, Florida Power and Light Co., to the NRC dated February 19, 2014, “Turkey 

Point Unit 4; Docket No. 50-251; Response to Request for Additional Information Regarding 

Steam Generator Tube Inspection Report.” ADAMS Accession No. ML14069A083

Letter from A. Klett, NRC, to M. Nazar, Florida Power and Light Co. dated June 19, 2014, 

“Turkey Point Nuclear Generating Unit No. 4—Review of Steam Generator Tube Inspection 

Report for Cycle 27 Refueling Outage (TAC No. MF2886).” ADAMS Accession 

No. ML14127A426







NUREG

-2188 U.S. Operating Experience with Thermally Treated Alloy 600 Steam 

Generator Tubes Through December 2013